bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Usage of an Etched Transparent Flowcell for Visualisation of Biofilm Induced Heterogeneities in Porous Media using Particle Image Velocimetry
Authors: van der Kraan Geert M. , Buijzen Floris , de Ridder Maarten , Thuss Barbara , Laros Mario , Poelma Christian , Lomans Bart P. , Muyzer Gerard , van Loosdrecht Mark C. , Bruining Johannes 
Published: February 2011

Abstract
Flow cells (or ‘transparent micromodels’) are widely used to observe complex processes in two dimensional (2D) porous media. The objective of this study is to design, develop, and apply a wet-etched glass micromodel suitable for the observation of biofilm formation, transport of microorganisms and flow measurements using Particle Image Velocimetry (PIV). PIV in this case can be used for the visualisation and quantification of flow diversion. The wet-etching technique applied here is relatively straightforward. The paper addresses all aspects involved necessary to perform these experiments. The chosen etching depth of around 25 μm proved to be well suited for transport experiments with microorganisms. We show that the micromodel containing a wet-etched cell (wafer) provides a high quality image of transport and growth of microorganisms in porous media. The microorganism Pseudomonas chlororaphis was used as a model strain to perform the experiments on biofilm formation and transport. In the transparent cell, we could clearly observe biofilm formation. Moreover, we showed that PIV techniques can indeed visualize the change in flow pattern caused by biofilm presence.
Flexible Simulation of Faults
Authors: Røe P. , Abrahamsen P. , Georgsen F. , Syversveen A. R. , Lia O. 
Published: February 2011

Abstract
Fault geometry is modelled on basis of seismic data, but restricted by fault observations in wells. Due to uncertainties in depth migration, seismic interpretation and well data, there is a significant uncertainty in the geometry and position of the faults. Fault uncertainty impact reservoir volume, flow properties and well planning, and can be studied by stochastic simulation of faults.
We have developed a method for stochastic simulation of fault surfaces and fault networks using standard geostatistical methods. This is made possible by the fault parameterization used, where the faults are modelled as tilted surfaces. This new method is more flexible and efficient compared to already existing algorithms due to a simpler parameterization. Conditioning to fault observations in wells is also made simpler.
The fault is defined as a two-dimensional surface on a tilted reference plane. The uncertainty for a fault surface is bounded by a volume enclosing the fault surface. The smoothness of the simulated fault surfaces is controlled by variograms. The simulation is done by adding a simulated Gaussian residual. Well conditioning is done by kriging.
Using the described method we can simulate a set of fault realizations where the simulated faults look realistic, are within the defined uncertainty volumes, and honour well observations.
Technical contributions compared to previous work include efficient simulation of fault geometry, a flexible uncertainty model and well conditioning with no performance impact.
Improved Reservoir Characterization Integrating Seismic Inversion, Rock Physics Model, and Petroelastic Log Facies Classification: A Real Case Application
Authors: Roncarolo F. , Grana D. 
Published: February 2011

Abstract
A real case application of a seismic reservoir characterization methodology in a deep water clastic reservoir located offshore West Africa is hereby presented.
The aim of this study is to integrate seismic facies classification into the reservoir static modelling workflow. The proposed probabilistic approach for petroelastic properties estimation and facies identification based on seismic data can be divided into three main steps. First, a Bayesian elastic inversion is performed to obtain seismic impedances from partial-stack seismic data. Then, a statistical rock physics model is applied to estimate the posterior probabilities of porosity, clay content and water saturation from impedances distributions. Finally, a litho-fluid classification is performed combining petrophysical properties probabilities with log facies analysis at well location, to propagate the identified classes in the 3D grid. The final result is a set of probability volumes for each seismic litho-fluid facies that can be used as prior 3D trend for geostatistical simulations. Using Sequential Indicator Simulation algorithm several facies realizations are generated and relevant sets of petrophysical properties are simulated within each facies.
The developed workflow has been applied in a real case study offshore West Africa. The available reservoir model has been updated including the results of the petroelastic inversion, in addition to a set of seismically derived geobodies representing the main geological features (channels, levees and sand lobes). Integrated use of seismic 3D probability trends and geological constraints provides advantages in terms of a more detailed spatial distribution of rock properties, a meaningful geological 3D representation and a better understanding of vertical and lateral connectivity within the reservoir. Moreover, development wells may be optimized in a more reliable way.
The contribution of the presented methodology is of key importance for fields in early development phase with few exploration well data available to constrain 3D models.
A Unified Wellbore Model for Reservoir Simulation
Authors: Holmes J. A. , Byer T. , Edwards D. A. , Stone T. W. , Pallister I. , Shaw G. , Walsh D. 
Published: February 2011

