bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Directional Drilling While Minimizing the Risk of Well Collision in Offshore Drilling
Authors: Sharma Nitin , McDonald Mike , Mohammed Jeffrey , Daire Bryan , Eicks Theodore , Jew Leo 
Published: October 2009

Abstract
As offshore drilling grows more crowded and more complex, greater emphasis is placed on avoiding collisions with offset wellbores. The implications of a collision with an existing well are very real, and care must be taken to minimize the risks associated with such incidents. Collision with a producing well carries additional risks, including potential well-control situations and lost income from shut-in wells. With more wells being drilled from multi-well locations, well collision is becoming a very real possibility. Today's drilling trends toward more directional, horizontal, and fishbone multilateral wells, often with several from a single slot using subsea wellheads. This paper covers the practices for sidetracking out of the well using a whipstock and minimizing the risk of collision with offset wells. Special emphasis is placed on optimizing whipstock placement (orientation and depth), use of gyroscopic tools while milling and drilling ahead, and the use of traveling cylinders for collision avoidance. Case histories are presented here to illustrate the successful application of these techniques.
Photo Review: Remote Assessment of HSE Conditions at Operational Facilities Using Digital Photography and On-Line Meeting Capabilities
Authors: Simon Flavio , Godfrey Richard , Pilling Lee , Graf Jake 
Published: October 2009

Abstract
Operating hundreds of facilities globally, both fixed and temporary, larger petroleum industry companies are challenged to ensure consistent compliance to HSE standards. Although local and regional staff members conduct regular inspections, corporate HSE inspections are less frequent due to the challenges of distance and limited resources. The Photo Review process was developed to bridge this gap.
Briefly, corporate HSE staff selects a facility for a Photo Review based on a number of criteria, such as leading and lagging indicators, follow-ups or elapsed time since prior inspections. Then, regional or local HSE staff members walk-about the facility, capturing digital photos according to a pre-defined shot-list that specifies points-of-interest to the corporate HSE team. The photos are inserted into a preformatted presentation template and posted to the Company's inspection database.
In an online video-teleconference, local management then conducts a virtual tour of their facility with the HSE team providing commentary, coaching, and solutions as needed. Depending on the perceived level of commitment and compliance to standards, the outcome is either "all good", "needs attention", or a follow-up in-person corporate inspection is warranted.
Understanding Reservoir Mechanisms Using Phase and Component Streamline Tracing and Visualization
Authors: Kumar Sarwesh , Datta-Gupta Akhil , Jimenez Eduardo A. 
Published: October 2009

Abstract
Streamline simulation has received considerable attention because of its computational efficiency and also for being visually appealing and physically intuitive. Conventionally streamlines are traced using total fluid fluxes across the grid cell faces. The visualization of total flux streamlines shows the movement of tracer and water flood front, injector-producer relationship, swept volumes for injectors and drainage volumes for producers. However, total fluxes mask many important features of reservoir flow embedded in the individual phase fluxes. These include reservoir dynamics, such as phase distribution, appearance and disappearance of phases, local drive mechanisms and reservoir miscibility conditions for CO2 or solvent flooding.
In this paper we demonstrate the benefits of visualizing phase and component streamlines, which are traced using phase and component fluxes respectively. Both three-phase black oil and compositional simulation are used to visualize reservoir flow and to understand the drive mechanisms active in the reservoir. Although the phase and component streamlines are not suited for flow simulation because of their local discontinuities, these streamlines provide unique insight into the reservoir processes and recovery mechanisms. In this study, the phase and component streamline tracing is done using phase/component fluxes from commercial finite-difference black oil and compositional simulators.
We demonstrate the power and utility of the phase and component streamlines using synthetic and field examples. The phase streamlines are shown to capture the dominant flowing phases in different parts of the reservoir and to help us optimize locations of infill injectors and producers. Based on the appearance and disappearance of phase streamlines, we can identify the regions of the field where different drive mechanisms such as waterflood and solution gas drives are active. The field applications involve waterflooding in a structurally complex reservoir in South America and also, a CO2 injection project in a large carbonate reservoir in Canada. We use component streamlines to track the movement of injected CO2 in the reservoir. By tracking the phase and component streamlines, we can clearly distinguish the CO2 in the gas phase and the dissolved CO2. This not only helps optimize CO2 injection but also has important implications in the effectiveness of the CO2 sequestration.
Pore Networks and Fluid Flow in Gas Shales
Authors: Wang F. P. , Reed R. M. , John A. , Katherine G. 
Published: October 2009

