bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Well Production Data to Reservoir Characterization
Authors: Yang Huade , Gao Yaming , Yang An-Ping 
Published: December 2007

Abstract
Many researchers have attempted to characterize reservoirs by qualitatively integrating all available seismic, geological, well logging, and core data. However, very few efforts have been made to incorporate the production data, an important reflection of reservoir properties, in reservoir characterization researches. One of the main reasons for the lack of efforts can be attributed to difficulties in determining reservoir properties from well performance data. In our study, well production data are used to derive relative trends of reservoir property distributions instead of calculating the exact reservoir parameters. These trends can be used as soft data in integrated reservoir characterization studies. Our approach was to partition reservoir into separate drainage area for each well and derive average reservoir pressure within this drainage area of a well from production data. The productivity index was then calculated and mapped using geostatistical techniques. Reservoir permeability trends were then derived from this field productivity index mapping. The validity of our approach was then checked using a conventional reservoir simulator.
Development of An Electronic Information System for the Petroleum Industry
Authors: Martin F. David 
Published: December 2007

Abstract
This paper discusses the development of the Gas and Oil Technology Exchange and Communication Highway (GO-TECH). GO-TECH is a PC-based networking system designed to make high-speed electronic links readily accessible to the petroleum community for rapidly exchanging information, data, ideas, and technology. Experience gained during the first year of operation is discussed, and the evolution of GO-TECH shows how a regional producer advisory group guided the development of the system. A brief background of the Internet and World Wide Web will be provided, and a glossary of related technical terms is provided for those not familiar with the terminology in this area.
Coupled Fluid Flow and Geomechanics in Reservoir Study -I. Theory and Governing Equations
Authors: Chen H. -Y. , Teufel L. W. , Lee R. L. 
Published: December 2007

Abstract
The purpose of this study is to examine Biot’s two-phase (fluid and rock), isothermal, linear poroelastic theory from the conventional porous fluid-flow modeling point of view. Biot’s theory and the published applications are oriented more toward rock mechanics than fluid flow. Our goal is to preserve the commonly used systematic porous fluid-flow modeling and include geomechanics as an additional module. By developing such an approach, complex reservoir situations involving geomechanical issues (e.g., naturally fractured reservoirs, stress-sensitive reservoirs) can be pursued more systematically and easily. We show how the conventional fluid-flow formulations is extended to a coupled fluid-flow-geomechanics model. Consistent interpretation of various rock compressibilities and the effective stress law are shown to be critical in achieving the coupling. The "total (or system) compressibility" commonly used in reservoir engineering is shown to be a function of boundary conditions. Under the simplest case (isotropic homogeneous material properties), the fluid pressure satisfies a fourth-order equation instead of the conventional second-order diffusion equation. Limiting cases include nondeformable, incompressible fluid and solid, and constant mean normal stress are analyzed.
Development and Exploitation Strategies in a High Pressure-Temperature Reservoir With a Complex Hydrocarbon Fluid Column.
Authors: Maan N. , Rosales E. , Medina H. 
Published: December 2007

ABSTRACT
This paper summarizes an interdisciplinary study performed to plan final Reservoir Development and Secondary Recovery Strategies for The Carito Field discovered in late 1987.
Carito is a very large oil Field located in Northeastern Venezuela, with an estimated Volumetric Oil in Place of 1.8 Billion Stb. Production is mainly from Naricual Formation with a thickness of about 1300 feet in a faulted anticline. At the time of this Study, 25 wells had been drilled below 12200 ft ss. These wells were producing about 90000 Stb/D through 39 completions. Original reservoir pressure was abnormally high (11300 psig at 14040 ft SS) and the Temperature averages 300 degrees Fahrenheit. The field shows a graded fluid system that varies from a gas condensate to a medium oil. Gas cap to oil zone ratio is about 1.2 and crude oil gravity varies with depth from 36 to 21 API degrees.
The simulation study, conducted to establish the optimum exploitation strategy, incorporated a detailed geologic model based on seismic, sedimentary environment, and production geologic concepts. The data from the geologic model, routine and special test data from conventional cores, and the data from 58 fluid analysis were consolidated in a numerical reservoir simulator model, which predicted the potential reservoir performance under various Development, Production and Secondary Recovery Planning.
The results of this study led us to design a Gas Injection Secondary Recovery Process encompassing a rate injection of 600 MMScf/D through 10 injector wells and the perforation of an additional 16 producer wells. We expect to double the natural depletion oil Recovery as a consequence of the Pressure Maintenance Program.
New Data Reduction Developments for Relative Permeability Determination
Authors: Kalbus James S. , Christiansen Richard L. 
Published: December 2007

