bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wet Gas Multi-Phase Measurement
Authors: Tuss Bernie 
Published: October 2008

Abstract
In the last decade, the world of petroleum industry multiphase measurement has evolved from its infancy in research to operational equipment. Virtually all the endeavors were focused on the predominantly liquids aspect of multi-phase, mainly in the low GOR, low water cut regimes. With considerable time and money spent on development, the technology has evolved to cover both water and oil-continuous flows of 0-100% water and to GVF (Gas Volume Fractions) upwards of 90%.
With the advancement of technology and the increase in natural gas usage, the demand for "wet gas" metering has become more apparent. Wet gas is roughly defined as production or pipeline streams with GVFs above 95% gas at the point of measurement.
This paper presents a discussion of the equipment currently available and/or in development and the efforts put forth to perform this type of multi-flow measurement.

Background
Measurement of gas well production has been primarily left to the orifice plate, recognizing that the resulting flow calculations were in error because of the associated liquids (water and condensate). Several attempts have been made (with little or no success) to quantify the degree of error in orifice plate measurement with variouspercentages of liquids.
Well testing of gas well production is predominantly accomplished by two or three phase well test separators, often with little concern for testing of liquid carryover in the gas, entrained and solution gas in the liquids, water carryover in the oil, and oil carryover in the water. Wells that surge or have slugging flow patterns often flood normally sized (for average flow) test separators, because the average liquid flow is considerably less than the liquidslug flow rates. Likewise, a well may tend to produce considerably more water as the well ages, and the test separator, by its internal design, is incapable of handling to 10 times the usual amount of water that can be experienced from one well test sequence to another. The range ability of a well test vessel and/or separator level control system is difficult to change in the field. A better, less expensive, lighter weight, portable and more accurate "mouse trap" was needed.

Wet Gas Technology
Virtually any and all multi-phase measurement technology has its limitations within different flow regimes. Considerable use is made of combining several technologies into a given high gas fraction (wet gas) multi-phase meter. Those technologies include:Phase DiversionCross CorrelationSplit PhaseUltrasonic
In addition to the existing or near operational technologies in wet gas metering additional approaches, such as nuclear activation, polymer solubility, and radioactive isotopes, are in the research and design phases in both Europe and the United States.
Factors Affecting Shut-In Pressure Rise: Kicks in Offshore HPHT Wells
Authors: Schilhab Larry C. , Rezmer I.M. 
Published: October 2008

Abstract
Deep water and HPHT operations are two areas where the use of sophisticated simulators can enable difficult processes and procedures to be broken down into individual identifiable contributions. In this paper we discuss some of the factors that are likely to affect shut-in pressure rise in offshore drilling operations, and how a simulator can be used toanswer other, less obvious questions concerning deep water well control operations.
We examine the effect of gas solubility by considering a gas-kick in a deep HPHT well drilled with oil-base mud. In this case, most of the influx will be dissolved in the mud, thus removing one of the processes for increasing the wellbore pressure. In terms of a safe state to disconnect from a well in rough weather, provided that the mud yield stress negates migration of the gas-cut mud, leaving the influx in solution at the bottom of the well should not lead to increasing wellbore pressures.
Significant wellbore pressure effects may also occur after closing the blowout preventers (BOP'S) on a well without an influx (or with an influx in solution), and allowing the mud to heat up. We show that in typical HPHT geometries the pressure can rise by up to 8 bar/°C. Similar magnitudes of pressure can also increase whilst circulating trapped gas out of a BOP at the end of a well control operation. We note that these effects may also be attenuated by fluid loss and wellbore compliance for wells with significant openhole sections.
Indeed, gas trapped in the BOP should be safely removed by established well control procedures. However, preliminary studies with the simulator (and confirmed by field tests in the literature) have shown that an accidental release of a small amount of gas into a deep Water riser may disperse, and not cause the riser to unload.

