bluuebunny/crossref_metadata_2025 huggingface dataset:
New Estimate for the Radius of a Condensate Bank from Well Test Data Using Dry Gas Pseudo-Pressure
Authors: Bozorgzadeh Manijeh , Gringarten Alain C.
Published: December 2007

Published well test analyses in gas-condensate reservoirs where the pressure drops below the dew point are usually based on a two-or three-zone radial composite well test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas condensate specific results from well test analysis are the mobility ratios between the various regions and the condensate bank radius. Unfortunately, for a given region, well test analysis cannot un-couple the storativity ratio from the region radius. The storativity ratio must therefore be estimated separately to obtain the bank radius.

In this study, a new method is introduced to estimate the storativity ratios between the different zones as a function of the saturation profile during the test. The paper describes an application of the method to the analysis of a transient pressure test in a gas condensate field in the North Sea. The analysis uses single-phase pseudo-pressures and two- and three-zone radial composite well test interpretation models and yields the condensate bank radius.

The calculated condensate bank radius is verified by comparing analytical well test analysis results with results from compositional simulations that include capillary number and inertia effects. It is shown that the proposed relationship between the condensate saturation profile at the time of shut-in and that at the end of shut-in yield a consistent interpretation of build-up data.
Impact of Relative Permeability Hysteresis on the Numerical Simulation of WAG Injection
Authors: Spiteri Elizabeth J. , Juanes Ruben
Published: December 2007

Pore-scale physics, laboratory investigations, and field experience, dictate that three-phase relative permeabilities exhibit strong dependence on the saturation path and the saturation history. Such dependence is especially relevant in water-alternating-gas (WAG) processes, which are characterized by a sequence of three-phase drainage and imbibition cycles. In this paper, we study the influence of relative permeability hysteresis on the field-scale predictions of WAG injection.

Because their measurement is difficult and timeconsuming, three-phase relative permeabilities are usually interpolated from two-phase data. The errors associated with this procedure have been investigated by Oak (SPE 20183), who reported that interpolated values may differ significantly from experimental ones. The effect of using different interpolation models in field-scale simulations has been illustrated by a number of authors, who found that recovery predictions could be significantly different depending on the three-phase relative permeability model.

Here, we study the impact of using history-dependent saturation functions in reservoir simulations. First, we investigate the degree of accuracy with which different hysteretic models reproduce Oak's three-phase relative permeability data. In doing so, we assess the validity of existing models, and we identify the model parameters subject to most uncertainty. Second, we illustrate how the use of a hysteretic relative permeability model affects reservoir simulations. We use a synthetic model of a quarter five-spot pattern in a homogenous reservoir, and a more realistic heterogeneous reservoir modified from the PUNQ-S3 model. We find that there is striking disparity in the simulation results depending on whether a hysteretic or a nonhysteretic model is employed, and conclude that it is essential to incorporate hysteresis in the relative permeabilities in order to obtain accurate predictions of realistic WAG processes.
Assessment of Global Uncertainty for Early Appraisal of Hydrocarbon Fields
Authors: Caumon G. , Strebelle S. , Caers J. K. , Journel A. G.
Published: December 2007

We propose a workflow to assess the uncertainty about a global reservoir parameter such as net-to-gross during early exploration. As opposed to traditional statistical approaches that assume data independence and cannot easily account for either seismic data or geological interpretation, this model, based on multiple point statistics, integrates the main components of uncertainty, namely: the choice of a geological scenario, probably the most important factor at the appraisal stage.The location of wells, which could have been drilled elsewhere, giving a different picture of the reservoir.The calibration of the seismic to the well data.

This global uncertainty model is demonstrated on a large 3D fluvial reservoir.
Top-Down Reservoir Modelling
Authors: Williams G. J. J. , Mansfield M. , MacDonald D. G. , Bush M. D
Published: December 2007

Over the last twenty or more years of reservoir performance prediction through simulation there have been only two fundamental changes. First was the evolutionary increase in computing speed that has allowed larger, more detailed reservoir models to be built. Second was the revolutionary change in approach that involved the entire subsurface community in building integrated reservoir descriptions. The next big change may in time prove to be BP's Top-Down Reservoir Modelling (TDRM). This is a new pragmatic approach to fully incorporate reservoir uncertainty in model construction and performance prediction.

TDRM is proprietary technology that has been developed in BP through extensive R&D, and consists of a philosophy and tools that enable a faster and more robust exploration of uncertainty than has hitherto been possible. The philosophy is to start investigations with the simplest possible model and simulator appropriate to the business decision. Detail is added later as required. The approach overcomes the problems of the conventional "bottom-up" process, which uses detailed models that are too slow and cumbersome to fully explore uncertainty and identify critical issues. Highly detailed models cannot overcome an underlying absence of information, and can have the negative effect of creating a false sense of understanding.

