bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Evaluation of Horizontal Wells in Stochastic Naturally Fractured Gas Reservoirs
Authors: Hatzignatiou D. G. , McKoy M. L. 
Published: December 2007

Abstract
The existence of natural fractures in hydrocarbon bearing formations may significantly enhance hydrocarbon production rates and recovery factors. Horizontal wells or drainholes drilled in these types of reservoirs (especially tight gas reservoirs) increase the possibilities of intersecting discrete natural fracture systems in ways that render high well productivity indexes and higher recovery factors than vertical wells, thus enhancing field developmental opportunities.
The performance of horizontal wells in naturally fractured formations and their ability of draining the formation effectively depend on a number of well and formation parameters. Simulation results clearly illustrate that the well location within the flow region, degree of fracture clustering, fracture density, fracture aperture distribution, along with the degree of fracture interconnectedness can govern gas production rates, ultimate gas recovery and reservoir drainage patterns (Hatzignatiou, 1999). Therefore, gas recovery factors for tight fractured reservoirs may differ significantly from those of homogeneous reservoirs with large formation permeability.
This work demonstrates a means of estimating well recovery factors in single-phase gas naturally fractured reservoirs. Uncertainties in these estimates due to network heterogeneity and variability in the connection between the well and the network are quantified in the form of probability-based recovery factors. Emphasis is placed on horizontal wells because these wells are commonly used in developing and producing tight fractured reservoirs.
Application of Azimuthal Density While Drilling Images for Dips, Facies and Reservoir Characterization – Niger/Delta Experience
Authors: Akinsanmi O. B. , Anwasi L. E , Ogundana M. A. , Aibangbe O. , Kienitz C. 
Published: December 2007

Abstract
With the introduction of azimuthal density while drilling tool into the stream of LWD technology in the last decade, a new frontier in understanding and evaluating lateral composition and architectural variability in most reservoirs has been made possible, by the utilisation of this tool in the drilling of high angle wells in the Niger delta. The availability of imaging technology from this tool and the resultant imaging answer product has been used for detailed structural and sedimentological analysis in characterizing reservoirs beyond the resolution of surface seismic. Determination of reservoir properties based on genetic units and identification of flow zones that could potentially contribute to production were derived to enhance the reservoir models for such reservoirs and improve reservoir management.
In most cases, the optimal placement of high angle wells using the conventional well to well correlation techniques have often proved unreliable, due to unexpected lateral discontinuity in the reservoir quality. These occurrence in many reservoirs have been associated with varying sedimentary structures, micro-faulting and unexpected changes in environment of deposition, as evident in Niger delta depobelts. Resulting production from high angle drain holes has been seen to be greatly influenced by the positioning of the well bore relative to structural and formation dip, apart from other completion related problems. Formation dip and structural features have historically been acquired from wire-line logging tools. However, electric logging in high angle wells presents operational difficulties which does not encourage the use of wireline logging.. Images acquired while drilling by the azimuthal density tool provide a method of resolving the correlation uncertainties, and allow quantification of the structural and sedimentological interpretation and the subsequent production pattern across the lateral wellbores. Two field examples where azimuthal density data were acquired and utilized are analyzed. From the data analysis an extra opportunity in terms of reserves were identified.
A Comparative Study of Hydraulic Models for Foam Drilling
Authors: Ozbayoglu M. Evren , Kuru Ergun , Miska Stefan , Takach Nicholas 
Published: December 2007

