bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Oil Pipeline Multiphase Pressure Drop Correlation
Authors: Ilic V. , Behnia M. 
Published: October 2008

ABSTRACT
In their respective laboratories, the authors have begun an extensive experimental program of systematic, mu1tiphase (oil/water, water/gas and oil/water/gas) pressure drop and void fraction data generation in 25 mm and 100 mm bore inclined pipes. In conjunction with flow pattern transition boundaries records, this data will be used as a basis for establishing scaleup parameters when combined with the available field data.
The aim of the initial work reported here was to establish a basis for a simp1e-to-use mu1tiphase pressure drop correlation that could be applied to the design or assessment of pipelines with flows of mixtures of oil and gas phases.
189 field data points were selected from (1). Only fully documented data were used.

INTRODUCTION
A plethora of mu1tiphase pressure drop correlations exists that are currently used in the oil industry (2). A recent (3) evaluation of pressure drop and holdup correlations for gas/condensate pipelines showed that, while accuracy is better with the former, most of the correlations produce significantly large errors. A study of similar correlations with air/water mixtures (4) indicated increasing error with pipe diameter for currently used holdup and pressure drop correlations.
It has generally been the case that data best described by a given correlation usually originated with the author of the correlation. Because of the variety of field conditions under which pipelines operate, the designer usually has to select the most appropriate correlations and base his choice on the most conservative result to obtain the pipeline bore. The pipe diameter chosen in this way is invariably oversize, and therefore the installation excessively costly. With an average cost in Australia of an installed pipeline in the Vicinity of $US1000/mm km, a 100 km pipeline would cost $5 million more than it should if it was deliberately oversized by 50 mm. Improved and new multiphase pressure drop models and correlations will therefore be justified until the uncertainty in the design is significantly reduced.
Because data obtained in laboratory experiments are better controlled and generally more accurate than field data, they are amenable to systematic generation and modelling. However, because pipeline sizes and flowrates are considerably smaller under such conditions, data correlations based on laboratory experiments generally produce large errors when compared with field data (4). Accurate scale-up techniques therefore need to be developed to improve application of such correlations to field conditions. As a first step towards that end, a brief analysis of data from (1) was made and initial results are reported here.
The aim of this paper is to present results of this analysis in the form of a simp1e-to-use correlation for mu1tiphase pipeline pressure drop derived for a selected batch of 189 data points taken from (1). The basis for data inclusion was their completeness.
Acquisition and Processing of Shallow Water 3-D Seismic Surveys Over Producing Fields in the Northwest Niger Delta
Authors: Olofin D.K. , Will R.A. 
Published: October 2008

ABSTRACT
Most of the fields operated by Gulf Nigeria on behalf of Nigerian National Petroleum Corp. (NNPC) and Gulf Joint Venture, lie in the shallow waters of the northwest Niger Delta. The techniques of radio-telemetric transmission of seismic data, shallow-draft seismic source vessels, and receiver swath survey methods have been used to gather data accurately and efficiently. Processing steps such as 3-D residual statics, dip move-out (DMO), and steep dip migration have been used to produce highly resolved images of the subsurface. The fields surveyed are mostly in mature stages of development and the 3-D data acquired in these surveys are better defined than the 2-D lines used for original mapping. Because of the new methods used to acquire and process the 3-D data, seismic interpreters have identified untested fault blocks, stratigraphic plays, and deeper pool potential. The fields can now be more completely and efficiently developed.