The TDRM tools have been designed to minimise manual iterations by creating a semi automated, flexible workflow for case management, assisted history matching, depletion planning optimisation and post-analysis. TDRM has been successfully applied to eighteen oil and gas reservoirs that range from development appraisal stage to mature fields, and has resulted in up to 20% increase in estimated net present value for the projects.
Special Non Polluting Emulsifier for Non Aqueous Drilling Fluids in Deep Offshore Drilling
Authors: Audibert A. , Dalmazzone C. , Dalmazzone D. , Dewattines C.
Published: December 2007

With the increasing number of deep offshore drilling operations and severe environmental constraints, operators and service companies are confronted to more and more complex technical challenges. Extreme conditions encountered at these water depths require an adaptation of the drilling mud composition and properties. In particular, range of temperature and pressure (close to 0 °C and up to 400 bar) are favorable conditions to the formation of gas hydrate solid structures that are liable to plug kill and choke lines as well as the annular, and may also cause interruption of the drilling operations and even destruction of the rig equipment. Oil based muds generally formulated as invert emulsions are difficult to stabilize over a large range of pressure and temperature conditions and specially at low temperature and high pressure where the appearance of hydrate compounds may induce a destabilization of the emulsion and loss of well control (cuttings transport, mud losses ….).

This paper presents credible laboratory data demonstrating the benefits of a special non polluting surfactant system engineered to stabilize brine droplets in an oil phase and to act as an efficient barrier to avoid droplets coalescence, even during hydrate formation. By using Differential Scanning Calorimetry technique without any dilution of the fluid, we show that emulsion droplet size is unaffected by ageing over a large range of temperatures; an adequate choice of oil plus the surfactant system permits to limit the amount of hydrate formed. Furthermore, the use of this specific emulsifying system allows to avoid agglomeration of droplets in the fluid as well as the breakage of emulsions after hydrate dissociation.
Optimizing Horizontal Completion Techniques in the Barnett Shale Using Microseismic Fracture Mapping
Authors: Fisher M. K. , Heinze J. R. , Harris C. D. , Davidson B. M , Wright C. A. , Dunn K. P.
Published: December 2007

The Barnett Shale of North Texas is an ultra low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. As a result, techniques to optimize hydraulic fracturing effectiveness have evolved over the past decade. The first Barnett Shale "discovery" well, the C.W. Slay #1, was drilled in 1981 and it was almost 17 years before any significant commercial success was found in the Barnett, so the Barnett is a relatively new play. In fact, 75% of the producing wells in the Barnett have been drilled since 2000. In 1995, when the USGS was performing a gas in place assessment of the significant gas fields in the United States, the Barnett was not even evaluated. In 2002, according to the Energy Information Administration, the Newark East Field produced 202 Bcf, more than any other field in Texas, and was the 7th largest gas producer in the United States!

In some areas of the Barnett, horizontal drilling has recently been applied in an attempt to optimize gas production. Issues such as nearby water bearing intervals, inadequate surface locations, improved gas production rates and cost per scf can, in some cases, be addressed by the use of horizontal wellbores. The goal is to maximize fracture network surface area in the targeted pay intervals, and in some areas, reduce the probability of excessive fracture height growth.

Several horizontal completion techniques have recently been utilized, including single and multiple stage treatments with multiple perforation clusters in uncemented casing and multiple stage treatments performed in cemented perforated casing. In order to understand created fracture geometry for various completion designs, fracture treatments are often mapped with microseismic and tilt sensors.

Production results from this pilot study of the first twenty-three horizontal wells in the same general "Core" area of the Fort Worth Basin are compared in addition to mapped fracture geometry from eleven of these with vertical wellbores. This paper will discuss drilling and completion strategies, look at fracture network areas obtained from each, and then compare and contrast the fracture effectiveness with the standard procedures used in vertical Barnett wells.
Use of Viscoelastic Surfactant-Based Diverting Agents for Acid Stimulation: Case Histories in GOM
Authors: Zeiler Chuck , Alleman David , Qu Qi
Published: December 2007

Viscoelastic surfactant (VES) based diverting fluid has been successfully used in matrix acidizing in the Gulf of Mexico in recent years. Some cases are acid stimulation to remove near wellbore formation damage, or to cleanup perforation channels prior to gravel or frac packing, while other cases are acidizing to remedy fines migration or inorganic scaling damage on previously frac/gravel packed completions. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac/gravel packed wells, since damage to the near wellbore area and completion needs to be minimized for optimum production. Lab studies and field applications have demonstrated the non-damaging properties of a VES fluid.

