bluuebunny/crossref_metadata_2025_split huggingface dataset:
Surrogate Modeling-Based Optimization of SAGD Processes
Authors: Queipo Nestor V. , Goicochea P. Javier V. , Pintos Salvador 
Published: December 2007

Abstract
This paper presents a solution methodology for the optimization of geometrical and operational parameters of SAGD processes in a heterogeneous and multiphase petroleum reservoir. The optimization refers to the maximization or minimization of performance measures such as net present value, cumulative oil production or cumulative steam injected.
The solution methodology includes the construction of a "fast surrogate" of an objective function whose evaluation involves the execution of a time-consuming mathematical model (i.e. reservoir numerical simulator) based on neural networks, DACE modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors.
The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss-Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general-purpose global optimization methods such as, simulated annealing, genetic algorithms, and pattern search methods.
The methodology is evaluated using a case study with vertical spacing, steam injected enthalpy, injection pressure and subcooling as the sought parameter values in a SAGD process that optimize a weighted sum of cumulative oil production and cumulative steam injected for a selected reservoir. From the results, it is concluded that the methodology can be used effectively and efficiently for the optimization of SAGD processes. In addition, the optimization approach holds promise to be useful in the optimization of objective functions involving the execution of computationally expensive reservoir numerical simulators, such as those found, not only in oil recovery processes, but also in other areas of petroleum engineering (e.g. hydraulic fracturing).
Mechanistic Modeling of Solution Gas Drive in Viscous Oils
Authors: Arora P. , Kovscek A. R. 
Published: December 2007

Abstract
Solution gas drive in reservoirs containing heavy and viscous oil is not well understood. This paper develops a mechanistic population balance model for describing the process of bubble nucleation and growth. The model is applied to both light and viscous oils. The primary modeling concept is a continuum bubble population balance. Appropriate rate equations are derived for two theories of bubble nucleation described in the literature—instantaneous nucleation (IN) and progressive nucleation (PN). The results of simulations for the IN and PN models are compared to experimental data reported elsewhere for light oil and to new data for viscous oils. Model parameters are all physically based. Within the IN model, the number density of bubbles must be specified while the PN model requires the cavity size distribution of the porous medium as input. The PN model matches the experiments somewhat better, but is more demanding computationally. Interestingly, the population balance description of either model does not require a critical supersaturation to be exceeded before the onset of bubble nucleation and growth. Supersaturation is the difference between the equilibrium and dynamic liquid pressure of a system. Liberation of gas from solution at the thermodynamic bubble point and the bubble growth equations presented here well describe the kinetics of the gas phase and pressure response of the systems examined.
Thermodynamic Characterization of a PVT of Foamy Oil
Authors: Romero Douglas J. , Fernandez Belkis , Rojas Gonzalo 
Published: December 2007

Abstract
This work is based on theoretical studies and/or experimental observations carried out diverse authors whom have investigated on the "foamy oil phenomenon" developing a methodology to characterize these crude oils thermodynamically, taking as bases nonconventional PVT analysis and using as research tool the application of equations of state and methods known for the determination of the equilibrium constants liquid-gas. It is presented two new correlations developed in this work for the calculation of the viscosity of heavy crude oils, which are based on values of molar fractions of liquid and gas in equilibrium. The proposed methodology was validated using conventional and nonconventional PVT data of wells located in the Orinoco Belt, Jobo Field, Morichal Area obtaining excellent results and showing that the proposed methodology is applicable to conventional and nonconventional heavy crude oils in all the possible scenes, that is to say, whether necessary information is available.
Practical Methods to Optimizing Production in a Heavy-Oil Carbonate Reservoir: Case Study From Issaran Field, Eastern Desert, Egypt
Authors: Waheed Arshad , El-Assal Hossam , Negm Ehab , Sanad Medhat , Sanad Osama , Tuchscherer Gary , Sayed Mohamed 
Published: December 2007

