bluuebunny/crossref_metadata_2025 huggingface dataset:
Pressure Transient Analysis in a Reservoir with a Compressible or Impermeable Circular Subregion: Gas Cap or EOR-Induced
Authors: Sageev Abraham , Horne R. N.
Published: December 2007

A practical pressure transient analysis method is presented for the analysis of a drawdown test in a well near a circular subregion. Such subregions may exist naturally as gas caps or may be artificially produced by EOR operations. These subregions may be treated as either constant pressure or impermeable inner boundaries. The problem is mathematically posed and solved using the Laplace Transformation. A new semilog type curve method is presented which may be used to determine the size of the circular subregion and the distance to it. The method is of particular importance in that it permits the estimation of the size of an EOR affected region without shutting in the injection well.
Chemical Stability of Biopolymer Solutions
Authors: Ash S. G. , Clarke-Sturman A. J. , Calvert R. , Nisbet T. M.
Published: December 2007

Biopolymers such as xanthan are being used increasingly in oilfield operations where the stability of the biopolymer is a prime consideration. The stability of xanthan depends on the brine salinity. Good viscosity retention over many months is observed in sea water at 90°C. The successful application of xanthan at temperatures higher than 90°C requires an understanding of the factors that limit stability. These factors include the nature of the polymer and the mechanisms of degradation. The stability features of a novel biopolymer are also described.
Porosity From Well Logs of the Kuparuk Reservoir: Procedures for Using Core Data
Authors: O'Brien W. J.
Published: December 2007

This paper describes a reservoir description technique for computing porosity using both core and log data from the Kuparuk formation, North Slope, Alaska. Core porosity is used as a calibration tool to define clay parameters of the gamma ray and porosity logs. The gamma ray log must be normalized to apply its corresponding clay parameters. This approach is necessary in this reservoir because of the uncertainty in estimating clay volume fractions from well logs alone. Clay parameters can be applied over a wide area to compute porosity in uncored wells.

An analysis of core samples indicates that quartz and siderite are the dominant non-clay components. Various clay minerals and minor amounts of other carbonate minerals are also present. Moreover, natural fractures and vugs have been identified in core samples from zone C of the Kuparuk. Porosity and volume fractions of quartz, siderite, and clay are calculated using the density, neutron, and gamma ray logs. Fractured intervals are identified with the sonic log.

A comparison of core versus log data is presented from three cored wells of the Kuparuk field. Siderite concentrations obtained from logs agree with foot-by-foot measurements on cores. Agreement between computed and core porosity is usually two porosity units or better.
Monitoring the Effects of Hydraulic Stimulation by Microseismic Event Location: A Case Study
Authors: Batchelor A. S. , Baria Roy , Hearn Kevin
Published: December 2007

One of the most promising techniques for monitoring the effects of hydraulic stimulation or fracturing is the use of the induced microseismicity to define the shape and orientation of the stimulated regions. The results presented in this paper are believed to be the first of their kind with an on-line location system mapping the stimulated zone during injection. The stimulation was undertaken as part of an investigation into the generation of hot dry rock geothermal reservoirs and consisted of a 3.5 million gallon injection at flow rates as high as 40 B/min. Many thousands of microseismic events were produced, located and presented as maps to enable the interpretation to proceed during the operation.

There are very few techniques which have been applied to give an independent measurement of fracture height, length and orientation. The monitoring of microseismicity offers the prospect of an accurate definition of the geometry provided other observation wells are available. The techniques presented in the paper would be applicable in dense, brittle formations without a significant velocity anisotropy. They are of direct relevance to the stimulation of geothermal systems, tight gas sands and limestone reservoirs. The results from such case studies will enable the design of fracturing procedures to be evaluated on directly measured results.

The results presented in the paper consist of a series of microseismic images relating to different stages in the hydraulic fracturing. The fracture front can be seen to grow with time and change orientation. The initial stimulated zone produced was 1.2 km long, 1.5 km high and 100 m thick. When the pressure was maintained on the system the stimulated zone grew to 400 m thick with the principal dimensions remaining the same.

These results represent a considerable step forward in the state of the art of monitoring hydraulic stimulation and have been an essential tool in understanding the geothermal reservoir performance.
Automated Type-Curve Matching in Well Test Analysis Using Laplace Space Determination of Parameter Gradients
Authors: Rosa A. J. , Home R. N.
Published: December 2007

This paper presents an investigation of automatic methods of type curve matching for the interpretation of drawdown tests in the presence of wellbore storage and skin. Gauss or Gauss-Marquardt nonlinear regression methods are used to estimate wellbore, reservoir and boundary parameters in single layered, unbounded reservoirs. The use of numerical Laplace Transform inversion techniques to obtain gradients of the solution with respect to the unkown reservoir parameters makes the problem particularly streamlined, and is a major improvement on existing techniques. In addition, constraining the reservoir parameters to positive values (where appropriate) is found to improve convergence of the nonlinear regression algorithms.