INTRODUCTION
Between 1984 and 1987, western Geophysical Company acquired and processed three 3-D seismic surveys for Gulf Oil Company in the following producing oil fields offshore northwest Niger Delta : Malu-Parabe, Okan, and Mina-Meren-Ewan (Fig. 1).
The first 3-D survey was conducted between August 1984 and March 1985 (processing inclusive) in Malu-Parabe fields using air gun sources and streamed cable. About 4266 mi (6,865 kID) of 4800% seismic data were acquired [equivalent to approximately 116 sq mi (300 sq kID)] in Malu-Parabe fields located in water depths varying between 20 and 100 ft (6.1 to 30.5 m). To date, a total of 61 wells have been spudded in these two adjoining fields which have been producing oil since 1971.
The second 3-D survey was carried out between December 1985 and January 1987 (processing inclusive) in Okan field located in 10 to 60 ft (3.1 to 18.3 m) water depth, using a radio telemetric acquisition system with airgun sources. Okan is a giant oilfield, and is the oldest field in Gulf's concession offshore Niger Delta. To date, 76 wells have been spudded in this field and it has been producing oil since 1965. The 3-D survey also encompassed parts of Mefa and Delta South fields which adjoin Okan field to the southwest and northeast respectively. The size of this survey was 96 sq mi (250 sq km) with a nominal fold of coverage of 4400%.
The third survey, which is the largest, embraced three field areas called Mina-Meren- Ewan. The water depth in Mina-Meren-Ewan area varies between 10 ft (3.1 m) and 80 ft (24.4 m). A similar but slightly modified radio telemetric shooting technique as was used in the Okan 3-D survey was applied to the Mina-Meren- Ewan area. About 154 sq mi (400 sq km) of 3-D data were successfully acquired in this area between November 1986 and May 1987 with 6000% multiplicity.
An Intercomparison of Measured Wave Grouping Parameters During a Storm
Authors: McCarthy T.J. 
Published: October 2008

ABSTRACT
This paper describes the results of a wave measurement experiment carried out at the Kinsale Head Gas field, off the South coast of Ireland between 21 and 23 November, 1984. Simultaneous wave recordings, of length up to two and a half hours, were made using wave buoy and wave staff devices. These recordings include the growth, peak and decay of a severe winter storm.
A comparison is made between the wave parameters obtained from the two devices. This includes first order wave spectra and their derived height and period parameters as well as the most commonly used wave grouping parameters.
The characteristic wave height and periods show good correlation between the wave buoy and staff while the chief grouping parameters demonstrate weaker dependence. The spectral peakedness parameter gave the strongest correlation but the mean run lengths were virtually un-correlated between the two locations. Each system gave similar values for the auto-correlation between successive wave heights with a weak but significant relationship. The Funke and Mansardgroupiness factor 1showed an even weaker dependency. This was slightly improved by employing a new modified factor. The agreement between SIWEH spectra was dependent on the length of the wave record.

1. INTRODUCTION
With the development of compliant and floating oil production systems, wave groups are increasingly important to offshore engineers. Many authors have demonstrated the relationship between the slow drift motions of moored floating structures and the presence of wave modulation due to groups. Despite this relatively little is known about the occurrence of wave groups during storms.
Attempts have been made to characterize nonrandom behavior of waves under two broad categories. Firstly, wave groups have been described in terms of the dependency of successive wave heights. The second category is the study of low frequency modulations of the sea surface.
The former may be described as counting methods, wherein the wave heights are discretized and examined as a series of statistical events. The most common definition of a wave group is a run of consecutive waves whose heights exceed some threshold value. Figure 1 demonstrates this definition showing two wave, groups of length 3 and 4. Goda considers the mean run length of a record for threshold values of Hs ' the significant wave height, and Havg, the average wave height. Goda also demonstrated that the individual run containing the largest wave of the record is on average longer than other wave groups. This particular wave group is termed the "extreme wave group" (EWG) and has been proposed as a design criterion for capsize tests.
Effect of Ripple Load on the Stress-Corrosion Cracking in Structural Steels
Authors: Pao P.S. , Bayles R.A. , Yoder G.R. 
Published: October 2008

ABSTRACT
The presence of small ripple loading can, under certain circumstances, significantly reduce time-to failure and threshold stress intensity for stress-corrosion cracking (SCC) of steels. A predictive framework for such ripple-loading effects (RLE) is developed from concepts and descriptors used in SCC and corrosion fatigue characterization. The proposed framework is capable of defining critical conditions required for the occurrence of RLE and predicting time-to-failure curves. The agreement between the predicted and laboratory data is excellent.