Abstract
The Issaran field, a heavy-oil reservoir with reserves of approximately 500 MM bbl of oil, was discovered in 1981. The producing horizons were carbonate formations of Miocene age occurring at an average depth of 2,200 ft. The oil being produced on artificial lift was of 9° to 12° API in a viscosity range of 3,000 to 5,000 cp.
Before mid-1999, nine wells had been drilled in the field with a cumulative production of about 450 BOPD. This field did not command high priority because of its low productivity and the low prices that heavy crude attracts. However, with the oil price increases in 1999 and 2000, the Egyptian government made a concerted effort toward developing this field. New and applied technology provided considerable returns within 1 year of new investments. The field has been producing as much as 1,800 BOPD (a four-fold increase), from five new wells drilled in the area.
Plans were made for thermal recovery in the form of steam stimulation for this heavy-oil reservoir, but first, it was necessary to produce under "cold production." Several industry publications&lt;SUP&gt;1-3&lt;/SUP&gt; have addressed cold production, predominantly pertaining to sandstone reservoirs. This paper highlights the experiences, challenges, and practical solutions in optimizing production from a fractured, carbonate reservoir. Several leading-edge technologies and optimization techniques that are effective in less-challenging reservoirs have contributed tremendously to enhancing production from this heavy-oil reservoir. The path to success began with the definition of the reservoir-flow mechanism, optimized perforating schemes, ehnanced carbonate stimulation, and improved completion designs.
Improved Permeability Estimates in Carbonate Reservoirs Using Electrofacies Characterization: A Case Study of the North Robertson Unit, West Texas
Authors: Mathisen Trond , Lee Sang Heon , Datta-Gupta Akhil 
Published: December 2007

Abstract
We propose a simple and cost-effective approach to obtain permeability estimates in heterogeneous carbonate reservoirs using commonly available well logs. Our approach follows a two-step procedure. First, we classify the well log data into electrofacies types. This classification does not require any artificial subdivision of the data population but follows naturally based on the unique characteristics of well log measurements reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis, model-based cluster analysis and discriminant analysis is used to identify and characterize electrofacies types. Second, we apply non-parametric regression techniques to predict permeability using well logs within each electrofacies.
Our proposed method has been successfully applied to the North Robertson Unit (NRU) in Gaines county, west Texas. Previous attempts to derive permeability correlations at the NRU have included rock type identification using thin section and pore geometry analysis that can sometimes be expensive and time-consuming. The proposed approach resulted in improved permeability estimates leading to an enhanced reservoir characterization and can potentially benefit both daily operations and reservoir simulation efforts. The successful field application demonstrates that the electrofacies classification used in conjunction with sound geologic interpretation can significantly improve reservoir descriptions in complex carbonate reservoirs.
Modeling Technique of Asphaltene Precipitation
Authors: Li Min , Guo Ping , Li Shilun 
Published: December 2007

Abstract
Study of three phase equilibrium has been seen from many literatures. Most research on modeling of asphaltene precipitation has remained in qualitative description stage. Even though quantitative calculation of asphaltene precipitation can be seen from some reports. However, quantitative calculation of asphaltene precipitation with three phase flash algorithm is unstable because gas-liquid-solid material balance equations is highly non-linear equations. In the light of general view that there are not heavy hydrocarbons with high molecular weight including asphalt in gas phase, technique of stable asphaltene precipitation calculation is put forward by the paper. The recommended technique in the paper separates gas-liquid-solid equilibrium into two parts: gas-liquid and liquid-solid equilibrium. Liquid phase is a bridge between gas and solid phase and solid precipitates always from liquid phase. Gas-liquid equilibrium is described through EOS and fugacity of asphaltene determined from gas-liquid equilibrium should be compared and accord with fugacity of pure solid phase of asphaltene. In this way, modeling of three phase equilibrium becomes easier and more stable. The validation of the model with experimental data is described also in the paper. Additionally, the paper puts forward gas-liqiud-asphaltene material balance equations which can be deduced from general three phase material balance equations and are not similar to them in forms.
Risk Reduction with a Fuzzy-Expert Exploration Tool
Authors: Weiss W. W. , Balch R. S. , Broadhead R. F. 
Published: December 2007

Abstract
Incomplete or sparse information on types of data such as geologic or formation characteristics introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries, including medical diagnostics, have demonstrated beneficial results. A state-of-the-art exploration "expert" tool, relying on a computerized data base and computer maps generated by neural networks, is proposed for development through the use of "fuzzy" logic, a relatively new mathematical treatment of imprecise or non-explicit parameters and values. Oil prospecting risk can be reduced with the use of a properly developed and validated "Fuzzy Expert Exploration (FEE) Tool."
This tool will be beneficial in many regions of the US, enabling risk reduction in oil and gas prospecting and decreased prospecting and development costs. In the 1998 - 1999 oil industry environment, many smaller exploration companies lacked the resources of a pool of expert exploration personnel. Downsizing, low oil prices and scarcity of exploration funds have also affected larger companies, and will, with time, affect the end users of oil industry products in the US as reserves are depleted. The proposed expert exploration tool will benefit a diverse group in the US, leading to a more efficient use of scarce funds and lower product prices for consumers.
A Strategy for Attacking Excess Water Production
Authors: Seright R. S. , Lane R. H. , Sydansk R. D. 
Published: December 2007