Introduction
The oil industry has had success in overcoming many of the technological challenges posed by drilling in deep waters and in high pressure, high temperature regimes.
Recently there has been discussion concerning the determination and determination of shut-in pressure build-up. There have been many cases of surface pressures taking a long time to stabilise. The reasons for this can be one, some, or all of the following:The influx originated from a low permeability zone.The influx created an instability in the wellbore leading to hole sloughing and packing off.The influx is migrating.The influx has dispersed.The influx is going into solution.Fluid is leaking off from the wellbore.The openhole section/casing is compliant.There are significant temperature effects.
Clearly, there are many factors that can modify the nature of the initial build-up and the stabilising of the shut-in pressures. In we consider in turn each of the processes and parameters that affect the shut-in pressures, and the estimate of the rate of gas migration.
An Integrated Team Approach to the Design, Construction, Start-Up and Operation of the World's Most Modern Drilling Rig.
Authors: Croucher T.M. 
Published: October 2008

Abstract
In 1994, Phillips Petroleum Company Norway, the operator of the Greater Ekofisk Area fields in the central North Sea, signed a contract for the construction of a state of the art, fit for purpose Drilling Rig to be located on the new Ekofisk 214 X wellhead production platform. The rig was an element of major importance to the Ekofisk II project, the redevelopment of one the largest fields in the North Sea. The start-up of drilling on the 214 X platform was the first major milestone in the Ekofisk II project and the timely redrilling of the Ekofisk field wells from the new rig was vital to maintain production levels. On 26th October 1996, exactly on schedule, the first well on the 214 X platform was spudded. To date six wells have been drilled by the rig including the fastest well ever drilled in the Ekofisk field. The drilling program is currently on schedule and the rig has operated at an average availability of 98%. The success of this project can be attributed to a number of factors, however, one element stands clearly as the key success factor - a truly integrated team approach to all phases of the delivery of the rig! From the very beginning, representatives of the real customer of the product, the offshore drilling team, joined the rig supplier's design team to work shoulder to shoulder on the specification and preliminary design of the rig. As the design process moved forward, the customer representation on the team was strengthened. Ultimately, the customer participated in an active manner in all aspects of design, construction, commissioning and start up of the rig. This paper will detail both the underlying philosophy and the practical process by which this state of the art rig was successfully built and put to work. The paper includes a description of the rig itself, a review of how the integrated team approached the various phases of delivery of the rig and an outline of how the project was managed. The paper then discusses the issue of whether an automated rig can lead to a reduction in manning levels and covers the unique way in which the rig crews rig were trained. Some equipment performance figures are included to demonstrate the successful operational capabilities of the rig, and finally some conclusions are drawn from the lessons that have been learned.

Introduction
The 214 X platform is part of a complex of facilities located at the centre of the Ekofisk field. Ekofisk is one of eight producing fields making up the Phillips Norway Group's Greater Ekofisk Area (production license 0 18) located in the southern comer of the Norwegian Sector of the North Sea. The Ekofisk field, discovered in 1969 and put on production in 1971, has recently entered into a new phase of redevelopment. Increasing operating costs, the result of ageing facilities and the need to mitigate the effect of seabed subsidence caused by reservoir compaction, has been the root cause of the redevelopment.
A Radical Alternative Approach To Design And Construction Of Pipelines In Deep Water
Authors: Palmer Andrew 
Published: October 2008

Abstract
The design of pipelines in deep water is conventionally governed by the external pressure. The line is laid air-filled, and the wall has to be strong enough to resist collapse and buckle propagation. This leads to extremely high wall thicknesses, often well over 1.5 inches (38.1 mm) even for modest diameters, to correspondingly high costs, and to additional difficulties with welding and possible repair. Newcomers to underwater pipeline engineering often ask why the pipe is always laid air-filled. This paper pursues that question, and explores the implications of laying the pipe partially liquid-filled, so that the external pressure is partly balanced by internal pressure. It presents the results of design and lay analysis for such a line. The pipe can then be much thinner and cheaper. It may be heavier, but overall it turns out to be less costly to lay a thinner pipe, even if the lay equipment has to be somewhat stronger. There are commissioning and operational implications if the line cannot be completely depressurised. These implications are much less serious for an oil or water line than for a gas line. The application is to economical design of large-diameter pipelines in deep water, such as the projected pipelines from Arabia to India and Pakistan. The results include graphs and formulas that can be used to design pipelines that will be laid partially water-filled. The most significant aspect of this radical alternative is that it offers a way forward which breaks free of a traditional constraint. The need for deep-water pipelines is clear. Some of the design and construction problems become easier in deep water, and some become more difficult. The principal difficulty is the inescapably large external pressure, which implies a large wall thickness if the pipeline is to be able to withstand the external pressure while it contains air at atmospheric pressure. A little can be done to lessen the problem by better understanding of collapse. A radical paradigm shift makes it possible to break free of the design constraint imposed by buckling.