This paper presents several case histories of VES diverting applications in the GOM, including acidizing prior to frac/gravel packing, and remedial treatment of a frac packed completions. The bottom hole static temperature of these cases range from 140° F to 290° F for gas and oil wells. Because of an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped for the entire acid treatment, and successful diversion was observed for each stage. The paper will detail the general fluid properties as well as fluid properties tailored to specific well conditions and formation characteristics. Details and pressure response of the treatments will be discussed.
Role of Dispersion in Injectivity Impairment: Mathematical and Laboratory Study
Authors: Altoé F. J. E. , Bedrikovetsky P. , Siqueira A. G. , Souza A. L. , Shecaira F. S.
Published: December 2007

Severe injectivity decline during the injection of sea/produced water is a serious problem in offshore waterfloodings. The permeability impairment occurs due to capture of particles from injected water by the rock. The reliable modelling-based prediction of this decline is important for the injected-water-treatment design, for injected water management (injection of sea- or produced water, their combinations, water filtering etc.).

Particle transport in porous media is determined by advective flow of carrier water and by hydrodynamic dispersion in micro-heterogeneous media. Thus, the particle flux is the sum of advective and dispersive fluxes. Transport of particles in porous media is described by an advection-diffusion equation and by a kinetic equation of particle capture. Conventional models for deep bed filtration take into account hydrodynamic particle dispersion in the mass balance equation but do not consider the effect of dispersive flux on retention kinetics.

In the present study, a model for deep bed filtration taking into account particle hydrodynamic dispersion in both the mass balance and retention kinetics equations is proposed. Analytical solutions are obtained for flows in infinite and semi-infinite reservoirs and in finite porous columns. The physical interpretation for the steady-state flows described by the proposed and the traditional models favours the former.

Comparative matching of experimental data on particle transport in porous columns by the two models is performed for two sets of laboratory data.
Effect of Stress Concentration Factors due to Corrosion on Production Tubing Design
Authors: Sun Kai , Samuel Robello , Guo Boyun
Published: December 2007

With the increase in operating costs, as well as the need to withstand the cyclic swing of the oil prices, there is a growing demand for cost effective production operations. Challenges associated with extreme depth, pressures and temperatures, where corrosion is a problem, translate to additional problems due to tubing burst, collapse and tension. Tubings subjected to corrosion suffer strength deterioration. This becomes even more detrimental when coupled with cyclic loading. Failure of tubings could lead to disastrous consequences and the loss of well. If tubings were not designed with consideration of corrosion effects, it may result in well control operations also. This paper studies the effects of corrosion and examines the alterations proposed to the conventional tubing design. The objective is to adapt to the new criterion for deep water and ultra deep high-temperature high-pressure production wells. Stress concentration caused by corrosion cavity plays a key factor in the tubing design under a corrosive environment. The failure analysis of the model is based on the pitting corrosion. A method and revised criteria have been proposed to predict the threshold pressure for a derated tubing strength. Approximated analytical formulae have been developed for semi-spherical cavities, shallow surface cavities and deep spherical cavities. The effects of stress concentration factor on tubing strength are analyzed. Solutions are presented in the form of plots that can easily be used by the production engineers. In the paper, quantification of the method is analyzed with a practical tubing design example.
Analisis of Oil-Water Flow Tests in Horizontal, Hilly-Terrain, and Vertical Pipes
Authors: Abduvayt P. , Manabe R. , Watanabe T. , Arihara N.
Published: December 2007

The flow pattern, pressure drop and water holdup were measured for oil-water flow in horizontal, hilly-terrain (± 0.5° and ± 3°) and vertical pipelines at a temperature of about 35 ± 5 °C and a pressure of about 245 kPa using the large-scale multiphase flow-test facility of Japan Oil, Gas and Metals National Corporation (JOGMEC). Test lines of 4.19 inch (106.4 mm) ID and 120 m total length were utilized which included a 40 m horizontal or hilly-terrain and a 10 m vertical test sections sequentially connected. The flow pattern was determined by visual observation with video recordings, and a flow pattern map was made for each condition.

New flow patterns were identified for horizontal and hilly-terrain flow, such as oil flow in a snake-like shape at top of pipe at high rate of water flow, and water flow at bottom of pipe at high rate of oil flow.

New holdup and pressure drop data are presented for each flow condition. The flow rate and inclination angle influences holdup and pressure drop behaviors. In vertical flow, when the oil superficial velocity exceeds a certain value, the pressure drop decreases exponentially as the superficial oil velocity increases.

Slippage between the phases was analyzed using the measured water holdup plotted against the input water cut with inlet oil flow rate as parameters. It was found that the slippage changed significant with slightly changes in inclination angle.

