bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of 3D Seismic Attributes and Well Logs for Electrofacies Mapping and Prediction of Reliable Petrophysical Properties
Authors: Mahdavi Ramin , Kharrat Riyaz 
Published: June 2009

Abstract
Accurate distribution of geological and petrophysical properties such as facies, porosity and water saturation in carbonate reservoir is an essential part of building robust static and dynamic models for proper reservoir management and making reliable decisions. An integration based approach is applied for the prediction of the essential reservoir properties using well logs and 3D seismic data. The method is based on the derivation of electrofacies classes using Artificial Neural Networks (ANN) method and Geostatisticsl Conditional Simulation (GCS) Approaches.
The electrofacies of the carbonate reservoir of late cretaceous understudy, which is located in the south west of Iran, were classified using the unsupervised ANN method. Based on the verification of cross plots of input logs (GR, DT, RHOB, NPHI, and LLD) versus electrofacies classes, seven rock types including one class as shale rock and others sex classes as argillaceous, dense, poor, moderate, good and best limestone rocks were identified. The unsupervised approach has provided unbiased classes of electrofacies that cover the vertical variations of the well logs very well and also provided a very fine correlation for the entire reservoir.
Based on the 3D seismic data, nine seismic volume attributes were calculated. The most correlative attributes for prediction each reservoir properties were selected based on the correlation coefficient investigation. At this stage, the ANN was used to create 3D model of electrofacies, effective porosity and water saturation based on the associated 3D seismic derived attributes. These seismic derived reservoir properties were used as secondary variable in collocated cokriging equation through the GCS. The 3D simulation of electrofacies represented similar seismic attribute responses, which was interpreted geologically, resulted in good consistency with sedimentary directions and conditions of the understudy area.
In conclusion, the seismic based 3D simulations of electrofacies, effective porosity and water saturation generated using ANN's and GCS have provided geologically more meaningful information about the lateral facies variations and reliable properties distributions in this carbonate reservoir.
Transport of CO2-Foaming Agents During CO2-Foam Processes in Fractured Chalk Rock
Authors: Zuta John , Fjelde Ingebret 
Published: June 2009

Abstract
The co-injection of CO2 and a CO2-foaming agent to form stable CO2-foam has been found to improve the sweep efficiency during CO2-foam processes in carbonates reservoirs. However, only a few studies of CO2-foam transport in fractured rock have been reported. In fractured chalk reservoirs with low matrix permeability, the aqueous CO2-foaming agent solution will flow mainly through the fractures. The total retention in the reservoir will depend on how much of the matrix that is contacted by the foaming agent solution during the project period and therefore its transport rate into the matrix.
This paper presents results from a series of static and flow-through experiments carried out to investigate the transport and retention phenomena of CO2-foaming agents in fractured chalk models at 55°C. Fractured chalk models with 100% water-saturation and at residual oil saturation after water flooding were used. In the static experiments, the fractured model was created by transferring core plugs with different diameters into steel cells with an annulus space around the plugs. The fracture volume was filled with foaming agent solutions with different initial concentrations. The experiments were carried out in parallel with liquid samples regularly taken out from the fracture above the plugs and analyzed for the foaming agent concentration. The experiments were monitored until the concentrations in the fractures reached a plateau.
At specific and constant concentrations of the foaming agent in the fractures, the plugs were demounted and samples drilled out from the outer, middle and centre portions. These samples were analyzed for foaming agent concentration to determine its transport rate into the matrix. Results indicate that the transport of the foaming agent decreases towards the centre of the plugs with 100% water-saturation and at residual oil saturation after water flooding. Modeling of the static experiments using the commercial simulator STARS were carried out to determine the transport rate for the foaming agent. A good match between experimental and modeling results was obtained.
In the flow-through retention experiments, the fractured model was created by drilling a concentric hole through the center of the plug. The hole simulating an artificial fracture was filled with glass beads of different dimensions. Fractured models with different effective permeability were flooded with the foaming agent solution until the inlet and the outlet concentrations were the same at stable differential pressures. Results show that the retention of foaming agent both in the absence and presence of oil to be slower in fractured models than in homogeneous models with viscous flooding of the rock.
An Improved Approach For Ensemble Based Production Optimization: Application To A Field Case
Authors: Chaudhri Masroor M. , Phale Hemant A. , Liu Ning 
Published: June 2009

