bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Displacement Rate and Wettability on Imbibition Relative Permeabilities
Authors: Nguyen V. H. , Sheppard A. P. , Knackstedt M. A. , Pinczewski W. V. 
Published: December 2007

Abstract
A new dynamic network model is used to investigate the effects of displacement rate and wettability on imbibition relative permeability. The network geometry and topology is representative of a Berea-type sandstone. In contrast to existing quasi-static network models where snap-off, the major pore-scale trapping mechanism in imbibition, is suppressed by contact angle alone, the dynamic model introduces displacement rate as an additional snap-off inhibiting mechanism. The network model is used to analyse the complex rate dependence of relative permeability and residual saturation displayed by laboratory measured data reported in the literature.
Value Creation with a Novel, Multiphase Flow Additive
Authors: Misman R. B. , Aggrey G. H. , Davies D. R. , Fortuin H. 
Published: December 2007

Abstract
A main challenge faced by the Oil Industry is to develop marginal discoveries and to maintain production from existing, depleting fields against a background of unstable oil price and increasing costs. Operators seek new, cost effective ways to increase their discovery's commercial viability and to meet the growing world energy demand. Multiphase field development is one such tool to reduce costs. Here liquid and gas are transported together over long distances in a multiphase pipeline. Multiphase technology is becoming accepted by the industry - gaining popularity as field experience increases and the accuracy of performance prediction tools proven.
Field experience has shown that the higher-pressure drops and the formation of large, liquid slugs are two of the drawbacks associated with multiphase rather than the traditional, single phase pipelines operations. Both of these negative, multiphase flow effects can be mitigated by use of a new class of production chemical that is effective in both reducing the flowing pressure drop and influencing slug formation. This new class of chemicals is effective in two phase flow – unlike the well established "Friction Reducers" which are widely used in (single phase) water and oil flow.
The value creation from the application of this chemical has been quantified for a range of model reservoirs located onshore, offshore and in deepwater. A multi-well field & export simulation showed that up to 10% acceleration for oil and gas condensate production could be achieved by the use of the new chemical to the multiphase flow. Additional recoveries varied between 0 to 10%. Other condensates recovery scenarios gave up to 25 % increase in production rates for depleted reservoir. Even better results were obtained in condensate fields with inadequate pressure/aquifer support.
Economic analysis showed that production acceleration without recovery increase improved the economic value (pre-Tax NPV) of multiphase projects by 5%-15%. The additional value created by a concurrent additional recovery gave a pre- tax NPV increase of 13-25%
Multiphase technology with Floostar injection is an important enabler in the development of marginal fields and deepwater prospects, improving company's reserve portfolio.
A full economic analysis of these Field Development scenarios will also be reported
Development and Field Testing of a Unique High-Temperature/High-Pressure (HTHP) Oil-Based Drilling Fluid With Minimum Rheology and Maximum SAG Stability
Authors: Taugbøl K. , Fimreite G. , Prebensen O. I. , Svanes K. , Omland T. H. , Svela P. E. , Breivik D. H. 
Published: December 2007

Abstract
When drilling wells in HTHP fields, the drilling fluid properties are of utmost importance. The difference between fracture and pore pressure, expressed as the hydraulic window, can be quite narrow. One of the remedies for making sure that one stays within this hydraulic window, is to design a drilling fluid with very low viscosity. This will reduce the Equivalent Circulating Density (ECD) effect from the fluid. While low- viscosity fluids have the ability to dramatically reduce frictional pressure loss compared to more viscous fluids, there is a limitation to the reduction in viscosity before conventional weight materials start to settle. In HTHP wells with extremely high pressures and temperatures, sag stability of the fluid is essential to ensure adequate well control.
This paper describes the development and application of a novel technology that has resulted in a ten-fold reduction in the particle size of the weighting agent. With this development, invert emulsion drilling fluids can be designed with reduced viscosity in combination with minimal settling potential of the weighting agent.
The paper further explains in detail the first field application of this specially treated micron-sized weighting agent used in a HTHP well. This successful field application has proven this technology to be a viable alternative to the use of high-density, high-cost brine-based drilling fluids.
Hole Cleaning and Pressure-Loss Prediction From a Bulk Transport Perspective
Authors: Datta B. K. , Ratnayake C. , Saasen A. , Omland T. H. 
Published: December 2007

