bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Methodologies To Evaluate the Risk of Petroleum Fields
Authors: Ligero Eliana L. , Risso Fernanda V. Alves , Schiozer Denis J. 
Published: December 2007

Abstract
A risk analysis process can be applied to several phases of a petroleum field. The methodologies required in the decision-making process depend on the level of uncertainties, which vary according to the field phase. This work is focused on the development phase and the decision process is based on probabilistic procedure to represent all possible scenarios of the reservoir.
The uncertain attributes can be combined through derivative tree or Monte Carlo technique. The risk can be evaluated by the Net Present Value, which depends on the reservoir performance. The reservoir production prediction can be obtained through numerical simulation or response surface. Most of works consider only the application of these procedures and comparisons of these techniques are not well evaluated. The goal of this work is to apply the alternative combinations of these techniques to petroleum fields and compare them to determine the result reliabilities.
The combination of Monte Carlo and numerical simulation is not viable, in some cases, due to the great number of simulations. The attribute combination by derivative tree can be an alternative, but can also yield a high number of simulation runs. Alternatives to speedup the process are to reduce the number of attributes and their discretization levels or substitute the conventional reservoir modeling by faster ones, such as the response surface, which is suited to evaluate the impact of uncertainty on production forecasts.
The contributions of this work are to: (1) to determine if the response surface can substitute the reservoir simulator, (2) to evaluate the capability of the response surface to substitute the reservoir simulator in order to obtain the risk curves, (3) to provide a guide to select an adequate combination of techniques according to the desired precision and (4) to determine if it is possible to reduce the number of simulation runs, maintaining the precision.
Fighting Lead and Zinc Sulphide Scales on a North Sea HP/HT Field
Authors: Orski K. , Grimbert B. , Menezes C. , Quin E. 
Published: December 2007

AbstractLead and Zinc sulphides have recently become a concern in some HP/HT gas fields.The Elgin/Franklin Field (Central Graben North Sea), started production early 2001. The wells produce a condensate-rich gas from the Fulmar and Pentland reservoirs, with initial temperature of 200 degC and pressure of 1100 bar.Mid-2002, the first Calcium Carbonate obstructions appeared downhole on several wells and resulted in a progressive production decrease.Moreover, lead and zinc sulphides were identified on well G6. The heavy scaling from its surface-controlled subsurface safety valve (SCSSV) to the Christmas Tree caused the well to be shut-in from end 2004 until an appropriate programme of remediation and prevention was implemented.Lead and zinc sulphides had not been predicted during the initial scaling studies. While several publications mention these on HP/HT fields, little information is available on downhole inhibitor squeeze.Scale removal lab studies included dissolution of the recovered scales and corrosion tests. A different fluid package was selected for downhole and SCSSV conditions.Scale remediation using downhole acid washes proved efficient by increasing wells production.The upper part of the completion on well G6 was cleared from scales by a coiled tubing operation in mid-2005 and the integrity of the SCSSV was restored.To prepare for scale prevention, a benchmarking of inhibitors from four suppliers was performed in a third party lab over a period of more than two years. Appropriate equipment was put in place and the methodology was optimised. The tests were conducted in anaerobic conditions with thermally aged chemicals.Two scale inhibitor squeezes were deployed, although progress is still to be made for "exotic" scale prevention.This paper presents the Elgin/Franklin scale-control strategy from a thorough fluids selection to the field deployments. Results and optimisation are discussed
Evaluation of a Conventional Steam Drive With Ancillary Materials: North Kern Front Field
Authors: Eson Rod L. , O'Nesky Stephen K. 
Published: December 2007