Abstract
Favorable gas content, depth, and thickness, along with high brittleness of the Barnett Shale in the Fort Worth Basin, North Texas, have made the basin one of the best shale-gas plays in North America. Using recent pore images and geochemical data for the Barnett Shale, we investigated potential effects of organic matter on petrophysical properties, pore networks and fluid flow in gas-shale systems.
Four types of porous media are present in productive gas-shale systems: nonorganic matrix, organic matter, natural fractures, and hydraulic fractures. Organic-matter pores, ranging from 5 to 1,000 nm, are especially important because they can adsorb gases as well as store free gases. Gas content and adsorption data from Barnett Shale also suggest that a significant amount of free gas is stored in organic matter. Porosity in organic matter can be five times higher than that in the nonorganic matrix. Organic matter is oil wet, and associated pores work as nanofilters for hydrocarbon flow, suggesting that fluid flow in organic matter is predominantly single phase.
Owing to high porosity, predominantly single-phase flow, and the gas slippage effect, gas permeability in organic matter, significantly higher than that in the nonorganic matrix, tends to enhance gas permeability in gas shale. In addition, the pore network in organic matter, can be larger than that in the fractures, could be the hidden pathway to high gas production in gas shale when connected to natural and hydraulic fractures.
Investigation of Formation Connectivity Using Asphaltene Gradient Log Predictions Coupled with Downhole Fluid Analysis
Authors: Zuo Julian Y. , Mullins Oliver C. , Dong Chengli , Betancourt Soraya S. , Dubost Francois X. , O’Keefe Michael , Zhang Dan 
Published: October 2009

Abstract
Reservoir fluids often demonstrate complicated phase behaviors in a single column as a result of the impacts of gravity, thermal gradients, biodegradation, active charging, water washing, leaky seals, and so on. Moreover, reservoir compartmentalization can cause discontinuous distributions of fluid compositions and properties, making the proper characterization of fluids and reservoirs even more challenging yet compelling. The recognition of flow barriers or compartmentalization is key to effective and efficient reservoir characterization, production, and management. Downhole fluid analysis (DFA) is an essential tool for determination of the compositional gradients in real time at reservoir conditions. However, analysis of flow connectivity in the reservoir by DFA can be complex, especially when the reservoir fluid compositional gradients are small with depth. In this case, the analyses of bulk fluid properties may not be sufficiently sensitive. However, DFA of asphaltene gradients provides an excellent method to delineate the complexity of black oil columns. Moreover, DFA measurements are very sensitive to and often linear in the asphaltene content.
A methodology has been developed to estimate downhole fluid coloration variations with depths using an equation-of-state (EOS) approach coupled with the DFA tools. The DFA tools are used to determine downhole fluid compositions of CO2, C1, C2, C3−C5, C6+, and the coloration associated with asphaltene contents. Recent additions to DFA measurements include fluid density and viscosity. The delumping and characterization procedures proposed by Zuo et al. (2008) are applied to obtain the detailed compositions including asphaltenes and the parameters of the EOS model. Fluid profile and coloration logs are computed by "tuning" the molar mass of asphaltene nanoaggregates against the DFA coloration logs. The methodology has been successfully applied to investigate reservoir connectivity for offshore and laboratory centrifugation cases. The adjusted molar mass of asphaltene nanoaggregates is determined to be in a range of 3,000–8,000 g/mol for the cases studied, yielding molecular aggregation numbers of roughly 7 in reservoir fluids, which is in agreement with laboratory studies. The results obtained in this work demonstrate that the proposed method provides a useful tool to reduce the uncertainties related to reservoir compartmentalization and to optimize DFA during the logging run. In addition, the results indicate that treating part of the Cn+ (e.g., C36+) fraction as an asphaltene component (monomer) in the traditional cubic EOS approach is contradicted by the recent observations that asphaltenes are nanoaggregates in crude oils.
A Fully Coupled Numerical Poroelastic Model to Investigate Interaction between Induced Hydraulic Fracture and Pre-Existing Natural Fracture in a Naturally Fractured Reservoir: Potential Application in Tight Gas and Geothermal Reservoirs
Authors: Rahman M. M. , Rahman Sheik S. 
Published: October 2009