Nonlinear regression algorithms require analytical expressions for the reservoir pressure drop and its derivatives with respect to the unknown reservoir parameters. These are frequently not available for existing type curves, which has prevented their automated fitting so far.

This work was successful in calculating these functions by numerical inversion of the known analytical expressions in Laplace space, making the automated fitting procedure possible in a wide range of formerly inaccessible cases.

Examples given demonstrate that the regression analysis in some cases can yield better results than the conventional graphical techniques.
Optimum Production Scheduling Using Reservoir Simulators: A Comparison of Linear Programming and Dynamic Programming Techniques
Authors: Lang Z. X. , Horne R. N.
Published: December 2007

An automatic control procedure for the determination of optimal production schedules is developed. Some production parameters such as injection rates or downhole flowing pressure are considered to be the decision variables, the values of which are to be chosen to maximize oil production. At the same time other production and economic parameters (such as water oil ratio) are to be constrained. The procedures discussed here are a way of using reservoir simulators to optimize production schedules in an automatic manner. The approximation of the non-linear processes in the models in terms of locally linear processes permits such problems to be solved iteratively using linear programming. This in turn results in a procedure which is feasible within reasonable expense. The multistep optimization procedure can be carried out in several different ways; step by step, over all time steps at once or using dynamic programming. Step by step optimization converges more quickly but does not take into account influences from one step to the next. Iterating over all time steps is the most desirable but is computationally the most expensive and converges least quickly. Dynamic programming was found to be the most efficient, requiring little additional computational effort beyond the step by step method while still allowing the solution in one time step to influence subsequent time steps.
Abrasion Technology for Electric Submergible Pumps
Authors: King D. G. , Traylor F. T. , Stewart R. E.
Published: December 2007

This paper describes the results of a five-year investigation of sand abrasion phenomena in conventional electrical submergible pumps (ESP). The investigation includes a review of the available literature on two body and three body wear processes in the presence of corrosive fluids, and the development of laboratory test methods from which baseline wear rates for conventional pumps can be established. These baseline wear rates are compared with performance data on pumps incorporating special wear resistant features. Preliminary field test results are also presented.
Compression of Wet CO2 in Reciprocating Compressors
Authors: Tanneberger F. J. , Feldmann J. L.
Published: December 2007

Compressing gaseous carbon dioxide (CO2) with a reciprocating compressor creates a potential for operational problems and inefficient performance. Ingersoll- Rand's (I–R) experience with compressing CO2, both in the field and in a closed test loop, has resulted in a number of recommendations for CO2 reciprocating compressor applications.
Simulation of Miscible Displacement Using Mixed Methods and a Modified Method of Characteristics
Authors: Ewing R. E. , Russell T. F. , Wheeler M. F.
Published: December 2007

Numerical dispersion and grid orientation problems with adverse mobility ratios are two of the major difficulties in the numerical simulation of enhanced recovery processes. An efficient method for modeling convection-dominated flows which greatly reduces numerical dispersion and grid orientation problems is presented and applied to miscible displacement in a porous medium. The base method utilizes characteristic flow directions to model convection and finite elements to treat the diffusion and dispersion. The characteristic approach also minimizes certain overshoot difficulties which accompany many finite element methods for problems with sharp fluid interfaces. The truncation error caused by the characteristic time-stepping technique is small, so large stable time-steps can be taken as in fully-implicit methods without the corresponding loss in accuracy. A finite difference analogue can also be formulated.

Since the computed fluid velocities help to determine the time-stepping procedure in the characteristic-based method and since accurate velocities are crucial in the method's ability to conserve mass, very accurate Darcy velocities are necessary. A mixed finite element method solves for the pressure and the Darcy velocity simultaneously, as a system of first order partial differential equations. By solving for u = −(k/µ)Vp as one term, we minimize the difficulties occurring in standard methods caused by differentiation or differencing of p and multiplying by rough coefficients k/µ.

Using a combination of characteristic-based time-stepping procedures and mixed methods for accurate velocities, a variety of problems with variable (or random) permeabilities, adverse mobility ratios, and tensor dispersion models are examined. A study of viscous fingering is presented. Computational results on a variety of two-dimensional problems show minimal grid-orientation effects, reduced numerical dispersion, minimal overshoot at the front, and very low mass balance errors.
A Nine-Point Finite Difference Operator for Reduction of the Grid Orientation Effect
Authors: Shah P. C.
Published: December 2007