ABSTRACT
Steam drive projects account for over 64% of all of the United States' Enhanced Oil Recovery (EOR) production, nearly 156,000 BOPD (24,000 m3/d). Even though steam drive is the most successful of all EOR processes, it is not without its problems. Gravity segregation and poor areal and vertical sweep efficiencies have limited recoveries in many heavy oil reservoirs. In many instances the injected steam prematurely breaks through into producing wells creating steam channels. If this steam channeling can be controlled to some degree and the steam is forced to contact more of the reservoir, overall recoveries can be improved. This paper documents efforts under a Department of Energy cost sharing contract to reduce steam channeling in a conventional steam drive using ancillary materials.
A steam foam solution and a steam foam encapsulated in a polymer gel are being introduced in four steam injection patterns in the North Kern Front Field near Bakersfield, California. The ability of the ancillary materials to improve recovery will be determined through injection profiles, chemical tracer surveys, casing vent gas analyses, core and log data, and residual oil saturation data, as well as through temperature and production monitoring.
It has been shown that in-situ steam foams can be used to alter the steam injection profiles to prevent excessive steam channeling. Results after injection of ancillary materials for approximately 18 months indicate that improvements in both the areal and vertical sweep efficiencies have been found in the four treated patterns when compared to the untreated control patterns. Several techniques are still under evaluation to determine the exact amount of incremental oil produced.
Disscussion of production response will be limited to two of the four treated patterns, Witmer B2-3 and Witmer B2-5. A comparison of these two patterns to the Witmer control pattern, Witmer A2-7, indicates approximately 52 B/D (8 mv/d) of incremental oil is being produced as a result of the weekly chemical treatments.
A Numerical Model for Multiphase Flow on Oil Production Wells
Authors: Ferro S. P. , Goldschmit M. B. 
Published: December 2007

Abstract
A numerical model for the analysis of multiphase flow on vertical or slightly inclined wells has been developed. The model calculates flow properties (velocity of each phase, volumetric fraction of each phase, pressure and fluids properties) on gas-oil-water wells as function of depth. Fluids properties are obtained under the assumption of black oil model by means of correlations taken from literature, requiring only petroleum °API and the gas specific gravity as input data.
The model may be applied to simulate both liquid flow and gas-liquid flow. In this case, different flow patterns are taken into account: -bubble, slug, dispersed bubble and annular-depending on flow conditions, which are determined from fluid properties and production rates of oil, gas and water. Flow in tubings consisting of several sections with different diameters and inclinations may also be simulated.
The model was validated by comparisons of measured and calculated the pressure variation along the well Good agreement was found between the numerically predicted pressure drop and measurements taken from different databases from open literature. As a consequence the proposed model proves to be a reliable tool to describe the flow on oil-gas-water wells.
The developed numerical model takes into account the most relevant effects that take place in a production well including multiphase flow, presence of different flow pattern, mass transfer from gaseous to liquid phase and influence of gas-liquid flow pattern on wall friction. Special attention is paid to the velocity profile of each phase along the well. Ishii's model for two-fluid flow is used to prescribe the slip velocity between liquid and gaseous phases and to determine the acceleration term contribution to the pressure gradient. This model is actually being employed for corrosion rate calculations inside production wells.
Wireline Logs and Core Data Integration in Los Molles Formation, Neuquen Basin, Argentina
Authors: Stinco L. P. 
Published: December 2007

Abstract
In Agua del Cajón Block (Neuquen Basin, Argentina), petrophysical data was treated according to deductive and inductive methods in order to get the most from both approaches. Deductive methods comprise those methodologies that seek to differentiate the data by the computation of a set of component proportions whose identification is linked with wireline log data by a set of response equations. The model is built considering the number of components and the number of variables (data curves). Normally, measures to detect mismatches and gross errors are included in the techniques, although mathematical consistency is not a guarantee of geological accuracy. This situation is well represented by standard log analysis. On the contrary, inductive methods establish their classes or transformations based on the data set and do not depend on any predetermined correlation among the components. These methods tend to isolate distinctive patterns and to derive classifications or new variables that can be interpreted with a physical meaning. Cluster analysis is one example of these types of methodologies. In this study, wireline logs (spontaneous potential, gamma ray, shallow-medium and deep resistivities, neutron, density, sonic, photoelectric factor, and microrresistivity images) were calibrated according to the lithological variations – facies- described in cores taken from the reservoirs developed within Los Molles Formation. These facies which comprised crudely bedded gravel with imbrication (Gm), medium to coarse, even pebbly sand with planar crossbeds (Sp), very fine to very coarse sand with horizontal lamination (Sh) and massive mud-silt (Fm), were linked with electrofacies using multivariate analysis, particularly cluster analysis. The first two facies are the actual reservoirs targets within the field. After the analysis of ten wells within the field, a more thorough understanding of the petrophysical properties and a deeper understanding of the dynamic responses of the reservoirs was achieved.
Improved ASP Design Using Organic Compound-Surfactant-Polymer (OCSP) for La Salina Field, Maracaibo Lake
Authors: Guerra E. , Valero E. , Rodriquez D. , Gutierrez L. , Castillo M. , Espinoza J. , Granja G. 
Published: December 2007

