bluuebunny/crossref_metadata_2025 huggingface dataset:
Thermal Reservoir Simulation Model of Production from Naturally Occurring Gas Hydrate Accumulations
Authors: Swinkels Wim J. A. M. , Drenth Rik J. J.
Published: December 2007

Interest in the potentially large deposits of natural gas hydrates and hydrate capped gas reservoirs is increasing. This interest is fuelled by foreseen requirements for large volumes of natural gas as a clean hydrocarbon fuel and by increasing deepwater and Arctic exploration and drilling experience. Analytical models are not sufficient any longer for developing production concepts for natural gas hydrate accumulations. We have applied a conventional thermal reservoir simulator to model production from natural gas hydrates and hydrate capped gas reservoirs.

Reservoir behavior of a hydrate-capped gas reservoir is modeled using a 3-D thermal reservoir simulator. The model incorporates a description of the phase behavior of the hydrates, heat flow and compaction in the reservoir and the hydrate cap.

Results help in understanding reservoir pressure and temperature behavior and allow matching of experimental data. The model also allows the calculation of well productivity, evaluation of well configurations, including horizontal wells and screening of production options. It shows the potentially self-sealing nature of the hydrate cap.

Production scenarios were also investigated for production from the solid hydrate layer itself, using horizontal wells and various ways of dissociating the naturally occurring gas hydrates. Important findings from these investigations are the role of excessive water production and the requirement for water handling facilities.

The paper concludes that thermal reservoir simulators can be used to build models of hydrate associated gas reservoirs. It is also concluded, that a dedicated data acquisition program is needed to obtain reservoir parameters for gas hydrate accumulations. Such parameters include relative phase permeability, heat capacity and thermal conductivity of the hydrate-filled formations, compaction parameters and rate of hydrate formation and decomposition in the reservoir.

Insights obtained from building these models help in acquiring the relevant reservoir data, interpreting observed reservoir behavior and in designing production scenarios for economical evaluation.
A New Efficient Averaging Technique for Scaleup of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B. , Kumar A.
Published: December 2007

Increased resolution in reservoir characterization is driving the need for efficient and accurate upscaling techniques for reservoir simulation on which reservoir performance prediction relies. Unfortunately, the existing averaging methods (i.e. harmonic, arithmetic, power law, geometric or a combination of harmonic and arithmetic methods) are only applicable under the circumstances of perfectly layered or perfectly random heterogeneity distributions, which realistic reservoirs are not. This paper presents a new averaging method that improves the upscaling averaging methods for realistic reservoirs and can substitute for the orders-of-magnitude slower performance of direct simulation methods, such as pressure solver techniques. The new averaging method first calculates the upper and lower bounds of the effective properties based on the nature of geology and then employs a new correlation, scaling, and rotation technique to estimate the effective properties for the upscaled grid. The approach not only preserves the accuracy of the time consuming simulation methods but also retains the speed of the traditional averaging methods.

Five real sandstone and carbonate reservoir geologic models (of which, three of them are multimillion cell models) from Africa, North America, and South America were employed as benchmark and working data sets to develop and validate the new technique. The technique has the advantage of suiting the more irregular geometries i.e. pinchouts, faults, and flexible simulation grids compared to the pressure solver methods which are more suited for relatively simple flow geometries.
Water Saturation Modeling: An Upscaling Point of View
Authors: Ekrann S.
Published: December 2007

The paper addresses some mathematical aspects of water saturation modeling. The upscaling problem, i.e., the substitution of an equivalent homogeneous medium for the real heterogeneous one, is shown to have a simple solution. This solution ensures reproduction of observed effective saturation in wells, and suggests methods to distribute saturation between wells. Elements of common practice are shown to be questionable. In particular, attempts to correlate effective saturation with effective permeability may preclude reproduction of observed saturation, and may lead to significant errors between wells.
Rigsite Measurement of Cuttings Weight Equipment: Method to Analyze the Data and Extended-Reach Field Test
Authors: Thonhauser Gerhard , Maidla Eric , O'Leary Paul , Millheim Keith
Published: December 2007

The technology for addressing the issue of hole cleaning is presented and two field tests have documented the successful results.

The technology includes a new mass flow rate equipment placed at the end of the shale shakers, a hole cleaning simulator, and a trend analysis methodology to diagnose hole cleaning problems.

The optimization of the drilling process is also addressed with the objective of minimizing the hole cleaning time.
Microbeads as Lubricant in Drilling Muds Using a Modified Lubricity Tester
Authors: Skalle P. , Backe K. R. , Lyomov S. K. , Kilaas L. , Dyrli A. D. , Sveen J.
Published: December 2007

Particles like barite and cuttings influence the friction properties of a mud. The standard API lubricity tester, however, cannot measure friction of fluids containing particles, and to overcome this problem it was modified with a cam setup. It was found that particles indeed alter the friction.