The grid orientation effect is a long-standing problem plaguing reservoir simulators that employ finite difference schemes for solution. The nine-point finite difference scheme is a well known way of reducing this effect. The schemes available in the literature are applicable only to point distributed grid systems. However, most simulators used in practice employ block centered grid systems. In this report we present a derivation of a new nine-point scheme for the block centered grid systems. The derivation is based on physical consideration and hence is free from any problems such as asymmetry or negativity of interblock transmissibilities that arise in some published schemes. The scheme is applicable to nonuniform rectangular grids and to reservoirs with inhomogeneous permeability distributions; both isotropic and anisotropic cases are treated. The expressions resulting from the new scheme reduce to those published in the literature when a square uniform grid and homogeneous isotropic permeability are considered. The reduction in the grid orientation effect due to the new scheme is illustrated by a study of the steam-flood process in a five-spot pattern.
Fieldwide Simulation of the Anschutz Ranch East Nitrogen Injection Project With a Generalized Compositional Model
Authors: Wendschlag D. D. , Stephenson R. E. , Clark T. J.
Published: December 2007

Anschutz Ranch East is a major rich gas condensate field located in the Western Overthrust Belt on the Wyoming-Utah border. The plan-of-depletion for the field involves injection of nitrogen to maintain reservoir pressure above the dew point of the in-place fluid.

Reservoir simulators were an essential tool in development of the Anschutz Ranch East plan of depletion. The fluid complexity dictated that a compositional simulator be employed which uses an equation of state. The preliminary simulation work was performed using a symmetry element, since data were initially very limited. As additional data became available, simulation efforts were directed towards modeling the entire field.

This paper discusses both the fieldwide and symmetry element simulations. The symmetry element approach was found to be adequate for comparison of various depletion schemes. Its limitations when extrapolating performance to the full field were identified. The performance of fieldwide simulations requiring up to 3.75 million words of storage was found to be efficient on scalar hardware.
A Comprehensive Well Management Program for Black Oil Reservoir Simulation
Authors: Wijesinghe A. M. , Leventhal S. H. , Mukherjee Hemanta , Laskey K. J. , Culham W. E.
Published: December 2007

A comprehensive well management program developed for use with current state-of-the-art black oil simulators during the prediction phase of reservoir performance studies, is presented. The reservoir is modelled as a hierarchical system possessing field, group, and well levels of control at which production and injection specifications and constraints can be imposed. The program enables wellhead rate changes, shut-in and reopening of wells, workovers, stimulations, artificial lift, and the drilling of new wells to be executed automatically to maintain production and injection levels. It also has the capability to automatically maintain the average reservoir pressure within specified limits through injection and production rate changes. This program incorporates a high degree of functional logic and many new concepts, strategies, and options not reported previously in the literature.

In this paper, the logical structure of the program, its optional features, and the strategies employed at different levels of control to meet the reservoir management objectives are described and are illustrated through specific numerical examples.
A Reservoir Simulation Model With Platform Production/Injection Constraints for Development Planning of Volatile Oil Reservoirs
Authors: Wallace D. J. , van Spronsen Engel
Published: December 2007

The development planning of offshore oilfields, such as in the British North Sea sector, involves a variety of platform production/injection constraints. The operation of the platforms is governed by reservoir engeering, operational and production policy considerations. This paper describes the production/injection control system as incorporated into a volatile oil reservoir simulator for use as a field management tool.

Production and injection operations are controlled at three levels in an offshore oilfield: At the individual well level in which rates, well inflow performance, pressure constraints and well bore hydraulics play a role.At the platform level in which well rates have to be controlled within available capacities (oil/gas/water production, gas/water injection).At the field level in which total fluid production from the field is governed by pipeline/tanker capacity, allowing shortfall to be taken up by platforms operating with spare capacity.

To meet gas sales contracts and/or flaring constraints use is made of gas wells operating in a dual injection and production role ("gas-control wells").

Such gas-control wells enable surplus gas production to be reinjected or alternatively gas to be produced to meet a gas sales contract.

The paper further describes the possibilities of the well management package to implement a policy of voidage replacement or pressure maintenance in distinct reservoir partitions (zones). Pressure maintenance is defined as maintaining the hydrocarbon pore volume averaged pressure at datum. Such strategies interact with the total available injection capacity of the platforms and/or the distribution of capacity usage over the platforms.
Iterative Methods for the Solution of Linear Equations Based on Incomplete Block Factorization of the Matrix
Authors: Meyerink J. A.
Published: December 2007

This paper presents a class of iterative methods for the solution of linear equations like those that arise in reservoir simulators. The methods are generalisations of the incomplete LU-factorisation technique introduced earlier.

It can be applied to equations generated by the usual 5- and 7-point finite difference approximations as well as to those generated by special 9-, 11-, 19-and 27-points approximations.

Application of the method to equations where the band structure of the matrix has been spoiled, e.g. by wells that are perforated in more gridblocks or by an irregular gridblock structure, is discussed and modifications for running efficiently on vector processors are given.

Numerical examples for well-known testproblems are presented and compared with results of other methods.
Incomplete Gaussian Elimination as a Preconditioning for Generalized Conjugate Gradient Acceleration
Authors: Wallis J. R.
Published: December 2007

This paper discusses the application of preconditioned generalized conjugate gradient acceleration to fully implicit thermal simulation. The preconditioning step utilizes incomplete Gaussian elimination (IGE) to form an approximate factorization of the Jacobian matrix.