Abstract
In design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability.
The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field.
Correction of Bound and Free Fluid Volumes in the Timur-Coates Permeability Equation for the Presence of Heavy Oil—A Case Study From the Golfo San Jorge Basin, Argentina
Authors: Gómez Hugo , Stinco Luis , Nawratil Alejandro , Lopetrone Javier , Romero Pedro , Saavedra Benito 
Published: December 2007

Abstract
In the Golfo San Jorge basin, Argentina, the Timur-Coates permeability index obtained from the T2 distributions is considered as a good indicator of reservoir quality and has been used as a very important variable for production forecast. However, when heavy oil is present, having a relaxation time below the standard free fluid-bound fluid cut-off of 33 ms, it is conventionally counted as part of the bound fluid, independently of its mobility. For this reason, in case of movable heavy oil, the standard Timur-Coates permeability index using 33 ms tends to be always pessimistic, in eventual disagreement with other reservoir quality indicators as the SP curve, depositional environment, cuttings and production data.
In order to perform a correction of the permeability index for the presence of heavy oil, two layers of one well from the Diadema field, with a complete set of SP, Resistivity, MREX and production data was selected and evaluated using 2DNMR (T2intrinsic - Diffusion) maps, which uses the diffusivity contrast for discriminating between capillary bound water and heavy oil, within the bound fluid window (BVI). The clay bound water (CBW) cut off has been chosen to be 6 ms.
The results show that the corrected Timur-Coates permeability can increase by an order of magnitude in the tested zone of the reservoir layers, but can become even higher within the whole layers, which is a reasonable estimation for the corresponding channel depositional environment. The production data also support the interpretation, indicating that the NMR rock quality estimation can be performed more accurately even in the presence of heavy oil. The corrected Timur-Coates permeability values can be used in a future update for forecasting well production.
Heavy-Crude-Oil Upgrading With Transition Metals
Authors: Nares H. R. , Schacht-Hernández P. , Ramírez-Garnica M. A. , Cabrera-Reyes M. C. , Noé-Valencia L. 
Published: December 2007

Abstract
In this paper are discussed the effects of some metallic oxides used to upgrade the heavy crude oil properties. The underlying objective is to increase the mobility of the oil in the reservoir by reducing viscosity and improving the oil quality using alumina supported transition metals and liquid phase transition metals catalysts (derived from either acetylacetonate or alkylhexanoate compounds), both homogeneously mixed with heavy crude oil. This heavy crude oil upgrading is based on the decrement of the asphaltenes, resins, and sulfur contents, and the increment of its API gravity, and strong reduction of viscosity.
In the present work the heavy crude oil from the Golf of Mexico was studied. The API gravity was increased from 12.5 to 21-26, the kinematics viscosity was decreased from 18,130 to 100-8 cSt (at 298 K), the asphaltene content was reduced from 26 to 7 wt%, the sulfur was removed in the range of 30 to 60 wt%, and the distillable fraction was increased between 20 to 30 wt%, and determinated by Simulated Distillation and True Boiling Point (TBP).
Treatment of Wellbore Storage Effects in the Analysis of Pressure Buildup and Drawdown Tests
Authors: Lo Tak Sing , Youngren Gary K. 
Published: December 2007

ABSTRACT
In this paper, we propose a new method for detecting the beginning of the useable portion of a Horner plot. The method is based on asymptotic solutions of the well-bore material balance in a form used in numerical simulators. They show that the Extent of Well-Bore Dominance, EWBD, which measure the effect of well-bore storage on pressure drawdown and buildup test results, is a function of well-bore storage capacity, the formation producing capacity (related to the productivity index), the bottom-hole pressure, and its time rate of change. EWBD always decreases to zero as the reservoir response assumes control of the bottom-hole pressure. This is true for any size well-bore, and is unaffected by the complicated flow history during the opening and closing of the valve. Here, the theoretical basis of EWBD is developed, followed by a description of its implementation in automated Horner analysis computer programs. Five examples are presented which demonstrate that the automated Horner analysis program can perform a classical Horner analysis rapidly, accurately, and reliably.
Evolutionary Optimization of Smart-Wells Control under Technical Uncertainties
Authors: Almeida Luciana Faletti , Túpac Yvan J. , Lazo Lazo Juan G. , Pacheco Marco Aurélio , Vellasco Marley M. B. R. 
Published: December 2007