Introduction
The future importance of deep-water production of oil and gas scarcely needs to be restated. Most of the oil and gas to be found in shallow water, in reasonably benign environments, and close to politically stable countries, has probably been found, and much of that is in the course of development. In the coming years the industry will be compelled to move into more demanding environments, into deeper water and into hostile environments such as the Arctic. In the recent Deep Offshore Technology conference in the Netherlands, Tim Warren said that "Deep water is the most significant opportunity facing Shell". Another major operator has estimated reserves in deep water off the continental shelf to be more than 40 Bbbl oil equivalent, of which 18 Bbbl are off West Africa and 8 Bbbl off Brazil. Pipelines will plainly be a major part of these new developments, and the cost of pipelines cannot be allowed to become a weak link that limits development.
Innovative Way to Run Liners in Horizontal or Extended Reach Wells
Authors: Fuller M.S. , Gharesi A. , Kaspersen B. 
Published: October 2008

Abstract
It has long been recognized that the ability to run a liner string to depth in highly deviated, horizontal or extended reach wells is limited by the amount of weight that can be applied from the surface to the liner string. Dog legs and horizontal sections create friction that reduces the amount of force that can be transferred to the liner to move the liner down hole. A new drilling fluid operated telescopic joint has been developed and tested that provides the additional "push" down hole to enable liners to be run where weight alone cannot provide the force necessary to install the liner. Through the use of a cyclical valve arrangement, the telescopic joint can be used to assist the liner through tight spots in the hole as well. Full circulation is provided to assist in removing cuttings if the liner is "drilled down" or establishing circulation for cementing of the liner. Designed to be a part of the liner running string, the telescopic joint provides hydraulically created forces for pushing liners or setting liner top packers. This provides cost savings by being able to locate a liner top exactly where needed regardless of hole deviation and direction. Further cost savings are expected in the reduced amount of weight needed to get the liner to bottom. This paper will describe the conventional liner running methods along with the improvements available with the telescopic joint.

Introduction:
As the oil/gas drilling industry continues to face new challenges, more sophisticated equipment is needed to allow the reserves to be retrieved. Using operations related to the installation of well bore liners as the background information, several different areas that historically provide new challenges are described and the potential solution discussed.

1. Installation of long liners in highly deviated or extended reach wells.
Figure 1 (available in full paper)
When installing long liners, especially in the long horizontal wells usually associated with extended reach drilling, problems may be encountered in reaching the desired depth due to high friction between the liner and the hole. Adding weight alone may not always solve the problem. The liner assembly is often rotated to help reduce the sliding friction. However, it is often observed that due to centralizers and scratchers on the liner itself, friction makes it difficult to rotate and still have enough. force to push the liner into the extended reach or horizontal section of the well. Centralizers are often removed to reduce the friction and allow the liner to reach the target. This results in potentially reducing the quality of the cement job. The purpose of the Telescopic Joint is to avoid these problems. The Telescopic Joint is added between the drill string and the liner's setting tool (See Figure 1). The weight of the drill string is used to anchor the Telescopic Joint, while the force generated in the Joint overcomes the friction between the hole and the liner and pushes the liner to the correct position.
Uncovering Peru's Offshore Petroleum Potential
Authors: Rivero F.  Zúñiga , Keeling J.A. , Roe H. Hay 
Published: October 2008

Abstract
TIlis paper attempts to spark a new phase in the exploration of Peru's 2,500-km-long continental shelf by helping to define major hydrocarbon possibilities in this extensive area. Recent seismic data acquired with optimwn field parameters have enabled us to define the tectonic, structural, and stratigraphic setting of Peru's coastal basins. Offshore Peru could well become one of the prominent oil and gas plays of the next decade.
TIle latest geophysical surveys, coupled with recently completed detailed geophysical and geological studies have confinned that:There are ten coastal sedimentary basins or sub-basins. Four of them are located entirely offshore while twoextend from onshore across the shelf to the upper continental slope and beyond.Most of the basins are strongly linear and parallel to the coast, in places bounded by one or two pre-Tertiary subsurface ridges-basement highs tllat show up clearly on seismic sections.Three basins that contain commercial oil or gas production all extend wlder the continental shelf.The total offshore area of tlle ten basins, out to a water depth of 2,000 m.. exceeds 150,000 sq. km. (37 million acres).Gross sedimentarythickness in the ten basins, as interpreted from modem seismic data and from drilling, ranges from 7,000 m to more than 20,000 m. This includes substantial thicknesses of previously unsuspected and prospective pre-Tertiary sediments, ranging in age from late Paleozoic to late Cretaceous.The most recent estimates of future hydrocarbon potential for the ten basins total 22 billion bbls of oil, without counting the onshore sectors of four basins. If natural gas were discovered, the equivalent potential would be 132 Tcf.
Offshore, almost no wildcatting has taken place south of the Talara basin., which has produced about 1.6 billion bbls of oil, including 280 million bbls from the shallow offshore sector, and over 3.5 Tcf of natural gas.

