bluuebunny/crossref_metadata_2025_split huggingface dataset:
Semi-Analytical Model for Thermal Effect on Gas Well Pressure Buildup Tests
Authors: Fan L. , Lee W. J. , Spivey J. P. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.