bluuebunny/crossref_metadata_2025 huggingface dataset:
Incorporation of Production Data Into the Reservoir Description Process
Authors: Hird K. B. , Kelkar M. G.
Published: December 2007

Current computer technology has given us the ability to generate realizations of spatial reservoir properties as never before. However, achieving the goal of generating reservoir descriptions which are consistent with all of the available information continues to be a difficult and time-consuming process. Especially, the inability to constrain probabilistic-based reservoir descriptions using (dynamic) production data is becoming recognized as one of the primary short-comings of existing techniques.

This paper describes a procedure to identify, quantify and incorporate within a conditional simulation procedure the spatial reservoir characteristics which dominate well performance. Primary production data are used to determine controlling spatial characteristics. The primary production parameters are combined with waterflood constraints and the method of simulated annealing to produce realistic reservoir descriptions-both in terms of their spatial characteristics and simulated well performance. Although excellent matches of well performance are also obtained using these "indirect performance constraints" while excluding the variogram constraint, it is shown that the resulting alternative reservoir descriptions poorly reproduce actual spatial reservoir properties. Thus, it is concluded that spatial correlation structures cannot be extracted from performance data. The robustness and flexibility of the approach is demonstrated using a two-dimensional areal, field scale reservoir study. The proposed technique can be used to greatly reduce the uncertainty of predicting future reservoir performance.
Quantification of the Relative Importance of Fracture and Matrix Flow Units to Reservoir Storage Capacity and Transmissibility
Authors: Cline S. B. , Tiab Djebbar
Published: December 2007

Unexpected early waterflood breakthrough in a high matrix porosity, Pennsylvanian age sandstone reservoir, indicated the possible presence of a high directional permeability fracture flow system superimposed on the matrix flow system. A simulation study was initiated to study this problem.

Simulation history matching results showed that the fractures exhibited high directional permeability but low storage capacity relative to the matrix portion of the reservoir. A low fracture intensity index was calculated. This low storage capacity fracture system supports the hypothesis that the fracture system resulted from previous stimulation treatments rather than from an extensive naturally occurring fracture system. The recognition and quantification of this new model led to significant improvements in field production practices, well alignments, ultimate oil recovery and production forecasting.
Proppant Effects on Zirconium Crosslinked Frac Fluids
Authors: Smith V. T. , Colt J. R. , Johnson R. L. , Sinclair A. R.
Published: December 2007

Interactions between proppants and a zirconium crosslinked hydroxypropyl guar (HPG) frac fluid were examined using rheological test methods. The advantages of curable RCP over tempered RCP and sand have been well chronicled.1,2 However, one disadvantage of curable RCP has been its effect on frac fluid viscosity and breaker activity. By definition, curable RCP is chemically reactive, and the chemistry required to form bonds between grains can interfere with a fluid's crosslinking mechanism. Using a Nordman 5002 viscometer with real-time digital data acquisition, viscosity data were gathered to quantify the rheology of crosslinked fluid exposed to uncoated sand, tempered RCP, and curable RCP. Proppant effects on oxidative breakers were studied by direct proppant / breaker consumption titrations. In addition, leachate samples of curable and tempered RCP were analyzed using Fourier Transform – Infrared Spectroscopy (FT-IR); differences in leachate provided information on which chemical species were reactive in interactive fluid chemistry.
Increased Production in Low-Temperature Gas Wells Through Improved Breaker Technology
Authors: Samuelson M. L. , Chmilowski Walt , Sinclair J. J.
Published: December 2007

A discussion is presented on the improvement of shallow gas well production through the use of advanced low-temperature breaker technology. A systematic field evaluation has shown that the use of this new breaker system has increased well production in spite of inherent problems in the area due to severe proppant embedment. Previous use of an encapsulated breaker (EB) designed for well temperatures above 125°F had shown some improvement in production over conventional dissolved breakers. However, the current study has shown that the new breaker system, designed for temperatures <125°F and closure stress <1000 psi, has been able to improve production by an additional 15 to 22% in direct offset comparisons. Study criteria included selection of a suitable area, maintenance of a consistent drilling and completion program, and variance only in the breaker system used. Laboratory development of the new breaker system also is discussed, including effects of temperature and closure stress on barrier properties, and fracture conductivity comparisons.
Integrated Approach Doubles System Capacity
Authors: Pelgrom J. J. , Angiblaud L. G. , Bouvet E. J. , Davidson C. J. , Holtslag paul , De Ruwe Bart , Shaw Julian
Published: December 2007