Abstract
Modifications of analytical methods were developed for obtaining relative permeability relationships from displacement experiments conducted in a centrifuge or at normal gravity conditions. The methods are modifications of the Johnson-Bossler-Naumann method (for normal gravity experiments) and the Hagoort method (for centrifuge experiments). As demonstrated by application to numerically simulated experiments, the methods accurately correct for capillary end effects.
State-Of-The-Art in Permeability Determination From Well Log Data: Part 2-Verifiable, Accurate Permeability Predictions, the Touch-Stone of All Models
Authors: Mohaghegh S. , Balan B. , Ameri S. 
Published: December 2007

AbstractThe ultimate test for any technique that bears the claim of permeability prediction from well log data, is accurate and verifiable prediction of permeability for wells from which only the well log data is available. So far all the available models and techniques have been tried on data that includes both well logs and the corresponding permeability values. This approach at best is nothing more than linear or nonlinear curve fitting. The objective of this paper is to test the capability of the most promising of these techniques in independent (where corresponding permeability values are not available or have not been used in development of the model) prediction of permeability in a heterogeneous formation.Since the empirical approaches for permeability prediction are mostly directed toward developing mathematical models from given data in particular formations, it has been shown that they lack the required generalization capability for the purposes of this study. These approaches have concentrated on modeling formation permeability as a function of porosity and irreducible water saturation. These models will be briefly discussed. The main focus of this paper will be on two techniques that show potentials in achieving the goal that was mentioned above. These techniques are "Multiple Regression" and "Virtual Measurements using Artificial Neural Networks." For the purposes of this study several wells from a heterogeneous formation in West Virginia were selected. Well log data and corresponding permeability values for these wells were available. In separate tests all data from an entire well were designated and put aside.The techniques were applied to the remaining data and a permeability model for the field was developed. The model was then applied to the well that was separated from the rest of the data earlier and the results were compared. This approach will test the generalization power of each technique. After all, this is the way that these techniques are used in the real life situations.The result will show that although Multiple Regression provides acceptable results for wells that were used during model development, (good curve fitting,) it lacks a consistent generalization capability, meaning that it does not perform as well with data it has not been exposed to (the data from well that has been put aside). On the other hand, Virtual Measurement technique provides a steady generalization power. This technique is able to perform the permeability prediction task even for the entire wells with no prior exposure to their permeability profile.
Helical Flow of Bentonite Slurries
Authors: Walker Richard E. , Al-Rawi Othmen 
Published: December 2007

Abstract
Laboratory flow experiments with four bentonite-water mixtures verified a method of calculation for laminar helical flow. The calculation technique includes the influence of rotating drill pipe and can give velocity and viscosity profiles as well as flowing pressure drop, thus it can be used to evaluate pressure drop, thus it can be used to evaluate muds under various operating conditions for hole cleaning and equivalent circulating density. The method proposed by Coleman and Noll uses a viscosity based on the vector value of the angular and axial stress components and a viscosity-stress relation measured with conventional rheometers.
One explanation of "gelling" in washed-out areas of a wellbore is suggested by the rheological behavior of two bentonite-water mixtures used in the experiments. The shear stress of these liquids increased at very low shear rates so two shear rates could exist for some values of shear stress. Tests in a rotating rheometer showed that some bentonite-water mixtures give, for the same shear stress, much lower shear rates when measured under constant stress conditions than under constant rate conditions. This behavior was limited to a stress range and did not occur above critical stress.

Introduction
The objective of this work is to experimentally test the validity (using a bentonite water fluid) of a method of predicting laminar helical flow proposed by Coleman and Noll and also by Fredrickson. The method of calculation has been shown experimentally to be correct for a polymer liquid in helical flow (Refs. 3 and 4) and was used by Savins and Wallick to predict velocity profiles and pressure drops in the annulus of a drilling well assuming that the liquid followed a three-constant Oldroyd liquid model. These calculations showed that rotating drill pipe can have a marked influence on the velocity profile and the flowing pressure drop. No experimental justification of the calculation methods has been done with bentonite or other clay materials.
If the calculation method is valid for drilling muds considerable additional information can be obtained about the fluid characteristics in the annulus. This will allow better predictions of the ability of liquid to carry cuttings to the surface, the equivalent circulating density, and rheological test conditions for evaluation of mud properties. For example, an indication of the ability of a liquid to carry cuttings might be inferred from the viscosity at various radial points in the annulus as well as the axial velocity profile.
The Use of Inertial Force and Low Shear Viscosity to Predict Cleanup of Fracturing Fluids within Proppant Packs
Authors: Penny Glenn S. , Jin Liang 
Published: December 2007