AbstractOne of the primary goals of the reservoir management is to enable decisions that maximize recovery from the reservoir. With recent developments in monitoring and control, the opportunity to optimize reservoir production through frequent adjustment of well controls has substantially increased. We recently proposed and demonstrated an improved ensemble-based production optimization method using Conjugate Gradient technique (CGEnOpt) on a synthetic reservoir model. The proposed method results in faster convergence as a result of using the conjugate gradient directions instead of steepest ascent search directions. The net present value (NPV) of a single reservoir is optimized by obtaining the gradient of the NPV from an ensemble of control variables.In this paper, the benefits and effectiveness of the proposed method is demonstrated on a real field example located off-shore west Africa with 15 producers and 11 water injectors. The production and injection rates are used as control variables to maximize NPV of the reservoir.The results indicate that the control settings from the proposed method result in a significantly higher NPV of the reservoir as compared to the reference case. The number of iterations needed for the proposed method is significantly reduced compared to the standard ensemble-based optimization. The proposed method is able to allocate the production and injection rates effectively which results in a substantial decrease in the amount of water produced.In the literature, a wide variety of approaches were developed and implemented for optimizing the reservoir performance by adjusting operational controls. The proposed method is completely adjoint-free and is independent of the reservoir simulator used for the prediction simulation run which makes it easy to implement. It can be used with any existing simulator with minimal code development.
High Pressure Acid Gas Viscosity Correlation
Authors: Galliéro G. , Boned C. , Baylaucq A. , Montel F. 
Published: June 2009

Abstract
Acid gases containing H2S are often encountered in the petroleum industry. However, reliable experiments on their thermophysical properties in reservoir conditions, in particular viscosity, are very scarce. From a modeling point of view H2S (and CO2) are polar compounds and are so often considered as rather difficult to model accurately. In this work, we propose a correlation based on a corresponding states approach in order to predict the viscosity of acid gas mixtures, among others, with a strong physical background. This correlation is based on the Lennard-Jones fluid model, which has been studied extensively thanks to molecular dynamics simulations over a wide range of thermodynamic conditions. This fluid model can be extended to deal with polar molecules such as CO2 or H2S without a loss of accuracy.
In a first part, we demonstrate that the proposed physically based correlation is able to provide an excellent estimation of the viscosity (with average absolute deviations below 5 %) of pure compounds including normal-alkanes, CO2 or even H2S whatever the thermodynamic conditions, gas, liquid or supercritical.
Then, using a one-fluid approximation and a set of combining rules, the correlation is applied to various mixtures in a fully predictive way, i.e. without any additional fitted parameters. Using this scheme, the deviations between predictions and measurements are as low as on pure fluids. The viscosity of natural and acid gas mixtures in reservoir conditions is shown to be very well predicted by the proposed scheme. In addition, it is shown that this correlation can also be applied to predict reasonably the viscosity of asymmetric high pressures mixtures even in the liquid phase.
This physically based approach is easy to plug in any simulation software as long as the only inputs, the molecular parameters, are directly related to the critical temperature and volume.
The Method of Characteristics Applied to Oil Displacement by Foam
Authors: Zanganeh M. Namdar , Kam S. I. , LaForce T. C. , Rossen W. R. 
Published: June 2009

Abstract
Method of characteristics (MOC) provides key insights into complex foam enhanced oil recovery (EOR) displacements and the simulators that represent them. Most applications of MOC to foam have excluded oil. We extend MOC to foam flow with oil, where foam might be weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this.
We examine SAG (surfactant-alternating-gas) and continuous foam injection (process of co-injection of gas and surfactant solution) processes in one dimension (1D), using both MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large impact on the nature of the displacement. For instance, for gas injection in a SAG process, if oil is assumed to completely destroy foam above some critical saturation, and initial oil saturation is above that value, foam has nearly no effect on the displacement. On the other hand, if oil saturation weakens foam abruptly but smoothly, then successful mobility control is possible.
The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the fraction of water in the injected foam and the functional forms used to express foam sensitivity to oil and water saturations.
Ensuring Sustained Production by Managing Annular-Pressure Buildup
Authors: Hasan A. R. , Izgec B. , Kabir C. S. 
Published: June 2009