The use of integrated system modelling of wells and facilities and the application of performance improving chemicals and novel techniques allowed Shell Gabon to increase Rabi field output by nearly a factor of two over the initial projections. Optimisations are carried out in a consistent and systematic manner without jeopardising system integrity and safety standards. These efforts increased project profitability while obviating the need for major system extensions. Some (identified) upgrading measures are still required to reduce long-term operating costs and to reduce deferments.
Integrated Reservoir Description and Flow Performance Evaluation of Self Unit, Glenn Pool Field
Authors: Ahuja B. K. , Bahar Asnul , Kerr D. R. , Kelkar M. G.
Published: December 2007

This paper presents reservoir characterization results of a mature oil field followed by a successful flow simulation. The study area is the Self Unit (160 Ac) in part of the Glenn Pool field, which was discovered in 1905. Since discovery, the Glenn Sand reservoir has only produced 20% of the original in place. Under the sponsorship of the Department of Energy, a methodology is being established to produce additional oil from the reservoir in a cost effective manner. The first step of this process is to generate an integrated reservoir description followed by a successful comparison between historical performance and the simulated performance. The details of this step are presented in this paper.
Monument Butte Unit Case Study: Demonstration of a Successful Waterflood in a Fluvial Deltaic Reservoir
Authors: Deo M. D. , Sarkar Avik , Nielson D. L. , Lomax J. D. , Pennington B. I.
Published: December 2007

Fluvial deltaic reservoirs contain a significant portion of the known world oil resources. Due to the sinuous na-ture of the sands, it is difficult to implement improved oil recovery projects in these reservoirs. The case study described in this paper is the demonstration of a well-planned water flood in a classic fluvial deltaic system, and consists of geologic characterization and reservoir simulation. The Monument Butte Unit, located in the Uinta Basin, Utah, has 22 operating wells; eight injectors and the rest producers. The oil from the unit is highly paraffinic and is produced primarily from two sands. In primary recovery, the reservoir performance was typical of an undersaturated reservoir whose initial pressure was close to the bubble point pressure. The Unit had produced about 5% of the oil in place at the end of primary production and was producing at a rate of 40 STB/day, when the water flood was initiated. The water flood design was novel and was engineered contrary to convention. The response to the water flood was extraordinary and the unit has been producing at more than 300 STB/day for the past two years. About 10% of OOIP has been recovered to date. Every aspect of the field history was matched well by the reservoir simulator.
Microbial Enhanced Waterflooding Field Tests
Authors: Bryant R. S. , Stepp A. K. , Bertus K. M. , Burchfield T. E. , Dennis Mike
Published: December 2007

To determine the feasibility of improving oil recovery and the economics of microbial enhanced waterflooding in mature oil wells in the United States, two field pilots have been conducted. Candidate fields were screened to determine whether they have any potential for a microbial system developed at the National Institute for Petroleum and Energy Research (NIPER), and microbial compatibility tests were conducted in the laboratory to select the target field. A specific microbial formulation was selected that was compatible with the chosen reservoir environment and had been shown to recover oil after waterflooding in Berea sandstone and field core. The microbial formulation was designed to improve microscopic oil displacement efficiency by surfactant, gas and acid production from fermentation of molasses. A 20-acre pilot test was initiated in October 1986, and completed in December 1989.

Results from this pilot demonstrated that microorganisms could be injected into an ongoing waterflood and that such injection could increase the oil production rate by at least 13%.

A larger test (380 producing acres) was completed in the same formation to evaluate the feasibility of commercial application of the technology. This field pilot was injected with microorganisms and molasses from a centralized injection station in June 1990. Although microorganisms were injected only once, nutrient injection continued throughout the project life. All 19 injection wells were treated, and oil production was monitored from the 47 production wells. Treatments were similar to procedures for the field pilot demonstration. No operational problems were encountered. At the end of May 1993, the oil production rate was improved by 19.6%.
A Single Well Test Method That Yields a Dispersion-Free Measure of Reservoir Fluid Drift Rate
Authors: Wellington S. L. , Simmons J. F. , Hara S. K. , Richardson E. A.
Published: December 2007

A unique single-well tracer test sequence for quantifying reservoir fluid drift rate free of dispersion is presented. Similarly with previous methods, the new method relies on the time dependence of drift. An analytical model allows the results to be interpreted using a Personal Computer at the wellsite.
EOR by Miscible CO2 Injection in the North Sea
Authors: Lindeberg Erik , Holt Torleif
Published: December 2007

A study of CO2 injection into an oil reservoir on the Norwegian Continental Shelf has been conducted. Oil production during miscible CO2 injection was simulated with a compositional reservoir simulator and a three dimensional reservoir model. This production profile was compared to water injection. The simulations showed that considerably more oil could be recovered with CO2 injection, approximately 63% OOIP, compared to approximately 43% OOIP for water injection.

