bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-time Mineralogy, Lithology, and Chemostratigraphy While Drilling using Portable Energy-Dispersive X-ray Fluorescence
Authors: Marsala Alberto F. , Loermans Ton , Shen Shouwen , Scheibe Christian , Zereik Rachad 
Published: September 2011

Abstract
Our objective is to obtain — while drilling, in real time — a complete petrophysical characterization from drill cuttings and the return mud-stream. Currently such rock and fluid direct characterization is achievable only, with significant time delay and at a considerable cost, from measurements on cores. The approach is to integrate the direct measurements on cuttings with the Logging While Drilling (LWD) practices and tools, to support drilling, geosteering and formation evaluation.
In this framework, it is key to accurately characterize drilling cuttings from a mineralogical and lithological point of view. This characterization can be achieved performing an elemental analysis, by means of Energy-Dispersive X-ray Fluorescence (ED-XRF), in real time, with a portable instrument capable for use at the rig-site, integrated inside the mud logging operations.
The portable X-ray Fluorescence (XRF), coupled with a methodology that enables to convert the elementary analysis into a mineralogical composition, produces a characterization comparable to what can be obtained by full scale X-ray Diffraction (XRD) laboratory equipment. An experimental set up was deployed, to assess the ability to model the mineralogy from geochemically analyses of a set of rock samples.
After portable ED-XRF geochemical analyses, further lab-based analyses were carried out on the same samples: laboratory Wavelength-Dispersive XRF (WD-XRF) and ED-XRF in state of the art facilities. The geochemical data from the portable ED-XRF were compared to the lab-based XRF results (both WD-XRF and ED-XRF) and showed good agreement, particularly between the two ED-XRF instruments. As a final result, the modeled mineralogy from geochemical whole-rock data showed good agreement with the mineralogy determined from XRD analyses. Finally, a first field geochemical monitoring, by portable ED-XRF while drilling, was then successfully executed in Saudi Arabia.
The Use of Seismic Attributes for Depth Conversion and Property Distributions, E-M Field, Offshore South Africa
Authors: Corbett C. , Frewin J. , Kgogo T. , Dubost F. , Navarro R. , Tyler E. , Portet M. 
Published: September 2011

Abstract
The E-M field is a gas reservoir that has been under production for nearly a decade. This paper presents the effort of the team to revise and improve the sub-surface model to delineate new drilling targets. Closure of the field to the east was uncertain, but critical to the field development plan. Inversion of the seismic data created an absolute acoustic impedance cube and a derived effective porosity cube. Attributes were extracted from each of the various seismic data, using direct and interval extractions following the interpreted surfaces. Careful inspection of the seismic amplitude in cross section revealed a flat spot, indicating a potential fluid contact. This feature was confirmed in several of the extracted attributes which were then used to constrain an iterative depth conversion. Fault interpretations in time were then adjusted to match the new depth horizons creating enechelon faults in a fashion analogous to surface outcrops observed in the Cape Town region.
Uncertainty also exists with respect to the vertical isolation of the reservoirs. Log responses record a thin shale, below seismic vertical resolution, in all of the drilled wells. However, the areal extent of the shale is unknown, and vertical communication is a possibility. Stochastic representations of the potential shale extents were introduced into the dynamic fluid-flow simulation, and fed through an experimental design to test the impact on vertical connectivity. Using a proxy model from these results a Monte-Carlo simulation provided a probability distribution for the production response.
The methods presented here are applicable to fields wherever sharp acoustic impedance contrasts exist between fluid types, particularly in gas reservoirs or reservoirs with an existing gas cap. Seismic attributes have refined the depth conversion for the E-M field, and the resulting geomodel provides new drilling targets for the operator.
Is It Sufficient to Calculate Gas Viscosities?
Authors: Potsch K. , Gumpenberger T. 
Published: September 2011

Abstract
For many years it has been customary to calculate gas viscosities from their composition. The argument for it is that a great number of publications on that topic is available. Measurements in the past though were conducted with the light ends of the hydrocarbon spectrum. The theory suggests that the principle of corresponding states is valid which is acceptable if the components are not interacting with each other. This assumption may be not fulfilled for rich gas condensates, associated gases from light oils, gases from HPHT wells and gases with large amounts of sour components. This work investigates the principle of corresponding states and the calculation of the viscosity with an equation of state using literature data of the dynamic viscosity and the gas density. In conjunction with the experimentally determined density, one can easily calculate the kinematic viscosity. This procedure can yield some insight into how the transport property, the viscosity, can be better understood. The data analysis reveals that the kinematic viscosity follows different laws in the gas and the liquid phase. The results are compared with the tabulated values found in the literature and ourown measurements with a falling body apparatus.
CO2 Injection Efficiency, Synthesis of Conceptual Chalk Model: Incremental Oil Recovery and CO2 Storage Potential
Authors: Vuillaume J.. , Akervoll I.. , Bergmo P.. 
Published: September 2011