This paper provides new experimental data of flow pattern, water holdup and pressure drop measured particularly at horizontal, hilly-terrain and vertical conditions with large-diameter pipes. These are the indispensable information of developing reliable prediction models for oil-water two-phase and gas-oil-water three-phase flow in pipelines.
The Stress Response of Permeability
Authors: Worthington Paul F.
Published: December 2007

The response of intergranular permeability to applied hydrostatic stress is quantified through third-order polynomial fits to data from three loosely-to-moderately consolidated sandstone reservoirs from the same geological province. The derivatives of the fitted polynomials allow diverse permeability vs. stress behaviors to be identified and grouped. This grouping is quantified using composite stress-response parameters based on the polynomial regression coefficients, most notably their root mean square. This composite parameter shows a sufficiently good correspondence to Leverett's equivalent circular pore diameter Lp to define exclusive "stress facies" in terms of ranges of Lp in these formations. A permeability reduction factor from ambient conditions to effective reservoir stress is determined for each stress facies as a basis for correcting conventional core measurements. Although the results are formation- and stress-facies-specific, the approach has a general validity and can be adopted for any appropriate permeability vs. stress function. Principal benefits include better reservoir characterization and a sharper description of the change in permeability with stress as a basis for improved simulation models for development planning.
Partial Probabilistic Addition: A Practical Approach for Aggregating Gas Resources
Authors: Delfiner Pierre , Barrier Robert
Published: December 2007

The portfolio of gas sources to supply an LNG project may involve many diverse fields, each with its range of uncertainty and degree of maturity. For project sanction it is necessary to aggregate the reserves/resources of all these fields into project-level representative numbers such as 1P/2P/3P or P90/P50/P10.

Arithmetic addition of all low estimates (1P or P90) and all high estimates (3P or P10) is known to overstate the range of uncertainty. On the other hand, independent probabilistic addition tends to produce unrealistically narrow ranges. The correct answer would be obtained by using correlated addition, but this requires the estimation of all correlations between field resource estimates.

This paper presents a simplified and pragmatic approach, partial probabilistic addition. A hierarchy of "resource containers" is defined from individual reservoirs to total project level, and resources are aggregated from bottom up using either arithmetic or probabilistic addition, whichever is more appropriate. This amounts to setting weak correlations to 0 and strong correlations to 1. Expert opinion is solicited only about the strength of dependencies, rather than being asked to specify elusive correlation coefficients.

The validity of the approach is investigated by applying partial probabilistic addition to a synthetic portfolio of fields with the same lognormal size distribution. The study indicates the feasibility of estimating a global P90 with a controlled error, whereas for a P10 the error can become quite large. The method is then discussed using a real LNG case study.

Partial probabilistic addition is a practical method. It is easy to understand and to explain. It can be summarized in a single table where a color code indicates for each cell how its value was calculated. These features facilitate technical interchange and QC, which are key to reducing as much as possible the degree of arbitrariness inherent in the modeling of dependencies.
Mapping Reservoir Fabric, Pressure Compartments and Natural Fracture Patterns Using Azimuthal Seismic Velocity
Authors: Parney Robert , Jenner Edward , Williams Marty
Published: December 2007

Recently new techniques have been developed for the purpose of solving a seismic image problem that is in part caused by fractures. Maps of velocity anisotropy can be used to predict the distribution of fracture intensity. Discrete Fracture Network (DFN) Models can be built on those maps of fracture intensity and then analyzed for engineering parameters. DFN model is constructed based on fracture intensities from a geologic analogue. Predictions based on only the fracture intensity, adding the geologic analogue, and adding an engineering analogue show that the interpretation of fracture intensity from seismic anisotropy will be improved by following geologic and engineering analogues.
Assessment of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs and Radial Profiling of Formation Elastic Parameters
Authors: Chi Shihong , Torres-Verdin Carlos , Wu Jianghui , Alpak Faruk O.
Published: December 2007

Despite continued improvements in acoustic logging technology, logs processed with industry standard methods often remain influenced by formation damage and mud-filtrate invasion. Proper quantitative understanding of the process of mud-filtrate invasion is necessary to identify and assess biases in the standard estimates of in-situ compressional- and shear-wave velocities. We describe a systematic approach to quantify the effects of mud-filtrate invasion on borehole acoustic logs and introduce a novel algorithm to estimate radial distributions of elastic parameters away from the borehole wall. Radial saturation distributions of mud filtrate and connate formation fluids are obtained by simulating the process of mud-filtrate invasion. Subsequently, radial profiles of the elastic properties are calculated using the Biot-Gassmann fluid substitution model. Array waveforms are simulated using the calculated radial profiles of formation elastic parameters as input. Estimated compressional- and shear-wave velocities for homogeneous, stepwise, and multilayered formation model are compared to quantify mud-filtrate invasion.