Results from miscibility studies, measurement of phase diagrams and extraction experiments were used to tune the phase behaviour description of the simulator. Numerical simulation of laboratory core flood experiments were used to quality test the compositional simulator. A good agreement between measured and simulated production profiles were obtained.
A Model To Estimate the Performance of Foamed Gel for Conformance Control
Authors: Miller M. J. , Fogler H. S.
Published: December 2007

Foamed gel barriers efficiently render porous media impermeable to gas or liquid flow and recently have been considered for fluid diversion. However, exceeding a critical pressure drop across the barrier will rupture conductive channels through the barrier. A foamed gel breakdown model has been developed to estimate the maximum pressure a given barrier can withstand and estimate the permeability after rupture. The simulation results are consistent with laboratory experiments. Only the elastic modulus and the critical failure stress are required to qualitatively compare two different foamed gels.
Tax Incentive for Enhanced Oil Recovery Projects
Authors: Buckner L. A.
Published: December 2007

Beginning with the Omnibus Budget Reconciliation Act of 1990*, the federal government has recently attempted to encourage domestic oil production through federal income tax incentives. Section 43 of the Internal Revenue Code provides a tax credit for projects employing enhanced oil recovery (EOR) methods. The EOR credit was enacted to stimulate the production of potentially recoverable domestic oil reserves. The federal tax system previously attempted to provide an incentive for EOR projects when the Windfall Profit Tax rules, before repeal, contained an incentive tax rate on oil recovered using tertiary (EOR) methods.

The credit is an amount equal to 15 percent of the qualified enhanced oil recovery costs paid or incurred by a taxpayer in connection with a qualified enhanced oil recovery project. A credit to reduce an income tax liability can provide a significant economic benefit as an indirect discount on the cost of a project. However, the true economic impact to an EOR project must be evaluated considering the rules for qualification and the limitations applicable to the credit as determined under the framework of the federal income tax system.
Development of a Model Technology Transfer Program To Assist Independent Operators
Authors: Schoeling L. G. , Green D. W. , Willhite G. P. , Watney W. L.
Published: December 2007

This paper describes the development of the Kansas Technology Transfer Model (KTTM) which is proposed as a regional model for the development of other technology-transfer programs for independent operators throughout other oil producing regions in the United States. The KTTM is an expansion and adaptation of the University of Kansas Tertiary Oil Recovery Project (TORP) concept of oilfield technology transfer to independent oil producers. The KTTM is the product of a grant from the United States Department of Energy (DOE) in August 1992 to the Kansas University Energy Research Center to develop a technology transfer model which could be utilized nationwide. The focus of the KTTM is to assist in reducing the rate of well abandonment in the near term and to increase oil recovery using conventional technology.

Included is the linkage of the regional model with the national technology transfer plan, and the methodology to adapt the model on a regional basis. The technology transfer plan also includes an evaluation technique to measure the process.
Mechanistic Prediction of Foam Displacement in Multidimensions: A Population Balance Approach
Authors: Kovscek A. R. , Patzek T. W. , Radke C. J.
Published: December 2007

The high mobility of typical gases used in enhanced oil recovery (EOR) techniques impairs ultimate oil recovery. Foamed gas, though, is a promising agent for achieving mobility control in porous media. Because reservoir-scale simulation is a vital component of the engineering and economic evaluation of any EOR project, efficient application of foam as a displacement fluid requires a predictive numerical model. Unfortunately, no such model is currently available for foam injection in the field.

We have incorporate a conservation equation for the number density of foam bubbles into an implicit, three-dimensional, compositional, and thermal reservoir simulator and created a fully functional, mechanistic foam simulator. Because foam mobility is a strong function of bubble texture, the bubble population balance is necessary to make accurate predictions of foam flow behavior. Foam generation and destruction are included through rate expressions that depend on saturations and surfactant concentration. Gas relative permeability and effective viscosity are modified according to the texture of foam bubbles. In this paper, we explore foam flow in radial, layered, and heterogeneous porous media. Simulations in radial geometries indicate that foam can be formed deep within rock formations, but that the rate of propagation is slow. Foam proves effective in controlling gas mobility in layered porous media. Significant flow diversion and sweep improvement by foam are predicted, regardless of whether the layers are communicating or isolated.
Floating Drilling Experience in Santa Barbara Channel, California
Authors: Harris L.M.
Published: December 2007

This paper was prepared for the 40th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., Nov. 6–7, 1969. 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 whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal 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.

The equipment and practices for two floating drilling vessels working in water depths greater than 1000 feet in the Santa Barbara Channel have been designed to provide maximum reliability and safety. Experience to date has shown the systems to be efficient and to have met design criteria.