Abstract
Compared to conventional (incompressible) drilling fluids, relatively little is known about the hydraulic and rheological properties of foamed drilling fluids. The complex flow mechanisms involved in compressible drilling fluid circulation make determination of the optimum combination of liquid and gas injection rates very difficult. Modeling of foam rheology is the key issue in hydraulic design in order to predict the bottom-hole pressure accurately and to optimize different controllable variables for effective cutting transport performance.
The University of Tulsa’s low-pressure ambient temperature flow loop has been recently modified to accommodate foam flow. The flow loop permits foam flow through 2", 3", 4" diameter pipes and an 8" by 4 1/2" annular section. Preliminary experiments have been conducted in which pressure losses were measured for different foam qualities. Measured parameters were gas/liquid flow rates, pressure, differential pressure loss, and temperature.
Statistical analysis was carried out to see the degree of fit provided by Bingham plastic, power law, and yield power law models for the generalized foam flow curve data.
A comparative study was conducted to investigate the predictive ability of the available foam hydraulic models. Models presented by Beyer et al. (1972), Blauer et al. (1974), Reidenbach et al. (1986), Sanghani and Ikoku (1983), Gardiner et al. (1988) and Valko and Economides (1992) were used to estimate the frictional pressure losses during the flow of foam in horizontal pipes. Comparison of the model predictions with experimental pressure loss values show that model predictions of frictional pressure losses can be different from the actual values by 2 to 250 %.
Simulation of Gas Production in SAGD
Authors: Gillis K. A. , Palmgren Claes , Thimm H. F. 
Published: December 2007

Abstract
In a previous paper, a general theory for gas production during Steam-Assisted Gravity Drainage (SAGD) has been presented1. The main gases formed during "aquathermolysis" reactions, carbon dioxide and hydrogen sulphide, tend to be produced primarily via the produced water.
The present paper reports a numerical analysis of the theory, and provides the results of a first simulation that describe the gas production history during SAGD. The numerical analysis includes hydrogen sulphide, carbon dioxide, and methane solution gas.
Gases were included in the numerical analysis by using K-values derived from new theory. This theory accounts for the asymptotic behaviour of gases in solution as the critical point of water is approached.
Simulation results corroborate the initial simple analysis, and agree with field observation. Minor differences are discussed.
A Multiple Fractured-Horizontal Well Case Study
Authors: Cvetkovic’ Branimir , Halvorsen Gotskalk , Sagen Jan 
Published: December 2007

Abstract
A series of solutions corresponding to various conditions are given in a multiple-fractured-horizontal well model. We were able to develop a fast, robust and easy to use software program, a screening-tool product, we hope will be of significant benefit to companies in the petroleum industry. A practising engineer should be able to predict an optimum number of induced fractures in a horizontal well. Some existing analytical approaches are recognised to be inefficient and solutions should be compared to new solutions and new modelling techniques. Extension of the existing single phase oil flow SLAB model to a BOX model improves well production optimisation of a horizontal well with induced fractures; particularly prognosis and diagnosis features. The bringing together of rate-time and pressure-time analysis provides a total package to better characterise horizontal well with induced fractures behaviour. The tendency to over- or under-estimate the oil production needs to be corrected. Inclusion of a restart option is demonstrated in a real case study. This analytical screening-tool is useful for prognosis, diagnosis and improved modelling of oil production from horizontal or near-horizontal well with induced fractures.
Fast-SAGD: Half the Wells and 30% Less Steam
Authors: Polikar M. , Cyr T. J. , Coates R. M. 
Published: December 2007

Abstract
Numerical simulation that provides history match of a SAGD pilot in a Cold Lake type reservoir may be expanded to include steaming of an offset well. In this theoretical configuration, the offset well is equidepth and parallel to, but 50 metres away, from the SAGD producer. After three years of SAGD operation, steam stimulation of the offset well with concomitant increased steaming of the SAGD injector provides early steam communication between the SAGD steam chest and the offset well. The result is markedly increased rate of production of bitumen and reduced steam-oil ratio. Mindful of such results, laboratory work is being undertaken to verify, and understand these results. We also encourage field-pilot testing of this process.
Matrix Acidizing Horizontal Gravel-Packed Wells for Fines Damage Removal
Authors: Stanley F. O. , Troncoso J. C. , Martin A. N. , Jamil Omar Ali 
Published: December 2007