A nonlinear Gauss-Newton inversion algorithm is used to estimate radial profiles of format1on elastic parameters in the presence of invaded zones using normalized spectral ratios of array waveform data. Inversion examples using synthetic and field data indicate that physically consistent profiles of formation elastic parameters can be reconstructed from array waveform data. In turn, radial profiles of formation elastic parameters can be used to construct more realistic near-wellbore petrophysical models for applications in reservoir simulation and production.
Optimum FractureTreatment Design Minimizes the Impact of Non-Darcy Flow Effects
Authors: Lopez-Hernandez Henry D. , Valko Peter P. , Pham Tai T.
Published: December 2007

Hydraulic fracturing is today the completion of choice in most of tight gas producing fields all over the world. Ultimate performance of fractured wells is severely diminished by the effects of non-Darcy flow inside the fracture. A design methodology based on the effective Proppant Number is presented in this paper.

Non-Darcy flow is described by the β factor method. Evaluation and selection of appropriate β factor correlation is a key step in this approach. Effective fracture permeability and corresponding optimum geometry is calculated through an iterative process.

The proposed methodology was implemented in the design of 11 fractures treatments of 3 tight gas wells in South Texas. Results show that optimal fracture design might increase expected production by 9.64 MMscf/day with respect to design that assumes Darcy flow through the propped pack. The basic finding is that for a given amount of proppant shorter and wider fractures compensate for a significant part of the non-Darcy effect. Optimum fracture geometry varies with the applied pressure drawdown (in contrast to the Darcy flow case, where it does not.)

Optimum fracture design is sensitive to the particular β factor correlation selected. It is recommended to use the equation developed specifically for the given type of proppant and mesh size, if available. Otherwise, the Pursell et al. or the Martins et al. equations are recommended as across the board reliable correlations for predicting non-Darcy flow effects in the propped pack.
Dynamic Interfacial Tension Phenomenon and Wettability Alteration of Crude Oil-Rock-Alkaline-Surfactant Solution Systems
Authors: Li Jingquan , Wang Wei , Gu Yongan
Published: December 2007

It has long been recognized that an alkaline-surfactant (AS) flood is an effective enhanced oil recovery (EOR) process. When an AS solution is injected into an acidic oil reservoir, it causes the interfacial tension (IFT) reduction and wettability alteration, which subsequently affect the flood performance to a large extent. Quantitative descriptions of this dynamic IFT phenomenon and wettability alteration are of great interest to the petroleum industry. In this paper, the axisymmetric drop shape analysis (ADSA) technique for the sessile drop case is employed to measure the dynamic IFT and the contact angle of a crude oil drop on a reservoir rock in several aqueous solutions. Based on the modern digital image acquisition, analysis and processing techniques, the ADSA technique obtains the accurate digital image of the sessile oil drop and accomplishes the relevant measurements. The aqueous solutions include alkaline solutions and AS solutions at different alkali, cationic and anionic surfactant concentrations. It has been found that the measured IFT varies with time. This dynamic IFT phenomenon is then interpreted in terms of the surfactant generation and adsorption at the interface and its subsequent dissolution into the adjacent bulk phases as well. Meanwhile, it has also been observed that the measured contact angle changes with time in a peculiar manner. When the crude oil is made in contact with an alkaline solution, a water-wet reservoir rock quickly becomes more water-wet to different degrees at different alkali concentrations. At the beginning, the contact angle increases but eventually decreases close to its initial value. This wettability alteration corresponds well to the measured dynamic IFTs. In addition, the synergistic effects of AS solutions on wettability alteration are studied. It has been found that the wettability alteration in a cationic surfactant-alkaline solution has a rather different trend from that in an anionic surfactant-alkaline solution. More specifically, a cationic surfactant can make a water-wet reservoir rock become oil-wet, whereas an anionic surfactant can only cause minor change of its wettability. It is speculated that adsorption of the cationic surfactant onto the rock surface is strong and stable so that the wettability alteration is irreversible. This laboratory study not only provides an improved understanding of the interfacial interactions in the crude oil-reservoir rock-AS solution systems but also helps to fully develop the oil recovery potential of AS flood processes in field applications.
Mechanistic Prediction of Capillary Imbibition Curves
Authors: Gladkikh Mikhail , Bryant Steven
Published: December 2007

The importance of capillarity–controlled processes in porous media, such as drainage or imbibition, is hard to overestimate. In this work a new way of modeling imbibition is presented, which is based upon a physically consistent dynamic criterion for the imbibition of a pore originally proposed by Melrose.

The approach is applied in a dense random packing of equal spheres, which serves as a simple but physically representative model of a well–sorted, unconsolidated sediment. The results of the geological process of cementation (e.g. quartz overgrowth) are simulated in the sphere pack. The pore space geometry of the resulting model sedimentary rock is completely defined, which makes possible a priori predictions of pore level processes.