AbstractIncreased tubinghead temperature with increased rate may induce pressure increase in the annuli for the trapped fluid. Managing annular-pressure buildup or APB for sustaining well deliverability is particularly crucial in subsea wells, which cannot be intervened easily. Ordinarily, a multistring casing design accommodates anomalous pressure rise from the standpoint of well integrity. However, management of day-to-day operations presents challenges when APB occurs. This study presents mechanistic models for understanding and mitigating APB during production. Specifically, by preserving mass, momentum, and energy in the wellbore we developed two approaches involving semisteady-state and transient formulations for estimating APB. The intrinsic idea is to mimic the physical process with minimal input parameters to estimate pressure buildup in the annuli. Our model formulation handles the mechanisms of fluid expansion and fluid influx/efflux quite rigorously. This approach appears quite sufficient because we account for most of the cases of APB encountered.
Role of Conventional and Unconventional Hydrocarbons in the 21st Century: Comparison of Resources, Reserves, Recovery Factors and Technologies
Authors: Lakatos István , Szabó Julianna Lakatos 
Published: June 2009

Abstract
The paper deals with the availability of natural hydrocarbons until 2100. Starting point of the evaluation is that the global demand will not be met by production of conventional oil and gas. Basis of the discussion is the comparison of available resources and reserves, recovery factors and technologies. The analysis comprised oil shale, tar sand, gas shale, tight sand gas, coalbed methane and gas hydrates. Taking the data of competent organizations into account, obviously the global resources of unconventional oil and gas significantly exceed the availability of conventional natural hydrocarbons in spite of the fact that their recovery efficiency is extremely low.
Although the production cost (operation expenditure) of unconventional hydrocarbons is usually much higher than those of the conventional ones, industrial scale production of tar sand oil, tight sand gas and coalbed methane has started over two decades ago and their contribution to total oil and gas production is already substantial in several countries (US, Canada). The authors stated, however, that wider application of sophisticated technology to recover unconventional hydrocarbons needs more extensive and intensive R&D activity and further, new paradigms are necessary in education, research, production, field management, and governmental regulation.
Effect of Aquifer Heterogeneity on CO2 Sequestration
Authors: Oloruntobi O. S. , LaForce T. 
Published: June 2009

Abstract
This paper investigates experimentally the effect of heterogeneity on buoyancy-driven flow in CO2 storage. The application of this work is for the storage of CO2 in aquifers, where the degree of heterogeneity affects its trapping capacity. The experimental set up idealizes the post-injection period when the migration of CO2 plume in an aquifer is mainly due to the buoyancy drive that results from the density contrast between the injected CO2 and formation brine.
A column of air was trapped beneath a brine-saturated sand pack at room temperature and the whole arrangement was placed in an Amott cell. The Amott cell was filled with brine to account for background regional groundwater support. The amount of air beneath the sand pack and the cumulative air production were measured throughout the experiments to determine the sand pack air saturation.
As the air plume migrates up the sand pack, the buoyancy drive decreases. This causes some regions in the sand pack that once permitted the upward migration of the air plume to serve as capillary barriers to the trailing air bubbles. In all the studies, the uniformity of the air front depends on the degree of heterogeneity in the sand pack. However, air migration through a homogeneous sand pack provided a more uniform front than the heterogeneous sand pack. The presence of a high-permeability streak in the sand pack reduced the trapping capacity of the entire pack. The presence of a low-permeability layer in the sand pack increased its trapping capacity. Irrespective of the degree of heterogeneity, a substantial amount of air was trapped in and below the sand packs (about 40% of the initial air volume). The results also showed that better consolidated sands trapped more air than poorly consolidated sands. Pulsing flows (fluctuation of air saturation with time) occurred in some experiments after air breakthrough.
Establishing Water Injection Dynamics by Leading-Edge Coreflood Testing
Authors: Costier L. , van den Hoek P. J. , Davidson C. , Ding Mei , vanden Berg J. T. M. , Hofland R. A. 
Published: June 2009