Introduction

Since the Federal Lease Sale in the Santa Barbara Channel of February 6, 1968, Humble has drilled fourteen wells with floating rigs in water depths ranging from 280 feet to 1300 feet. Although the water depth for some of these wells exceeds previous industry experience, the environment in the Channel is relatively mild. Historical data have indicated that the probable yearly maximum conditions in the central Santa Barbara Channel would not exceed:

Five-minute average winds of 65 knots from the west and northwest or from the east and southeast. Significant wave heights of 16 feet with a period of 13 seconds. Maximum waves associated with this sea state would be about 30 feet. Surface or near surface currents of 2.4 knots parallel to the California coastline.

The data have shown generally that these conditions occur for only a very small percentage of the time in winter months in the main part of the Channel east of Point Conception. Near the west end of the Channel, a yearly maximum significant wave height of 18 feet might occur with greater frequency.
Thermal Stability of Foam Additive in Steamflood Core Tests
Authors: Allawzi M. A. , Patton J. T.
Published: December 2007

The thermal degradation of a commercial steam-foam surfactant, was evaluated in flow under simulated reservoir conditions. Degradation was studied at 1500 psi in a conventional slim-tube flow model mounted in a furnace. The model was packed with core material taken from the steamflood area of Wilmington's Tar Zone reservoir.

The rate of decrease in additive concentration over time indicated the degradation reaction is first order. The effect of temperature on the degradation rate constant, k, was determined using the Arrhenius equation.

A mathematical model is presented that allows the calculation of thermal degradation at any temperature as a function of time. The model can be incorporated in advanced reservoir simulators such as CMG's STAR model to predict surfactant concentration at any point in the reservoir. Surfactant half-life is 221 days at 200°F, decreasing to 37 days at 500-°F.
Fluid Production Enhancement by Exploiting Sand Production
Authors: Geilikman M. B. , Dusseault M. B. , Dullien F. A.
Published: December 2007

Sand production instability is considered as a result of wellbore fluid pressure reduction (drawdown) below some critical level. A continuum model for sand production is developed by considering coupling of fluid flow and rate-sensitive plastic flow of granular matrix. The model provides a physical mechanism of yielding front propagation away from the wellbore as the process of sand production continues. Mass balance analysis leads to a relation between cumulative sand production and the current yielding front location. Short-term enhancement of fluid production because of simultaneous sand production turns out to be dependent not only on instantaneous sand flux, but also on the current radius of the yielded zone around wellbore, that is, the history of sand production for the well. Long-term enhancement is stipulated mainly by appearance of yielded, highly permeable zone around the wellbore.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase IIIC—Reservoir Characterization and Response to Foam Injection
Authors: Harpole K. J. , Siemers W. T. , Gerard M. G.
Published: December 2007

This paper summarizes the comprehensive reservoir characterization effort for the foam pilot area and discusses the response to foam injection in the CO2 Foam Field Verification Pilot Test conducted in the East Vacuum Grayburg San Andres Unit (EVGSAU) in New Mexico. A detailed study of the pilot pattern geology provided an understanding of the major controls on fluid flow in the foam pattern. Pattern performance data, falloff testing, profile surveys, and interwell tracer results were integrated into the geologic model to guide project design work and provide a framework for interpretation of foam performance. Localized regions of high permeability resulting from solution enhancement of the matrix pore system appear to be the primary cause of the early CO2 breakthrough and channeling of injected CO2 toward the problem production well in the foam pattern. Positive response to foam injection is indicated by reduced injectivity and injection profile data in the foam injection well; by results from time sequence monitor logging in the observation well; and by changes in production performance in the high GOR, "offending" production well in the foam pattern. Hall plots and pressure falloff testing were used to measure in situ changes in fluid mobility near the foam injection well. Time sequence logging responses at an observation well located 150 feet from the foam injector provided evidence of changes in fluid flow patterns in response to foam injection. Positive response to foam injection is further evidenced by changes in the C02 production and oil rate performance at the "offending" production well in the foam pilot pattern.
Evaluation of Flooding Strategies for a North Sea Reservoir Using Stochastic Techniques To Model Heterogeneities
Authors: Samuelsen E. T. , Langlais V. N. , Svanes Tarald , Dalen Vilgeir , Tyler K. J.
Published: December 2007

An element model of the Raude member of the Statfjord formation in a North Sea field has been used for development of a long term drainage strategy. The heterogeneities of this fluvial reservou call for the use of stochastic techniques when modelling IOR processes. This approach makes it possible to create more realistic heterogeneity patterns than conventional interpolation techniques, and to produce several possible distributions of facies and petrophysical variables in a simple manner. Facies distribution has been modelled by a technique combining marked point processes and Gaussian random fields. It produces channel belts in 3D with their specific characteristics such as sinuosity. The petrophysical variables are simulated subsequently on a fine grid, taking into account the facies distribution. Upscaling is performed to provide input to the flow simulator. Water, gas and water alternating gas injection schemes are the investigated flooding strategies. Sensitivity tests are performed on different stochastic images and selected parameters such as WAG period, residual oil saturation after water-flooding, well location and petrophysical parameters. In this reservoir WAG injection improves the recovery from the element compared to water or gas injection. The average permeability appears to be as important as different spatial facies distributions. The residual oil saturation has significantly more influence on the recovery than considering spatial distributions of facies and permeability.
Daqing Oil Field: The Success of Two Pilots Initiates First Extension of Polymer Injection in a Giant Oil Field
Authors: Delamaide Eric , Corlay Philippe , Demin Wang
Published: December 2007