ABSTRACT
This paper investigates interaction of induced and pre-existing fracture by coupling wellbore, induced fracture and natural fracture in a poroelastic reservoir. Possibilities of fracture crossing, bending, arrest and shear dilation for various angles of approach are investigated under different scenarios: in-situ stress state, reservoir rock and fluid properties and characteristics of natural fracture.
The fully coupled poroelastic model and results of this study in particular have a beneficial application in the design and optimization of hydraulic fracture treatments in naturally fractured reservoirs, therefore tight gas reservoirs and enhanced geothermal systems. The model can be extended to design stimulation of naturally fractured reservoirs based on shear dilation (high pressure low injection rate).
In this paper we have demonstrated that natural fractures, faults and other discontinuities severely restrict propagation of an induced fracture. In-situ stress state, orientation and shear strength of pre-existing fracture prove to be most significant factors that influence the fracture propagation trajectory:
– Because of the poro-elastic formulation it was possible to investigate the change in stress state ahead of the fracture tip and evaluate whether the fracture is going to be attracted or rejected by the interface. It was observed that high leak off influences dilation of natural fracture ahead of the arrival of the induced fracture tip. – Possibilities of fracture arrest increases with increase in high differential stress state and shear strength of pre existing fractures. – Fracture crossing is another dominating behaviour for natural fracture with small aperture while fracture dilating for natural fracture with larger aperture.
Fully coupled poroelastic modelling allowed us to gain new knowledge on interaction between induced and pre-existing fractures. This methodology and knowledge base will significantly improve our current approach to design and implement hydraulic fracture treatment in naturally fractured reservoirs.
Oil Recovery by Low Salinity Brine Injection: Laboratory Results on Outcrop and Reservoir Cores
Authors: Boussour S. , Cissokho M. , Cordier P. , Bertin H. , Hamon G. 
Published: October 2009

Abstract
Over the last 10 years, the emerging EOR process by injection of low salinity water has been investigated through numerous laboratories and some field tests. Extensive research programs have been launched by different teams, aiming at better understanding the involved mechanisms (clay release, pH increase, cation exchange). One of the main issues is to explain the observed dispersion in additional oil recoveries.
In this study, we integrate new experimental observations to the literature to carry out a mechanism analysis of recovery by low salinity injection. These new results were obtained on outcrop sandstones with 9-10 % clay content (Cissokho 2009) and on reservoir cores with reservoir oil.
Very positive results to dilute brine injection on the outcrop rock / crude oil of field A system have been observed either in tertiary mode or secondary mode. Corefloods on the same outcrop rock/ crude oil system show that the benefits of low salinity brine injection may vary against the flood temperature. Corefloods in pseudo-reservoir conditions using reservoir cores and the same crude oil of field A showed no response to injection of low salinity brine. Corefloods using reservoir cores and oils from three different fields did not show any positive response to dilute brine injection.
In this paper, we analyze the different theories proposed in the literature and present experimental counter-examples for most of them, particularly related to the presence of kaolinite, divalent ions in injected brine, or the effect of temperature. We show that low salinity water injection as an EOR method appears very sensitive to a combination of several parameters.
Development of a Ribbon Gravity Gradiometer and its Applications for Reservoir Monitoring
Authors: Neill F. 
Published: October 2009

Abstract
Gravity Gradiometry has been rapidly gaining acceptance as an additional tool in the geophysical tool box when deployed in either aircraft or ships. The potential for its use for downhole applications including reservoir monitoring has been identified for some time. However the sensors used for surface applications are unsuitable for downhole applications and as a result of the lack of a suitable sensor, little investigation has been carried out on wellbore applications.
This paper briefly explains gravity gradiometry and its history in the oilfield. Measurements of gravity (Gz)and gravity gradiometry (Γzx) are compared with the advantages and disadvantages of each outlined. The potential application of the technology as an ultra-deep reading density measurement for reservoir monitoring is shown. Depending on the resolution of the sensor and the reservoir parameters the paper shows that it will be possible to detect a gas / liquid interface in a directional manner at distances up to one kilometre from the wellbore.
The paper explains the principles of the ribbon gravity gradiometer and its suitability for downhole deployment. Its inherent common mode rejection and the subsequent relative immunity to downhole noise and deviation issues are outlined. The equations for the derivation of the borehole gravity gradients are shown and immunity to environmental influences explained. The limited impact of near well bore effects is explained. Depending on the deployment method, time averaging is shown to increase sensitivity and an example is shown of the depth of investigation versus sensor sensitivity for oil/water, oil/gas and gas/water interfaces.
The paper clearly demonstrates that the ribbon gravity gradiometer is a viable downhole sensor and will provide a significantly deeper depth of investigation than traditional nuclear or electrical measurements.
New Integrated Approach for Updating Pore-Pressure Predictions During Drilling
Authors: Lüthje M. , Helset H. M. , Hovland S. 
Published: October 2009