Large beads are being used to reduce friction. They are, however, filtered out in the solids control equipment and to avoid this, we have investigated smaller polymer microbeads which will pass unhindered. The microbeads reduce the friction in water based muds with around 40% which is significantly better than four commercial lubricants.
An Integrated Solution of Extended-Reach Drilling Problems in the Niakuk Field, Alaska: Part II- Hydraulics, Cuttings Transport and PWD
Authors: Green M. D. , Thomesen C. R. , Wolfson L. , Bern P. A.
Published: December 2007

The extended-reach drilling (ERD) program in the Niakuk field, North Slope, Alaska, was suspended in January 1998 due to hole problems in the 8.5-in sections on two ERD wells. An integrated study was undertaken to identify and address the problems. The areas examined included wellbore stability, drilling fluid optimisation, hydraulics and cuttings transport, operational practices, and pressure-while-drilling (PWD) tool utilisation. In the previous paper, the wellbore stability study determined the optimum salinity, down-hole mud density and limits for the equivalent circulation density (ECD) to minimise wellbore damage. To minimise the ECD, a low viscosity fluid with adequate cuttings transport was required. In this paper, the hydraulics and cuttings transport models used to optimise the rheology are discussed. An additional rheological concern was to minimise barite sag. Laboratory tests were performed to determine the fluid formulation to meet the rheological and barite sag requirements. Operational practices were also implemented to enhance cuttings transport in the long, high angle intervals, and to reduce surge and swab pressures on connections, when reaming and during trips.

The optimised drilling fluid and drilling practices were successfully applied to a medium ERD well in June 1998. Real-time PWD data analysis was essential to the operation. The effects of rotation and annular cuttings loading on the ECD were quantified through PWD tests in cased hole prior to drilling the interval. The ECD was monitored and controlled within the required limits during drilling. The hydraulic models, drilling fluid design and operational practices were further refined after that well. In August 1998, one of the problem ERD wells was re-entered. Using the techniques determined in the above studies, the well was successfully drilled with no hole-related problems. In this paper, the aspects integral to the success of these wells are discussed.
Flow Experiments on Concentrated Hydrate Slurries
Authors: Andersson V. , Gudmundsson J. S.
Published: December 2007

Natural gas hydrates have been proposed to capture associated gas produced from offshore marginal oil fields. To evaluate slurry based hydrate technology, the flow properties of both water-based and oil-based hydrate slurries were investigated for different hydrate concentrations. This paper summarizes the production of oil-based hydrate slurries and the flow experiments performed on these slurries. The flow experiments were carried out in laminar and turbulent flow in a high-pressure pipe viscometer in the hydrate laboratory at the Norwegian University of Science and Technology (NTNU).
Interdependencies Among E&P Projects and Portfolio Risk Management
Authors: Brashear Jerry Paul , Becker Alan B. , Gabriel Steven A.
Published: December 2007

Risk management through portfolio optimization requires the avoidance of positive correlation and exploitation of negative correlation among the individual assets in the portfolio. In developing a portfolio of E&P projects, some such interdependencies arise from geotechnical factors that are generally recognized, such as projects in the same play or trend being likely to have similar geologic uncertainties (e.g. source or seal) or correlated reservoir properties. Other correlations, however, are more difficult to recognize, let alone quantify. These include such above-ground uncertainties as: changes in environmental or operating regulations at the national and state levels; changes in the transportation network, processing or refining capacities, or end-use demand; evolution of exploration and recovery technologies; and changes in fiscal regimes or the policies of countries in the same market. Any of these can enhance or detract from the project's ability to compete with other projects, so can directly influence their viability. A new method for estimating the interdependencies that arise from such factors, based on reservoir-on-reservoir competition as evaluated by summary simulation of actual reservoir properties, technologies, costs, logistics, etc., is described, along with worked examples to demonstrate the changes in optimal choices attributable to consideration of above-ground uncertainties and the interdependencies they create.
The Quality Map: A Tool for Reservoir Uncertainty Quantification and Decision Making
Authors: da Cruz P. S. , Horne R. N. , Deutsch C. V.
Published: December 2007

The parameters that govern fuid flow through heterogeneous reservoirs are numerous and uncertain. Even when it is possible to visualize all the parameters together, the complex and non-linear interaction between them makes it difficult to predict the dynamic reservoir responses to production. A flow simulator may be used to evaluate the responses and make reservoir management decisions, but normally only one deterministic set of parameters is considered and no uncertainty is associated with the responses or taken into account for the decisions.

This paper introduces the concept of a "quality map", which is a two-dimensional representation of the reservoir responses and their uncertainties. The quality concept may be applied to compare reservoirs, to rank stochastic realizations and to incorporate reservoir characterization uncertainty into decision making, such as choosing well locations, with fewer full field simulation runs.