The implementation allows any finite difference approximationany grid block orderingassociated well constraint equationsany level of incomplete factorizationreduced system preconditioningconstrained residual preconditioning

Acceleration procedures include ORTHOMINORTHORES

IGE preconditioning and its implementation is discussed with respect to five, seven, nine or eleven-point finite difference approximations and optional well constraint equations. Numerical results were obtained using a thermal model allowing any number Nc of components. The model's implicit formulation requires the solution of a linear system of equations in which each grid block has Nc + 1 unknowns. Test problems involved combustion, steam drive and cyclic steam stimulation processes, some of which exhibited ill-conditioning, negative transmissabilities and high transmissability ratios. Numerical results indicate how different grid block orderings, different levels of incomplete factorization and different acceleration procedures affect convergence, storage and work requirements.
An Extension of Pseudofunction Concepts
Authors: Thomas G. W.
Published: December 2007

In this work, we examine various pseudo function concepts that have appeared in the technical literature Emphasis is devoted to gravity-segregated vertical equilibrium (VE)4 and a dynamic pseudo function concept that requires no assumptions regarding the state of fluids in a reservoir. We extend the gravity-segregated VE concept to a system of N stratified layers and show that, in reality, the Hearn technique11 is a special case of this. We also relate it to previous work by Coats et al4 and van Poolen, et al10.

The dynamic pseudo function approach we postulate leads to the concept of sets of directionally dependent and time-dependent pseudo relative permeabilities. We discuss its connection with a similar work of Kyte and Berry8 and finally, present an example application of this extended idea.
New Method for Finding Hydraulic Diffusivity From Data in Underground Storage
Authors: Udegbunam E. O. , Tek M. R. , Wilkes J. O.
Published: December 2007

A new transient well-testing procedure, which extends "pulse-testing" technology, has been developed for determining the hydraulic diffusivity (K/[μcϕ]) in underground-storage reservoirs. The method depends on the availability of cyclic pressure data from a pair of adjacent and communicating wells: A, the upstream or "forcing-function" well, and B, the downstream or "observation" well.

In general, the pressure fluctuations at well B will exhibit both an attenuated amplitude and a phase lag when compared with those at well A. The theory, which relates the two sets of fluctuations, relies on a solution of the diffusion equation, which governs pressure or potential variations with time and distance in a compressible medium.

To apply the theory to experimental observations, a Fourier analysis is performed on the transient pressures at both A and B. The method has been tested with field data and indicates good success in predicting the pressures at offset wells.
A Coupled Fracturing Model and its Application to Hydraulic Fracturing
Authors: Roegiers J. -C. , Ishijima Y.
Published: December 2007

Although hydraulic fracturing has been used for several decades in the stimulation of hydrocarbon reservoirs, a thorough understanding of the interwoven phenomena is still lacking, especially in the case of porous media. This paper describes a two-dimensional numerical approach allowing the study of the fluid/rock skeleton interaction. The elastic stress analysis is coupled with the transient fluid-flow phenomenon. By introducing a failure criterion based on the critical stress intensity factor, quasi-static situations can easily be studied and instability conditions outlined.

This approach was used to interpret fracture initiation, fracture reopening as well as fracture closure after shut-in. The pressure/time curves generated for each of these phenomena clearly depend on the percolation characteristics of the fracturing fluid and the contact time as well as on the intrinsic properties of the rock mass.
Production Potential from Devonian Gas Shales: Effective Production Strategies
Authors: Kuuskraa V. S. , Wicks D. E. , Sawyer W. K. , Esposito P. R. , Komar C. A.
Published: December 2007

The estimate of technically recoverable gas from Devonian shale in Ohio ranges from 6.2 to 22.5 Tcf, depending on stimulation method and pattern size selected. This estimate is based on (1) a compilation of the latest geologic and reservoir data, (2) analysis of key productive mechanisms, and (3) examination of alternative stimulation and production strategies.

The key findings of this study are: A substantial volume of gas is recoverable, although advanced technology will be required to reach economically attractive production rates in the state,Well spacing can be reduced by half from the traditional 150 to 160 acres per well without severly impairing per-well recovery, andDue to the high degree of permeability anisotropy in the shales, a rectangular, generally 3 by 1 well pattern leads to optimum recovery.
New Generation Fracturing Fluid for Ultrahigh-Temperature Application
Authors: Harms S. D. , Goss M. L. , Payne K. L.
Published: December 2007

This paper presents the results of laboratory tests on a unique combination of polymer, stabilizer and crosslinking chemicals that provide the extended thermal stability necessary for high temperature massive hydraulic fracturing. This fluid system was designed to improve the efficiency of MHF operations, With this thermally stable fluid, treatments may be designed using 20% less polymer than conventional fluids. The lower polymer loading helps lower costs and reduces the possibility of damage due to polymer residue.
High-Strength Proppants Behavior Under Extreme Conditions
Authors: Becq D. F. , Roque Claude , Sarda J. P.
Published: December 2007

Various types of propping agents have been tested in order to evaluate their behaviour at great depth. Several experimental procedures have been used: short duration tests with stress increase at constant temperature, long term tests at constant stress and temperature, tests with simultaneous increase of stress and temperature, with and without continuous flow of water or brine. The behaviour of the proppants having-the "average" density of 3.7 is satisfactory up to a temperature of 100 to 150°C and a stress of 70 MPa.