INTRODUCTION
Stress-corrosion cracking (SCC) is a cracking process caused by the conjoint action of stress and a corrodent. Conceptually, SCC will occur if a sensitive material is exposed to a corrosive environment under sufficient stress for a sufficient length of time. For a structural material which contains a crack or crack-like defect, the resistance to SCC is normally evaluated in terms of the fracture mechanics parameter, KIlscc the threshold stress-intensity factor below which fracture will not occur. The measurement of KIlscc and its application to design of structures for the marine environment commonly presumes sustained or constant load conditions. Applications in the real world, however - including many in offshore platform structures, rarely involve an absolutely constant load condition, but are far more apt to involve the superposition of relatively small amplitude load perturbations or "ripple load". Recent work [1-4] has demonstrated that under such ripple- Ioading conditions, fracture can occur in some cases at stress-intensity levels much less than KIlscc. Thus, the implications of the ripple-load effect (RLE) may be quite serious. An extensive literature survey on ripple-load effects was recently prepared, which cited several examples from both low- and high-strength and ferrous and nonferrous alloy systems [5].
The objective of this paper is to develop the understanding of the RLE and the framework required for the prediction of the RLE. First of all, RLE is investigated in two different classes of steels: the medium strength, high toughness 5Ni-Cr-Mo-V steel and the high strength, low toughness AISI 4340 steel. Secondly, the critical conditions required for a material to exhibit RLE in the marine environment are defined and quantitative prediction of the maximum extent of degradation by the RLE is presented. And finally, the quantitative predictive methodology for time-to-failure curves associated with the ripple-load cracking is offered for a given combination of material and loading conditions.

MATERIALS AND EXPERIMENTAL PROCEDURES
Two steels studied in this investigation are 5Ni- Cr-Mo-V and AH 4340 rolled plate materials. Results of chemical analysis and tensile properties are given in Tables 1 and 2, respectively. Time-to-failure data under SCC and RLE conditions were determined using precracked cantilever-beam specimens.
Deep Sea Mining Technology: Recent Developments and Future Projects
Authors: Bath A.R. 
Published: October 2008

ABSTRACT
During the late 1970s pilot mining tests carried out on manganese nodules in the Pacific and metalliferous mud in the Red Sea demonstrated the technical feasibility of deep sea mining operations. However, the production of manganese nodules on a commercial scale is subject to numerous technical problems. As a result a German/French joint development project has been underway since 1985 into the following key points; nodule pick-up device, locomotion of self propelled collectors, hydraulic lifting of nodules. This paper presents the scope of this R+D program, its main results to date and future prospects.

INTRODUCTION
Ten years ago deep sea mining, i.e. the production of ore-bearing minerals from the deep sea was at a zenith and enjoyed a large amount of interest worldwide. Spring 1978 saw the first continuous pilot scale production of manganese nodules from the floor of the Pacific ocean (OMI Pilot Mining Test) and May 1979 saw the first production of metalliferous sediments from the floor of the Red Sea (Saudi Sudanese Red Sea Commission, Preussag, Pre Pilot Mining Test)..
We now know that these forecasts were incorrect. The start of commercial deep sea mining has moved further away for a number of reasons of which price development in the metal market was undoubtedly one of the more important. This does not mean that development of deep sea mining technologies has ground to a complete standstill. On the contrary; the number of countries in which corresponding research is underway has increased. The USA, Japan, France and Germany have been joined by the USSR, India and Finland. For some years now development work in Germany has concentrated on the development and optimization of critical components and subsystems of deep sea mining techniques, whereby the demand for environmentally non-disruptive production methods has increasingly been taken into account. The following report concentrates on this work where by manganese nodule production technologies represent the major focus.
There follows a brief review of the pilot mining tests executed in the late seventies as an outline of the scope of work.