Abstract
Enhanced Oil Recovery (EOR) using CO2 as injection gas after water injection is a method to increase the oil recovery efficiency compared to only using the water injection process. In addition, it also constitutes a storage method in an oil reservoir. CO2-EOR can help to reduce CO2 emissions regionally and simultaneously improve the security of energy supplies.
The purpose of the present paper is:
- To describe the base case simulations of continuous CO2 injection and CO2 Water-Alternating-Gas (CO2 WAG) injection in the North Sea "conceptual" chalk model. - To give quantitative results on EOR and CO2 storage capacity of the North Sea "generic" chalk model for the continuous CO2 injection and WAG-CO2 injection scenario.
Base case simulations of CO2 injection have been described using the North Sea anticline sector-type model as geometry. SINTEF's oil field database was used. Then conceptual reservoir properties were calculated. Porosity and permeability were computed based on the same methods as used previously for average and standard deviation to populate the conceptual model. Finally a stochastic model based on a Probability Distribution Function of porosity and permeability was used. A conceptual "chalk oil composition" was derived from the Syd-Arne oil field (DK) by an oil composition change in order to match the viscosity and density of conceptual oil. A general development strategy which consists of one producer (P1) and one injector (I1) has been applied.
Numerical simulation using a commercial compositional reservoir simulator was performed a Finite Difference Method. In addition, the dual permeability module was used in order to simulate fractures and matrix permeability flow. Molecular diffusion of CO2 (gas) into oil, oil into gas and CO2 into water was used. Gravity drainage, capillary forces and molecular diffusion are considered as the main factors to influence the oil recovery efficiency.
Results are compared for three cases:
-- Water flooding, continuous CO2 injection and CO2-WAG injection: - Field Oil Production Rate and Field Oil Production Total per pore volume injected - CO2 volume stored per pore volume injected
In all the reservoir model cases under investigation with CO2 continuous injection and WAG-CO2 injection, CO2 injection is found to increase the hydrocarbon recovery by 12% to 13.2% recovery after injection of 1.4 Hydrocarbon Pore Volume compared with a base case scenario which is water injection. After 90 years of injection, from 1.35 to 2.95 millions tonnes CO2 were stored for the WAG-CO2 and CO2 injection case respectively.
New Recovery Method for Carbonate Reservoirs through Tuning the Injection Water Salinity: Smart WaterFlooding
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed 
Published: September 2011

Abstract
Water flooding is the most widely applied method for recovering oil from reservoirs. The salinity and ion composition of the injection water in the past have not been considered as a key parameter in oil recovery from water-flooded reservoirs. In recent years, evidence — from laboratory studies verified by some field tests mainly targeting sandstones — has shown that injecting low salinity water has a significant impact on oil recovery. The potential for carbonates has not been thoroughly investigated where some of the reported studies have excluded carbonates from this effect.
Saudi Aramco, through its upstream research arm (the Advanced Research Center) has initiated a research program tagged "Smart WaterFlood" to explore the potential of increasing oil recovery by tuning the injection water properties. Based on the research work for the last three years, we present in this paper the results of reservoir condition laboratory coreflooding studies, conducted using composite rock samples from a carbonate reservoir, to investigate the impact of salinity and ionic composition on oil recovery. Also, we report a broad range of laboratory studies addressing oil recovery mechanisms.
The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injection water. The new trend is distinct from what have been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. Laboratory studies have also shown that altering the salinity and ionic content of the injection water has a significant impact on the wettability of the rock surface. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanisms for substantial oil recovery by altering salinity of field injection brine is wettability alteration.
Measuring Partitioning Coefficients for Gas Tracer Mass Balance and Gas Injection Allocation
Authors: Cubillos H. , Torgersen H. , Chatzichristos C. , Rodriguez R. 
Published: September 2011