In order to simulate the steam injection or geothermal, or water producting wells, the propping agents have been tested first without stress at 200°C and 280°C in alcaline solutions at pH chosen from 10,5 to 11,5. At 280°Cthe behaviour of these materials is insufficient at pH 11,5 relatively satisfactory at pH 10,5 for the bauxites having a low silica content. At 200°C a stress of 10 MPa leads to a loss of mechanical strength, Whatever pH may be.
Initial Study of Temperature and Pressure Effects on Formation Damage by Completion Fluids
Authors: Allen F. L. , Riley S. M. , Strassner J. E.
Published: December 2007

An apparatus was selected and modified for formation damage studies at elevated temperatures and pressures. Procedures were developed to ensure reproducible results and are discussed in detail. Initial tests demonstrate a decline in formation damage with increased temperature when clear brine systems are used. The technique may be applicable for selection of drilling and completion fluids for field use.
Vapor-Liquid Phase Behavior Of The Helium-Methane System
Authors: Sinor J.E. , Schindler D.L. , Kurata F.
Published: December 2007

Publication Rights Reserved

This paper was to be presented at the 40th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colorado, October 3–6, 1965, and is considered to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract elsewhere after publication in the Journal of Petroleum Technology or Society of Petroleum Engineers Journal is granted on request, providing proper credit is given that publication and the original presentation of the paper.

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.

This report presents more extensive experimental vapor-liquid equilibria data for the helium-methane system than is found in the literature. A static sampling technique was used to obtain vapor and liquid compositions for six temperatures between -180C and -85C and pressures up to 2,000 psia. Data at 2,000 psia were extended to the critical temperature of the mixture.

Average scatter of the data from the smoothed lines is approximately 1 per cent of the helium concentration or 0.03 mole per cent helium, whichever is greater. Vapor compositions -140C, -160C, and -180C were analyzed by a different technique and scattered on the average from the smoothed curve less than 4 per cent of the methane concentration. Comparisons are drawn between the data of this study and the previously published work of Kharakhorin. The solubility of helium in liquid methane was found to be considerably less than the values indicated by Kharakhorin.

Experimental data are presented in tabular form and in various phase-composition diagrams. The behavior of the helium-methane system is seen tb be very similar to that of the helium-nitrogen system, with helium being much less soluble in methane than in nitrogen.

The data were satisfactorily correlated by means of the Krichevsky-Kazarnovsky equation. Extrapolations to higher pressures should be feasible.

VAPOR-LIQUID PHASE BEHAVIOR OF THE HELIUM-METHANE SYSTEM

Interest in conserving the only appreciable supply of helium has led to legislation enabling private industry to extract helium from streams of natural gases in which it occurs. The helium is purchased by the government for storage in underground formations. The separation processes used by all recovery plants now in operation depend upon low-temperature phase-equilibrium phenomena. Since helium is the least condensible of all gases, it is obtained by condensing all of the other components present in the natural gas. The helium-free natural-gas is then returned to the market stream.
Screening Tests to Evaluate Formation Damage in EOR Operations
Authors: Somerton W. H. , Chen S. P. , Schuh M. J. , Yuen J. P.
Published: December 2007

Tests have been run on cores from a number of California oil-producing formations, which are potential candidates for Enhanced Oil Recovery (EOR) operations, to evaluate the effects of disturbing fluid/rock equilibrium by injecting EOR fluids. The fluid-flow capacity of reservoir rocks may be severely affected by introduction of foreign fluids. In addition, loss of injected chemicals to the rock by adsorption, ion exchange, and mineral dissolution and by reactions with formation brines, may minimize the effectiveness of the EOR fluid injection.

Many of the cores tested did show serious reduction in fluid-flow capacity upon changing the ionic content and/or concentration of the injected fluid. This reduction is attributed to mobilization of and subsequent plugging by formation fines. Ultra-fine mineral particles have been noted in the effluent from fluid-flow tests. Some cores from two Southern San Joaquin Valley fields (Kern Front and Midway-Sunset), showed anomalous behavior in this regard. These cores showed a reduction of the effluent pH to as low as 4.0 when neutral NaCl solution was injected. This pH reduction which lasts for many pore volumes (PV) of injection, is attributed to H+/Na+ exchange, releasing H+ into the flowing fluid. These cores, although mineralogically similar to other cores from the same formation and, in one case, from the same well, show no reduction in permeability regardless of the nature of the injected fluid.