BRIEF REVIEW OF PILOT OPERATIONS
The first successful pilot mining test on manganese nodules was carried out in 1978 by OMI (Ocean Management Inc.) in which 800 tonnes of nodules were recovered from the floor of the Pacific ocean.
This was a joint venture involving American, Japanese, Canadian and German companies (Fig. 1).
The mining system comprised:the converted drill ship. SEDCO 445a 5500 m long pipe stringa towed collector
Two types of hydraulic lifting systems were tested successfully:an air lift systema pump lift system (multistage mixed flow pumps)
Two different nodule collector concepts were tested (Fig. 2):hydraulicmechanical
The overall system design had a mining rate of around 30 t/h.
MWD VSP and Checkshot Surveys Using the Drill Bit as a Downhole Energy Source
Authors: Rector J.W. , Marion B.P. 
Published: October 2008

Vertical Seismic Profiling (VSP) has been used over the past decade to provide seismic images near a wellbore and to make time-to-depth calibrations of surface seismic data. A new wellbore seismic technique, the TOMEX® Survey, uses the vibrations produced by a drill bit while drilling as a downhole seismic energy source to produce VSP data. No downhole instrumentation is required to acquire the data, and the data recording does not interfere with the drilling process. Hence, there is no loss of rig time and MWD (measurement-while-drilling) borehole seismic data is acquired. Rig time savings are particularly important on offshore wells where the daily cost of rig time can be very high. The continuous signals generated by the drill bit during drilling are monitored with a reference sensor attached to the top of the drillstring. The reference sensor signals are processed in combination with the signals from receivers placed at or near the earth's surface to produce VSP data. In a marine environment, sensors are deployed on the ocean bottom. Results from a land test well demonstrate that the processed drill-bit source data are virtually identical to conventional VSP data. Offshore tests demonstrate that drill-bit VSP data quality offshore is superior to that on land.

INTRODUCTION
Vertical Seismic Profiling (VSP) consists of recording seismic data using a surface energy source and a receiver lowered by a wireline into a borehole. VSP surveys are used like checkshot surveys to convert surface seismic sections to depth. They are also used to estimate formation interval velocities. The reflected energy recorded in VSP surveys are used to image formations near the wellbore and to predict formations yet to be encountered by the drill bit. One disadvantage of VSP is that the drilling activity must cease while the data are being recorded.
The TOMEX Survey, or drill-bit VSP, uses the natural vibrations created by the drill bit during the drilling of a well as a downhole energy source. No downhole instrumentation is required, so there is no lost rig time and, complications of open-hole wireline operations are avoided. Offshore, the savings in rig time achieved by a drill-bit VSP versus conventional VSP is often greater than the cost of the entire survey.
Ideally, an explorationist wants the information obtained with a VSP to be available while the well is being drilled, because the ability to locate the seismic target with respect to the current drill-bit position could enormously reduce drilling expenditures. However, prior to acquiring the VSP, the driller must trip out of the hole, and in many cases, a wiper run must be performed to condition the borehole walls. This drilling inactivity period can be rather long. Hence, VSPs are usually performed during the final logging run, after it is too late to affect the drilling plan. By contrast, drill-bit VSP data are acquired and processed as drilling proceeds.
Emerging Technology in Borehole Geophysics With Multiple Applications in Drilling, Production, Exploration, and Enhanced Oil Recovery
Authors: Kfaveness A. 
Published: October 2008

ABSTRACT
In this study, it is demonstrated that sonic pulses of sufficient strength and suitable frequencies can be emitted from a borehole energy source concurrently while drilling oil and gas wells and that these pulses can be used to scan or "look ahead" of the drill bit to determine the character and the structural conditions of the materials to be drilled. Additionally, such pulses can be used to provide continuous inverse three dimensional 96 trace Vertical Seismic Profiles (VSP) to map the geology immediately surrounding the borehole to distances of 6000 feet or more (faults, reefs, salt overhangs, etc.).