Abstract
A comprehensive well model that exists within a next-generation parallel reservoir simulator is described. It incorporates a general formulation approach which handles global phase-component partitioning allowing any number of phases and components, where any component can exist in any phase. The model can run in either isothermal or thermal mode, the latter including special features for steam injection and production. A multisegment capability enables the wellbore to be divided into segments for improved accuracy when simulating horizontal and multilateral wells. This unified well model reduces to a ‘conventional’ model when a single segment is used.
Coiled Tubing: A Key Enabler for Successful Multifractured, Horizontal Wells in Recent Low-Permeability Gas Developments Offshore UK
Authors: Holland B. , Cruickshank B. , Coghlan G. 
Published: February 2011

Abstract
Stimulation technology advances and gas market fundamentals are giving a strong impetus to low permeability gas developments in the UKCS. Technologies developed in regions outside the UK were selected and tailored to this challenging, high cost, offshore environment.
The multi-fractured, horizontal well has been key to near-exponential growth in developments of various shale plays onshore; it was also key to an earlier unlocking of chalk plays offshore Denmark and Norway. Location and well construction practises mean offshore execution of this completion strategy is complex and expensive. Historic attempts offshore in Rotliegendes sandstone (the predominant play) fell prey to technical difficulties. As a result execution risk was perceived as high, operators did not consider it viable offshore.
The strategy was adopted and successfully executed in two fields operated by Centrica Energy*. Encouraged by its success other UK operators are executing offshore developments using the same strategy and it is being reevaluated by Dutch operators.
A key component and unsung ‘hero’ is coiled tubing and its use in the Chiswick and Ensign fields. This paper is a case study of the three wells drilled, completed and stimulated in 2007/2008. Such was the confidence in employing this technique; further wells were added in Q4/2009 and Q2/2010.
The paper discusses equipment used, problems experienced and working practices that evolved. For example, 2− 3/8" coiled tubing was deployed in one well with a 20,000 ft well TD at 11,000 ft TVDSS. In a five-stage stimulation program, coil was worked on multiple occasions to perforate and to clean a path through proppant in the liner. It was operated at the edge of its design envelope and operating parameters were revised and fine-tuned onsite. It proved capable of everything asked of it and is a key enabler to allowing these reservoirs to be developed.
Post-Plateau Reservoir Management in the Magnus Field
Authors: Moulds Tim P. , Trussell Phillip , Erbas Demet , Cox David J. , Laws Ewan D. , Davies Chris , Strachan Neil 
Published: February 2011