Imbibition is simulated in a network that naturally corresponds to the pore-space of the model rock. This allows quantifying the influence of different parameters, such as wettability (specified by the value of contact angle of fluid-fluid-solid interface), initial conditions (different drainage endpoints) and sample geology (amount of cement). It also provides a basis for a mechanistic understanding of phenomena such as "snap-off" of nonwetting phase in the pore throats.

The simulations show that the imbibition capillary pressure curve is very sensitive to the value of contact angle and degree of cementation. Predicted capillary pressure curves compare favorably with experimental data presented in the literature. In contrast, simulations with alternative criteria for pore-level events do not explain the data. We conclude that the dynamic criterion captures the relevant pore-scale physics for two–phase displacements. This provides a new foundation for understanding behavior of multiple fluid phases in porous media.
Pore Scale Characterisation of Carbonates using X-ray microtomography
Authors: Arns C. H. , Bauget F. , Limaye A. , Sakellariou A. , Senden T. J. , Sheppard A. P. , Sok R. M. , Pinczewski W. V. , Bakke S. , Berge L. I. , Øren P.-E. , Knackstedt M. A.
Published: December 2007

A reservoir carbonate core plug has been imaged in 3D across a range of length scales using high resolution X-ray microtomography (µ-CT). Data from the original 40 mm diameter plug was obtained at the vug scale (42 µm resolution) and allows the size, shape and spatial distribution of the disconnected vuggy porosity, φvug = 3.5% to be measured. Within the imaged volume over 32000 separate vugs are identified and a broad vug size distribution is measured. Higher resolution images, down to 1.1 µm resolution, on subsets of the plug exhibit interconnected porosity and allow one to measure characteristic, intergranular pore size. Pore scale structure and petrophysical properties (permeability, drainage capillary pressure, formation factor and NMR response) are derived directly on the highest resolution tomographic dataset. We show that data over a range of porosity can be computed from a single plug fragment. Data for the carbonate core is compared to results derived from 3D images of clastic cores and strong differences noted. Computations of permeability are compared to conventional laboratory measurements on the same core material with good agreement. This demonstrates the feasibility of combining digitized images with numerical calculations to predict properties and derive cross-correlations for carbonate lithologies.
Utilizing the Value of Continuously Measured Data
Authors: Holland Jeff , Oberwinkler Christian , Huber Michael , Zangl Georg
Published: December 2007

Smart Fields and Intelligent Wells are the new buzz words currently dominating in the petroleum industry. Many papers have been published so far on the implementation of intelligent wells but less has been seen on the actual application of the continuously measured data.

There are many different problems the engineer is facing during his attempt to use the real time data for real time optimization. Just to mention a few of them: Data qualityMoving huge amounts of dataMany engineering software packages are not able to handle high frequency data

Basically, the question is, how can the real time data stream be used for continuous asset optimization and is there any economic value to it?

The first part of the SPE paper will deal with a general introduction into current problems and how they can be solved.

The second part will give an actual example of the implementation of an Automated Reservoir Surveillance System1 in the Medusa field, Gulf of Mexico (GOM). Different levels of implementation have been identified: Data management and integrationAutomationReal time rate allocationDetection

The first three points have been successfully implemented. The remaining point is currently in progess. A detailed view will be given on the goals which should be achieved in the end - in particular how to actually use real time data for continuous monitoring and optimization.

The uniqueness of this approach lies in the continuous and automatic comparison of real values to estimated values based on computational models. If the two values deviate from each other, the engineer is notified by an alarm system. This is a powerful and new approach and can be seen as the first step towards a Smart Field implementation.
Multiphase Non-Darcy Pressure Drop in Hydraulic Fracturing
Authors: Olson Karen E. , Haidar Sami , Milton-Tayler David , Olsen Eivind
Published: December 2007

Valhall, an offshore field in Norway, is a black oil reservoir producing mainly through multi-fractured (with proppant) horizontal wells.1 The bottom hole flowing pressure is well below the bubble point and hence the fracture conductivity is significantly constrained by multiphase non-Darcy pressure drop losses.

Geertsma in 1974 was the first to propose a multiphase Beta (non-Darcy constant) correlation as a function of permeability, porosity (size) and saturation. Recent testing to measure the non-Darcy pressure drop for multiphase flow in proppant packs was successful in verifying a strong relationship to saturation.

Three different types of 16/20 proppants with three different resins and one of 12/18 and 20/40 were tested (total of eleven samples) in a conductivity cell under field conditions (temperature of 195 deg F and 1,500-6,500 psi confining stress), for a proppant loading of 4 Lb/ft2 The proppant was placed in the cell using a 30 lb crosslink borate X-link fluid with 4 ppt (lbs/1000 gal gel) of encapsulated breaker for 24 hours to allow fluid break prior to conducting the flow tests.