Abstract
It’s a fact of life – many gravel packs plug up. As time passes, skin factors go up and production rates go down. Much of the money that was spent on creating a sand control completion with minimum skin may eventually count for nothing. In order to prolong the effectiveness of the gravel pack (GP) and as a added benefit reduce the need for workovers, a method was developed in the Far East to remove these fines and dramatically reduce the skin factor. The method employs relatively small volumes of a specialized HF (hydrogen fluoride) acid system, designed to penetrate into the GP and very near wellbore area. The HF acid system uses an organo-phosphonate (HV) acid to control the production of HF and to control and drastically reduce potentially damaging secondary and tertiary precipitates. The system will be referred to as HV:HF Acid in this paper.
This HV:HF Acid system can be applied to any well with a screen and/or GP that has damage caused by the migration of formation fines and/or drilling mud particles. It is not limited by the type of screen or gravel nor by the length or number of sets of screens. The method has potentially enormous implications throughout the world. Any well with a GP or screen could potentially benefit from this method of treatment, including long horizontal intervals, which up to now have been very expensive to treat, due to the larger volumes of acid normally recommended.
The results of this HV:HF Acid method will be illustrated by 3 case histories from the Far East, including horizontal wells. The observations from these treatments allow us to conclude that this method is highly successful, cost effective, and applicable to a broad spectrum of well conditions. The reduced stimulation volumes provide better economics, so that even long sections and horizontal wells can now be stimulated at reasonable costs.
Controlling Inclination in Rotary Mode in Tight TVD Corridors using a 2-Dimensional Steerable System
Authors: Rasheed W. 
Published: December 2007

Abstract
This paper is a review of a 2D Rotary Steerable System as used to control the inclination of over 200 horizontal wells. Horizontal well drilling is a common directional drilling technique enabling access to hydrocarbon reserves whilst lowering field development costs and improving well production. In order to maximise drilling in the "filet mignon" of the reservoir, geologists often require tight TVD corridors to be maintained. To achieve this, TVD corrections can be made in either rotary or oriented mode. Both methods are evaluated in terms of their effectiveness and efficiency. Factors in favour of a 2D Rotary Steerable System are: it is reliable, proven and adds significant value to the drilling process. It is effective because it enables tight TVD objectives to be met. It is efficient because it increases Rates of Penetration (ROP) whilst improving well-bore quality. These benefits are direct consequences of eliminating oriented inclination control, the smoothing out of well-bore curvature (dogleg severity) and the continuous mechanical agitation of cuttings beds. Considerable offset data (Ref 1 to 7 inc) shows how directional drillers have used rotary BHA’s to meet tight TVD objectives; much to the satisfaction of Geologists.
The Use of Brine as an Injection Fluid to Reduce Disposal Cost and Increase Gas Production
Authors: Schneider Barry , Freeman David 
Published: December 2007

Abstract
A major concern of any hydrocarbon producer is the production of brine. Since the brine is potentially environmentally hazardous certain legal guidelines for its disposal must be followed. The current process is to inject it into an empty reservoir. However, the problem of increasing cost has made this option undesirable. A possible alternative to this process is to use the brine as an injection fluid into the same active reservoir from which it was produced. The benefits from doing this are two-fold. The cost of brine disposal is reduced or eliminated and the reservoir will under go volumetric sweeping creating an increase in gas and oil production. The potential of decreasing the net production costs is important to the local producers in determining the economic feasibility of new projects.
This study includes a sample set of data that shows the level of production increase that could be expected from brine injection into a gas-condensate reservoir located in the Rose Run formation, a producing zone found throughout the Appalachian Basin. Due to the nature of a gas-condensate reservoir, the pressure increase or pressure maintenance that would be developed in the reservoir will cause the amount of gas produced to increase as well as the associated light oils. The results, calculated through application of the material balance equation of injecting 10 STB/d of brine into the reservoir shows an increase in cumulative gas recovery of 0.35%. Also included for review are the legal issues which apply to the injection of brine in the state of Ohio.
New Environmentally Safe Heat Transfer Fluid Improves The Performance of Heaters in Gas Production and Transmission Systems
Authors: Hallman John H. , Acor Lori G. 
Published: December 2007