The data points necessary to generate the quality map are obtained by running a flow simulator with a single well and varying the location of the well in each run to have a good coverage of the entire horizontal grid. The "quality" for each position of the well is the cumulative oil production after a long time of production.

The geological model uncertainty is captured by multiple stochastic realizations. One quality map is generated for each realization and the difference between the realization maps is a measure of the uncertainty in the flow responses. For each cell, the lower quartile of the local distribution of quality is extracted to build a map, which can be used for decision making accounting for uncertainty.

The methodology for building the quality map is presented in detail and the applications of the map are demonstrated with fifty realistic reservoir models.
State-of-the-Art Simulator for Field Applications of Gas-Liquid Cylindrical Cyclone Separators
Authors: Gomez Luis E. , Mohan Ram S. , Shoham Ovadia , Marrelli Jack D. , Kouba Gene E.
Published: December 2007

The Gas-Liquid Cylindrical Cyclone (GLCC©1) is an example of a compact separator which is simple, lightweight, and having low capital and operational costs. The GLCC© has a wide variety of potential applications, varying from only partial to complete phase separation. This paper presents a state-of-the-art simulator for GLCC© design and analysis, based on an improved mechanistic model, written in an Excel Visual-Basic® platform. The simulator has two components namely, design wizard code and performance code. The design wizard is used for performing the preliminary design of the GLCC©, and the performance code enables detailed prediction of the complex hydrodynamic flow behavior in the GLCC©. This user-friendly simulator incorporates the best available technology for the design of GLCC© separators for the industry. The simulator has been used to design over 100 GLCC© units operating in the USA and around the world. Details of successful field application of GLCC© separator for offshore Lake Maracaibo, PDVSA, Venezuela, (multiphase flow-metering loop), PETROBRAS, Brazil, (external pre-separation) ARCO, Alaska (gas knockout) and Minas, CPI, Indonesia (bulk separation/metering), are presented and discussed. These examples demonstrate the potential, advantages, and benefits offered by the GLCC© simulator for enhancing the utilization of compact separators in both offshore and onshore environments.
Openhole Stability and Sanding Predictions by 3D Extrapolation from Hole Collapse Tests
Authors: Ewy R. T. , Ray P. , Bovberg C. A. , Norman P. D. , Goodman H. E.
Published: December 2007

Wellbore failure is best simulated in the laboratory by subjecting a model hole to simulated in-situ stresses. This can be routinely done on available core by performing a hole collapse test. This test uses a hollow cylinder with an outer diameter of 1.5 inches and a hole diameter of 0.5 inches. The jacketed sample is subjected to increasing pressure on the outer surface until collapse of the hole occurs. This provides a direct measure of the stress required to cause hole failure in that particular formation interval. To predict hole stability and sanding, a method is required for applying this measured strength to the downhole situation. Equations are necessary to account for the fact that the downhole stress situation is more complex than that in the hole collapse test. These equations must include the three-dimensional nature of rock strength. A three-dimensional analytic model is presented that is applicable to both stability and sanding of open wellbores. This model uses a Modified Lade failure criterion which properly accounts for the effect of the intermediate principal stress on rock failure. The Modified Lade rock strength parameters are extracted from the measured hole collapse strength and are then combined with the in situ stresses and formation pore pressure using one of two sets of equations: The first set determines required mud weight for stability while drilling, while the second set determines allowable drawdown pressure for prevention of sand production.
Roughness of Hydraulic Fractures: The Importance of In-Situ Stress and Tip Processes
Authors: van Dam D. B. , de Pater C. J.
Published: December 2007

The surface roughness of hydraulic fractures reflects the fracturing process at the tip. We did an experimental study of hydraulic fracture propagation, in which a characteristic roughness pattern was observed. This roughness developed without shear- or torsional loading in the plane of the penny-shaped fracture. The roughness showed to be determined by material properties and the externally applied stresses on the sample, which represent the effective in-situ stresses. We quantified the roughness, and showed that it correlated well with a measure of the plastic zone size around the fracture tip. New explanations for fracture surface roughness that develops under mode I loading conditions are presented.
Incorporating Crossflow and Spurt-Loss Effects in Filtration Modeling Within a Fully 3D Fracture-Growth Simulator
Authors: McGowen James M. , Barree Robert D. , Conway Michael W.
Published: December 2007

A practical numerical fracturing-fluid filtration model has been successfully incorporated into a fully three-dimensional (3D) fracture-growth simulator. This filtration model incorporates four principal filtration mechanisms: (1) compressibility and flow of the reservoir fluid, (2) invasion of non-Newtonian filtrate, (3) filter-cake deposition, and (4) quasi-equilibrium of filter-cake thickness with the fluid shear stress. When this filtration model is used with a numerical 3D fracture-growth simulator, the impact of these filtration mechanisms on fracture-treatment design can be evaluated. Because the 3D fracture-growth simulator allows the filtration properties to vary spatially, the simulator can accurately evaluate the impact of changing filtration parameters such as filtration pressure, shear rate, fluid rheological properties, and fluid composition.

