bluuebunny/crossref_metadata_2025 huggingface dataset:
Temperature Modeling and Analysis of Wells with Advanced Completion
Authors: Muradov K. M. , Davies D. R.
Published: June 2009

Advanced completions using technologies such as Inflow Control Devices or Interval Control Valves are successfully optimising oil and gas production. They are often accompanied by the installation of Distributed Temperature Sensors and Permanent Downhole Gauges, providing continuous, real-time monitoring of the downhole pressure and temperature. Interpretation of such data to locate influxes and to track zonal inflow performance is an important step towards a comprehensive well and field control strategy.

Interpretation of these downhole measurements requires accurate modelling of the well's pressure and temperature. Modelling of the pressures associated with the production of wells with advanced completion has been available for sometime. However, the workflow required for temperature modelling is not yet complete. This paper discusses using available theoretical models and software tools to model the temperature distribution in wells with advanced completion. The strengths and weaknesses of the various approaches for data interpretation will be discussed.

Several methods for the quantitative interpretation of downhole temperature measurements are proposed. The application of both currently available and novel theoretical models will be discussed. The workflow will be shown to be capable of providing both zonal flow rates and phase compositions.

The interpretation and analysis techniques presented here form the basis of a well and/or field monitoring and production control workflow.
Zonal Rate Allocation in Intelligent Wells
Authors: Muradov K. M. , Davies D. R.
Published: June 2009

Intelligent well system technology enables continuous downhole monitoring and zonal production control. Knowledge of zonal multiphase rates in real time gives the ability to flexibly respond to changes in the well and reservoir performance; leading to recovery optimization, etc. Frequently, only pressure and temperature data are measured downhole. Solution of the zonal flow rate calculation problem solely on the basis of these values is possible using mathematical optimization methods along with soft-sensing tools.

This paper presents a method of automatic zonal rate allocation for intelligent wells based on measured downhole pressure and temperature data. A group of mathematical optimization algorithms is used for the rate allocation at a particular time. The inverse problem is solved by matching the calculated, downhole pressure and temperature values with those measured (possibly with limited accuracy) at certain positions.

A further step illustrates the application of soft-sensing methods to data measured in real-time. The potential for system parameter calibration and influx detection will be discussed. The resulting, zonal flow rate allocation techniques are tested on synthetic and real data, which illustrates their use as the basis of a comprehensive workflow for the control of intelligent wells and fields.
Well Test Analysis in Tight Gas Reservoirs
Authors: Borges Jose Umberto A. , Jamiolahmady Mahmoud
Published: June 2009

The increasing global energy demand, rising energy prices and declining conventional gas reserves all call for increasing exploitation of gas reserves from unconventional sources, most notably gas trapped in tight formations. This study describes an investigation of some of the key issues related to well test interpretation in tight gas condensate formations, which are often overlooked or ignored.

A single-well radial model was constructed with measured rock and fluid properties using ECLIPSE300. This compositional simulator was used to generate synthetic pressure transient data which were subsequently interpreted in PanSystem welltesting package. The impact of test duration (drawdown, buildup), phases present (gas, condensate), type of fluid system (lean, rich) and reservoir heterogeneity (homogeneous, layered) were investigated. The results indicate that in the absence of wellbore storage effects, a short drawdown period ensures that a short buildup is sufficient to compute reservoir parameters from radial flow regime. For long drawdown periods, the subsequent buildup period can take months to reach infinite-acting radial flow. The time needed to dissipate layering effects (such as a high-perm streak) is frequently excessively long in tight reservoirs.