Abstract
Magnus is a high productivity oil field in the northern North Sea. First oil was produced in 1983 and the plateau of 150 MSTB/D ended in 1995. In the post-plateau period a variety of reservoir management techniques have been employed to arrest decline rate. Two major projects have been executed post-plateau: in 2002 a gas injection EOR scheme was initiated and more recently additional drilling slots were added to the platform to increase reservoir access. These major projects have rejuvenated the field development options and will enable significant oil production beyond the next decade.
The EOR scheme exemplifies the synergies that are important to continuing to extract value in a mature oil province. The gas that is injected is sourced from several other fields and provides an export route for associated gas that would otherwise be stranded. After seven years of operation the impact of the EOR scheme is readily quantified, as are the challenges inherent in operating such a scheme. This paper describes the reservoir performance of EOR, discusses observations that may impact gas relative permeability under WAG operation, describes the tools that have supported reservoir management decisions and considers the operational issues that continually challenge delivery and the surveillance approach taken to mitigate these.
The extended slots project used slot-splitter technology to increase the number of wells. Wells from the new slots are now the longest wells that have been drilled from the platform enabling recovery from targets at the periphery of the field.
The combination of EOR and additional slots has generated a position where the field is once again opportunity-rich. Together with technology developments in 4D seismic and revised geological description a new tranche of opportunities are being identified that combine initially dry oil attic targets along with the underpinning volumes from EOR delivery.
Estimation of the Potential of an Oil-Viscosity-Reducing Bacterium Petrotoga sp. Isolated from an Oil Field for MEOR
Authors: Purwasena Isty A. , Sugai Yuichi , Sasaki Kyuro 
Published: February 2011

Abstract
An anaerobic oil-degrading thermophile, Petrotoga sp. AR80, was isolated from reservoir brine of an oilfield in Japan. This bacterium degrades long-chain hydrocarbons of crude oil into shorter-chain hydrocarbons in brine medium. Therefore, the oil viscosity can be decreased and the enhancement of oil recovery can be expected by this bacterium. The potential of this bacterium as a candidate for MEOR was estimated in this study. Some nitrogen source which is essential for bacteria should be injected into reservoir to stimulate the bacterial growth. To select a suitable brine medium for this bacterial activity on the reduction of crude oil viscosity, the numbers of nitrogen sources were evaluated. The highest growth rate was observed in medium contained yeast extract with maximum cell concentration in this medium was 10 times higher than that in other mediums. The influence of reservoir conditions such as temperature, salinity, and pressure on the bacterium was evaluated. This bacterium can grow and decrease oil viscosity at a temperature between 50 °C and 70 °C. The oil viscosity incubated with Petrotoga sp. AR80 was 46.3 %, 51.6 % and 65.9 % lower than control after 3 weeks incubation at 50 °C, 60 °C and 70 °C. In addition, the oil viscosity was 35.1 % lower than control at 70 °C and 800 psi. The result of GC chromatogram showed that this bacterium can convert and/or degrade various components of oil lead to depletion in heavier oil components and enrichment of light oil components respectively. Oil extracted from Oman, China and Canada can be utilized by this bacterium instead of Japanese oil. These results show that the isolated bacterium can be applied to a wide range of reservoirs for MEOR. In addition, this bacterium achieves economically feasible MEOR because it doesn't need costly nutrients such as molasses which has been used as a nutrient in MEOR.
Identifying the Optimum Wettability Conditions for the Near-Wellbore Region in Gas-Condensate Reservoirs
Authors: Zoghbi B. , Fahes M. M. , Nasrabadi H. 
Published: February 2011

Abstract
The problem of condensate blocking in low permeability gas-condensate reservoirs is greatly affected by the rock-fluid interactions and capillary trapping. Many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. In this work, we present a simulation study on the optimum wettability conditions for maximum gas-condensate well productivity enhancement. Most of the work in this area focuses on reversal of wetting conditions from liquid-wetting (contact angle of 0 degree) to gas-wetting (with contact angle around 150 degrees). On the experimental side, chemicals are tested in its ability to change wettability. On the simulation side, research shows that changing the wettability to gas-wetting in the near wellbore region results in better productivity than the original liquid-wetting state. Our work investigates various states of wettability ranging from liquid-wetting to gas-wetting and its effect on gas-condensate well productivity. We also study the effect of reservoir permeability, reservoir pressure and treatment radius on the well productivity enhancement by wettability alteration.
Solid Earth Modeling and Geometric Uncertainties
Authors: Mallet J.-L. , Tertois A.-L. 
Published: February 2011