Abstract
This paper presents a new integrated approach for updating pore pressure predictions during drilling of a well. Pore pressures in sedimentary rocks can vary from hydrostatic (normal) pressures to very high (abnormal) overpressures. Sediment pore pressures are important constraints that need to be carefully considered when planning a new well and will influence drilling strategy, casing program, and mud-weights.
A pre-drill prediction of pore pressures is used as input in the well planning phase and is based on an assumption of the local geology in the prospect, typically extrapolated from near-by wells. However, the pre-drill prediction may be inaccurate or erroneous due to incorrect assumptions.
To help solving this problem we have developed an integrated approach for updating the pore pressure prognosis during drilling. The methods for pore pressure predictions are integrated with an eDrilling system for real-time simulation of the drilling process. Data from the drilling operation are processed real-time and includes drilling parameters, logging while drilling data, and other measurements performed during drilling. The base for a real-time update is pre-drill pore pressure predictions from basin modeling using Monte Carlo analysis. As drilling and log data becomes available during the drilling operation, fast calculations of pore pressure along the well are performed. The calculated pressure along the well is used to weight the pre-drill Monte Carlo results in order to update the pore pressure prediction ahead of the bit.
Real-time updated pore pressure predictions are of vital importance for advanced computer based systems for online supervision and decision support during drilling. Early warnings can be supplied if abnormal overpressures are to be expected ahead of the bit, or if measures should be taken to avoid dropping below the pore pressure. This paper presents the methodology and simulation results using log data from the Norwegian North Sea. Simulations show that pore pressure predictions ahead of the bit are improved compared with the pre-drill predictions, when updating predictions using the drilling logs.
The novel combination of automatically updated pore pressure data during drilling with an advanced real-time integrated drilling simulator provides a powerful tool for next generation drilling software.
Stochastic Modeling of Objects Extracted from High-Quality Seismic Data
Authors: Syversveen A. R. , Hauge R. , Tollefsrud J. I. , Lægreid U. , MacDonald A. 
Published: October 2009

Abstract
In this paper we present an approach for modeling facies bodies based on detailed seismic interpretation of the reservoir's sedimentological architecture. The approach involves the use of a highly constrained stochastic object model to integrate directly the seismic facies interpretations in a 3D reservoir model. It fills the gap between the use of seismic data in a true deterministic sense, where the facies body top and base are resolved and mapped directly, and stochastic methods where the relationship between seismic attributes and facies is defined by conditional probabilities.
In the new approach the lateral geometry of the facies bodies is controlled by seismic interpretations on horizon slices or by direct body extraction. Facies body thickness and cross-sectional shape are defined by a mixture of seismic data, well data and user defined object shapes. The stochastic terms in the model are used to incorporate local geometric variability which is used to increase the geological realism of the facies bodies and allow for correct, flexible well conditioning.
The result is a set of 3D facies bodies which are constrained to the seismic interpretations and well data. Each body is defined as a "parametric object" which includes information such as: Location of the body axis, depositional direction, axis-to-margin normals, and external body geometry. The parametric information is useful for defining geologically realistic intrabody petrophysical trends and for controlling connectivity between stacked facies bodies.
Reactive Pore Network Modeling Dedicated to the Determination of the Petrophysical Property Changes while Injecting CO2
Authors: Algive Lionnel , Bekri Samir , Vizika Olga 
Published: October 2009

Abstract
A Pore Network Model is an efficient tool to account for phenomena occurring at the pore scale. Its explicit threedimensional network of pores interconnected by throats enables to easily consider the topology and geometry effects on upscaled and homogenized petrophysical parameters. In particular, this modeling approach is appropriate to study the rock/fluid interactions. It can provide quantitative information both on the effective transport property modifications due to the reactions and on the structure evolution resulting from dissolution/precipitation mechanisms.
The developed model is based on the resolution of the macroscopic reactive transport equation between the nodes of the network. By upscaling the results, we have then determined the effective transport properties at the core-scale. A sensitivity study on reactive and flow regimes has been conducted in the case of single-phase flow in the limit of long times.
It has been observed that the mean reactive solute velocity and dispersion can vary up to one order of magnitude compared to the tracer values because of the concentration profile heterogeneity at the pore scale resulting from the surface reactions. As for the reactive apparent coefficient, when the kinetics is limited by the mass transfer, it can decrease by several orders of magnitude with regard to the one calculated by the usual perfect mixing assumption. That is why scale factors should be added to the classical macroscopic transport equation implemented in reservoir simulator to accurately predict the reactive flow impacts. For each study case we have also obtained the permeability variation versus the porosity evolution in a physical way which accounts for reactive transport conditions. It appears that the wall deformation pattern and its impact on petrophysical properties must be explained by considering both microscopic and macroscopic scales of the reactive transport, each one governed by a dimensionless number comparing reaction and transport characteristic times.
This work contributes to improve the understanding of surface reactions impacts on reactive flow in one hand, and on permeability and porosity modifications in the other hand. Using the PNM approach, scale factors parameters and permeability versus porosity relations can be determined for various rock-types and reactive flow regimes. Once integrated as inputs in a reservoir simulator, these relations are a powerful and convenient means to enhance the modelling accuracy of the petrophysical properties evolution during a reactive fluid injection such as CO2-rich brines.