bluuebunny/crossref_metadata_2025_split huggingface dataset:
Incorporating Seismic Attribute Porosity into a Flow Model of the Grayburg Reservoir
Authors: Weinbrandt R.M. , Trentham Robert C. , Robinson William 
Published: December 2007

Abstract
The Grayburg reservoir of the Foster - South Cowden field has been produced since 1938 and water-flooded since 1962. Production had declined to near abandonment level at the start of this project. The initial approach to construction of the flow model was conventional. Logs and cores provided the basis for a geological model. Production data was assembled and validated as were the few measured pressures taken early in the fields history. Production testing of all wells was initiated with new equipment to provide accurate current production data. Pressure transient testing of all wells was initiated to provide accurate current pressures. History matching pressures and water cuts validated the flow model and the flow model has since guided field operation, subject to the limits imposed by the spacing of the well data which was one reliable well log per 32 acres of reservoir. At this scale compartmentalization, heterogenialy, of the reservoir was obvious, requiring the use of 3-D seismic to define porosity in the area between wells.
The 3-D seismic data set was reprocessed to retain high frequencies, thereby improving vertical resolution to the range of 50 feet. Seismic traces sample areas are 110 by 110 feet (bin size). Seismic inversion model traces exhibit a high degree of correlation to the well log data and a correlation was developed between seismic velocities and porosity for each geologic zone. The correlation was used to develop porosity maps for each zone used in the flow model. The resulting flow model was validated through the history matching process and used to guide the redevelopment of the waterflood.
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A Closer Look at Non-Uniqueness During Dynamic Data Integration into Reservoir
Authors: Cobena Rafael H. , Aprilian Salis S. , Datta-Gupta Akhil 
Published: December 2007

Abstract
Characterizing heterogeneous permeable media using dynamic data such as transient pressure, tracer or multiphase production history typically requires the solution of an inverse problem. It is well known that such inverse problems are ill- posed in general and cannot uniquely constrain the detailed variations in reservoir properties. In this paper, we systematically examine the nature of the objective function during multiphase production data integration to explore the source of the non-uniqueness and the impact of some proposed remedies using prior information, structural analysis or smoothness conditions. The results are compared with ensemble inference from multiple realizations of permeability field generated from dynamic data without using any prior information. We show that continuous nonlinear trade-off between parameters is the major source of non-uniqueness during dynamic data integration. Another source is the presence of isolated, distinct local minima. Our results clearly demonstrate the danger associated with using dynamic data in isolation and the potential pitfall associated with the dictum finer is better'. We show that during reservoir characterization, there is a trade-off between high resolution and minimizing uncertainty and a compromise must be made. Finally, recognizing the general lack of prior information during reservoir characterization, the relative merits of different approaches to remedy the ill-posed behavior are examined.
P. 155
Water Shutoff in Extremely Hostile Environment: An Experimental Approach in
Authors: Krilov Z. , Tomic M. , Mesic I. , Domitrovic D. , Myers R.R. 
Published: December 2007

Abstract
Based on case history and laboratory research, this paper documents the efforts made to date to solve the problem of excess water production in the large gas condensate fields located in the southwestern part of Pannonian Basin Croatia.
According to laboratory studies, a polymer-gel system could be an applicable method to shut off water production in reservoirs characterized as extremely hostile (ultra-high downhole temperature, geologically complex payzone and sour gas, rich with CO). Phenol-formaldehyde crosslinked gels appear to be the most promising for use under such harsh conditions. Long-term stability during in vitro tests, and selective rock permeability reduction during core flooding tests have been achieved at 180C. The problem of retarding the gelation time at reservoir conditions has to be further investigated prior to performing the water shutoff treatment on a candidate gas condensate production well.
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Control of In-Situ Gelation Time for HPAAM-Chromium Acetate Systems
Authors: Natarajan Dilip , McCool C.S. , Green D.W. , Willhite G.P. 
Published: December 2007