The Geertsma type equation was used to match the laboratory data. The equation constants (for permeability, porosity and saturation) for each proppant/resin type were derived. The non-Darcy correlations for each proppant were used in a numerical simulator to determine the pressure drop in the fracture and to quantify the effects on production rates.

The paper highlights the importance of proppant size for optimizing fracture design for wells producing under multiphase flow.
Fine-Scale Simulation of Sandstone Acidizing
Authors: Li C. , Xie T. , Pournik M. , Zhu D. , Hill A. D.
Published: December 2007

The current state of the art of sandstone acidizing modeling considers heterogeneities only in a very gross manner. The most sophisticated design models treat the formation as a series of layers with constant properties (mineralogy, permeability, etc.) in each layer. A radial variation in formation properties may be considered as a method of simulating the damaged region, but there is typically only two discrete regions considered – the damaged zone extending to some assumed radial distance, and the unaltered formation beyond this distance. However, sandstones invariably have small – scale heterogeneities in mineralogy and flow properties that may cause the effects of injected acids to differ greatly from what is predicted by a model based on a homogeneous formation.

Matrix acidizing of sandstone is influenced by very small-scale variations in the permeability field. Preferential flow of the acid through higher permeability pathways in the matrix allows much deeper acid penetration and better overall permeability response than is predicted by any current model of sandstone acidizing. This may be particularly important for high concentration HF treatments that are currently being applied, where channeling of the acid may create wormhole-like structures. In addition to variations in the permeability field, variations in the mineral distribution affect the stimulation achieved with acid. For example, a sandstone containing clay-rich streaks may experience a large permeability increase as the clay is dissolved by acid.

We have developed a fine-scale model of the sandstone core acid flooding process. The model divides the domain into grid blocks on the order of 0.1 inches on a side to simulate the fine-scale structure of sandstone. A highly variable matrix domain was generated by using standard geostatistical techniques, and the acid and mineral balance equations allowed us to predict the changing permeability field as acidizing proceeds. Permeability response to acidizing is predicted in which not only the porosity, but also the mineralogy, tortuosity, and statistical parameters of particle size are considered. The initial porosity and mineralogy field can be generated in a correlated manner in three dimensions; thus, a striated or laminated sandstone can be simulated by the model.

Application of the new model to typical acidizing conditions shows that acid tends to channel through a heterogeneous sandstone, with the most efficient acidizing occurring when the rock has a layered structure. Layering is simulated by assuming a correlated permeability field in the main flow direction, as occurs in sandstones having horizontal laminations. The model shows that acid can stimulate the matrix permeability two to three times farther into the rock than would be predicted with a standard acidizing model. The effects illustrated for acid penetration would also apply to other injection processes that rely on transport and chemical reaction in the matrix.
Analysis of Lost Circulation During Drilling in Cooled Formations
Authors: Hettema M. H. H. , Bostrøm B. , Lund T.
Published: December 2007

A few of the lost circulation incidents that have occurred at the Statfjord field and the Veslefrikk field appeared to have been caused by drilling through cooled formations. These lost circulation incidents have been analyzed and compared with offset wells drilled with full returns. We have made plausible that the presented cases of lost circulation are caused by the fact that these wells have been drilled too close to a water injector. Injection data have been analyzed to determine the thermo-elastic stress changes around these injectors. To quantify the thermal cooling effect, downhole pressure data measured during the mud loss incident are analyzed. We found a significant reduction both in the breakdown pressure and minimum horizontal stress. When comparing these data with a thermo-elastic model, the theory predicts a much stronger effect than the interpreted downhole pressure measurements. Numerical simulations of near-wellbore thermal stress effects showed that differences between the mud temperature and the formation temperature could significantly increase the wellbore stresses toward compression. However, the combined near-wellbore thermal effects of formation cooling and a warm mud could not explain the discrepancy between the model and the interpreted stress measurements.
Characterizing Casing-Cement-Formation Interactions Under Stress Conditions: Impact on Long-Term Zonal Isolation
Authors: Mueller Dan T. , GoBoncan Virgilio , Dillenbeck Robert Lee , Heinold Thomas
Published: December 2007

The investigation of cement integrity over life of well conditions continues to be a high priority within the well cementing industry. Increasing awareness of problems associated with cement sheath failure and subsequent loss of zonal isolation or sustained casing pressure have demanded that set cement material behavior and the coupled behavior of casing, cement and formation be more fully understood in order to make rational engineering decisions. Recent advances in wellbore stress modeling can now provide a probabilistic determination of the suitability of a particular cement design for the expected range of induced well stresses.