Abstract
Hole cleaning is still among the most important problems to handle in drilling operations and one of the most studied phenomena within the petroleum industry. Insufficient hole cleansing can lead to stuck-pipe, excessive pump pressures and equivalent circulating density (ECD), pack-offs, lost circulation, etc. all of which again can lead to loss of sections or complete wells. Due to the number of parameters influencing the hole cleaning operation and the complex mechanisms involved, the phenomenon has not yet been fully understood.
The issue of transportation of cuttings along with drilling fluids is essentially a two-phase flow. Several other industries are dealing with similar issues when transporting solids using air (fluid) as the transporting medium. Although the transporting mediums are different, flow regimes and basic transporting mechanisms similar to hole cleaning can be observed also in pneumatic conveying of particulate materials. While horizontal and vertical pneumatic transport are quite often used, very rarely people try to use inclined pneumatic conveying for the very reason that it involves much higher pressure drop as compared to both horizontal & vertical conveying and is associated with the problems of particles dropping out of suspension unless a very high fluid velocity is used. Through an extensive laboratory study a simple model1,2,3 has been developed for pressure drop calculation in pneumatic conveying based on classical Darcy's equation with some modifications. The predicted pressure values match well with the test data.
This article has tried to look at the possibility of a unified approach for two-phase flow. An attempt has been made to relate the knowledge developed in the field of two-phase pneumatic conveying systems to the challenges associated with the hole cleaning mechanism. The paper also describes some of the work that has been performed for studying hole cleaning and the associated pressure loss prediction.
A Comparative Assessment of Options for Produced-Water Management in the North Sea
Authors: Ekins P. , Vanner R. , Firebrace J. 
Published: December 2007

Abstract
There is currently no evidence of harm to the marine environment from produced water, but a number of areas of uncertainty remain. Using a novel methodology to compare a number of different techniques of reducing produced water discharges, it is found that these techniques have significant environmental and financial implications. In the absence of evidence of actual environmental harm being caused by produced water, the current policy objective of achieving zero discharge of hazardous substances in produced water implies a relatively high social valuation of the reduction in environmental risk that this achieves.
Risk Minimisation by the Use of Failure Mode Analysis in the Qualification of New Technology
Authors: Hother J. 
Published: December 2007

Abstract
Industry has recently recognised the value of failure mode analysis, which is now being used on a rapidly expanding scale, to reduce the risk associated with applying new technology and increase the probability of success.
Early applications showed forcefully that some of the methods used in other industries, for which there are internationally accepted standards, are not directly usable in oil and gas projects. Significant effort has now been applied to correcting these shortcomings.
This paper explores the aspects in which traditional methods have been found to be inappropriate, and demonstrates current best practice, including a number of new developments, illustrated by examples from recent case studies on well completions, intelligent wells, permanent downhole gauges, expandables, and new sand control technologies.
Those new developments address key issues that have been recognised as result of recent project experience, namely — oHaving a good definition of functional requirements before embarking on failure mode analysis.oHandling the life-cycle phases (primarily installation and production / operation) in a coherent manner, especially where downhole equipment is concerned, because many failure modes impacting production and value/investment criteria originate during installation.oMaintaining sufficient traceability to route-map from critical risks to specific components or process steps, so that avoidance or remedial measures can be accurately targeted.oRelating consequences of failure to the true economics of the project in hand, representing the different life-cycle phases realistically.oProducing useful results beyond just identifying critical failure modes, namely key actions targeted at specific aspects of the design, QA/QC, test procedures and installation processes, thus becoming an integral art of a coherent qualification process.
These issues are important wherever the risk of applying new technology is high, which is true of most oil and gas E&P projects. The risks are higher still when projects have significant downhole complexity, because the downhole elements are subject to the worst operating conditions and may have the highest consequences of failure. It is important to understand the failure modes, in order to focus the testing for maximum effectiveness, and to feed back improvements into the design and into the application, to maximise reliability.
This work has been instrumental in developing the methods that are now being widely adopted in oil and gas projects because they satisfy the unique needs of this industry.
Case Study: Aconcagua and Camden Hills Fields Utilize Intelligent Completions To Optimize Production and Reservoir Performance
Authors: Jackson Nielsen V. B. , Illeman J. , Guillory T. L. 
Published: December 2007

Abstract
As part of the Canyon Express project, four intelligent completions were installed in the Total Aconcagua Field and two in the Marathon Oil Camden Hills Field, Mississippi Canyon Blocks 305 and 348 respectively, in ultra-deepwater Gulf of Mexico. As a result of production optimization objectives and reservoir conditions, the intelligent completions have been utilized extensively to enhance field performance since installation and host platform commissioning in 2002.
With the use of direct hydraulic open/close valves, various zones have been shut-in and cycled open to optimize production. The objectives of this paper are to provide an overview of using intelligent completions to improve well performance, to discuss the reliability of the intelligent completion equipment three years after installation, and to qualitatively present the value proposition of reservoir management of intelligent completions.
Faced with reservoir depletion, suspected sand production, and water influx, the intelligent completions have proven themselves useful in the management of these assets.
Constructing and Completing the World's First Offshore Reformable CRA Multilateral Junction Well
Authors: Kjosnes I , Syrstad S. O. , Flormoelen R. A. J. , Førdedal H. , Nygårdsvoll K. , Hogg C. , Westgard D. 
Published: December 2007