Abstract
Indirect line heaters are used in gas production, storage, and transmission systems to boost gas temperature in order to facilitate transmission efficiency and reduce problems from water condensation and hydrates. Heat transfer efficiency in these systems is governed by conduction and convection forces, which are determined by the thermophysical properties of the fluids. An ethylene glycol/water mixture is the most common heat transfer fluid used, but it and propylene glycol suffer from less than optimal heat transfer efficiency. Glycols have low thermal conductivities and high viscosities, which degrade thermal performance, and they can have environmental and toxicity issues which limit their use in some applications.
A novel heat transfer fluid has been developed that offers both better heat transfer efficiency and a safer environmental profile than glycol systems. This fluid has individual thermophysical properties that are better than glycol systems, and may provide reduced fuel usage and higher throughput in line heaters. In addition, this new fluid is environmentally safe, being highly biodegradable if discharged, but having a low oxygen demand, reducing the chance of fish kill. The fluid is inhibited for prevention of corrosion, can be formulated for low freeze points, and is expected to be readily serviceable and stable for long life. This paper presents an analysis of the heat transfer process, a comparison of the novel fluid with glycols, and data from an initial pilot test of the system.
The Effect of Fluid Loss During Fracture Calibration Tests on the Main Treatment
Authors: Meyer Bruce R. , Jacot R. Henry 
Published: December 2007

Abstract
Fracture calibration tests (minifracs) are very successful methods for providing estimates of the fluid efficiency, closure pressure, fracture geometry and leakoff coefficient prior to the main treatment. The pressure decline data is normally analyzed using a Nolte type method for calibration and redesign of the main treatment.
Many times it has been observed that the main treatment has a higher efficiency (less fluid loss) than the minifrac which can adversely impact the fracture treatment. This paper addresses the effect of fluid loss during fracture calibration tests on the main treatment.
An analytical method for leakoff controlled by the filter cake and/or filtrate fluid has been developed for analyzing the effect of fluid loss in the formation prior to the main treatment. The main treatment leakoff velocity and volume loss equations account for the effects of the minifrac fluid loss behavior, including filter cake, spurt loss, mobility, time of fracture creation and relative fracture planes.
This paper presents the foundation for a generalized set of equations quantifying the effects of the minifrac fluid loss on the main treatment by conservation of mass and Darcy’s law. Equations are formulated for the main treatment leakoff velocity and volume loss. Numerous figures are provided that illustrate the parametric effects of the minifrac fluid loss on the main treatment efficiency and fraction of pad volume.
Hyperbolic Decline Parameter Identification Using Optimization Procedures
Authors: Jikich Sinisha A. , Popa Andrei S. 
Published: December 2007

Abstract
This paper describes two techniques for hyperbolic decline parameter identification. The first technique uses a genetic algorithm in the optimization procedure. The genetic algorithms are potentially useful in solving optimization problems when the objective function contains irregularities. The second technique uses linear regression for fitting a decline curve to data. The method weights equally the production rates during curve fitting, resulting in a stable solution. Consequently, the results are reproducible for a wide range of applications. Both methods were tested against field and literature data, demonstrating rapid, stable convergence and reproducible curves.
Reservoir Characterization Through Synthetic Logs
Authors: Mohaghegh S. D. , Goddard C. , Popa A. , Ameri S. , Bhuiyan M. 
Published: December 2007