This paper describes the cement evaluation and wellbore-modeling methodologies specifically developed to predict the magnitude of tensile or compressive forces created by changing wellbore or reservoir conditions.
Development & Field-Testing of a Cost Effective Rotary Steerable System
Authors: Moody M. , Jones S. , Leonard P.
Published: December 2007

This paper describes a new Rotary Steerable System (RSS) and results from its field testing program. The RSS has been designed to handle the technical requirements of the most challenging wells, but also to be economical for use in low cost wells. This important feature was achieved by a unique hydraulics and electronic design and through the use of durable but low cost materials. The tool itself consists of three active and independent steering blades placed close to the bit, and a near-bit stabilizer which acts as a fulcrum. The steering blades apply a constant force to the formation. The displacement of the blades is measured to offset the Bottom Hole Assembly (BHA) in the desired direction. The clamping force of the tool in the hole acts to stabilize the lower part of the BHA and remove unwanted vibration and instability from the drill bit. This significantly improves BHA response, borehole quality, ROP and bit life. Since the RSS has a full 3D capability, it can drill constant curvature boreholes in any direction.

The tool has been tested in wells in Texas, Louisiana, Oklahoma and the Gulf of Mexico. The results of these tests will be presented in detail. It is shown that BHA optimization can make a significant difference to the quality of directional holes drilled with a RSS. The data obtained during testing have, in fact, lead to an optimized BHA configuration which is unique compared with any other existing RSS. This optimized BHA configuration was determined from test runs in both point-the-bit and push-the-bit modes. Through the course of this exercise, it was shown that point-the-bit technology can provide superior borehole quality, improved Rate Of Penetration (ROP) and consistent Dog Leg Severity (DLS).

Finally, the improved performance and time saving obtained with this new RSS will be compared with offset data from directional wells that were drilled with conventional steerable motor assemblies.
A Physical Model for Stress Cages
Authors: Alberty Mark W. , McLean Michael R.
Published: December 2007

Well designs are constrained by the variation of both the pore pressure and fracture gradients throughout the depth of the well. Each hole section is designed such that the pressure profile within the hole at any time during drilling will not exceed the fracture pressure profile at any point throughout that section. The maximum pressures catered for in the design are invariably dictated by permeable formations with the highest pore pressure gradient. The casing depths are set to put behind pipe formations with too weak a fracture gradient to resist the planned pressure profile expected during drilling. This prevents a weak formation from failing and cross flow occurring between that failed zone and any high pressure permeable formations within the same hole section. The fracture gradient is typically determined by measuring the pressure at which losses begin to occur in the hole section and converting the downhole pressure into an equivalent mud weight. Most operators and mud companies have observed that the addition of some mud additives has influenced the pressure at which these induced losses begin. However, the use of those additives has been unreliable in many instances.

Recent work at BP has resulted in the development of a physical model that describes the mechanism that allows the fracture resistance to increase above conventional minimum horizontal stress through the addition of mud additives. These additives result in the formation of a "stress cage" which is a near wellbore region of high stress induced by propping open and sealing shallow fractures at the wellbore/formation interface. With the development of the physical model it is now possible to analyze the effects of different drilling practices upon the reliability and stability of those induced stress cages.

The development of stress cages is influenced by a number of properties including the diameter of the borehole, the width of fractures induced in a formation, the range of particle sizes which can be used as proppant in the fracture, the sealing properties of the mud, and the permeability of the formation. The successful implementation of the stress cage mechanism is dependent upon the use of appropriate constructive drilling practices and avoidance of detrimental practices which may destabilize the stress cages.
Gas Lift Optimization for Long-Term Reservoir Simulations
Authors: Wang Pengju , Litvak Michael
Published: December 2007

Although various gas-lift optimization algorithms have been proposed in literature, few of them is suitable for long-term reservoir development studies, which require the gas-lift optimizer to be highly efficient, flexible and powerful enough to handle complicated fluid flows and operational constraints, and have low impact on simulator convergences. This paper investigated methods to address these important issues.

The gas-lift optimization problem considered in this paper is to maximize the daily hydrocarbon production by selecting optimally the well production and lift gas rates subject to pressure and rate constraints in nodes of the surface pipeline network and to the amount of lift gas available. The problem is regarded as a well management problem in a commercial reservoir simulator capable of simulating multiphase compositional fluid flow in reservoirs, well tubing strings, surface pipeline network systems, and separation facilities. The problem is solved in selected iterations of a reservoir simulation time step.

This paper proposed a method for the described gas-lift optimization problem and investigated its performance against multiple existing methods. Case studies showed that the new method is capable of producing high quality results while requires less CPU time for optimization and has smaller impact on reservoir simulator convergence.

This paper also applied the concept of multiobjective optimization to smooth the rate oscillation between adjacent iterations by sacrificing a certain amount of oil production. In certain cases, this method reduces the simulation time significantly.