Abstract
An interwell gas tracer test provides very useful information not only to improve reservoir description but also to characterize flow dynamics.
Approaches to tracer application can range from conventional qualitative interpretation to quantitative analysis including numerical simulation. Our aim is to optimize miscible gas injection efficiency by correct calculation of gas injection allocation based on mass balance of the injected tracer (how much of an injected tracer is produced in the various production wells). Since perfluorocarbon gas tracers are partitioning tracers, and the capillary tube sampling technique only allows measurement of tracer concentration in the gas phase, knowledge of the partitioning coefficient (Kd) of the gas tracers at sampling conditions (wellhead pressure and temperature) is required. We successfully developed and implemented experimental design, equipment set up and procedures to measure a set of consistent Kd values for the oil and the gas mix for all commercial available gas tracers.
Subsequently, we integrated the Kd values with tracer and production data and estimated the correct recovery of the gas tracers. The next step was to estimate the gas injection allocation to optimize gas injection patterns and to provide input for improving the simulation history match.
Our approach is a further step in quantitative analysis of tracer data and can be applied to provide valuable information to optimize gas injection and oil production.
Towards an Integrated Workflow for Structural Reservoir Model Updating and History Matching
Authors: Leeuwenburgh O. , Peters E. , Wilschut F. 
Published: September 2011

Abstract
A history matching workflow, as typically used for updating of petrophysical reservoir model properties, is modified to include structural parameters including the top reservoir and several fault properties: position, slope, throw and transmissibility. A simple 2D synthetic oil reservoir produced by waterflooding is used to demonstrate issues related to observability and identifiability of structural uncertainties. A series of history matching experiments are performed that demonstrate the potential for estimation of uncertain structural parameter values. The experiments are performed with ensemble-based assisted history matching schemes that allow for the proper characterization of prior uncertainties, and in principle enable the updating of both model parameters and the dynamic states such as pressures and saturations. The results show that the approach works well when individual structural parameters are estimated and suggest further scope for building a fully integrated workflow that includes the improved construction of geo-models into the history matching loop.
Pre-Combustion Capture of CO2 from Synthesis Gas Mixture CO2/H2 Using Hydrate Formation
Authors: Gholinezhad J. , Chapoy A. , Haghighi H. , Tohidi B. 
Published: September 2011

Abstract
CO2 capture from CO2/H2 gas mixture is an attractive approach for reducing greenhouse gas emissions. This mixture is associated with power generation processes in power plants and typically contains 40% CO2 and 60% H2. A novel method for capturing CO2 from the above gas mixture is to use gas hydrate formation. This process is based on selective partition of CO2 between hydrate phase and gas phase. Due to their larger diameters, CO2 molecules have higher tendency to go into hydrate clathrates than H2 molecules, which ultimately results in a gas rich in carbon dioxide.
This study demonstrates the concept and presents the results of our experimental investigation for CO2/H2 separation by hydrate formation process. Since hydrate formation from water and gas requires high pressures, tetrabutylammonium bromide (TBAB) is added to the system to reduce the equilibrium pressure. TBAB forms semi-clathrates that can encage small gas molecules. The results shows that in one stage of gas hydrate formation and dissociation, CO2 can be enriched from 40% to 88%. In addition, the concentration of CO2 in equilibrium gas phase is reduced from 40% to 18%. While separation efficiency is comparable with the process without any additive, the presence of TBAB improves the operating conditions significantly. In addition, CO2 could be enriched to 98% by two stages of hydrate formation.
Contribution of the Gravel Mesh Size in Screen Damage on a Gravel Pack System
Authors: Villarroel F. M. , Braga A. M. , Camerini M. G. , Simoes T. B. , Bloch M. 
Published: September 2011

Abstract
The performance of a gravel pack sand control system is analyzed considering the potential screen damage associated to the gravel mesh size, which is the key-parameter for designing efficient gravel pack systems. Indeed, the largest mesh size able to reduce solid production while keeping the head loss as minimal as possible, would always appear to be the logical choice. However, screen integrity should also be considered whenever choosing the gravel mesh size, and experimental results presented in this paper show that the larger the mesh size, higher is the chance of localized damage appearing on the screen of the gravel-pack system.
Experimental tests with gravel pack prototypes were run in a large poliaxial frame, using two of the most common gravel sizes: 16/20 and 20/40 mesh. The system was set on artificial cubic rock samples of 11.8 in side, with a centered hole of 2.4 in diameter. The cubical samples were submitted to a triaxial stress field reaching the ratio SMAX/Smin equal to 1.6.
Visible localized damage in the screen’s outer surface was observed when testing the larger gravel agent (16/20 mesh), as compared to the smaller 20/40 mesh. The experimental observation was explained by contact stress effect, indicating that larger particle sizes are more prone to damage the screen, while the stresses transferred by smaller particles are more uniform. On the long run, the contact stress effect can result in erosion and, in some cases, screen collapse. A simple, qualitative, analytical model is employed to corroborate the mechanical effects observed in the experimental test.
Whenever designing gravel pack systems for deepwater wells, one should consider long term operation, avoiding complex and expensive workover operations. Thus, a more conservative design criterion is recommended to improve the gravel pack operational life, including the analysis of possible contact stress effects.
Assessment of Rate-Dependent Skin Factors in Gas Condensate and Volatile Oil Wells
Authors: Gringarten A. C. , Ogunrewo O. , Uxukbayev G. 
Published: September 2011