Abstract
This paper describes the development and use of laboratory data to show the impact of multiphase, non-Darcy flow and gel damage upon gas production from hydraulic fractures. In the work, the percent cleanup is related to the molecular weight and concentration of the gel remaining in the proppant pack and the inertial force available from the flow of gas and liquids during cleanup and production. The impact of proppant permeability and multiphase, non-Darcy flow is further combined with inertial force and gel damage to provide a newly developed relationship to predict the degree of cleanup. The new relationship can be used to calculate the effective conductivity for various proppant types, sizes and concentrations vs. closure, temperature, gel and breaker concentration, and prevailing gas/water/oil ratios. The calculated effective conductivities can then be used to predict gas productivity and economics under various conditions of multiphase, non-Darcy flow.
The results of the testing show that multiphase, non-Darcy flow dramatically increases the difference between the effective conductivities of various proppants and fracturing fluids with different retained permeabilities. The laboratory data and field observations show that when multiphase flow is taken into account, fracturing fluids with high retained permeabilities and premium high conductivity proppants can produce at as much as twice the gas production rate of fluids with 50% cleanup in gas wells producing as little as 10 barrels of water or condensate per MMCF. Using the developed criteria, proppants and fluids can be selected to optimize gas production from wells based upon prevailing reservoir conditions.
Prediction of Formation Damage During Fluid Injection into Fractured, Low Permeability Reservoirs via Neural Networks
Authors: Nikravesh M. , Kovscek A. R. , Johnston R. M. , Patzek T. W. 
Published: December 2007

Abstract
The coupled, nonlinear and dynamic mechanisms that affect fluid injection for pressure maintenance or displacement, and oil production, are not well understood in low permeability fractured reservoirs. Thus, it is difficult to select an injection policy which maximizes oil recovery while minimizing formation damage caused by fluid injection and withdrawal. Here, we show that neural network models can be developed and used to predict, on a well-by-well basis, the dynamics of low permeability, fractured reservoirs undergoing fluid injection. The networks are trained using historical data from field operations.
We present an example from (i) a water and (ii) a steam injection project where over-pressurization has lead to unwanted extensions of fractures. First, using data from a waterflood project in the South Belridge Diatomite (Kern County, CA), we have built a neural network to predict wellhead pressure as a function of injection rate, and vice versa. The resulting model provides an excellent correlation between the inputs and outputs and recognizes major patterns in the input data structure, even though the behavior of the waterflood is complex. Second, using data from a dual injector steam drive pilot in the same field, we have created neural networks which correlate the injection pressures and rates, and temperature responses in seven observation wells. Assuming a future injection pressure policy, the neural networks predict the injection rate and growth of heated reservoir volume. These predictions are then combined with a history-matching reservoir simulator to demonstrate how predictive simulation can be achieved even when mechanisms of steam injection and oil displacement into a tight fractured rock are not fully understood.
Water Quality for Water Injection Wells
Authors: Rochon J. , Creusot M. R. , Rivet P. , Roque C. , Renard M. 
Published: December 2007

Abstract
A multidisciplinary study has been carried out so as to characterize the permeability impairment due to suspended particles during water injection. The approach is based on extensive laboratory experiments reproducing the complete range of parameters met in the industry. Experiments were carried out at both constant flowrate and constant pressure gradient. They reproduce static filtration conditions, i.e. without a flow component tangential to the rock face such as can occur when there are open fractures.
The analysis of experimental results has confirmed that injectivity damage can be separated into two successive processes. Internal permeability damage close to the entry face switches to the build-up of an external filter cake after the injection of a critical volume. This is true even when particles are very small as compared to the size of the pore throats. Analytical equations have been developped for each mechanism, as well as for the critical cumulative injection when the external cake starts to form. These equations require at most two parameters. The extensive range of experimental conditions in our laboratory study enables us to propose correlations for the values of these parameters from basic data (velocity, concentration, particle size).
Ultrasonic Removal of Organic Deposits and Polymer Induced Formation Damage
Authors: Roberts Peter M. , Venkitaraman Adinathan , Sharma Mukul M. 
Published: December 2007

Abstract
Experiments were conducted that evaluate the feasibility of using high intensity acoustic sources to remove near wellbore formation damage caused by organic deposits (paraffins and asphaltenes) and polymers (HEC). It is shown that mechanical agitation provided by the acoustic waves effectively re-suspends the paraffin and restores the effective permeability of the core to oil to its undamaged condition in a relatively short period of time. The depth of treatment is approximately 12-15 cm. This suggests that an acoustic source with or without solvents may provide an effective method of removing paraffins from the wellbore and the near wellbore region.
Acoustics was not found to be as effective at restoring the permeability of cores damaged by polymers (HEC). Only small (factor of 1.5) increases in permeability were obtained for both poorly mixed and well mixed HEC.
Experiments conducted over a range of frequencies and acoustic intensities allow us to specify the design requirements for a field deployable transducer. Eight such transducers have been incorporated into a through tubing tool that has recently been built and is now available for field testing.
Our results demonstrate that acoustic cleaning may be a viable method for cleaning both the wellbore and near wellbore region when paraffin precipitation is a problem. The method would be particularly effective at treating long sections of pay (horizontal wells) where chemical methods may be too expensive. Acoustic cleaning is much less effective for treating polymer damage problems.
Prospects For Nuclear Energy
Authors: Simpson John W. 
Published: December 2007