Two highly successful polymer pilot experiments were carried out between 1987 and 1993 on the Daqing oil field (People Republic of China) after favorable laboratory results and preliminary reservoir studies.

The Daqing oil field is a fluvio-deltaic formation with several sand beds and great heterogeneities. The oil is slightly viscous (9.5 cp), water is fresh and the temperature is 45°C, making the conditions favorable for polymer injection.

Each pilot consisted of 4 injectors and 9 producers. One pilot was devoted to one reservoir, whereas simultaneous injection into two reservoirs was performed in the second pilot.

Polymer injection was started in 1990 with a 915-ppm-solution of Polyacrylamide. Approximately 0.6 PV of solution was injected in each pilot, yielding a significant decrease in the water-cut and a respective oil production of 73 120 m3 and 1 1 8 950 m3 in April 1993.

The results of the pilots were matched with a numerical simulator and interpreted in terms of reservoir description. The injection parameters were optimized in terms of viscosity and slug size, in order to extend the process to the whole field.

The sensitivity of the process to the reservoir heterogeneity was also considered.
A New Mathematical Model and Experimental Validation of Multicomponent Adsorption
Authors: Song Fu Yin , Islam M. R.
Published: December 2007

Numerical simulation of multicomponent adsorption (such as in foam-forming surfactants, lignosulfonate, polymer/surfactants, etc.) is still at an early stage. Mathematical models of multicomponent adsorption and desorption in a surfactant/rock system have not yet been well developed. In this paper, a mathematical model for multicomponent adsorption, based on surface excess theory, is presented. The mathematical model is validated through more than 30 experimental runs under a wide range of operating conditions. Several multicomponent mixtures were used in the experimental runs to observe the effects of surfactant concentration, chemical slug size, flow rate, rock properties, salinity of the surfactant solution, and temperature. With the application of lignosulfonate as a sacrificial adsorbate, the amount of surfactant adsorption can be reduced significantly. Polymer-surfactant solution flooding system is a economical way to increase the efficiency of chemical injection. Polymer has beneficial effects on surfactant adsorption though polymer itself still has strong adsorption at the solid/liquid interface relative to surfactant. Numerical simulation results showed excellent agreement with experimental data.
New Pressure Tool Development Yields Critical Bottomhole Data
Authors: Bond A. J. , Palisch T. T. , Oakley R. M.
Published: December 2007

Development of a new pressure measuring tool has yielded critical bottom hole pressure data in the fields on the North Slope of Alaska. The new tool permits gathering bottom hole pressure and temperature data that previously was uneconomical to obtain. This paper outlines the development of the new pressure measuring tool, its application and the results obtained from the new data. Also presented are the large cost savings that have been realized through the use of this tool.
Improvements in Defining the Magnitude of the Minimum In-Situ Stress Using Hydraulic Impedance Testing and Pressure Derivative Analysis.
Authors: Branagan P. T. , Holzhausen G. R.
Published: December 2007

Hydraulic Impedance Testing (HIT)1,2 is an easily applied transient pressure response method that can be successfully employed in determining fracture closure. In addition pressure derivative analysis when applied to fracturing and/or falloff data can readily define the actual changing flow regimes that exist within the fracture at any given time. Knowledge of the proper flow regime is a critical component in selecting the most appropriate analysis methods that should be used to define the minimum in-situ stress (σmin), i.e techniques based on linear or bilinear3 flow analysis. The combined diagnostic methodology that employs HIT and improved pressure derivative analysis4 when used in conjunction with conventional microfracturing techniques5,6 can substantially reduce the error in defining σmin. The results of several field tests will be used to illustrate the power and simplicity of these techniques in assessing what can often appear to be ambiguous pressure falloff data.
Analysis of Pressure Data From Heterogeneous Reservoirs: Wellbore Storage and Skin Effects
Authors: Chu Lifu , Reynolds A. C.
Published: December 2007