Abstract
In computer geoscience, reservoir studies aim at estimating hydrocarbons in place to determine prospect viability and define development strategies. Assessing uncertainty on reservoir geometry is even more important than assessing uncertainty on rock properties because the property model depends on reservoir geometry. The authors propose a methodology for assessing geometric uncertainties on a unified solid earth model and show its application to a subsurface model.
A reference structural model is perturbed to reflect geometric uncertainty and several equiprobable realizations of the structural model are created. Instead of applying one global transformation as in most current methods, geometric uncertainties from different sources are assessed successively or jointly in each realization. The difficult problem of maintaining geological consistency while modifying structural models is addressed by using a structural model which is solid-based rather than surface-based: fault/fault and fault/horizon contacts are watertight by construction and constraints developed for this project ensure horizons do not intersect. The structural model is linked to the property model by a three-dimensional transformation, which enables perturbing the structural model independently from the property model instead of applying geometric transformations to the property model or having to recreate a property model for each geometric realization.
Iwafune-Oki Gas-Flood; the First Commercially Successful Gas-Based IOR in Japan
Authors: Yamada Tomomi 
Published: February 2011

Abstract
Iwafune-Oki is the only offshore oil and gas field currently operated in Japan. It was discovered in 1983 and has been producing from several oil- and gas-reservoirs since 1990. After 8 years of plateau production, the field's oil started to decline whereas the gas-zones’ recovery had been constrained by the regional gas demand. There was incentive to arrest the oil decline using the abundant gas.
In 2002, IOR potential was reviewed on Zone 2100m, the main oil reservoir, using an existing numerical model and WAG injection of associated gas was identified as prospective. Although its economics was evaluated as marginal, it was decided to proceed to definitive study and pilot injection test as better reality was anticipated by such mechanisms that the simplified black- oil model could not sufficiently simulate. They include components exchange, double displacement and gravity segregation between the injected and the resident phases. The pilot test, sourced by an unexploited gas reservoir, was conducted in parallel with the study, because significant loss in the project economics was expected if the implementation was delayed.
The pilot injection, started in December 2004 has shifted to regular operation since 2006 using also other high-pressure gas zones. Around 2% of incremental recovery has already been achieved and URF is enhanced by 7% on P50 basis. While no apparent production decline has been observed, GOR has significantly risen. Installation of gas compressor is ongoing, which enables WAG injection and will add roughly 4% of increment to URF.
This story illustrates the importance of correct understanding on the recovery process and the nature of IOR implementation. Right judgments on the project come from precise understanding on the expected displacement mechanism versus limitations of the simulation model at hand. Economic gain is maximized through balanced management between the project's implementation speed and associated risk.
Field Experience Leads to Effective Bypass of Formation Damage Caused by Asphaltenes Deposition and Improves Production from a Naturally Fractured Carbonate Oil Reservoir
Authors: Strippoli Pasquale Danilo , Tiani Alessandro , Mauri Luca , Appicciutoli Danilo , Maier Robert 
Published: February 2011