Abstract
Chromium acetate - polyacrylamide gel systems have been used primarily to treat fracture systems, casing leaks and near wellbore regions in matrix rock where short gel times are acceptable. In-depth treatment of matrix rock is limited by gelation time for this system. This paper describes a study of a method to increase gelation time of chromium polyacrylamide systems by using excess acetate ion to reduce the rate of crosslinking between chromium and the polymer. Data are presented to show the effect of excess acetate ions (provided as sodium acetate) on the rate of gelation in bottle tests. Displacement experiments were conducted in sandpacks of various lengths to confirm effects anticipated from bottle tests. Gel samples were prepared at concentrations of 5000 ppm polyacrylamide, 109 ppm chromium acetate and a pH of 5, in sample bottles maintained at 25 C. The effect of excess sodium acetate concentration on the gel times of partially hydrolyzed polyacrylamide-chromium acetate gel systems was determined by varying the mole ratio of acetate to chromium from 3.00 (stoichiometric) to 600. Gelation delays on the order of several days were achieved by increasing the acetate/chromium ratio from 3.00 to 91. Gelation was prevented (for the observation period of one year) when the acetate/Cr ratio was greater than 260. The delay in gelation time was related to a critical acetate/Cr ratio that was characteristic of the concentration and source of the polymer and Cr(III). Aged chromium stock gave significantly shorter gel times than freshly prepared stocks. Displacement experiments were conducted in sandpacks using gel solutions with selected acetate/Cr ratios to determine flow resistance during placement and during brine flow after shut-in. At low ratios of acetate/Cr, buildup of flow resistance in the sandpacks due to formation and filtration of aggregates limited the penetration of the gelant and caused termination of injection. In most of the experiments the time for development of flow resistance was on the order of 10% of the bulk gel times. However, when the acetate/Cr ratio was 600, no buildup of flow resistance was observed when 4 PV of gelant was injected into a one ft sandpack and this system had not gel led in situ at four months after placement. In situ gelation of chromium acetate-polyacrylamide systems at 25 C can be controlled by varying the acetate/Cr ratio.
P. 407
An Artificial Neural Network Model for Estimating Tight Gas Sand Permeability
Authors: Garrouch A. , Smaoui N.H. 
Published: December 2007

Abstract
A back-propagation neural network model has been used to estimate tight gas sand permeability from porosity, mean pore size, and mineralogical data. The optimal network topology consists of an eight-neuron input layer, two five-neuron hidden layers that use nonlinear sigmoid transfer functions, and a linear single-neuron output layer.
The network model has been trained on a data set from a tight gas sand well and tested on some core samples data that were not seen by the network during training. The optimal network architecture was able to estimate back the permeability from the training set within 0.89 % average relative error and was able to predict the permeability of the test data set within 3.3 % average relative error. This is a remarkable result, since linear and nonlinear multivariate regression models were unable to predict the intrinsic permeability within less than 40% average relative error.
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Parametric Utility Functions for Decisions Under Uncertainty
Authors: Smith Marvin B. 
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
By identifying a few key parameters for certain representative algebraic functions which characterize the decision-maker's economic environment, a meaningful utility function can be defined. The specification of these parameters and the appropriate function describe a unique curve relating utility values to potential monetary values. Parametric utility functions offer Parametric utility functions offer solutions to some perplexing problems where expected value theory does not indicate the best decision.

Introduction
Application of utility theory has not been well-accepted as a practical procedure in the analysis of investments procedure in the analysis of investments under uncertainty. Although risk economics in the petroleum industry has evolved to the current state of comprehensive probability models, the incorporation of utility methods has been avoided by most model-builders. Economic analysts generally subscribe to the principle of the expected utility calculation, but the difficulties in obtaining a utility function by the traditional utility experiment have made decision-makers reluctant to introduce such curves into routine problem solving. problem solving. The parametric method for obtaining a utility function presents an alternative to the traditional utility experiment. The purpose of the utility experiment is to describe the decision-maker's intrinsic function, but the parametric approach allows the decision-maker to prescribe the transformation that will be used to compute expected utilities. Parametric utility functions can be defined by group deliberation, while the experimental method is basically an individual effort. A parametric utility function can be updated automatically by changing the values of the parameters, without restudying the philosophical basis for the function.