We consider a well completed in a heterogeneous reservoir where permeability is a function of position and investigate the analysis of well-test pressure data influenced by wellbore storage and skin effects. Methods to estimate the pressure drop due to skin are presented. It is shown that if wellbore storage effects are small or can be removed by deconvolution, then an equivalent radial permeability distribution can be estimated. By combining this permeability distribution with the estimate of an appropriately defined skin factor, it is shown that reliable predictions of long-time well performance can be obtained.
Higher-Order Neural Networks in Petroleum Engineering
Authors: Kumoluyi A. O. , Daltaban T. S.
Published: December 2007

In this paper, we discuss the general application of higher neural networks, this follows from the successful application of such networks to the identification of well test models. During the course of the research, it was discovered that these networks have a large range of applications in petroleum engineering. Hence the objective of this paper is to give a background of higher order neural networks and their potential uses. Conventional neural networks have activation functions that are linear correlations of their inputs, whereas higher order networks have a non-linear correlation of their inputs. Higher order neural networks do not have wide practical applications due to the enormous amount of parameters (weights) associated with them. However, for certain problems these vast amount of weights are greatly reduced by constraining the architecture of the network. That is, problems that need to be classified regardless of some transformation groups such as translation, scaling and rotation. A typical example is the identification of well test models where standard type curves are translated both horizontally and vertically with respect to field data plots.
Practical Well Test Interpretation
Authors: Mattar Louis
Published: December 2007

Well Test Interpretation involves much more than Pressure Transient Analysis. It includes scrutinizing the field notes, the surface operations, the equipment and the wellbore configuration. It means incorporating geological information and production information; adjusting the measured data to reservoir conditions and accounting for multiphase effects both in the wellbore and in the reservoir; recognizing that wellbore effects during a buildup are different from those during a drawdown; in short, integrating the practical issues with the theoretical analysis.

Field examples will be presented to illustrate these effects. Ignoring these effects can lead to the wrong pressure transient analysis.
Roller-Vane Motor and Pump
Authors: Grupping A. W.
Published: December 2007

Roller-vane motors and pumps are positive displacement type rotating machines. They are of simple design, short, compact and lightweight. The mud motor is particularly suitable for short-radius directional drilling and well cleaning. The pump will lift a full range of volumes of oil, water or brine. The production motor/pump combination is an attractive alternative to other artificial lift methods as its efficiency is high, the pump speed is variable by control of the power fluid, the set can be installed in strongly deviated wells and can be installed/retrieved without pulling the tubing.
Applications for Multiphase Compartmentalized Material Balance
Authors: Ehlig-Economides C. A.
Published: December 2007

Material balance computations provide a mechanism for estimating the volume of fluids in place underground. Frequently the material balance is applied without using exhaustive static data from geophysical, geological and petrophysical analyses that would provide an independent estimate for fluid volumes in place. Workstations offer a possibility to integrate data from many sources and enable highly detailed visualizations of delineations of reservoir limits, correlations of geological features among wells, potential barriers to flow, and reservoir heterogeneity. The reservoir model derived from the workstation environment contains sufficient detail to discourage the conventional global material balance approach as too simplistic. Instead, partitioning the reservoir into compartments, or portions of the reservoir with similar fluid flow characteristics and a common recovery mechanism, offers a means to incorporate the volumetric estimates from static data into material balance equations, thus enabling the use of these equations for additional purposes.

Fox, et al.1 introduced the compartmentalized single phase material balance as a means for characterizing intercompartment communication and effective compartment volumes and for interpreting pressure transient well tests and formation test pressures in heavily faulted formations. This work extends the concept to multiphase and multiwell cases and for vertical compartmentalization in addition to horizontal.

The objectives of the compartmentalized material balance introduced in this work are to validate compartment volumes, fluid PVT behavior, rock compressibility, and production data, and to quantify and characterize flux between compartments. This paper details the computations used and some of the theory behind them. Then practical applications for this type of model are described.
Practical Aspects of Compositional Simulation
Authors: Wattenbarger Robert A.
Published: December 2007

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.

Compositional reservoir simulation is a relatively new facet of reservoir simulation. Although the mathematical equations are somewhat more complicated than for conventional reservoir simulation, the concepts can be simplified by stating that we are simultaneously modeling (1) three-phase Darcy flow, (2) the movement of each individual hydrocarbon component through the reservoir, and (3) phase equilibrium at each point in the reservoir. The phase equilibrium between gas and oil is determined by the K-values which are used for each particular temperature, pressure, and composition.

Compositional simulation is applied to a variety of reservoir fluids but the most common application is to volatile oil and gas condensate reservoirs. For these reservoirs, gas cycling, waterflooding, and primary depletion can be modeled for the purpose of making economic comparisons and making decisions.

The cost and computational speed of compositional simulation depends partly on the number of components which are being modeled. A typical computational requirement is 0.1 seconds/mesh point/time step on a CDC 6400 computer for a 12 component system.