Introduction
Marine exploration off the Peruvian coast (Fig. I) has been going on intennittently since the 1960s, but it is only recently tllat a thorough, fresh look at Peru's entire offshore has revealed previously unsuspected potential. Rather than isolated basins with a relatively thin section of late Tertiary sediments1 we now know that a thick prospective sequence is present along the entire coast, in places exceeding 10,000 m total thickness.

Findings.
The latest extensive regional seismic survey (Table I) was recorded and processed in 1993–94. Under detailed review, substantial changes have been made in the preliminaryinterpretation. For example, a detailed study of interval velocity has shown values as low as 3,836 m1sec at a reflection time of 7.1 seconds, in water less than 200 m deep. We must conclude that continuous reflections previously thought to be intrabasement more likely originated at the Paleozoic Mesozoic contact. Trapping features visible on the seisnticlines include anticlinal closures, updip closures against nonnal faults, lateral pinchouts, angular unconfonnities, and onlap onto old highs.
Banzala Development Plan: Overcoming the Shallow Gas Hazard
Authors: Smith M.E. , Rieken M.K. , Streu D.J. , Gaona M.T. , Sousa J. 
Published: October 2008

Abstract
The Banzala Field, located offshore Cabinda, Angola, contains over one billion barrels of oil in place, in shallow water, at shallow depth and close to an existing infrastructure. The field was discovered in 1981, but the well was lost due to a blowout after reaching total depth.
The blowout resulted in the charging of a very shallow interval with over-pressure gas that now completely overlies the deeper oil reservoirs. The gas pressure was unknown, but believed to be very close to fracture pressure. Exact areal extent of the gas was unknown and it was not known if the system was static or continuing to charge from a deeper gas sand.
The field has not been developed because of the extent and uncertainty of shallow overpressured gas that overlies the deeper oil reservoirs and because of limited individual well productivity.
It was surmised that the outer limit of the shallow gas or gas/water contact (GWC) should correspond to a structural contour elevation such that the corresponding hydrostatic head of sea water exactly balanced the pressure of the gas bubble. Hydrostatic pressure data dating from 1983 was used to boundgas pressure between a maximum and minimum value. Consequently, it was believed, the vertical subsea depth of the GWC was bounded.
A dynamically positioned geotechnical vessel was chartered to drill along the calculated gas boundary. The effort was successful and appraisal wells have been drilled and evaluated.
Low well productivity will be solved by closely spaced wells on electric submersible pump (ESP). Well downtime and pump pulling costs are being minimized by deploying theESPs on coil tubing. A "hard landing" area is being designed into the platforms to support coil tubing equipment spreads.

Introduction
The Banzala Field is located in Blocks 34, 35, 45, and 46 in Area A of the Cabinda Concession, offshore Angola, West Africa (Figure 1) in approximately 125 to 175 ft of water. The hydrocarbon accumulation at Banzala occurs in three primaryreservoirs (Mesa, Lago, and Azul) between -1600 ft and -2000 ft tvdss. It is estimated that these sands contain over one billion barrels of oil in place. The productive oil bearing reservoirs are overlain by the Frio and Landana gas sands. The Frio is a naturally occurring overpressured gas sand at -1000 ft tvdss. The Landana was originally normally pressured, but has been supercharged with gas as a result of the discovery well blowout in 1981. The Landana is between -425 and -600 ft tvdss.
The Banzala Field is an anticline with four-way dip closure. The anticlinal structure (Figure 2) is well defined by six wells and 2seismic data. The crest of the anticlinal structure is difficult to resolve seismically because seismic data quality is locally degraded by shallow gas. Although amaximum of three faults have been mapped, additional faults that are not imaged with the current seismic data may be present.