Before evaluation in the fracture simulator, the results of this new filtration model are first verified against laboratory-generated filtration data, and then compared to the classical filtration theory. The fully 3D fracture-growth simulator is then used to verify the impact of the fluid-leakoff model. The comparisons show that this filtration model can have a pronounced effect on treatment design when spurt loss is significant, and in treatments in which the quasi-equilibrium filter-cake formation (caused by fluid flow over the filter cake) causes dramatic deviations from classical filtration models. The simulations highlight concerns about the accuracy of present minifracturing analysis and treatment-design techniques.
High Propagation Pressures in Transverse Hydraulic Fractures: Cause, Effect, and Remediation
Authors: Deeg W. F. J.
Published: December 2007

Highly deviated or horizontal wells completed in tight formations are frequently aligned with the minimum principal formation stress and completed with evenly spaced, transverse hydraulic fractures. When a transverse hydraulic fracture is created, unexpectedly high fracture-propagation pressures are often encountered. The hydraulic fracture-growth simulators currently available cannot explain these high treating pressures. Therefore, the pressures have been attributed to complex fracture geometries.

Another likely cause of unexpectedly high fracture-treating pressures is the fracturing-fluid flow regime under which transverse hydraulic fractures are created. In transverse fractures, fluid flows radially outward from a fipoint sourcefl (the wellbore). Flow is not linear, as implicitly assumed and hard-coded in many of today™s hydraulic-fracturing models or simulators.

Where radial flow exists under a constant injection rate, fluid velocities are much greater near the wellbore than out in the fracture. This condition causes high near-wellbore pressure gradients, which result in relatively high fracturing-fluid pressures in and near the wellbore, compared with pressures out in the hydraulic fracture.

This pressure-profile effect on fracture-propagation pressure and created fracture dimensions is demonstrated with analytical calculations. The pressure profiles analyzed include a constant pressure throughout the fracture (the equilibrium base case) and a parabolic pressure decay along the length of the fracture (the most severe case considered).

The calculations show that, for severe hydraulic-fracture pressure profiles, the fracture-propagation pressure in the wellbore can be more than 12 times greater than the propagation pressure required for constant pressure throughout the fracture. The more severe the pressure drop in the near-wellbore region, the wider and shorter the hydraulic fracture will be.

Results from these calculations suggest procedural changes for minimizing the effects of adverse pressure profiles. They also demonstrate that current hydraulic-fracturing models and simulators must be modified to account for the pressure profiles expected under radial-flow conditions.
Injection of Lean Gases into Light Oil Reservoirs: Interfacial Aspects
Authors: Lakatos I. , Bauer K. , Lakatos-Szabó J. , Puskás S. , Palásthy Gy. , Trömböczki S. , Kosztin B.
Published: December 2007

Application of lean gases, particularly a methane rich gas, nitrogen, carbon dioxide, air and their mixtures in an ultra light oil bearing reservoir located in Southern Hungary, is in an advanced stage. The relevant studies and mathematical simulations have definitely indicated a substantial surplus oil production and it was also revealed that gravity segregation and vaporization of light hydrocarbons were the main elements of the displacement mechanism. However, well founded arguments have arisen about anomalous interfacial phenomena and precipitation of some oil constituents during the recovery process since the oil was strongly paraffinic and the predicted vaporization was high. Therefore, a detailed laboratory study were commenced to determine the effect of nitrogen, carbon dioxide and lean methane on surface and interfacial properties. On the basis of the experimental results it was concluded that the well known surface and interfacial effects, like enrichment of asphaltenes, resins and heavy hydrocarbons at interfaces, can be neglected when lean and non-reactive gases are injected into an ultra light bearing reservoirs. On the other hand, the precipitation of paraffins and other waxes at oil/water interface may take place even at very low vaporization in both the reservoir space and the surface facilities. Since that inter-facial, probably catalyzed phenomena is newly recognized, further laboratory and field studies are needed to elucidate its detrimental effects on recovery efficiency, well performance and surface technology.
Semi-Analytical Model for Thermal Effect on Gas Well Pressure Buildup Tests
Authors: Fan L. , Lee W. J. , Spivey J. P.
Published: December 2007