Abstract
This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution.
Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems— i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problems—i.e., three-dimensional coning, cusping, or channeling through strata with crossflow.
A Completion Technique For Overcoming Formation Damage
Authors: Colle Ed A. 
Published: December 2007

Abstract
A technique has been developed to overcome the formation damage of drilling, cementing, and perforating.
Using this technique, you often get natural well completions in zones that heretofore required extensive stimulation to overcome the damage.
Basically, the technique is perforating with deep penetrating shaped charges and immediately backsurging with maximum differential pressure to the wellbore. This often is done with the tubing practically dry, thereby fully utilizing the natural formation pressure to give clean, efficient flow charnels after perforating.
Results to date indicate you get more clean, producing perforations than with any other system.
The paper discusses the mechanical equipment that has been designed and field proved for running the guns on tubing below retrievable packers. Various hookups are shown for single, dual, or commingled completions.
Depth-control techniques for correct gun positioning are explained.
Field results of over 500 completions from Wyoming to the Gulf of Mexico are discussed, with emphasis on results completing fluid-sensitive formations.

Introduction
The increased demand for gas and oil in recent years has emphasized the need for increased initial well production and continued high production rates.
Intrastate gas demand at higher prices has created a tremendous opportunity for improved well completion engineering, especially in areas where the gas production was formerly unprofitable.
Therefore, a new approach has been developed and field proved on over 500 completions from Wyoming to the Gulf of Mexico.
Basically, formation damage of drilling, cementing, and perforating are overcome by perforating with deep penetrating shaped charges and immediately backsurging with maximum differential pressure to the wellbore. Thus, formation energy is utilized to give good, clean flow channels.

THROUGH-TUBING GUN APPROACH
Overcoming perforating damage with differential to the wellbore when shooting has been used for some time, especially with through-tubing type perforators rum on wire line. Fig. 1 illustrates this approach is not always a good solution to the problems of compaction and plugging.
In consolidated formations and/or fluid sensitive, shaley zones, the through-tubing guns may not give sufficient penetration to get beyond the invaded zone. Then, too, the small perforation hole size and the limited differential pressure used for wireline operation can result in having a lowered permeability zone and debris clogged perforation. Flow area then is greatly reduced.
Reduced flow area can result in excessive velocities that may cause water coning and/or sand flow.

WIRELINE CASING GUN APPROACH
Fig. 2 illustrates perforation with a casing gun and deep penetrating charges run in the conventional manner on wire line. The differential pressure is into the formation, and mud or a completion fluid is in the wellbore. The debris from the shaped charge, the cement, the formation displaced, and the well fluid often combine to form a crushed and compacted zone.
A Theoretical and Experimental Study of the Steady State Capillary End Effect
Authors: Hadley G.F. , Handy L.L. 
Published: December 2007

Abstract
Formulas are derived for calculating the steady state saturation profile and pressure profile resulting from the end effect. A numerical integration is required to obtain the results. Two dimensionless numbers containing various parameters of the system are introduced, which, along with the viscosity ratio and the fractional flow of one component, characterize the system. It is suggested that the magnitude of the end effect can be estimated just knowing these numbers. Sample calculations are carried out showing the influence of the various parameters on the end effect.
A discussion is given to show that in the measurement of relative permeability curves by the dynamic method, the end effect has a large influence on the preferentially nonwetting phase relative permeability curve if the pressure drop is measured in the wetting phase. If the pressure drop is measured in the nonwetting phase, the largest error appears in the wetting phase curve. If the pressures are measured in both phases, the errors tend to be self-correcting for each relative permeability curve.
End effects were measured experimentally on a Boise core for water-oil and gas-oil systems. Three different rates were used in each series. There was satisfactory agreement between the theory and experimental results.