Abstract
This work presents a system, based on Evolutionary Algorithms, capable of optimizing the controlling process of intelligent wells technology present in Intelligent Fields. The control refers to the opening and shutting operation of valves in these wells. A proactive controlling strategy to find a configuration of opening and shutting valves was assumed. It anticipates and maximizes the oil recuperation, delays the water cut on producer wells, and reduces the quantity of produced water, maximizing the wells life. As a result, the obtained configuration promotes the increasing of NPV (Net Present Value). The use of control strategies to benefit the completion identifies the field as intelligent. The proposed representation can formulate a controlling strategy for all valves, for any desired time interval. To improve the decision making for using or not using smart wells, the fault risk of the control device existing in the intelligent completions was considered into optimization. For this purpose, the system applies Monte Carlo simulation together with some simulation techniques for convergence acceleration and uncertainties representation by probability distributions. Even considering the existence of uncertainties into valves operation, the results obtained in the tests reveal significant gains by using the intelligent completion on the field such as: increasing the recuperation factor of the field, reducing the water inflow and increasing the longevity of the field. For all valves representations, improvements were achieved when compared with the case without valves. The conception and implementation of an intelligent system, capable of supporting the development and management of intelligent petroleum fields, builds up an important advantage for the spreading of intelligent field technology. The results obtained in this work demonstrate that the intelligent control of valves can become a competitive difference in the strategy of hydro-carbon production.
Miscible EOR Processes: Existence of Elliptic Regions in Gasflood Modeling
Authors: Dutra T. A. , Pires A. P. , Bedrikovetsky P. G. 
Published: December 2007

Abstract
Enhanced Oil Recovery (EOR) methods include injection of different fluids into reservoirs to improve oil displacement. Analytical models for 1-D displacement of oil by gas have been developed during the last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process are not dependent on transport properties. The model for one-dimensional displacement of oil by miscible fluids is analyzed in this paper. The main result is the splitting of thermodynamical and hydrodynamical parts in the EOR mathematical model. The introduction of a potential associated with one of the conservation laws and its use as an independent variable reduces the number of equations. The reduced auxiliary system contains just thermodynamical (equilibrium fractions of each phase, sorption isotherms) variables and the lifting equation contains just hydrodynamical (phases relative permeabilities and viscosities) parameters while the initial EOR model contains both thermodynamical and hydrodynamical functions. So, the problem of EOR displacement was divided into two independent problems: one thermodynamical and one hydrodynamical. Therefore, phase transitions occurring during displacement are determined by the auxiliary system, i.e. they are independent of hydrodynamic properties of fluids and rock. For example, the minimum miscibility pressure (MMP) is independent of relative permeabilities and phases viscosities. The new technique developed permits splitting for both self-similar continuous injection problems and for non-self-similar slug injection problems. Splitting significantly reduces amount of calculations for sensitivity study with respect to transport properties: auxiliary thermodynamic problem may be solved once for given reservoir and injected compositions; variation of relative permeabilities and viscosities should be performed just in the solution of one transport equation. In this paper, different analytical solutions for 4-component gas injection problems are analysed. It was considered the injection of nitrogen and hydrocarbon gases into a three-component liquid reservoir fluid. The eigenvalues of the system are related to the propagation velocity of each component in porous media. The existence of elliptic regions (complex eigenvalues) is well known in three-phase flow, but for the first time it is shown that this feature may also occur in two-phase flow. The independence of compositional dynamics on transport properties can be used for testing numerical compositional simulators. If the mobility ratio is close to one, this model may be applied in the development of streamlines simulators.
Tracer Experiments in Eastern Devonian Shale
Authors: Cook Thomas L. , Brown Lee F. , Meadows Wayne R. 
Published: December 2007

ABSTRACT
For the purpose of characterizing the properties of the Eastern Devonian gas shale, a seven-day tracer experiment was carried out in August of 1981 by the Los Alamos National Laboratory as part of the DOE's Offset-Well Test. Two wells had been drilled in a Columbia Gas Company field in southeastern Ohio, each with a downhole separation of approximately 120 feet from an existing production well. The isoceles triangle formed by the three wells had an apex angle of approximately 110 degrees. About 56,000 SCF of nitrogen were injected into a producing zone located at a depth of 3300 feet in one of the wells. Gas was then produced from the various wells at different rates and pressures for the duration of the test. Both pressure and gas composition in the three wells were monitored thoughout the test.