This paper presents a semi-analytical wellbore/reservoir model1 that can describe general wellbore effects, especially the thermal effect, on high temperature gas well pressure buildup tests. A numerical simulator has been developed from the model. Using different combinations of wellbore and reservoir parameters, the simulator generated curve shapes that differed with wellbore thermal effects. Many of the curve shapes have been observed in the field.2–3 Using the results from this paper, engineers can distinguish the difference between general wellbore effects and reservoir behavior in the pressure data, which will make the interpretation more accurate. Also, with the help of the simulator developed from the model, engineers can effectively design gas well pressure buildup tests by running the simulator to determine the minimum time required to obtain the data not distorted by the wellbore effects.4

The governing equations of the wellbore model were based on mass, momentum, and energy balances for single-phase gas in one-dimensional space. The gas PVT correlation was also used. Different flow regimes (laminar, transitional, and turbulent) inside the wellbore are modeled for calculating the friction factor. As one boundary condition, a simple analytical reservoir model was connected to the wellbore model at the bottomhole using Duhamel's principle. Heat loss effects accounted for forced-convectional heat transfer inside the tubing, heat conduction between tubing and formation, natural convection and radiation heat transfer of annular fluid, and transient heat flow in the formation. Pressure, temperature, velocity, and gas properties inside the wellbore can be predicted at any depth during an entire pressure buildup test. Variable wellbore storage, momentum, and thermal effects can be simulated.
Use Of Temperature Data in Gas Well Tests
Authors: Elshahawi Hani , Osman Magdy S. , Sengul Mahmut
Published: December 2007

In theory, both build-up and draw-down pressure transients can be analyzed in gas well tests. Quite frequently, only build-up pressure data is usable as the draw-down data can be quite noisy. Draw-down pressure data is often strongly affected by flow rate changes, which can only be roughly estimated in the absence of down-hole flow rate recording. Heavy data filtering can sometimes help, but such filtering can mask important reservoir features such as boundaries and double porosity.

Modern well test gauges can measure temperature as accurately as pressure. Use of these temperature measurements is typically limited to correction or calibration of the raw pressure signal. Less commonly, temperature readings are used to explain anomalous pressure trends or to estimate static and flowing bottom hole temperatures. In addition to reviewing the more classical uses of temperature in wells, this work provides a new use of transient temperature data to yield valuable information in gas well tests. It presents a novel approach for estimating the down-hole flow rate from flowing temperature measurements. This is possible because the temperature departure is intimately linked to pressure, fluid composition, and fluid velocity changes. Since down hole pressure is continuously measured and fluid composition can be quantified, an estimated down-hole flow rate can be generated. This flow rate can be used to deconvolve the draw down pressure data, and the results can be compared to pressure build-up analysis results.
Integrated Nonlinear Regression Analysis of Multiprobe Wireline Formation Tester Packer and Probe Pressures and Flow Rate Measurements
Authors: Onur Mustafa , Kuchuk Fikri J.
Published: December 2007

In this paper, we present a new computationally efficient optimization scheme (in the least-squares minimization framework) that allows simultaneous nonlinear parameter and flow rate estimation from multiprobe wireline formation tester packer and probe(s) pressure data. Our optimization scheme is based on a simultaneous iteration of all of the unknown parameters (formation parameters and flow rate steps) and is quite general in that it can also be applied to all transient tests. Parameter optimization is achieved using the public domain Levenberg-Marquardt algorithm with the restricted step, LMDER, from Argonne National Laboratory. Two examples (one synthetic and one actual field data) are considered to demonstrate the applications of the scheme. The first example pertains to a normal buildup test in single layer system where the flow rate data are not available, whereas the second example pertains to real multiprobe wireline formation tester packer and probe data in a three-layer crossflow system.
Echo-Meter Buildup Tests: The Effects of Fluid Hydraulics and Thermodynamics
Authors: de Sa Neto Abelardo , Grader Abraham S.
Published: December 2007

Some well testing operations include computing bottom hole pressure using the location of the oil/gas interface in the wellbore. The location of the interface is determined acoustically by measuring the travel time from the wellhead to the interface and back to the well head. Empirical and simplifying assumptions about the densities of the fluids and the speed of sound in the fluids are used to compute the BHP. A two-phase wellbore model with two fluid regions is presented and applied to echo-meter acoustic field data. In this model, the momentum, mass, and energy balances are solved simultaneously over both the liquid and the gas regions. In the separate phase regions we consider mass convection, diffusion, and heat conduction and solves simultaneously for pressure, temperature, and velocity. Hence, the model removes the need for many assumptions and simplifications that are used in acoustic testing and computes two-way travel times and bottom hole pressures from fundamental mechanistic principles. The model predicts the sonic travel times and the simulation results can be matched directly to the field measurements. The model can be applied to low energy tests, where fluid motion is slow, and to high energy tests where complicated fluid dynamics, such as differential momentum, take place. In this paper we demonstrate the effects of productivity index, average reservoir pressure, oil viscosity, and heat loss to the formation on sonic travel time, fluid levels, bottom hole pressures and fluid velocities in the wellbore. Three acoustic well tests from Northern Brazil are presented. This paper forms another step in the integration of wellbore fluid dynamics and fluid thermodynamics into the practice of well testing.
Validation and Automatic Tuning of Integrated Reservoir and Surface Pipeline Network Models
Authors: Litvak M. L. , Macdonald C. J. , Darlow B. L.
Published: December 2007