Also, a number of simulations with and without rate-dependent relative permeability curves were performed to investigate the positive impact of velocity (coupling effect) on two-phase skin due to condensate banking. The results reveal that the conventional two-phase pseudo-pressure function results in more difficult interpretations for obtaining reservoir parameters and is also unable to capture the positive coupling, which is more pronounced than negative inertia especially for richer fluid systems. Finally, the application of the probe radius concept yielded remarkably accurate reservoir pressure profiles versus distance as compared to those obtained by compositional simulations. This data could be used to calculate reasonably accurate rate-dependent relative permeability curves, thus improving long-term well deliverability predictions.
Modeling Mud-Filtrate Invasion Effects on Resistivity Logs to Estimate Permeability of Vuggy and Fractured Carbonate Formations
Authors: Miranda Luis Javier , Torres-Verdín Carlos , Lucia Jerry
Published: June 2009

We develop and validate a new method to diagnose and estimate secondary porosity and absolute permeability of fractured and vuggy carbonate formations based on the numerical simulation of the process of mud-filtrate invasion. The method includes the geological characterization of core laboratory data and their integration with well logs and fluid production measurements. We apply the new method to the interpretation of data acquired in a carbonate reservoir in the Barinas-Apure Basin in southwest Venezuela. The latter reservoir behaves as a triple-porosity petrophysical system which exhibits inter-crystalline, intra-crystalline, moldic, vuggy (connected and non-connected) and fractured porosity, all embedded in a tight matrix. Rock-core data and wellbore resistivity images indicate that vugs are the mayor component of secondary porosity while fractures and interconnected vugs account for most of the permeability.

The initial phase of our interpretation method consists of integrating core measurements with conventional and non-conventional well logs to calculate static and dynamic petrophysical properties via standard carbonate evaluation procedures. Starting with the calculated petrophysical properties, we simulate the process of invasion with both water- and oil-base muds. Resulting spatial distributions of water saturation and salt concentration in the near-borehole region give rise to spatial distributions of electrical resistivity which are used to numerically simulate laterolog and induction apparent resistivity logs. If the input values of porosity and permeability are not correct, the simulation of mud-filtrate invasion will result in a poor match of resistivity logs. In such cases, we update porosity and permeability until securing a good match between measurements and simulations. This procedure was tested on several key wells with and without core measurements, wellbore resistivity images, and well-testing measurements. We conclusively find that our final estimates of porosity and permeability are in good agreement with the properties of the global petrophysical system. Differences between porosity and permeability before and after simulation of the process of invasion are reliable indicators of presence and influence of vugs and/or fractures in the displacement of hydrocarbons by mud filtrate.
Innovative Data-Driven Permeability Prediction in a Heterogeneous Reservoir
Authors: Al-anazi Ammal , Gates Ian , Azaiez Jalel
Published: June 2009

In complex reservoirs where heterogeneity of properties and errors associated with sampling yield uncertain measurements of geological properties, e.g. porosity and permeability, conventional techniques such as empirical and nonlinear regression methods attempt to estimate values of these properties with low or no error. Conversely, artificial intelligence asserts that the error contains useful information that complements conventional techniques. For example, fuzzy logic methods to predict permeability at uncored wells provide uncertainty measures based on secondary variables such gamma ray, neutron porosity, sonic porosity, bulk density, formation resistivity, and core-based permeability. Fuzzy logic provides tools for uncertainty modeling and improved permeability estimation.

Here, a two-stage fuzzy ranking algorithm is integrated in the fuzzy predictive model to improve generalization capability and transparency of the model through selecting inputs best suited to predict permeability. Fuzzy curve and surface analysis is used to rapidly and automatically identify information-rich well logs and filter out data dependencies. Subtractive clustering algorithm generates membership functions and isolates clusters of data. The Takagi-Sugeno-Kang fuzzy rule-based system (TSK) is constructed from a subset of logs and core measurements. The antecedent fuzzy sets are obtained by projecting the mean and variance onto input data axes. The consequent functions consist of a set of linear equations. To tune antecedent and consequent membership function parameters, an Adaptive Network based fuzzy inference systems (ANFIS) is used.