Abstract
The increasing amounts of water being produced from oilfields, and the increasing need or necessity to return it to the reservoir it originated from, are posing a challenge to the industry. A fundamental question in Produced Water Reinjection (PWRI) is: "How clean is clean ?", or perhaps even more succinct: "How clean is fit for purpose ?" There is no universal correct answer to this question, as it depends on specific variables, largely intrinsic properties of a reservoir, its produced fluids and the contaminants that eventually end up in the produced water.
PWRI for reservoir management purposes must find the balance between injector plugging and the extent of induced fractures [1], for which duty the available simulation models have been found to be wanting as they do not adequately describe leak-off dynamics. Recognizing this constraint, Shell decided that there is a need for unambiguous empirical data that do not suffer from the limitations associated with commercially available coreflood services. A coreflood rig was designed and built, featuring an accurate, automated high injection pressure capability and a much extended test duration.
This test rig has since 2007 been field tested at two oilfields, main findings being: ✓Steady-state conditions can only be achieved in long term exposure windows✓Leak-off dynamics at high dP cannot be extrapolated from experiments at low dP✓Filtercake permeability depends on the permeability of the flooded core✓Membrane tests (Barkman-Davidson) fail to produce representative filtercake properties
Although the test rig performed satisfactorily, prospects for further development were identified, leading to a hardware upgrade and quality monitoring instrumentation that is expected to produce even better results in imminent field tests.
It is expected that the now gleaned information will provide much improved input for simulators modelling fractured injection.
An Innovative Tool on a Probabilistic Approach Related to the Well Construction Costs and Times Estimation
Authors: Merlo A. , D'Alesio P. , Loberg T. , Arild O. 
Published: June 2009

Abstract
When planning oil and gas wells, the cost and duration uncertainty, related to the well construction process, could be a big concern.
Traditionally, Drilling Engineers, in different geographical areas, have utilized different estimation methods with a consequent difficulty of communication. This tool could represent a common platform on the well construction cost and duration estimation.
In recent years probabilistic well cost estimates have become a requirement as part of the internal procedures of the E&P Companies, e.g. when applying for an Authorization for Expenditure (AFE) approval.
This paper describes the tool and methodology which have been developed upon request by Eni E&P to introduce and strengthen the application of probabilistic well construction cost and duration estimation within the drilling department. The tool offers decision support for well and operation planning and has the potential to make the cost and duration uncertainty analysis an integrated activity of the well planning process.
The software is characterized by a user friendly interface and is tailored to Drilling Engineers’ needs, to easily and effectively perform the probabilistic risk analysis and to systematize the corresponding workflow.
It also facilitates both internal and external communication, since it has the potential to be used as a standard tool.
In conclusion, the developed tool allows Drilling Engineers to: perform a quantitative risk analysis;calculate risked cost and duration;identify operations which mostly affect drilling uncertainties;evaluate and select alternative technical solutions;prepare prevention and mitigation plans for the reduction of both duration and cost.
Integrated Approach To Identify Fault Pattern And Fracture Corridors In A Matured Field
Authors: Thakur Ram Kumar , Wani Mohammad Rafiq , Chouhdary muhammad Akram , Rashidi Hussain , Al-Hajri Mubarak 
Published: June 2009

Abstract
The development of low reservoir pressure pockets and deteriorating reservoir properties in southern parts of the Ratawi Oolite reservoir has revealed the complex nature of fault and fracture network in Wafra field. These faults could not be observed directly on 3D seismic data due to the lack of perceptible change in seismic trace along stratigraphic boundary. This problem has been resolved with innovative fault/fracture characterization technique synthesizing seismic attributes, well information and reservoir behaviour.
The instantaneous phase attribute volume derived from reprocessed 3D seismic data highlighted the lateral impedance contrast to provide better resolution at discontinuities to detect even subtle change in dip and azimuth to identify fault traces along seismic sections. The alignment of fault pattern was mapped with variance cube, sum of amplitude and edge detection attributes along Ratawi Oolite Top seismic reflector.
The localized nature of the effect of injection wells to improve reservoir pressure in the Ratawi Oolite reservoir in the southern portion of the field has stressed upon the presence of fault compartments and fracture corridors in the vicinity of these drilled wells. The envisaged fracture corridors were mapped integrating seismic attributes such as coherency, attenuation time with interpretation of rose diagram, Formation Micro Image and core data. The heterogeneity in reservoir behaviour, complex nature of fault and associated fracture network was further confirmed by impedance slice at Ratawi Oolite level derived using post stack seismic inversion technique. The estimated depth map with fault and fracture corridors at the Top Ratawi Oolite reservoir, generated using interpreted seismic time, modelled stacking velocity provided a guide to plan development and delineation wells in this field.
This paper presents an integrated approach to identify alignment of fault and fracture corridors to plan for optimum location of injectors/development wells to optimize recovery in a matured field.