INTRODUCTION
Recent developments in borehole geophysics can reduce the hazards and improve the chances for success when drilling for oil and gas. Seismic Telemetry Logging uses sonic pulses and seismic techniques to scan or "look ahead" of the drill bit to determine the character and the structural conditions of the materials to be drilled. Fracture prone formations and over pressured gas zones can be detected before they are penetrated by the bit, thus permitting mud weights to be altered in sufficient time to prevent lost circulation and dangerous blowouts. Additionally, the degree of compaction, the dipping attitude of the bedding and the position of formations below the borehole are determined so that drilling programs may be optimized and good casing seats can be established.
The same sonic pulses monitor the position of the drill bit and may therefore be used to detect deviations from a true vertical drilling path (crooked holes) and guide directional wells to planned objectives.
Also, precise measurements are made of sonic transit times in materials drilled, thus providing a continuous velocity log, density log and porosity log as the drilling progresses. Productive horizons associated with nearby faults, reefs, salt intrusions and porous sand bodies are mapped, hence the drill can be deflected into them at the best possible position.. Sometimes such reservoirs are barely penetrated or missed entirely, resulting in large and possibly unnecessary expenditures for marginal wells or dry holes.
It is significant to note that this information is obtained without lowering wire lines or measuring devices into the well and that it is done without interrupting or interfering with the drilling operations. Sonic telemetry procedures are used to transmit the data to the surface in less than 30 seconds. The results are, therefore, available immediately on the rig floor where they may be used to alter or optimize the drilling program.
In conventional well logging it is customary to stop the drilling and remove the drill string and the drill bit from the borehole while the logging is in progress. This is not necessary with the new method. Here the log is obtained while the drilling continues.
The Bullwinkle Project: An Overview
Authors: Sterling G.H. , Krebs J.E. , Dunn F.P. 
Published: October 2008

ABSTRACT
The Bullwinkle platform is located in Green Canyon area, Gulf of Mexico in 1353 feet of water. It is the largest steel offshore platform in the world, located in the deepest water and is taller than the world's highest building.
The platform took five years to design, build and install. Seventy-five thousand tons of steel were used to build this structure, of which 49,000 tons were in the jacket, 13,000 in the conductors, 11,000 in the piling and 2,000 in the deck.
This paper discusses the planning, phased bid/award and schedule control and gives a broad overview of the building and installation process. Several companion. Papers (1-11), give specific details of the platform design and construction.

INTRODUCTION
In May 1983, Shell Offshore Inc. (SOl) acquired Blocks 65 and 109, Green Canyon area, for a lease bonus of $30.1MM. In April 1984, Block 64 was acquired for an additional $4.4MM. The leases on all three blocks are 100% owned by SOl. This prospect area (Fig. 1) was code named Bullwinkle by SOl's explorationists, a name that continued throughout development.
The discovery well was drilled in October 1983 on Green Canyon Block 65. A total of four wells and four sidetracks were drilled in the three blocks to evaluate and delineate the reservoirs. Evaluation of development alternatives had been underway concurrent with field exploration, and in June 1985 construction of a platform was begun in accordance with the schedule shown in Fig. 2. Platform installation was completed in late September 1988. The basic characteristics of the platform are described in detail in companion papers (1-11), but Fig. 3 provides some basic information on forces, weights and dimensions.
Development drilling is presently underway, with initial production scheduled to begin in 1989 while drilling continues. Oil production is expected to peak at 50,000 barrels per day, with natural gas production reaching 90 million cubic feet per day in 1992.
The Bu11wink1e project will cost about $500MM excluding lease bonus costs. About 50% of the project costs was spent to build and install the platform. The other 50% will be spent for development drilling, permanent production facilities and a pipeline system.

PLANNING
Various concepts for field development received consideration during the early engineering efforts. These included (i) two fixed platforms, each With 24 well slots; (ii) one fixed platform with 50 slots; (iii) a compliant tower. Based on in-house estimates of project costs the single fixed platform, with capability to handle two drilling rigs and 60 wells, was chosen. The project schedule noted in Fig. 2 was developed with an early June 1988 target date for launch. That launch time was chosen to avoid the spring weather, and to allow sufficient time for offshore work before the major part of the hurricane season. Figure 4 dramatically shows the statistical .significance of working offshore early in the hurricane season.