The proposed methodology is initially validates using the standard Box & Jenkins’ gas furnace data to predict C02 concentration and compared to a multilinear regression technique. Generalization capability has increased through using the most significant inputs during modeling gas furnace data. The methodology was also demonstrated by predicting permeability from well log data of a heterogeneous sandstone reservoir located in the Middle East. The fuzzy model was compared to conventional linear and multilinear regression models to show its applicability and superiority in heterogeneous systems. Unlike conventional methods, the proposed fuzzy technique does not require any prior knowledge of the reservoir and relationships between permeability and input variables. In addition, the technique accounts for uncertainty that exists in log data. The result is an efficient interpretation expert system that can be continuously conditioned as new data becomes available.
Enhanced Mass Transfer of CO2 into Water: Experiment and Modeling
Authors: Farajzadeh Rouhollah , Zitha Pacelli L. J. , Bruining Hans
Published: June 2009

Global warming has increased interest in quantification of the dissolution of CO2 in (sub)-surface water. CO2 is present above the surface water. Dissolution of CO2 into water (or oil) causes a density increase, with respect to pure water (or oil). This density effect causes natural convection, which enhances the mass transfer rate across the interface. This article describes a series of experiments performed in a cylindrical PVT-cell at a pressure range of pi=10-50 bar, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The results show that the mass transfer rate across the interface is much faster than predicted by Fickian diffusion. This mass transfer rate increases with increasing initial gas pressure and in the long term it is controlled by diffusion.

A theoretical interpretation of the observed effects has been proposed, based on diffusion and natural convection phenomena. The CO2 concentration at the interface is estimated from the gas pressure using Henry's solubility law, in which the coefficient varies with both pressure and temperature. Good agreement between the experiments and the theoretical results has been obtained.
Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Fluid System Executed From a Supply Vessel; Lebada Vest Field, Black Sea Offshore Romania
Authors: Bukovac Tomislav , Belhaouas Rafik , Perez Daniel , Dragomir Alexandru , Ghita Viorel , Webel Carlos
Published: June 2009

Offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. This results in a significant impact on operational efficiency by lowering costs and ultimately increasing hydrocarbon production.

To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single operation, adding additional savings to the process and improving efficiency.

Interpreted openhole images and advanced sonic logs were used to determine the optimum completion configuration and to select favorable fracture initiation points and treatment designs.

Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks.

To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously.

This novel multistage fracturing system was introduced in Europe for the first time. Results indicate a sustained increased production. Because of this success, additional wells are scheduled to be stimulated using same approach in the following months.
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

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

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

One 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

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

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

Increased 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

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

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

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

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

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.
Rock Strength from Core and Logs, Where We Stand and Ways to Go
Authors: Khaksar A. , Taylor P. G. , Fang Z. , Kayes T. , Salazar A. , Rahman K.
Published: June 2009

Knowledge of accurate rock strength is essential for in situ stress estimation, wellbore stability analysis, sand production prediction and other geomechanical applications. Reliable quantitative data on rock strength can only be obtained from cores. However, cores are limited, discontinuous and often biased. Consequently, rock strength evaluation is primarily based on log strength indicators, calibrated where possible against limited core measured values. There are a number of published log-core strength correlations that can be used for rock strength modelling. These empirical relationships are developed for specific rock type, age, depth range and field. Their general applications, therefore, need to be critically assessed on a case by case basis. This paper briefly: (i) outlines the best practice for obtaining quality rock strength data from core tests; (ii) presents common empirical rock strength equations for sedimentary rocks and (iii) discusses ways of improving rock strength estimates.

While some equations such as porosity-based or sonic log-based rock strength models work reasonably well, rock strength variations within individual rock properties show considerable scatter, indicating that most of the empirical models are not sufficiently generic to fit all rocks in the database. Like any other physical rock properties, the variation in rock strength in a given sedimentary rock is controlled by mineralogy, sedimentology and micro-structure of the rock and simple log-derived rock strength models need further modification and classification incorporating these geological characteristics.

This paper has shown that when sufficient core rock strength data exists, applications of computing techniques, such as fuzzy logic and cluster pattern recognition, coupled with sedimentary facies analysis and diagenetic classification can improve strength estimation. Semi-continuous impact energy logs using portable non-destructive testing tools can be correlated with petrophysical logs to generate mechanical facies and improved sampling for conventional rock testing.
Partial Movement of Asphaltene in Presence of Connate Water in Vapex Process
Authors: Ardali M. , Kharrat R. , Rostami B. , Derakhshanfar M.
Published: June 2009

Vapor extraction (VAPEX) process is solvent analogue of SAGD process in which low molecular weight solvent are used to reduce the viscosity of heavy oil and bitumen. This process may be a good candidate to be applied in problematic reservoirs in which thermal methods are not efficient due to severe heat losses.