Introduction

Fortunately, many reservoirs contain fluids which have a simple type of phase behavior and physical properties. It is sufficiently accurate for these fluids, to represent the amount of gas in solution as an empirical function of pressure only. The densities of gas and reservoir oil are related to surface densities through formation-volume-factors which are empirical functions of pressure. Viscosities are also empirical functions of pressure. pressure. Viscosities are also empirical functions of pressure. Such simple systems are sometimes called "black-oil" systems. This is the type of fluid system which has been the basis of most of the reservoir simulation technology developed in recent years.
Comparative Analysis of Successful Application of EOR in Russia and CIS
Authors: Basnieva I. K. , Zolotukhin A. B. , Eremin N. A. , Udovina E. F.
Published: December 2007

The oil industry of the former Soviet Union (FSU) has extensive experience in enhanced oil recovery (EOR) methods. Variety of conditions, both geological and geographical, require systematic analysis of the applicability of EOR methods under different reservoir conditions.

Fuzzy logic comparative analysis enabled the identification of the main reservoir/fluid parameters that have an impact on the success of EOR methods. Analysis was done on EOR methods such as steam injection, polymer flooding, surfactant flooding, group of the gas injection methods, and CO2-flooding. The data base created by the authors includes more than 800 EOR projects with a substantial part of them carried in the FSU. Several examples of the EOR feasibility study are discussed in the paper.

The approach described in this paper allows the selection of secondary/tertiary oil recovery methods which are most promising for the given geological conditions. This reduces the number of diverse field performances and, hence, shortens the risk and uncertainty in the decision making.
Measurements of Complex Electrical Conductivity and Fluid Permeability In Porous Rocks at Raised Confining Pressures
Authors: Glover Paul W. J. , Meredith R. G. , Sammonds P. R. , Murrell S. A. F.
Published: December 2007

Combination of electrical and permeability measurements provides a great deal of information about changes in pore and crack networks as saturated rocks are deformed. Complex electrical parameters measured as a function of frequency provide information on the internal surface topology of the rock, information that is of prime importance to explanation of the way fluid permeability of rocks varies with confining pressure and deformation. Tests made at raised hydrostatic confining pressure and during uniaxial deformation until failure, show how processes of pore/crack compaction, dilation and inter-linking control both the electrical conductivity and the fluid permeability of the rock.
Capillary Forces: The Neglected Factor In Shale Instability Studies?
Authors: Forsans Thierry M. , Schmitt Laurent
Published: December 2007

Most phenomena in shale drilling instabilities have only been proved in laboratories, on reconstituted, outcrop or core samples. Partial saturation is evidenced for these samples, its origins explained and its consequences detailed. A model is proposed for the calculation of the apparent compressive strength of a rock from its pore size distribution and moisture content. Effects of capillary pressures are presented in various shale/fluid inhibition tests and some classical interpretations turned down. Last, a rehydration procedure is presented, which has been validated on a low permeability shale.
A Non Iterative Technique for Solving Parabolic Partial Differential Equation Problems
Authors: Sheffield M.
Published: December 2007

This paper presents a new noniterative difference technique which may be used to solve parabolic partial differential equation parabolic partial differential equation problems, including those arising in the prediction problems, including those arising in the prediction of fluid flow in a porous media. It is shown that this difference technique is unconditionally stable and is suitable to solve engineering problems. A comparison is made between the new problems. A comparison is made between the new method and two other stable noniterative difference techniques, the Saul'ev technique and the noniterative ADI technique. Of the two problems worked as examples, the new method is problems worked as examples, the new method is most efficient for the elongated grid problem, and noniterative ADI is most efficient for the square grid problem.

Introduction

Since the introduction of high speed computers, a reservoir engineering research goal has been to develop increasingly efficient methods of predicting reservoir fluid movement. Various methods have been developed or used by petroleum engineers to predict the performance petroleum engineers to predict the performance of an oil field. The major emphasis in the solution of partial differential equations simulating multiphase fluid flow has been the finite difference approach, which can be summarized by the following series of steps.

The reservoir or section of a reservoir is characterized by a series of mesh points wit varying rock and fluid properties simulated at each point. The partial differential equations which describe the fluid flow are written. At each mesh point the partial differential equations are replaced by difference equations. The resulting equations are solved [sometimes iteratively to obtain an approximate solution to the original partial differential equation problem.

This paper presents a new technique for replacing the differential equation at each mesh point by a difference equation.

Difference equations are evaluated in terms of the stability, consistency and order of accuracy. Usually these items are discussed in regard to solution of the diffusivity equation, a linear partial differential equation for sore uniform rectangular mesh covering the region of interest. The same approach is used here. However, it should be noted that the conclusions reached considering a linear partial differential equation and a uniform rectangular mesh are not always applicable to petroleum problems where the differential equations are nonlinear and the mesh is often not uniform.