Abstract
Well testing in gas-condensate and volatile oil reservoirs with flowing bottomhole pressure below the saturation pressure creates multiphase flow in the reservoir, resulting in relative permeability reduction and a rate-dependent skin factor. In lean gas condensate reservoirs, the wellbore skin effect calculated using single-phase pseudo-pressures has often been found to be constant or even to decrease with increasing gas rates, instead of increasing as in dry gas reservoirs. This behaviour has been tentatively attributed to capillary number effects compensating for condensate blockage and inertia effects, but no detailed study of this behaviour has appeared in the literature to-date.
This paper investigates wellbore skin behaviours in lean and rich gas condensate reservoirs and in volatile oil reservoirs by using compositional simulation with capillary numbers and non-Darcy flow to generate well test data. It is shown that below saturation pressure, gas condensate well test analyses with single-phase pseudo-pressures and volatile oil well test analyses with pressures do not correctly estimate the rate-independent wellbore skin effects and the non-Darcy flow coefficients, whereas analyses with two-phase pseudo-pressure do, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. In gas condensate reservoirs below the dew point pressure, the rate independent skin factor and the non-Darcy flow coefficient calculated with two-phase pseudo-pressures are identical to the corresponding values calculated above the dew point pressure with single-phase pseudo-pressures. These simulation results are applied to actual field data.
Quantitative Analysis Involving Scaling Procedures for Integration between History Matching and 4D Seismic
Authors: Avansi G. D. , Schiozer D. J. 
Published: September 2011

Abstract
Time-lapse seismic has been providing valuable information on identifying fluid movements, to locate bypassed oil and well placement optimization to reduce uncertainties in reservoir development and production management. Most of these are made through a qualitative approach, which limits seismic data integration in reservoir simulation studies due to different scales. In order to overcome this and to develop new data integration techniques, many studies involving these processes have the assumption that both frameworks are in the same scale. Nonetheless, the quantification of lost information in the scaling procedures needs to be evaluated and quantitative seismic data integration into the simulator should improve the mitigation of these problems improving the knowledge about the representativeness of the scaled data.
In this context, it is presented a technique regarding scale issues relating time-lapse seismic data and simulation models aiming to quantify the information lost due to scaling problems and how these troubles affect the history matching.
This paper describes a methodology involving seismic attributes and reservoir simulation. The lost information due to scaling procedures is evaluated through comparison between flux model properties and seismic attributes, at each respective framework. This technique allows reliability improvement of reservoir parameters from seismic attributes regarding the loss of information due to scaling procedures and history matching.
It has been shown that it is possible to match the history production in order to improve the process considering the scaling issues between the seismic and simulation scale, increasing model quality and reliability on results through a quantitatively analysis involving scaling procedures between 4D seismic data and reservoir simulation integrated studies.
The main contributions of this technique are the integration procedures regarding scaling issues between seismic data, reservoir simulation models and history matching procedure by time-lapse seismic attributes.
A Method for Full-Range Young's Modulus Correction
Authors: Canady Wyatt 
Published: September 2011

Abstract
Deriving rock moduli from acoustic velocities is the most common method for evaluating formation mechanical strength in the petroleum industry. While common, the accuracy of the method is hindered by the difficulty correcting the moduli, as measured by the acoustic logging tool to values representative of the actual moduli of the rock.
Analysts generally rely on simple empirical equations to provide the estimates for the corrections that must be made. These empirical equations are usually derived from wireline logs or from core analysis of samples taken from the formation of interest. The usefulness and accuracy of this method of modulus correction is hampered by the fact that the dynamic-to-static conversions are strongly non-linear. The method is also hampered by the rather narrow range of values available in a particular empirical function.
This paper presents an empirical method featuring a simple, single equation that provides estimates of static Young's modulus across the whole-range stresses and rock strengths that might be encountered in a reservoir.