A PARTIAL LITERATURE REVIEW
The concept of utility was developed by Daniel Bernoulli in his "Exposition of a New Theory on the Measurement of Risk", presented in 1738 to the Imperial Academy of Sciences in Petersburg.
Integrated Workflow Methodologies for Asset Teams
Authors: Tobias Steve , Thompson David , Ahmed Usman 
Published: December 2007

Abstract
Developing oil and gas fields in Southeast Asia profitably can be very challenging. This is partly due to the unique and difficult geological and geophysical problems associated with the Tertiary non-marine basins so prevalent in this part of the world. These problems stem from the discontinuous nature of these reservoirs, which make log correlation difficult and seismic mapping slow and untenable. In addition, reservoirs tend to be highly faulted, and characterized more often than not by poor seismic character. Numerous recompletions, relatively low per-well yields and fast drilling rates combine to pressure asset management teams to continually generate new well locations and update reserves. The workload is immense.
These and other challenges have led to the recent emphasis on workflow planning as a means by which to reduce cycle time and increase integration. Effective workflow demands the need for integrated workstation software system This paper discusses workflow planning in Southeast Asia, its problems, some solutions and implications via the use of the GeoFrame* software platform.
Integration of Production History into Geostatistical Reservoir Description
Authors: Yang An-Ping , Yang Huade 
Published: December 2007

Abstract
Production history is an important reflection of reservoir properties. One of our major goals in reservoir description is to increase production. If we can integrate production data into the building of the reservoir model, we can build a more realistic model and have greater confidence in our predictions. In addition, when reservoir simulation is performed with such a reservoir model, cycle time for history matching can be reduced.
Production data can be applied in reservoir description in three aspects: as soft data in geostatistical gridding, as constraints in gridding, or in post-processing of the reservoir model. The conventional approach of history matching is in the third aspect, which is indirect and time consuming. Our attempt is in the first two aspects. The key is in calculating an attribute from production data that can be calibrated to reservoir properties such as permeability. One such attribute is productivity index. The most difficult task is to normalize the attribute to compensate for differences in starting time, pressure, saturation, mechanical problems, and so on. After verification with synthetic data, the methodology is applied to producing fields with primary production data. The results are consistent with the geological description of the field and can be used in reservoir description. For fields with many wells and lots of data, when the history matching approach is more costly, this approach can be effectively used to map permeability trends and improve the reservoir description model, providing a better tool for optimization of hydrocarbon production.
P. 149
Integrated Reservoir Characterization of Neelam Field
Authors: Joshi Sameer , Lahiri Gopal 
Published: December 2007

Abstract
The Neelam field, located in Western offshore India, is a heteregeneous limestone reservoir of Middle to Late Eocene age with a lack of well defined layering, variation in lithofacies and early high water cut behaviour. Detailed characterization of the reservoir was needed to understand its complex nature in order to arrest the declining production trend.
An integrated reservoir modelling technique was used in order to shorten the E&P interpretation cycle, manage and integrate a large amount of geoscientific data and provide an inbuilt link between the static reservoir model and its dynamic activation using numerical simulation. The available data included well logs, 3D seismic, VSP's, pressure and production data, PVT analyses and core data.
All data was loaded on a common database. Seismic time-depth conversion was done. Well data was tied to seismic and markers correlated across the field. Seismic attributes were mapped and matched with log derived properties. Seismic acoustic impedance was generated. Component thicknesses and properties were mapped across the field with seismic guidance and volumetrics calculated. This resulted in a static reservoir description appropriate to the real life situation. The static description was used in creating a simulation mesh that closely followed the heteregeneities and fault patterns in the field. A complete input data file for a black oil simulator was generated. A consistent reservoir characterization was arrived at which honoured all the input data and successfully explained some of the observed field problems.
Such an integrated reservoir model is an essential building block for an integrated Asset Management system so that the inter-relationship and inter-dependence between different elements in the E&P value chain can be clearly recognized and accounted for.
P. 161
Modeling Simultaneous Oil and Water Flow in Reservoirs with Water Influx
Authors: Permadi A.K. , Mamora D.D. , Lee W.J. 
Published: December 2007