We describe a procedure which has been developed and implemented in a commercial reservoir simulation package for validating and automatic tuning of integrated reservoir and surface pipeline network models. The procedure has been designed to automatically history match well tubing string and surface pipeline network modules in an integrated model. Differences between simulation results and field measurements of well bottomhole pressure, well tubinghead pressure, flow line inlet and outlet pressures, as well as well production rates in a specified tuning time interval are minimized. The simulation parameters describing well perforations, well tubing strings, and pipelines are adjusted within specified ranges to achieve the minimization.

The developed procedure has been successfully applied to automatically tuning integrated reservoir and facility models of oil fields in the Gulf of Mexico and Alaska. Significant reductions in the history matching errors demonstrate the effectiveness of the procedure.

The developed procedure is very general: it can be applied to a large variety of reservoir simulation problems.
Formation-Grain-Size Prediction Whilst Drilling: A Key Factor in Intelligent Sand Control Completions
Authors: Oyeneyin M. B. , Faga A. T.
Published: December 2007

More than 80% of oil and gas reservoirs especially in HP/HTwells and deep water environments of the Atlantic Margin areknown to be highly unconsolidated requiring some form ofadvanced, complex well geometry sand control completions. Akey factor in an optimum sand control completion is a thoroughknowledge of formation sand profile, which is traditionallydetermined by sieve analysis of samples obtained from cores, production lines, etc. In complex wellbore geometries, thesamples obtained through these traditional processes may betotally unreliable.

In this paper, a neural network technique for predictinggrain-size distribution from wireline logs is presented. Thepaper briefly introduces neural networks and discusses theimplementation of the network and its application to SmartWell Sand Control Completions.

The network is recommended for application for either real-timeprediction (that is, while drilling) where input data may be feddirectly to the neural network prediction model, or forprediction at office base depending on the requirements, urgency and purpose of the data. Benefits of the new modelinclude real time prediction of formation grain-size and morereliable prediction of grain size in complex well geometrieswhere the use of traditional sand sampling would be difficult.There is potential for application in the prediction of pluggingtendency of screen systems and gravelpacks.
Realistic Sanding Predictions: A Neural Approach
Authors: Kanj Mazen Y. , Abousleiman Younane
Published: December 2007

Predicting when, or if, sand production will stabilize, and/or in what amounts it will occur, remains a priority item on the wish list of this Industry. For example, if beforehand one knows that Mother Nature is able to reach a stable geometry downhole, early in the life of the well, none of the remedial, productivity decreasing measures would need to be implemented. The complexities involved in the problem still hinder the success of numerous methodologies at their utmost capabilities. Sand exclusion measures are very much complicated by the absence of known precursors to sanding. Accordingly, smart tools that are capable of learning from the past (case histories) to better predict the future of sanding occurrences in the field will certainly help "us" optimize "our" decisions about the problem and may stand solid in making this predictive wish of the Industry come true.

This study is concerned with using the feedforward backpropagation network (BPN) and the generalized regression neural network (GRNN) architectures to predict important sanding indication parameters for gas wells of the Northern Adriatic Basin. Design, tuning, and implementation issues of both network types are briefly introduced in this paper. Data from twenty-three (23) problematic wells and eight (8) sand-free wells are utilized, herein, to train, cross validate, and test the newly applied methodology. Previously, AGIP S.p.A. provided the data and made it public domain property. Input to the system includes total vertical depth, transit time, formation cohesive strength, water and gas rates, drawdown pressure, original static reservoir pressure, effective overburden stress, interval length, and perforation density. The devised system works on classifying the well, forecasting the problematic year in the well's life, and predicting the well's sanding potentiality value (a predefined parameter), as well as its critical total drawdown.

The developed approach far outperformed AGIP's recognized correlations for wells in the same field and showed much better generalization capabilities on all new and unseen cases. Thus, a critical module in a much larger sand inflow treatment-expert, prediction, and analysis software has been devised and validated.
Rheological Properties of Aqueous Foams for Underbalanced Drilling
Authors: Saintpere Stéphane , Herzhaft Benjamin , Toure Abdoulaye , Jollet Stéphane
Published: December 2007

Underbalanced drilling is a non-conventional drilling operation where the hydrostatic pressure of the drilling fluid is maintained below the formation pore pressure. Many advantages can be provided by this specific drilling approach: higher ROP, minimised losses through formation, minimised formation damage in low permeability reservoir or depleted wells. Among the existing low-density fluids used in underbalanced drilling, foam is very beneficial due to its good cuttings carrying capacity. However, the knowledge of foam properties and especially of flowing properties is still incomplete.