DESCRIPTION OF THE DIFFERENCE TECHNIQUE

In this paper a new two-step noniterative difference technique is presented.
Experimental and Numerical Analysis of Strain Localization In Two Rock Materials
Authors: Diouta N. G. , Haied A. , Kondo D. , Shao J. F.
Published: December 2007

The theoretical framework of strain localization is summarized. Two kinds of material are studied: an overconsolidated clay and a sandstone. In the case of the oveiconsolidated clay which is contractant, non-associativity of a plastic flow (Khan's model) is found to be sufficient for the detection of the localization in the hardening regime. But for a strong dilatant material such as Fontainebleau sandstone, the non-associativity is no longer sufficient. Non coaxial flow theory needs to be added to the constitutive law to have bifurcation consistent with data provided by careful experiments.
A solution to wave propagation in randomly heterogeneous media: The 3-D analogue of the 1-D reflectivity sequence
Authors: Leary P. C.
Published: December 2007

Measurement of seismic structure at scales below «20m (the resolution limit of surfacegenerated seismic waves) requires borehole seismic sources and receivers. For borehole seismic data analysis, typical seismic imaging using plane wave propagation in 1-D layering must be supplanted by spherical wave propagation in 3 dimensions. Images of production fronts and discrete rock units must be sought as coherent scattering in a background of incoherent scattering by random discontinuities. The spectrum of scattered waves measures the density and size of the velocity fluctuations; as velocity fluctuations are often due to changing porosity and fracture density, broadband borehole seismic scattering spectra can characterize these features of reservoir volumes in the sub-metre to multi-metre range.
Steady and Unsteady State Two-Phase Flow Through Vertical Flow Strings
Authors: Gould T.L. , Tek M.R.
Published: December 2007

A numerical simulation for vertical multiphase systems has been developed, based on the original concepts presented by J. Orkiszewski. The rather marked variability for different flow regimes in a given well and the simultaneous coexistence of these various regimes at different depths are properly accounted for in the interative calculation of the pressure distributions. The method features the most reliable and proven correlations available for each of the flow regimes encountered. A programmed data package in support of the above correlations is described.

The concept of "Lifting Potential" introduced in an earlier paper has been programmed, permitting applications in programmed, permitting applications in a variety of multiphase flow problems. These include both steady and unsteady state applications. In general, the applications involve the study of "heading," "loading," "unloading," and "dying" of gas wells subject to liquid production, as well as different well production, as well as different well engineering and design optimization problems encountered in gas-lift and problems encountered in gas-lift and condensate production.

Introduction

The occurrence of two-phase flow in vertical flow systems is common to many engineering applications. Problems ranging from oil field technology to boiler design, from nuclear reactors fluidized beds, from special heat exchangers to thermosiphon reboilers frequently encounter conditions of multiphase flow.

The main problem of engineering interest in vertical two-phase flow may be defined as follows: Knowing the physical properties of each phase, physical properties of each phase, geometry of the flow system and conditions prevailing at one terminus to predict the pressure distribution along predict the pressure distribution along the pipe.

The literature available on vertical two-phase flow includes a large variety of correlations, analytical and empirical methods developed for prediction of energy losses as well as the flow regimes. It is significant to note that the references quoted above belong to two notably different schools of thought. The first group of papers, references 1 through a correlate friction losses by a unique energy loss factor without any particular regard to "slippage." particular regard to "slippage."
Rock failure mechanisms identification: A key for wellbore stability and reservoir behaviour problem
Authors: Maury V.
Published: December 2007

Generally several deformation and rupture mechanisms are involved in the problems of wellbore stability and reservoir behaviour. Adequate prognosis of the main mechanism responsible for an unexpected behaviour is a fundamental step in proposing a remedy which sometimes may be unusual or not conform to common practice but which has proven to be successful in several applications. This paper reviews and recalls some basic mechanism of wellbore instability until present overlooked and their practical consequences on the remedy to the problem. Another illustration is given by the various mechanisms involved in the reservoir behaviour of highly compactable material and the necessary evaluation of mechanisms involved for the prediction of significant movements.
Finite element modelling of shear band localisation and application to rock cutting by a PDC tool
Authors: Pierry Joélle , Charlier Robert
Published: December 2007

Several simulations of rock cutting at great depth by a single PDC cutter were carried out using the finite element method. They proved of great help in understanding the failure mechanisms inside the rock that are determinant for cutting efficiency. Shear bands, i.e. weaker regions along which a chip will develop, are successfully detected and localised using two different criteria, including an original one based on the evolution of strains during the cutting process. As classical finite element meshes lock the actual progression of shear bands, remeshing techniques are developed and applied so as to model the effective formation of chips into the rock. Automation of the different steps will result in a very useful numerical tool for optimisation in well-boring.