Abstract
This paper describes the recent installation of a new re-formable corrosion resistant alloy (CRA) multilateral system in the Norwegian sector of the North Sea. Choosing a multilateral completion option allowed the operator to cost-effectively access more reservoir targets than would have been possible with a traditional horizontal well.
This multilateral deployment marked several industry "firsts": first combination of conventional casing exit techniques with formed metal junction technologies; first deployment of conventional gravel pack sand control systems in both legs of a level 5 multilateral system and first use of corrosion resistant alloy material in a re-formable multilateral junction system. The resulting multilateral offers full hydraulic isolation of the junction, optimum flow capability and selective through tubing accessibility into either leg.
The decision making process and evaluation criteria of the operator that led to this multilateral selection is discussed in this paper. Additionally, the formed metal junction approach that was chosen is explored and the installation sequence detailed. Finally, the results and lessons learned during the installation process and future status are addressed.
The Bacton (U. K.) Work Process Solution for Liquids and Gas Quality Management
Authors: Hudson J. D. , Kinghorn P. L. , McVinnie G. , Paterson P. A. , Proot M. M. J. , Doran S. M. 
Published: December 2007

Abstract
Historically, gas production to the Bacton gas terminal from the southern UK sector of the North Sea has been predominately lean gas. In the recent years fields producing richer gas have been added to the production system, bringing significantly increased condensate production. While the condensate is itself a valuable product, the increased volumes have raised a number of liquids management challenges both for offshore and onshore operations.
To address these challenges, a software-based operational guidance system has been deployed over a broadly integrated scope that includes onshore and offshore components. This system includes performance monitoring and operational guidance for the offshore compression stations, liquids and gas quality management for the offshore production system and operational guidance for the onshore plant. The implementation is well-aligned with SmartFields architectural approaches. This paper details the business case, the technical approach and the experience gained both in the implementation and operation of the system.
Turning a North Sea Oil Giant Into a Gas Field - Depressurization of the Statfjord Field
Authors: Boge R. , Lien S. K. , Gjesdal A. , Hansen A. G. 
Published: December 2007

Abstract
The Statfjord Field has produced about 635 million Sm3 (4 billion bbl) of oil and exported 68 billion Sm3 of gas. This equals to an oil recovery factor of 65% and a gas recovery factor of 48% of volumes initially in place. Currently, the field is producing at an oil rate of approximately 20 000 Sm3/d, which is about 17% of the plateau production rate.
The predominant drainage strategy has been pressure maintenance by water and gas injection. However plans to extend production life for the Statfjord Field even longer will require changing drainage strategy from pressure maintenance to depressurization. Estimates show that implementation of the new drainage strategy will lead to an increased ultimate gas recovery from 53% to 74% and an oil recovery factor of 68%. Lifetime for the Statfjord Field will be extended by approximately 10 years.
A change in focus from oil production to gas production has consequences both subsurface and topside. Key elements for implementing the depressurization of the Statfjord Field reservoirs are drilling and recompletion of approximately 80 wells which will be equipped with artificial lift and sand control, as well as topside modifications on the three existing platforms. This results in a high offshore activity level for several years on a field in production. A new gas export pipeline to the UK FLAGS system (Far north Liquid And Gas System) is necessary to provide sufficient offtake of the produced gas.
Implementation of a new drainage strategy on the Statfjord Field has also regional effects. Prolonged life time of the Statfjord Field installations leads to increased recovery for the Statfjord Satellites and opens for business opportunities in a longer term.
Case Study of Integrated Solutions Used To Locate and Extract Bypassed Hydrocarbons in the Mature Reservoirs of the Algyö Field, Hungary
Authors: Werovszky V. P. , Benedek L. , Tóth I. Vargáné , Tóth J. , Lövei A. , Palásthy G. , Olson J. 
Published: December 2007