Asphaltene precipitation as a result of compositional alteration of solvent/bitumen has substantial effects on performance of VAPEX. In this process if operating pressure is very close to dew point pressure, asphaltene precipitation occurs. In-situ deasphalting of heavy oil and bitumen reduces the viscosity of the produced oil and creates the oil that is more easily refined, but the main concern is whether this advantage can outweigh reduced permeability and plugging of formation caused by adsorption and precipitation of asphaltenes.

In current work experiments have been conducted in low permeability sandpacks in both dry and non-dry systems to assess the performance of Vapex process when asphaltene precipitation occurs. Experiments are carried out in a 2D visual cell using highly asphaltenic heavy oil from one of Iranian reservoirs (Kuh-e-Mond) and propane as a solvent.

The results show that performance of Vapex process increases when asphaltene precipitation occurs provided that optimal pressure has been designed to prevent extensive asphaltene deposition and subsequent plugging of porous media. It has been observed that adsorption of asphaltenes has considerably decreased in non-dry systems. Movement of precipitated asphaltene and less adsorption in non-dry experiments results in a more stable and efficient Vapex process while in dry experiments higher adsorption of asphaltenes resulted in plugging of low permeability porous medium.
Increased Rates, Reserves, and Revenues From Heavy Oil Reservoir Using ESP Technology: A Suriname Case Study
Authors: Anthony E. , Grauwde G. , Domangue Michael
Published: June 2009

Wells producing heavy oil (16° API), completed in shallow, high permeability, low-dipping, and very unconsolidated reservoirs experienced very early water breakthrough, short-circuiting significant reserve potential. Wells were completed as vertical open-hole gravel packs and produced ‘water-free’ at rates 150 – 300 bopd for a few months, then plummeted to 25 – 50 bopd when water broke through. Progressing Cavity Pumps were the primary Artificial Lift method used in 5.5" casing completions. In an attempt to restore some of the lost oil production after water breakthrough, efforts to reduce the flowing BHP were made by using high-volume PC pumps. Fluid withdrawal rates were increased from ±350 bpd to ±700 bpd with no significant change in fluid level (FBHP), watercut, or oil production. The Electrical Submersible Pump (ESP) was then used to reduce the FBHP sufficiently to stimulate increased oil production to the wellbore. Fluid withdrawal rates were taken to ±2200 bpd which achieved approximately 100 psi(25%) reduction in FBHP.

Sustained oil production increases between 100% and 400% were realized. Watercuts increased by no more than 3%. Dynamic fluid levels in surrounding wells showed a temporary reduction, but increased and stabilized at original levels after 2-3 months, indicating a very active edge-water drive mechanism. Infill wells with 7" production casings are planned to accommodate larger volume ESP's. No sand production has been observed to date indicating no deterioration of the gravel pack at these elevated extraction rates. At prevailing oil prices, project investments were recovered within 4 months.

Under the conditions of low GOR, low dipping, high permeability, edge-water drive, heavy oil reservoirs, increased fluid extraction rates can result in significant increase in oil production rates and producible reserves, even though wells may have experienced early water breakthroughs.
Well Production Forecasting by Extrapolation of the Deconvolution of Well Test Pressure Transients
Authors: Whittle Tim , Hui Jiang , Young Stuart , Gringarten Alain
Published: June 2009

The deconvolution of well test pressure transient data provides a constant rate pressure response that applies for the duration of the test. By extrapolating this response in time, the future performance of a well can be predicted.

The extrapolation can include constraints defined by estimates of the volume of reservoir connected to the well but otherwise, relies only on information that is normally available at the time of testing. Uncertainty in either the deconvolution or the connected volume will result in a variety of extrapolations that defines the range of expected well performance. The advantage of this procedure is that a well's future production profile can be estimated very quickly and easily. Such a scoping exercise helps to understand a well's potential and to define the expected range of outcomes from more detailed modelling. Furthermore, it can be an efficient method for screening prospects when time and resources are limited.