Screening tests have been developed to identify those cores which do not show permeability reduction to fresh-water injection. Similar tests have also been developed to demonstrate the effectiveness of stabilizing agents (dilute AlCl3 solution in this work) in reducing the susceptibility of cores to permeability reduction.
Log-Derived Stratigraphic Reservoir Description
Authors: McGinley T. R. , McKnight T. N.
Published: December 2007

Definitive resolution of rock type in complex lithology enhances full development of hydrocarbon reserves. The suggested petrophysical model combines acoustic, neutron, bulk density and photoelectric effect in a descriptive four-mineral model that requires minimum log parameter decisions. Results are utilized to understand subsurface geology and design well completions.
A Capillary Viscometer for the Study of EOR Polymers
Authors: Liauh W. W. , Liu T. W.
Published: December 2007

This paper describes the design and principles of operation of a new capillary viscometer that was developed to measure viscosities of dilute EOR polymer solutions under conditions involving both high temperature and low shear rate. Development of this viscometer was undertaken primarily because there are no commercial viscometers available to make measurements under these conditions. The viscometer was designed so that it could also be used at low temperatures and at high shear rates. In addition, it has the capability to qualitatively determine the viscoelastic character that polymer solutions often exhibit in porous media.

Some results obtained with the capillary viscometer are also presented. This viscometer has been used to make viscosity measurements at shear rates ranging from 0.01 to 10,000 sec−1 and at temperatures from 20 to 99°C. Results obtained to date indicate that the viscosities of different polymers respond quite differently to changes in temperature. For example, compared to the two most commonly used EOR polymers--xanthan bio-polymer and polyacrylamide--scleroglucan bio-polymer has a more favorable viscosity-temperature relationship. The effectiveness of the scleroglucan polymer, as measured by its viscosity relative to water, increases with temperature, while that of the other two polymers decreases with temperature. In general, the relationship between viscosity and temperature is an important consideration in selecting the most effective polymers for high-temperature applications.
Methods of Enhancing Fluid Communication in Oil Sands
Authors: Tam E. S. , Edmunds N. R. , Redford D. A.
Published: December 2007

Effective steamflooding of oil sands requires fluid communication between injectors and producers. Such a communication path can be developed through a naturally occurring zone of low bitumen saturation. If a water sand with little or no bitumen saturation is encountered, high injectivity can be achieved and a steamflood can be carried out immediately. With zones having mobile water and some bitumen as well, special enhancement processes are required to prevent tar bank ing when steam is injected which is common in steam drive processes where cold bitumen is displaced ahead of a steam front. One way to prevent tar banking is to heat the mobility zones slowly with hot water so that hot bitumen will be displaced when steam drive is initiated. Depending upon the nature of the mobility zones, the efficiency of the enhancement process might be improved by the use of solvents such as naphtha or synthetic crudes.

In this study numerical simulation was used to develop a communication enhancement process which involves the stimulation of production wells with hot water followed by hot water injection into the injection well. A reservoir description was assumed with initial mobility such that a steam drive process could not be started readily. Results of the study indicate that the communication path can be heated gradually using production wellbore stimulation and hot water injection. However, the process is not effective for low mobility zones. In the latter case organic solvents may be used to enhance the process. The study generally outlines the range of permeability thicknesses for which hot water can be used as an enhancement agent. The possibility of using CO2 as a viscosity reduction agent was also considered. Results show that CO2 injection cannot attain mobile conditions for the bitumen unless the reservoir pressure is sufficiently high. On the other hand, CO2 has an adverse effect on water injectivity; CO2 is not recommended as a communication enhancement agent unless sufficient high injection pressure is used.
CO2 Miscible Flooding Evaluation of the South Welch Unit, Welch San Andres Field
Authors: Keeling R. J.
Published: December 2007

The South Welch Unit, in Dawson County, Texas, was selected as a miscible flooding candidate in 1981 based on the recommendation of a feasibility study. The central 300 acres (1,214 Mm2) of the unit were designated as the Phase One area, and infill drilling of this area was begun in 1981. CO2 injection was initiated in February of 1982 with CO2 trucked to the location in liquid form. Simulations were made to predict the recovery from the Phase One area under several production methods. These methods included:

20% IHCPV slug CO2 injected continuously 20% IHCPV slug CO2 injected using a 2:1 4 cycle WAG 25% IHCPV slug CO2 injected using a 2:1 5 cycle WAG Continued waterf looding on 20 acre line drive patterns

All simulations were made with the current CO2 supply limitations taken into consideration. The 25% slug, 2:1 5 cycle WAG case is the optimum mode of operation based on sensitivity studies.
CO2 Flooding a Waterflooded Shallow Pennsylvanian Sand in Oklahoma: A Case History
Authors: Kumar Rajeshwar , Eibeck J. N.
Published: December 2007