Abstract
Globally, the provable reserves of new discoveries have been reduced, making the technological challenges of EOR/IOR and increased recovery factors even more important. Many of these same technologies can be tested for new discovery applications through extensive evaluation in mature, established fields.
This paper focuses on four primary areas: -Review the evolution of reservoir recovery technology in Algyö Field.-Outline the various IOR techniques and how they have enhanced production-Explain the science and methods of the innovative technologies that have allowed us to push the envelope of reservoir understanding and recovery further out over time-Emphasize reservoir simulation enhancement and pre- drill well path qualification through wellbore fluid saturation measurements extracted from existing wellbores
Pursuant to the discussion of the four areas above, we will emphasize in detail: -Geological and petrophysical environment-Production history-Increased oil recovery methods and associated uplifts as:
Utilizing horizontal wells, including planning, successes and challenges, direct application of carbon/oxygen ratio and pulsed neutron captures data to reservoir simulation enhancement and horizontal well planning in a field exploited mainly by water injection technology.
New Concept for Drilling Hydraulics
Authors: Vestavik O. M. 
Published: December 2007

Abstract
The feasibility of a new concept for drilling and lining of a well has been investigated. The patented concept is based on the use of a dual channel drill string, where one of the channels is used for the return flow from the well. A sliding piston in the annular downhole section of the well, is used for force and pressure control. The concept is suited for drilling with a liner, which optionally can be expanded in place in the same run. The concept has special advantages for improved downhole pressure control, and for safe and efficient drilling of reservoirs with challenging pressure zones.The concept is also expected to provide solutions for cost efficient drilling, especially for sub-sea wells.
Designing for a Healthy Working Environment–Engineering Practices and Tools Used in the Norwegian Petroleum Industry
Authors: Throndsen T. I. , Høivik D. 
Published: December 2007

Abstract
The paper will give an overview of the current practice in the Norwegian petroleum industry, with respect to systematic follow-up of design and construction. It is described how possible health risk and future working environment conditions at the plant during operations are assessed systematically during design and construction. The methods used have become highly professional tools for follow-up of design and construction through 20+ years of experience from the petroleum industry in Norway.
Monitoring of Mercury Content of Fishes near the Bongkot Platform, Gulf of Thailand
Authors: Dhanasin P. , Utoomprurkporn W. , Hungspreugs M. , Soponkanabhorn T. 
Published: December 2007

Abstract
Since mercury is known to be a naturally occurring component of geologically derived hydrocarbons in the Gulf of Thailand, the Bongkot Operation Marine Environmental Monitoring concentrated on the measurement of mercury content in commercial species of demersal fishes in the vicinity of the Bongkot Operation Platform. The main species studied were groupers Epinephelus areolatus, red snappers Lutjanus sebae, sharptooth jobfish Pristipomoides typus. But in the two most recent surveys, sharptooth jobfish was not available so it had to be replaced with other species e.g. painted sweetlips Diagramma pictum.
Before late in 1997, treated produced water from the production platform was discharged into the sea. This water contained certain amount of mercury. Since then, the treated produced water was re-injected back into the depleted gas wells. And less and less direct discharge was made until in the year 2002, the volume of produced water re-injected was over 99.9%. Hence, the seawater surrounding the Bongkot Platform showed only the background level of mercury in natural seawater and fish should not be contaminated with mercury. From the results of the fish monitoring in 1997, 1998, 2000, 2002, 2004, the mercury content in fishes appear to be lower, within the natural range of values among each individual fish of the same species. The exception is painted sweetlips which showed a slightly higher average in 2004 compared to the concentration found in 2002, although the number of this species used in the analysis was much smaller than other species. Equally large numbers should be used to ascertain this issue in the next monitoring survey.
Lessons Learned From Four Selective Water-Shutoff Treatments in Mature Reservoirs in Maracaibo Lake
Authors: Der Sarkissian J. , Venline Venline , Prado M. , Rauseo O. 
Published: December 2007

Abstract
Some of the most important oil reservoirs located at the Maracaibo Lake Basin are produced by a waterdrive mechanism. After four decades since the beginning of production, oil rates have declined mainly due to a continuous increase in water production.
These reservoirs are characterized by highly heterogeneous sandstone formations in which water channeling through high permeability strakes is a very common cause of water production. Another type of problem affecting production in these reservoirs is behind casing communication between producing sand and nearby water sands. Both problems have caused a rapid increase in the water-oil ratio of the wells, which in most of the cases were abandoned affecting considerably the oil recovery of the reservoirs.
This paper describes four successful selective water shutoff applications in producing wells from mature reservoirs at Maracaibo Lake Basin performed during the last seven years. The aim was to correct problems of channeling and behind casing communication. An elastic gel system of variable consistency with easily controlled gelling times was used. In some applications a gel-cement combination was necessary to improve results. Reservoir and well characteristics, diagnostic analysis and the different types of selective placement used are shown as key factors for success.
Using the elastic gel system the water production has been reduced to a minimum, obtaining an increase in wells productive life-time, which in global terms reaches a volume higher than 2 millions barrels of additional oil recovered.