1970 Annual Fall Meeting, October 4–7, 1970 - Houston, TX
I appreciate very much the invitation to address this meeting today and to talk about nuclear power.
I would like to make a few points about nuclear power — such as why we must move ahead with the power — such as why we must move ahead with the development of this energy source — and then discuss my subject in terms of kilowatts and dollars and cents.
There are several very compelling reasons why the continued development of nuclear power is of the greatest importance to this nation.
The first and most obvious reason is that our utilities urgently need additional capacity on their systems. Our electrical energy crisis was dramatically brought home to millions of people this year on the last day of summer when the entire east coast found itself in the throes of a massive brownout stretching from New England to South Carolina over to Ohio.
Gas Availability from Casinghead Systems
Authors: Rist Barry C. 
Published: December 2007

Abstract
The Hugoton Anadarko Area has seen the growth of several large casinghead systems during the past few years. Since pipe line companies historically look for the long term sources of supply, analyses of various casinghead gas gathering systems have been made. Gas supply from these systems can most generally be depended upon for long periods of time. The system should be located in a developing gas and oil area and should be available early in the development life.
The casinghead reserves per well can be expected to be small and, in order to maintain a break-even position, 20 - 25% new wells must be connected each year. In the successful operation of a casinghead system, the company must be aggressive. The drilling slump has not appreciably effected those systems whose managements are active.
The Hugoton Anadarko Area has 2.5 Tcf of proved remaining recoverable casinghead gas reserves at January 1, 1970.

Introduction
The Hugoton Anadarko Area is located on the map shown on Page 5. The proved remaining recoverable natural gas reserves for the total Hugoton Anadarko Area has been steadily declining since 1959 at an average rate of 1.25 Tcf/year, see Fig. 14. However, during this time the casinghead gas reserves continued to increase, peaking in 1965 at a remaining recoverable reserve of 3.6 Tcf of gas. When this trend was noticed in the early 1960's, an evaluation was set in motion to determine some of the more desirable characteristics of a casinghead gas gathering system and if they could be depended upon for long term supplies of gas.
In analyzing this question, two large problems are encountered immediately. The problems are encountered immediately. The first problem is that all of the casinghead systems are very complex. The second problem encountered is that very little problem encountered is that very little information concerning these systems is available for analysis.
Anadarko Basin, Buffalo Wallow Field - Operation of Deep Gas Wells and Gathering System Serving Them
Authors: Richards J.D. , Swanson Thomas C. 
Published: December 2007

Abstract
The Buffalo wallow (Hunton 19,600 ft.) field was discovered November 25, 1967, and during the ensuing period to the present, very significant technology in the areas of drilling, completion, producing, and pipelining has been developed. The problems encountered have been many but, as is the case in any new field development, application of the correct technology will evidence itself in the success achieve. Through diligent efforts to achieve cooperation between operator and purchaser, the task of completing, equipping, and commencement of sales from these wells was minimized. Subsequent operating problems have been more easily solved through this cooperative effort.

Introduction
The Buffalo Wallow (Hunton 19,600 ft.) field was discovered on November 25, 1967, by the Union Oil Company of Calif. No. 1 Bradstreet in which Gulf has a 25 percent working interest. There are presently 12 completed wells in the field with development still in progress in the south portion of the field. The Buffalo Wallow (Morrow) field was discovered on June 10, 1969, by the Jake L. Hamon No. 1 Mack. Completions to date number 8 and there is still considerable infill drilling to be done as well as potentially extending the field boundaries. Fig. potentially extending the field boundaries. Fig. No. 1 depicts the field in its stage of development on September 15, 1970.
There are currently three purchasers in the field with sales to Natural Gas Pipeline Co. of America commencing on February 6, 1969, to Kansas-Nebraska Gas Co. on November 14, 1969, and to Pioneer Natural Gas CO. on August 5, 1970. Cumulative volumes run from Buffalo Wallow through August, 1970, approximate 60,000 MMcf.
Kansas-Nebraska takes all of Gulf's working interest gas from the field as well as considerable volumes from others. Gulf has completed 6 Hunton wells and two Morrow wells to date and have, through the efforts of many people, achieved this very successfully. My people, achieved this very successfully. My portion of this paper will deal with the portion of this paper will deal with the experience gained in completion, equipment installation, and subsequent producing stages of this development.