ARCO Oil and Gas Company started work on a CO2 Tertiary Pilot in the Garber field located in Garfield Co., Ok. in 1980. Garber is a Pennsylvanian age, multiplay field, discovered in 1916. It has produced in early years under depletion drive and later by waterflooding. The purpose of the pilot was to investigate the tertiary oil potential of the shallow sands which were previously waterflooded to depletion. CO2 was injected into the Crews sand, a shallow Pennsylvanian sand located at an average depth of 1950 ft (594 m). Prior to the start of the pilot program, the depleted Crews sand waterflood was not producing in the pilot area. The main pilot is a 10.4 acres (4.2 ha), normal 5-spot, which is enclosed by backup water injectors and outside producers. Water was initially injected in the project area to raise the reservoir pressure and to establish a base production curve. Then a total of 27,000 tons (24,500 × 103 kgs) of CO2, equalling 35% HCPV in the effective area, was injected as a straight slug. The pilot response has been very encouraging. The project has already produced 70,000 STBO (11.1 × 103m3). Ultimate recovery from this pilot should exceed 14% of the original oil in place within the effective area. The success of this pilot suggests that it is possible to CO2 flood reservoirs at depths shallower than previously thought possible.
Enhanced Recovery Surveillance Using Well-to-Well Tomography
Authors: Kretzschmar J. L. , Witterholt E. J.
Published: December 2007

In the past decade, the tools of the petroleum engineer for predicting reservoir behavior have increased significantly in terms of more complete mathematical models and enormously faster computing hardware. Unfortunately, the tools for in situ monitoring of actual behavior are largely unchanged and most often involve data characteristic of only a limited volume around individual wells.

Techniques are now emerging which can provide a more complete view of fluid distributions in the reservoir over the entire distance between wells. These techniques, sometimes referred to as geotomography, use wave propagation between observation wells as a basis for reservoir mapping in a procedure analogous to that used in the CAT scan now common in diagnostic medicine.
Observations on Tailoring Chemical Slugs and Simulating Reservoir Cores for an Oil-Wet Reservoir
Authors: Lorenz P. B. , Tham M. K. , Brock Sylvia , Bayazeed A. F. , Burtch F. W.
Published: December 2007

Results are presented from three areas of the laboratory studies in connection with the surfactant-polymer pilot field test conducted by the U. S. Department of Energy: 1. Sulfonate produced, both in the field and laboratory tests, was chiefly in the oil phase, indicating a marked departure from the optimal condition of equal distribution. This cannot be attributed to increased salinity, as the salinity of the produced brine was not very different from that of the injected surfactant slug. Suggested causes are dilution and changing water/oil ratio that resulted in fractional repartitioning of the complex alcohol and sulfonate.

2. The use of dilute brine instead of fresh water for the polymer slug avoided large variations in viscosity that would have resulted from seasonal variations in the supply water. In this connection, it was found that the non-Newtonian character of the polymer was different for two solutions at the same viscosity but different polymer/salt composition.

3. Berea cores, when fired, behaved like the oil-wet reservoir cores in respect to oil recovery, relative permeability, and flow-resistance history. A supplementary silicone treatment to give the same wettability is the oilfield cores had no beneficial effect.
Geology and Physical Properties of the Monterey Formation, California
Authors: Isaacs C. M.
Published: December 2007

Original sediments of the Monterey Formation have diverse compositions reflecting both paleobasin setting (fine detritus) and oceanographic productivity (silica/carbonate). Varying stages of diagenesis, which includes silica phase transformations and dolomitization, have produced fractured reservoirs characterized by a complex array of rock types with a wide range of physical properties.
Two-Phase Flow and Calcite Deposition
Authors: Gudmundsson J. S. , Ortiz-R. J. , Granadso-G. E.
Published: December 2007

The literature on two-phase flow in geothermal wells shows that the Orkiszewski1 method has found wide application in state-of-the-art wellbore simulators. Such a simulator was developed and then used for the problem of wellbore deposition of calcite in the Miravalles geothermal field in Costa Rica. The output of wells suffering calcite deposition decreases slowly at early time but rapidly at late time. The simulator was also used to estimate the deliver ability curve for a large diameter well in the Svartsengi geothemal field in Iceland. The view is presented that more accurate wellbore simulators will make new reservoir engineering studies possible in geothermal fields.
Use of a Mineral Fines Stabilizer in Well Completions
Authors: Borchardt J. K. , Roll D. L. , Rayne L. M.
Published: December 2007

Formation damage in the vicinity of the wellbore is a major cause of low productivity1–6 and the difficulties attendant to restoration of the damage leave a significant number of wells that do not respond to remedial treatment.1 Operators have recognized the importance of damage control during drilling, workover and other operations and have used filtration processes to reduce the damage caused by fluids invading the formation.