Abstract
The largest active onshore field in Western Europe produces crude from 20 long horizontal wells from a naturally fractured carbonate reservoir. The produced crude deposited asphaltenes in tubing, openhole sections, and slotted liners. Over time, the deposition became so severe that it involved the reservoir fractures, affected well productivity, and caused a premature field-production decline. Removing the formation damage, therefore, became a priority for appropriate field management.
The injection of asphaltene inhibitors at packer depth reduced asphaltene deposition in tubing but did not protect the long openhole or the natural fractures from plugging. Bullheading or coiled-tubing (CT) solvent treatments were frequently performed with limited benefits.
In 2009, an extensive asphaltene cleanout campaign was performed with more aggressive solvent treatments, covering almost 70% of producing wells. Continuous post-treatment-analysis improved the stimulation effectiveness and optimizing the dissolving fluids led to a production increase per treated well of 500 to 3,500 bbl crude per day. Unfortunately, the treatment techniques applied did not allow sustained production increase unless well interventions were frequent, up to bi-monthly.
To reduce the treatment frequency, an emulsified-acid treatment was performed. The innovative emulsion, where acid was emulsified in solvent, provided a delayed acid reaction and allowed live acid to penetrate deeper into the formation. This allowed the flow pattern to be changed in a way such that the asphaltene deposition was slowed down, and the high well production was sustained over a prolonged period.
This paper describes the history of the treatment methods, the extensive asphaltene-cleanout campaign performed, the post-job analysis, stimulation-treatment improvements based on field experience, and the final novel application of an emulsified-acid treatment that sustained a prolonged production gain of more than 10,000 BOPD and recovered initial well productivity.
Inflow-Control-Device Completion in a Scaling Environment: Findings and Experiences Obtained During Production Logging in the Heidrun Field
Authors: Gustavsen Øyvind , Selle Olav Martin , Fadnes Finn Hallstein , Svela Per Einar , Gudding Erlend , Stene Karin 
Published: February 2011

Abstract
There is an ongoing debate in the industry regarding the use of ICD (inflow control devices) in wells with scale potential. Several concepts for ICD in sand screen completions were evaluated for the Heidrun field, and the equipment chosen had a robust design of the housing, into which the flow goes before entering the basepipe through the nozzles.
Oil field scale is an increasing challenge on the Norwegian continental shelf. One reason for this is the wide use of seawater for reservoir pressure support. Seawater contains sulphate, and mixing of such with barium and strontium containing formation water forms the basis for precipitation of low soluble sulphate salts. In commingled producers mixing of incompatible waters from different reservoir zones can occur due to seawater being flooded through high permeable zones.
The most critical places for scale deposition are the screen section and the DHSV (downhole safety valve). Deposition in the screens hinders inflow to the well and reduces the well productivity.
Recently collected production log data from an ICD completed well with sulphate scale potential forms an important basis for the evaluation of this novel completion solution. The well is a horizontal oil producer completed with 5 1/2" ICD standalone sand screen in 8 1/2" open hole. There are three inflow zones divided by swell packers in blank sections to avoid annular communication. Scale deposits present in the well seem to precipitate around the ICD nozzles inside the tubing, as seen from both GR (gamma ray) and x-y caliper data. Scale deposited in the middle zone does not disappear during the course of multiple logging passes in the well, while the deposits in the upper zone are clearly reduced. This indicates different precipitation processes for the two zones.
Assessment of Asphaltene Deposition Risk in an EOR Intervention Through CO2 Injection
Authors: Correra S. , De Simoni M. , Bartosek M. , Colombani G. , Diatto P. , Maddinelli G. , Parasiliti V. 
Published: February 2011

Abstract
Enhanced Oil Recovery through CO2 injection allows to reach a twofold valuable objective, increasing the amount of crude oil extracted from an oil field while mitigating the contribution of emissions to global warming. Such an intervention is planned in an oil production field in Sicily (Italy) by employing a CO2 stream already available from an oil refinery located near to the field. The oil is currently produced through a pump artificial lift and fluidized by a fluidizing stream injected at the bottom of the well, due to its characteristics: it is an heavy, asphaltene-rich oil. Just these characteristics worried about the possibility that injected CO2 could destabilize the asphaltene fraction, leading to the formation a of a sludge or a solid phase, that would plug the formation pores and, ultimately, decrease injectivity and productivity. In order to assess this risk, the eni in-house-developed asphaltene deposition model was employed to investigate various conditions close to the expected operating conditions. At the same time, a lab activity was undertaken, in order to have an experimental check at least on a narrow range of conditions. Results of these activities showed that no deposition happens in the expected range of operating conditions.
A description of both simulation and experimental activities is reported, in order to show how it is possible to assess the risk of asphaltene deposition before operations potentially dangerous to the field productivity.