Introduction
The so-called capillary end effect or the holdup of the preferentially wetting phase at the outlet of a porous medium during the simultaneous flow of two or more fluids has received considerable attention from time to time in the oil industry. In particular, there has been interest in how much influence the end effect has on the production from oil reservoirs and how much laboratory measurements of relative permeability are dependent on the end effect. Even though there has been quite a bit of qualitative discussion of these matters, there has been very little quantitative theoretical or laboratory work performed. The present investigation gives a fairly complete theoretical treatment of the capillary end effect within the bounds of Darcy's law and the capillary pressure relation. Experimental results on end effects are also presented for water-oil and gas-oil systems.
The end effect comes about at the efflux face of a core or around the wellbore in a reservoir because of the discontinuity in capillary pressure when the flowing fluids leave the porous medium and abruptly enter a region where there is no capillary pressure.
Transient Pressure Analysis of Bounded Communicating Reservoirs
Authors: Zhao Gang , Thompson Leslie G. 
Published: December 2007

Abstract
This paper presents a general methodology for computing semi-analytical transient pressure responses for bounded communicating reservoirs. It focuses on the hydraulic fluid contact relationship inside the complex geometry reservoir, i.e., the fluid flow between different parts of the reservoir, and reveals the transient pressure behaviors of different kinds of bounded communication reservoirs, such as parallel communicating channels and branching channels. It can also predict the transient pressure behaviors of channel and splay reservoirs and other complex reservoir shapes.
The method proposed consists of decomposing the original complex-geometry bounded reservoir into a set of simple-geometry reservoirs, which interact with each other by transfer of fluid and equality of pressure over the regions where they are in hydraulic contact. Analytical solutions are written down for each of the simple bounded reservoir components in terms of the unknown pressures and fluxes at their boundaries, and the coupled systems are solved for the desired wellbore pressure responses.
The source and sink method is used to compute the pressure response in the Laplace domain and the results are inverted numerically using the Stehfest Inversion algorithm. The proposed methodology can be extended to any system where the Laplace-space solution can be easily written in terms of integrals of real-space source/sink functions, including production at constant bottom-hole pressure, wellbore storage effects or naturally fractured systems. Minimizing the computational requirement is still a topic of research. Excellent pressure responses and their derivatives have been obtained for the bounded communicating reservoirs. Further research will be focused on the behaviors of other naturally-occurring complex geometry reservoirs formed through depositional and tectonic processes.
Viscoelasticity of ASP Solution is a More Important Factor of Enhancing Displacement Efficiency than Ultra-low Interfacial Tension in ASP Flooding
Authors: Hou Jirui , Liu Zhongchun , Xia Huifen 
Published: December 2007

Abstract
In Alkali-surfactant-polymer flooding, although the high concentration of alkali, for example 1.2%wtNaOH in ASP flooding in Daqing oilfield, can lead to an ultra low interfacial tension, it brings many new technological problems such as scale production in well bore, reduction of injectivity resulted from producing of alkali scale etc. The sharply shortened period of checking pump have adversely influenced the production of wells.
In this paper, the effect of alkali on viscoelasticity of displacing phase and the effect of viscoelasticities of ASP solution on displacement efficiency has been studied by studying rheology of ASP solution and physical simulating of ASP flooding which included the macro-displacement experiments in heterogeneous models and micro-displacement experiments to ASP flooding in Daqing oilfield. The mechanism that the viscoelasticity is more important than ultra low interfacial tension as a factor of affecting displacement efficiency has been confirmed. The sorts of surfactant, which can reach ultra low interfacial tension, are limited and expensive. These surfactants solution also need to add a high concentration of alkali to get ultra low interfacial tension. But for adding alkali, the viscoelasticity of ASP solution is decreased, and new technological problems have been brought about. On the contrary, decreasing the amount of alkali and weakening the demand of low interfacial tension can increase viscoelascity of ASP solution. The experimental results show that the displacement efficiencies of ASP solution with low alkali concentration aren't less than that with high alkali concentration and ultra low interfacial tension. The results not only enlarges the selectable range of surfactant and decreases the costs of ASP flooding, but also solves the problem of Alkali scale, and are of great importance to the further development of ASP flooding and its application.
In China, It is the first time to study the effects of ASP solution viscoelasticity on displacement efficiency by macro and micro physical simulation. Ultra low interfacial tension is not a necessary condition for enhancing oil recovery. The limit of capillary number theory has been discussed in ASP flooding. The mechanism of ASP flooding has been recognized again.