Foam can't be considered as a classical fluid and must be seen as a dispersion of gas bubbles in a continuous liquid matrix. Due to its own nature, foam is a thermodynamically unstable system, contrary to drilling fluids. The lack of knowledge on foam properties mustn't prevent engineers from considering this option in their technico-economical studies. The purpose of this work is to provide innovative procedures for foam rheology characterisation in order to better understand its behavior.

The apparent viscosity of a foam is not only a function of its quality (ratio between gas volume and total foam volume) but also of its texture (bubbles size distribution), and of the presence of polymers in the aqueous matrix.

A careful experimental procedure was elaborated, which uses a parallel plates geometry. Attention has been paid to foam stability, texture and evolution properties in order to have correct and reproducible measurements. In particular, wall slip phenomena and strain localisation were investigated and controlled. Shear flow properties were thus determined for different foams formulations with a very satisfying repeatability. The presence of a yield stress has been highlighted. Small amplitude oscillatory shearing experiments demonstrate that foam behaves like an elastic solid for small deformations. Use of a vane rheometer and observation of start-up in the creep mode confirm the elastic nature of the material. Excellent coherence was found between the different measurements. As a conclusion, a reproducible methodology for characterising foam rheological properties was elaborated. Those results constitute the first step on our way to accurately predict down-hole pressures while drilling with foam.
A Probabilistic Reasoning Tool for Circulation Monitoring Based on Flow Measurements
Authors: Mansure A. J. , Whitlow G. L. , Corser G. P. , Harmse J. , Wallace R. D.
Published: December 2007

An expert system is being developed to automatically detect and diagnose several important circulation system problems in geothermal drilling. The system is called the Circulation Monitoring System (CMS) and will be useful for detecting, characterizing, and quantifying lost circulation, fluid influx, gas/steam kicks, loss of mud pump efficiency, washouts, plugged nozzles, and sensor problems. Data from the outflow meter, pump-stroke counter, inflow meter, pit volume indicator, standpipe pressure sensor, and other sensors are processed by a Kalman filter and examined for deviations from expected patterns. The deviations are transformed into evidence for a Bayesian Network, which estimates the probability of each fault. The results are displayed by a Graphical User Interface, which also allows the user to see data related to a specific fault. A prototype has been field-tested and has successfully detected and diagnosed a variety of faults.

The ability of the expert system to analyze circulation system problems is dependent on having high quality inflow and outflow measurements. Sandia National Laboratories has developed a Rolling Float Meter (RFM) to measure outflow and is testing commercially available ultrasonic inflow meters. The RFM has proven rig worthy and is ready for commercialization. Most recently it has been tested by Epoch Wellsite Services on a relief well in California where it has successfully detected kicks that were not observable by standard outflow measuring devices.
Optimal Lifetime Design of Primary Hydrocarbon Production Separation Systems
Authors: Grødal E. O. , Realff M. J.
Published: December 2007

The design of primary hydrocarbon production separation systems, given predicted wellstream flowrates and composition, is subject to nonlinear thermodynamic, hydrodynamic and mechanical constraints. Obtaining an optimal design for lifetime application represents a challenging problem because of the large changes in the production profiles that can be expected. In this paper we present a systematic and rigorous design method that generates the optimal lifetime design of such systems. The proposed method includes unit replacement and retrofit decisions. The method employ clustering theory and combinatorial and non-linear optimization to arrive at a solution. The method can be used during initial development planning and at any time during the lifetime as more knowledge of the field is gained. We exemplify the method on two fields with different economical models: one field with long lifetime based on an investment/salvage model and one field with a short lifetime based on a model for leased units.
Effectiveness of Scale Inhibitor Squeezes in the Mitigation of Tight Emulsions in Saudi Arabian Wet Crude Oil
Authors: Al-Mulhim A. K. , Wingrove M. D. , Sarbar M. A.
Published: December 2007

Tight emulsions, formed during the production of Arabian Light crude oil, were causing problems at an increasing number of wet crude handling facilities. The processing of these fluids impacted operations in three major areas: Inability to produce some wells, particularly during cooler weather.Plant upsets due to grid trips and accumulation of sludge in vessels.Increased demulsifier usage.

The overall effect was a loss of revenue and increase in treatment costs.

In January 1995 a multi-disciplined team of scientists and engineers was formed to characterize the emulsions and make recommendations for improved emulsion treatment. Studies showed that solids, which include scale particles, are precipitated from produced fluids during production. These solids were shown to be largely responsible for the formation of stable emulsions in our systems.