Abstract
This paper presents the development and application of semianalytical solutions to model multi-phase flow of oil and water. Our solutions are modifications of single-phase solutions, with multi-phase flow introduced using the Perrine-Marin "total mobility" to replace single-phase mobility in the standard diffusivity equation. This modification led to very satisfactory agreement between calculated and simulated results. Our results include new solutions for an outer boundary condition of "specified flux." With water influx, this "specified flux" will vary with time and is calculated using an aquifer model coupled with the reservoir model.
The importance of this work is in its possible implementation in software designed for production data and well test data analysis. Most commercial software is limited to single-phase flow, with multi-phase water-oil flow modeled (if at all) by highly simplified models.
Our model assumes a producing well centered in its drainage area surrounded by a cylindrical aquifer or injected water bank. Cumulative water influx is related to the well production and reservoir flow properties by material balance. Any standard water influx model can be used to relate cumulative water influx and the reservoir-aquifer interface pressure.
We relate the average reservoir pressure to well performance using solutions first derived to model single-phase, slightly compressible liquid flow. Oil and water production rates are obtained from the total rate using Darcy's law. Fluid saturations at a given time are computed volumetrically, and this technique does not require knowledge of saturation distribution in the reservoir. Pre- and post-breakthrough oil and water rates are based on fractional flow theory. Although we considered only the case of constant-rate production, our method can be extended readily to the case of constant-pressure production.
P. 263
A New Compositional Simulation Approach to Model Recovery from Volatile Oil Reservoirs
Authors: Syahrial E. , Daltaban T.S. 
Published: December 2007

Abstract
This paper proposes a new compositional simulation approach which has an implicit equation for the oil-phase pressure and water saturation, an explicit equation for the hydrocarbon saturation, and explicit equation for the overall composition of each hydrocarbon component that satisfies thermodynamic equilibrium. The proposed formulation uses an Equation of State for phase equilibrium and property calculations. Interfacial tension effects are included in this research to characterize the thermodynamically dynamic nature of the relative permeability. A two-dimensional relative permeability algorithm is included which handles lumped hydrocarbon phase hydrocarbon phase as well as individual phase flows.
For each grid block two equations are required, namely total hydrocarbon and water-phase flow equations. These equations are highly non-linear and they are linearized by using Newton-Raphson method. The resulting set of equations are solved by an efficient Conjugate Gradient based iterative technique to obtain pressures and saturations simultaneously, and hydrocarbon-phase saturations are deduced from their respective equations.
The new compositional simulation approach is validated through analytical and other numerical methods. lt is demonstrated in this present paper that the results are compared favourably with analytical techniques and published numerical results. They also confirm that the proposed codified formulation is unconditionally stable and it is as stable as the fully compositional model yet the computational cost reduction was substantial.
Impact of sequence-based on correlation style on volatile oil recovery is modelled with this approach. Specifically, the effect of clino-formal permeability barriers on predicted displacement efficiency of oil by injected water and injected gas into volatile oil reservoirs is assessed. The results show that oil recovery factors are strongly affected by the combination of the structure of permeability and the transmissibility barriers between the layers.
P. 281
Improving Flow Simulation Performance with a Seismic-Enhanced Geologic Model
Authors: Hinterlong G.D. , Taylor A.R. , Watts G.P. , Kumar K.H. 
Published: December 2007

Abstract
The DOE Class 2 Demonstration Project operated by OXY USA Inc. in the West Welch Unit was designed to enhance economics in IOR projects in lower quality shallow shelf carbonate reservoirs. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in heterogeneous reservoirs. Therefore, the majority of the pre-injection effort was devoted to developing a geologic model that would allow a flow simulator to accurately match and predict reservoir performance. A base geologic model was constructed utilizing standard correlation and extrapolation methods to distribute the wellbore data across the interwell area. With the base geologic model, the flow simulator could only obtain a history match by making changes in porosity, net pay, and permeability of grid cells in the model. The changes were made using conventional history matching techniques, and the revised geologic model may not have been representative of the formation although a history match was obtained.
The base geologic model was then enhanced by incorporating seismic-guided porosity and pore volume map data to define the interwell properties. Since the seismic traces were on approximately the same spacing as the model grids, reservoir properties of porosity and thickness were available at each grid block. With the enhanced geologic model, the simulator was able to match the historical total fluid rates without the use of porosity or permeability multipliers. The simulator's water/oil ratio was too low with this model. Net pay and pay continuity were identified by other methods as the controlling parameters in the waterflood history match. The revisions resulted in higher oil saturation at the start of CO flood and an increase in forecasted oil production during tertiary recovery than when not using the seismic data. The predicted injection for the first three months is matching the actual field rates indicating these were valid changes to the simulator.
P. 499