By monitoring the actual well performance against its prediction, underperforming wells can be identified for work-over. If permanent downhole pressure gauge data are available, the deconvolution can be continuously updated thus improving the production forecast.

Where a production well is planned that is of a different type to the tested well (e.g. a horizontal or hydraulically fractured well instead of a normal vertical well), a technique is described to modify the tested well's deconvolved response to account for the change in well type whilst preserving the pressure transient response due to the reservoir and its boundaries.

Two field examples of gas well tests are presented which demonstrate the method and the predicted production profiles are compared with observed data.
Hydrate Problem in the Oil Production Industry
Authors: Buzatoiu B. , Popp V. V. , Loas I. R.
Published: June 2009

The paper briefly presents some important aspects related to natural gas hydrates.

Some theoretical aspects in connection with the thermodynamic and kinetic mechanisms of hydrates formation are reviewed, following which the methods for controlling their generation during drilling, gas production, transportation and processing are mentioned.

At the end of the paper the possibilities for hydrate utilization in connection with natural gas storage are being considered.
Water withdrawal for brackish and inland aquaculture, and options to produce more fish in ponds with present water use
Authors: Verdegem M. C. J. , Bosma R. H.
Published: June 2009

This paper reviews freshwater use in inland and coastal pond aquaculture, and focuses on options to increase productivity while reducing water use. Total freshwater use depends on system-associated and feed-associated water losses. System-associated water losses depend on total area, evaporation, infiltration and water replacement. About 8,750,000 ha freshwater and 2,333,000 ha brackish water ponds are in use today. Total water withdrawal in freshwater aquaculture is estimated at 16.9 m3/kg production, representing 429 km3/yr, which is 3.6% of flowing water globally. Infiltration and replacement water recharges aquifers; if these losses are clean, their re-use decreases aquaculture-related water withdrawal by nearly 60%. A further reduction in freshwater use in aquaculture can come from intensification and aquafeed development. The goal should be to feed the pond, not the fish. A tripling of average pond production should be possible, without increasing total freshwater use. Such improvements will also benefit brackish water aquaculture, which could in turn further reduce freshwater use by increasing the productivity of saline systems.
Seed Rate Effects on Rainfed and Irrigated Safflower Yield in Eastern Mediterranean
Authors: Yau S.K.
Published: June 2009

Effects of seed rates on grain, straw and oil yield of safflower (Carthamus tinctorius L.) were studied for two
years in the semi-arid central Bekaa Valley of Lebanon. Three trials, two under rainfed and one under supplementary
irrigations, were conducted using seed rates of 6, 12, 24 and 48 kg ha-1 corresponding to intra-row spacing of 20, 10, 5,
and 2.5 cm, respectively. There was significant seed-rate by trial interaction on grain, straw and oil yield. In general,
significant seed rate effects did not exist in the rainfed trials in 2004 and 2005, confirming that safflower has the capacity
to compensate for planting density. In the irrigated trial in 2005, the 24 and 48 kg ha-1 seed rates gave higher grain, straw
and oil yields than the lower seed rates. Averaged over trials, the 24 kg ha-1 seed rate gave the highest yields. Even if
supplementary irrigation is not available, the large variation in annual rainfall in semi-arid areas warrants the use of 24 kg
ha-1 seed rate as it will benefit in years with above-average rainfall.
Barriers to and Facilitators of Inclusion for Children with Disabilities in Early Childhood Education
Authors: Purdue Kerry
Published: June 2009

In the New Zealand education system, as in other countries, legislation and early childhood policy has been developed to support equity, social justice and democratic participation for children with disabilities and their families. However, despite this non-discriminatory and inclusive policy and legislative environment, some children with disabilities and their families experience exclusionary and discriminatory early childhood settings and struggle to access quality education. In this article, the author examines some of the barriers to and facilitators of inclusion for children with disabilities and their families in early childhood education. The author also suggests some changes in cultures, policies and practices that may help create early childhood settings that would see all children included.