Abstract
Magnetic resonance logs provide the capability of in-situ measurement of reservoir characteristics such as effective porosity, fluid saturation, and rock permeability. This study presents a new and novel methodology to generate synthetic magnetic resonance logs using readily available conventional wireline logs such as spontaneous potential, gamma ray, density, and induction logs. The study also examines and provides alternatives for situations in which all required conventional logs are unavailable for a particular well. Synthetic magnetic resonance logs for wells with an incomplete suite of conventional logs are generated and compared with actual magnetic resonance logs for the same well.
In order to demonstrate the feasibility of the concept being introduced here, the methodology is applied to a highly heterogeneous reservoir in East Texas. The process was verified by applying it to a well away from the wells used during the development process. This technique is capable of providing a better image of the reservoir properties (effective porosity, fluid saturation, and permeability) and more realistic reserve estimation at a much lower cost.
Scale Prediction in Geothermal Operations-State of the Art
Authors: Vetter O.J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The production of brine from geothermal reservoirs is hampered by serious and very unique scale problems.
Presently, no reliable scale prediction models are available despite many efforts in this direction. None of the known models can be proven by field results except in some very proven by field results except in some very simple situations. This paper describes the state-of-the-art to stimulate desperately needed research on the subject.
A reliable scale prediction model must take into account:ThermodynamicsKineticsFluid-Dynamics
of every conceivable mechanism leading to scale depositions. Most mechanisms are not thoroughly known. In addition, many parameters or variables required for such a model are presently unknown. Many of the variables cannot be measured at all or within the required accuracy. The fluid-dynamics are especially obscure, but also many thermodynamic variables (brine composition, ph, enthalpies, partial mole properties, etc.) cannot be determined with present instrumentation under field conditions. Expected long-term problems within the reservoir, wellbore and problems within the reservoir, wellbore and surface equipment should be considered. The gigantic mass flow, unique for geothermal operations, is not well understood in many details and can create new and complex situations.
Present models are not scale predicting models but chemical models which could eventually become an integral part of reliable scale predicting models. Even these chemical models still predicting models. Even these chemical models still show vital shortcomings.

Introduction

SCALE IN GEOTHERMAL OPERATIONS
The production, utilization and/or reinjection of brine found in liquid-dominated reservoirs is often hampered by serious and very unique scale problems. Some of these scale problems are so severe that entire field operations are endangered. Some scale problems seem to be rather "harmless" at the present time, but could offer severe and costly long-term interferences with the economical and trouble-free production and utilization of these brines.
High-Performance Reservoir Simulation With Parallel ATHOS
Authors: Magras J-F. , Quandalle P. , Bia P. 
Published: December 2007

Abstract
One way to reduce uncertainties in reservoir simulation is to use geostatistical fine grids with little or no upscaling, but this approach can lead to excessively large simulations with literally millions of gridblocks. In the case of compositional studies, another way is to increase the number of components. Running this kind of large simulations requires the use of powerful computers with vector or parallel architectures.
In general, existing simulators must be restructured to make the use of parallel computers possible and efficient. Reengineering and re-writing of the source code are time and cost consuming for multi-purpose simulators. Previous papers have described the use of MPI (Message Passing Interface) to trigger parallel processing. This approach is delicate to manage as it involves incremental reengineering of the code, which is rather difficult to perform.
We present our experience of parallelization of an existing all-purpose reservoir simulator for shared memory platforms, using OpenMP instructions. The paper describes the methodology of parallelization in three incremental steps: first identifying the most CPU time consuming routines. Second, parallelizing these routines. Finally, developing efficient dedicated parallel preconditioned solvers. It is shown that this approach is easier to manage than the MPI approach while being as efficient on shared memory parallel architectures like SGI Origin2000, IBM SP3, or Compaq ES40.
Several large simulations, typically one million gridblocks, are presented to show the capabilities of ATHOS simulator on these parallel architectures. Simulations carried out on NEC SX5 are also presented, for comparison with a vector computer. These simulations include the main physical features of the ATHOS simulator used for black-oil, compositional and fractured reservoir studies.