Until recently, however, little could be done to control permeability damage caused by the movement of fine particles native to the formation of interest.

Prevention of the migration of fine particles (defined) as those having a diameter less than 44 micrometers and which will pass through the openings of a 325 U.S. mesh screen7) is a complex problem. Certain cationic organic polymers (COP's) have been developed to control the swelling of water-expandable clays such smectite in the presence of low salinity fluids.8–14 While damaging in itself, the major detrimental aspect of smectite swelling is the associated release of fine particles.8 This arises because, when present, the particles. This arises because, when present, the smectite clay frequently acts as the cementation medium holding sand grains and fine particles in place.7,8
Field Application of a Chemical Heat and Nitrogen Generating System
Authors: Mitchell T. I. , Donovan S. C. , Collesi J. B. , McSpadden H. W.
Published: December 2007

Heat is often required to stimulate production in wells with recurrent histories of paraffin deposition and plugging. A chemical system which produces heat and nitrogen at a predetermined well depth is proposed as an alternative to the traditional hot oil and steam generation treatments. The system is described briefly and case histories are given for 3 wells in California and 5 wells in Wyoming.

The field results indicate that heat produced by the nitrogen generating system effectively stimulates production from paraffin plugged wells. The heat and nitrogen generating system further shows increased production cycle lengths over those which result from hot oil or paraffin solvent treatments. Beneficial effects of including a paraffin inhibitor in the treatment design are discussed, along with other potential applications for the heat produced by this system.
Numerical Simulation Of A Reservoir Complex With A Tilting Gascap D5/D6 Sands - Utorogu Field, Nigeria
Authors: Becker-Hoff A.H.F. , McAlpine A. , O'Neill N.
Published: December 2007

This paper presents complete analysis of a tilting gascap reservoir with the reservoir engineering supported by production geology and petrophysics. As a whole the study illustrates that a combination petrophysics. As a whole the study illustrates that a combination of conventional and modern tools, can provide a good insight into the reservoir drive mechanisms. Numerical simulation capabilities (Ref. 1) are discussed in some detail.
Effect of Pressure-Dependent Permeability on Well-Test Analyses and Long-Term Production of Methane From Coal Seams
Authors: Schwerer F. C. , Pavone A. M.
Published: December 2007

Laboratory measurements have shown that the permeability of coal samples varies significantly for ranges of pressure encountered during the testing of coalbed methane wells.

A laboratory pressure-permeability relation has been used with a numerical, two-phase coalbed methane simulator to examine the effect of pressure-dependent permeability on well-tests and on production of coalbed methane.
Evaluation of the Influence of In-Situ Reservoir Conditions on the Geometry of Hydraulic Fractures Using a 3-D Simulator: Part 1—Technical Approach
Authors: Abou-Sayed A. S. , Sinha K. P. , Clifton R. J.
Published: December 2007

A three dimensional simulator based on a coupled hydromechanical analysis is described in the paper. The mathematical formulation is based on analyses of three dimensional rock deformation and two dimensional fluid flow through the fracture. Both the rock deformation and fluid flow problems are solved using variational principles for fracture opening and the fracturing fluid pressure, respectively. The fracture criterion is based on a stress intensity factor approach.

The fracturing fluid is allowed to leak off into a formation at a rate determined by the excess pressure. Linear elastic fracture mechanics concepts are utilized to characterize the critical conditions for fracture propagation as the fluid is injected.

The fracture is assumed to open in a vertical plane and to be perpendicular to the minimum horizontal in-situ compressive stress. The rock mass is modeled as an isotropic homogeneous medium, but variations in permeability and in-situ stress are accounted for. The fracture is created by injection of an incompressible, non-Newtonian fluid with power-law characteristics.

The actual numerical procedure including the details of modeling some important phenomenon such as in-situ stress contrast, fluid loss, etc. has been described.

This paper forms the technical background for a companion paper, part II, in which several case analyses using the 3-D simulator have been reported along with parametric evaluation of the influence of reservoir conditions.
Fluid-Level Determinations Through Internal Flush Tubing Without Depth, Temperature, or Pressure Limitations
Authors: Weeks S. G. , Podio A. L. , McCoy J. N.
Published: December 2007

Potential hazards of wireline exposures to hostile CO2 and H2S environments often discourage running bottom hole pressure (BHP) surveys. While surface pressure build-ups may be utilized for dry-gas wells, detailed analyses may be of limited value where there is also liquid production. However, concurrent fluid level determinations can be used to enhance the value of surface build-ups. Other practical applications of fluid level determinations include a means of monitoring liquid loading or depths of fluid displacement, such as encountered during some stimulation or corrosion inhibition treatments. Detailed testing, of a recently developed high-pressure acoustical well sounder, verifies that fluid levels can now be determined even under the most adverse well conditions.