A very successful scale squeeze program was already in place to mitigate carbonate scaling – with squeeze lifetimes of over ten years. Based on the link between scale and tight emulsions, this program was accelerated and scale treatments were performed on emulsion ‘problem’ wells to suppress solids formation and therefore reduce/ eliminate emulsion problems.

The paper describes the emulsion model developed. The mechanism of organic and inorganic solids precipitation during production is presented and the effect of pressure drops caused by mechanical ‘chokes’ used for well restriction is demonstrated. Scale inhibitor squeeze and encapsulated inhibitor treatments are discussed with reference to case histories. The effectiveness of scale inhibitor in reducing emulsion tightness is demonstrated using laboratory data.

The paper concludes by summarizing the success of this treatment strategy in terms of economics, reduction of chemical demulsifier use and elimination of downtime due to emulsion problems
The Barua Field, Venezuela: Comparison of the Results and Process of Deterministic versus Stochastic Reservoir Characterization
Authors: Carnes A. , Yarus J. , Cordova P. , Delgado M. , Rodriguez H. , Black P. J. , Brown R. L. , Kramer K. , Yang K. , Green L. D.
Published: December 2007

The onshore Barua Field, near the southeast edge of Lake Maracaibo, is a highly faulted structure producing from the Eocene Pauji and Misoa intervals. This mature field has undergone significant depletion from approximately 30 wells since 1958. A classical, deterministic reservoir characterization study followed by reservoir simulation history matching was conducted. Prior to completing the history match, a stochastic reservoir characterization, including multiple realizations, was performed. Barua's Eocene interval of near shore littoral bar environments can be modeled using a variety of geostatistical techniques. A pixel-based method was selected over object modeling due to the long continuous nature of the reservoir sands and shales, and the absence of any definitive local genetic depositional facies geometries. Understanding the petrofacies and lithofacies and their relationship in the depositional environment was key to creating a representative stochastic reservoir characterization. This modeling process is described. The process of integrating seismic, well logs, depositional concepts, and facies data is also described.

The comparative reservoir simulation results between the stochastic and deterministic approaches, and the resulting impact from an engineering perspective on the history matching process provide insight into the different methodologies. A discussion of the differences and benefits is provided.
Verification of Transient, Multi-Phase Flow Simulation for Gas Lift Applications
Authors: Asheim H.
Published: December 2007

An analytical solution describing dynamic variations in gas lifted flow has been developed. The solution builds on a classical paper and extends this to also include flow friction and interface slippage. Since the analytical solution is neither subject to numerical instability, nor numerical diffusion, it provides reference cases against which transient simulators can be tested.

An experimental numerical simulator has been developed and tested against the analytical solution. The simulated flow performance showed similar dynamic properties as those predicted analytically. A commercially available simulator was also tested. This provided similar steady-state predictions but the simulated dynamic performance was quite different from the analytical predictions.
The Analysis and Prediction of Electric-Submersible-Pump Failures in the Milne Point Field, Alaska
Authors: Sawaryn S. J. , Norrell K. S. , Whelehan O. P.
Published: December 2007

Electric Submersible Pumps (ESPs) are the predominant lift method used in the Milne Point Field (MPU), Alaska. Each year some 50 ESP failures occur, adversely effecting lifting costs, rig utility and production. Statistical methods based on the Weibull distribution and the Bathtub reliability model have been used to analyse ESP reliability data collected over a thirteen year period. The analysis differs from earlier works by treating a portion of the infant failures (the early part of the Bathtub model) as a series of Bernoulli trials. Analysis shows the three main factors effecting ESP reliability in MPU are reservoir, sand control and if the ESP is newly installed or a replacement. Further, the ESP failure rate is shown to be dynamic, influenced by the delivery of new wells and the time lag between failure and replacement. The results have been incorporated in to a computer based failure simulator which uses Monte-Carlo techniques to simulate the failure rates. Numerical values for the statistical parameters are included together with details of the simulator.

The simulator is currently used within the MPU asset as a planning tool to establish changes in rig utility, production loss and ESP replacement strategies in a cash constrained environment. It is also used to assess improvements in ESP performance and to secure commercial terms for ESP lease and purchase options.In the future it is recommended that the simulator be used, with suitable analogue data,to predict the economic impacts of ESP failures on development programs prior to sanction.
Wettability Effects on Oil Recovery Mechanisms in Fractured Reservoirs
Authors: Graue A. , Bognø T.
Published: December 2007

Iterative comparison between experimental work and numerical simulations has been used to predict oil recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperature, produced chalk blocks which were strongly-water-wet and moderately-water-wet, but with identical minerology and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored waterflooding these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability input data used in the simulations. Capillary pressure and relative permeabilities at each given wettabilities were experimentally measured and used as input for the simulations. Optimization of either Pc- data or kr-curves gave indications of which of these input data could be trusted. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations.