bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture Detection in Low-Permeability Reservoir Sandstone: A Comparison of BHTV and FMS Logs to Core
Authors: Laubach S. E. , Baumgardner R. W. , Monson E. R. , Hunt E. , Meador K. J.
Published: December 2007

Detection and characterization of fractures in low-permeability reservoirs is an important goal of reservoir analysis. Natural fractures may increase porosity in low-permeability rock and may enhance or limit the success of hydraulic fracture treatment. Two logging tools used for fracture detection are the borehole televiewer (BHTV), an acoustic device that maps the smoothness of the borehole wall, and the Formation Microscanner (FMS*), a resistivity tool that produces a conductivity map of two 2.8-inch-wide strips of the borehole wall. Our analysis compares BHTV and FMS logs to 1,028 ft of core from three wells in the 2,000-ft-thick Lower Cretaceous Travis Peak Formation, a sandstone and shale unit that produces gas from low-permeability sandstone in East Texas. Core was obtained from depths of 5,900 to 9,900 ft. The Travis Peak provides a good test of fracture-imaging logs because natural fractures have complex geometry and variable mineral fill and because there are borehole breakouts, drilling-induced fractures, and vertical sedimentary structures that must be distinguished from natural fractures for successful fracture analysis.

Vertical extension fractures in Travis Peak sandstone usually are visible on BHTV and FMS logs, but some fractures were missed by FMS pads. Low-angle natural shear fractures observed in core were not seen on either log. Both BHTV and FMS represent fracture shape and distinguish fractures from borehole breakouts. FMS gives a high-resolution image of fracture shape, but natural fractures could not be distinguished from drilling-induced fractures on either log. Existing commercial BHTV and FMS techniques do not give a quantitative measure of fracture aperture. Fracture orientation is readily obtained for inclined fractures from either BHTV or FMS logs, but the orientation of vertical fractures is commonly ambiguous on both logs. These results show that BHTV and FMS logs are useful adjuncts to core-based fracture studies for evaluation of fractured reservoirs.
Similarities and Differences in Methods Currently Used to Analyze Pressure-Transient Data from Layered Reservoirs
Authors: Larsen Leif
Published: December 2007

Methods currently used to analyze pressure-transient data from layered reservoirs are investigated, and similarities and differences highlighted with emphasis on the mathemats behind the various methods. All of the basic mathematical models for single-phase flow of slightly compressible fluids in layered reservoirs are considered, allowing layers to have only horizontal flow, only vertical flow, or flow in both directions in the basic model, and allowing both uniform and mixed boundary conditions.

Generation of type curves for standard analyses and generation of synthetic data for use in history-matching procedures are considered the most important applications of the results of the paper. The results are, however, also used to show that some aspects of the characteristic behavior reported in the literature for layered reservoirs are caused by the mathematical modelling and not by reservoir layering.
Improving Prudhoe Bay Pulse-Test Data by Processing with Fourier Transforms
Authors: Bradley D. A. , Allen T. T.
Published: December 2007

Pulse testing using surface-pressure measurement has proven to be a cost-effective way to establish reservoir continuity and to determine interwell reservoir properties at Prudhoe Bay. Using portable surface measurement equipment – instead of wireline-conveyed bottom-hole measurement tools – at the observation wells has significantly reduced the cost of conducting the tests. However, the pulse test analysis is often complicated by extraneous pressure fluctuations in the surface-measured data. These fluctuations may be caused by variations in ambient temperature, by operation of surface production equipment, or by reservoir pressure transients generated by offset wells. To eliminate these detrimental effects, a method has been developed which uses Fourier transforms to process the surface data. Once the data has been processed, conventional analysis of the pulse-test data can be improved substantially. This paper discusses the method, as well as its application to two Prudhoe Bay pulse tests.
A Rule-Based Approach to Dipmeter Processing
Authors: Kerzner M. G.
Published: December 2007

A new algorithm for dipmeter processing is being described. This work is a continuation of the work described in a previous paper1, however, to achieve improved performance, major changes were introduced, both in the theory and in realization of the algorithm. The central idea of the new work is the formulation of a number of rules of visual correlation. These rules are then applied in attempts to find acceptable correlations. The sequence of the application of the rules is dependent upon the character of the data, and the process continues until a good correlation is found. In contrast, in previous work, there were fewer rules, and all of them were applied together in a general optimization scheme. This new approach gives the program additional flexibility, which lets it process data that could not be handled previously, and also results in a much more practical running time. Another advantage of the new algorithm is the possibility of a number of options in the level of detail of the dip analysis — from very general to very fine.
Electrolytic Conduction in Partially Saturated Shaly Formations
Authors: Schwartz L. M. , Sen P. N.
Published: December 2007

An essential feature of electrical conduction in shaly sands is the fact that the surface and bulk tortuosities are not identical as assumed in most empirical models. For an arbitrary geometry of insulating, but charged, objects immersed in an electrolyte for which diffusion currents are important, the DC electrical conductivity problem can be mapped into a superposition of two ordinary conduction problems without diffusion currents but with conductive surface layers. We apply this mapping to a generalization of the grain consolidation model in which a shaly sand is modelled by a three dimensional periodic array of charged overlapping spherical grains. We solve numerically for the electrical conductivity, σ, as a function of the porosity ϕ, brine salinity σw, charge density Qv, and water saturation Sw. The results of these calculations provide a basis for new empirical saturation equations which can be used in exploration geophysics.
Interference Test in a Fractured Carbonate: A Lisburne Case History
Authors: Sampson L. E. , Marcou J. A.
Published: December 2007

A case history is presented for a 160-acre-five-spot interference test performed in the Wahoo formation, a fractured carbonate within the Lisburne reservoir located at the North Slope of Alaska. Several results are realized from this test. First, the Lisburne reservoir is a heterogeneous formation with the possibility for dual porosity and multi-layered behavior. Second, interference pressure data from two of the four observation wells can be analyzed utilizing a modified approach to the conventional anisotropic permeability technique. Third, even with considerable pre-test planning and design, the reservoir responded differently than expected.

The Lisburne Interference Test preceded field startup in an effort to determine directional permeability and to evaluate vertical and lateral continuity within the reservoir with a rninimum amount of offset interference. The center well was cycled through a drawdown and build up while the four corner wells monitored pressure. Bottomhole pressure recorders were installed in the wellbores prior to the start of the test. During the interference test, the observed pressure responses in the observation wells were significantly more rapid and of a greater magnitude than expected. Concurrent pressure transient analysis of the data, made possible by surface readout equipment, resulted in a shorter, less expensive test.

The test analysis provided effective reservoir permeability from dual porosity type curve matching and semi-log analysis of the active well data with good agreement between the drawdown and build up results. Analysis of the observation well pressure data was consistent with the active well data and was achieved using dual porosity transient interporosity flow type curves and semi-log analysis.

Because of reservoir heterogenities, the pressure data from only two of the four observation wells were analyzable with the conventional anisotropic permeability analysis method. Generally this method requires pressure data from three uniquely-oriented observation wells to obtain a solution. However, the anisotropic permeability model can place limits on the feasible solutions using data from only two wells, and with the elimination of one of the four unknown values through core data, a complete solution of the Lisburne Interference Test was achieved.
Falloff Testing a Waterflood-lnduced Fractured Well in Western Venezuela
Authors: Prado L. R. , van Kruysdijk C. , Niko H. , Sancevic Z. A. , Rodríguez R.
Published: December 2007

A high-precision fall-off test, carried out by Maraven in the water injection well VLA-440w in western Venezuela with the objective of determining the length of a waterflood induced fracture, has been analysed using the latest interpretation tools available. Deconvolution techniques were used to remove the effects of storage on the pressure data, thus enabling the identification of the characteristic flow regimes for a fractured well. In addition, the use of the pressure derivative plot enabled the characterisation of the flow system which led to a type-curve match of the data as the only way to interpret the test. Using a recently developed semi-analytical model, a type curve match was obtained with the response of a fractured well with fracture wall skin effect.

The presence of a skin on the fracture wall in fact extends the duration of the fracture linear flow period which allowed us to observe this period in the data. An effective permeability of 2 mD, a fracture half-length of 900 ft and a skin of 0.15 were obtained from the type-curve match. Moreover, the formation permeability calculated is in agreement with available petrophysical information. In addition, a short injectivity test performed after the fall-off qualitatively confirmed the interpretation.
Facies Modeling and the Flow Unit Concept as a Sedimentological Tool in Reservoir Description: A Case Study
Authors: Rodriguez A.
Published: December 2007

Early recognition of porosity and permeability contrast in a reservoir has economic implications in reservoir management. Correct reservoir heterogeneity description is the key for such recognition. Problems such as number of blocks to be used in simulation modelling can be minimized with a proper understanding of the reservoir. Several techniques, including "slice-technique," "fining and coarsening-upwards" sequences, and lithological transgressive/regressive concepts, have been used for reservoir description.

With the advance in facies modelling, sedimentological studies have introduced facies-zones, and facies associations as flow units for reservoir sublayering. But, in the literature, there is a lack of objective parameters with which to place boundaries between adjacent production intervals. The objective of this paper, therefore, is to present a methodology which allows subdivision of a sedimentary column, for reservoir description, based on quantifiable rock characteristics.

The study of the cored section of the Eocene C Reservoir, Block III, lake Maracaibo, allowed facies characterization with physical, chemical, and biological parameters. By identifiying major changes in the related depositional sequences, facies units were characterized with porosity and permeability values. The so defined intervals were proven valid by histograms and cross-plots obtained from the petrophysical data. Biostratigraphic analysis also support this subdivision.

Since the combination of sedimentological, petrophysical and biostratigraphic characteristics support a similar sublayering of the cored sedimentary section, the Sedimentary Units were taken as representative of main flow units. Facies maps constructed for each Unit, show a sequential deltaic development with different sand geometries.

Results obtained with this facies approach show that by combining independent 1ines of evidence it is possible to have an objective and quantifiable methodology for reservoir heterogeneity description. A scientific tool for minimizing number of blocks to be utilized in simulation studies is given by grouping of facies with similar permeability characteristics within a well defined Flow Unit.
Reliability of Anelastic Strain Recovery Estimates for Stress Orientation in the Travis Peak Formation, Harrison County, Texas
Authors: Owen L. B. , Toronto T. W. , Peterson R. E.
Published: December 2007

The Gas Research Institute sponsored a series of Staged Field Experiments (SFE) which collectively provided an important opportunity for critical evaluation of various methods for prediction of hydraulic fracture orientation. During the period August-September, 1986, the SFE No. 1 well was drilled in the Waskom Field, Harrison County, Texas. This well penetrated the Travis Peak Formation of Lower Cretaceous age. Core recovery was 471 ft of which 91.4 ft was oriented. Eight methods were employed for the determination of in-situ stress orientation: Orientation of Natural Fractures and MicrofracturesOrientation of Fluid Inclusion PlanesOrientation of Coring Induced Centerline and Petal FracturesOrientation of Stress Test FracturesBorehole Ellipticity3-D Microseismic SurveysDifferential Strain AnalysisAnelastic Strain Recovery

Orientation of natural fractures by petrography, borehole televiewer and formation microscanner resolved a primary fracture with an azimuth between 70-80 deg. Subsidiary fractures were observed at 90-100 deg and 120-130 deg. Minor features were found at 35-45 deg and 145-165 deg. The orientation of fluid inclusion planes was more scattered but of similar character, coring induced fractures observed in recovered oriented core were generally coincident with the observed natural fracture pattern.

Four stress tests performed during the coring operation provided evidence for a preferred fracturing direction at 76 ± 8 deg. The orientation of a treatment-induced fracture at a depth of 6410 ft was mapped by a microseismic survey at 69 deg. Average well bore ellipticity was 68 deg. One differential strain analysis for a mudstone yielded a maximum horizontal stress orientation of 90 ± 20 deg.

Horizontal strain recovery data were successfully obtained for 18 samples during the coring operation. Core orientation data were available for 11 of the analyzed samples. Each sample was approximately 6 inches in length. Tested litholo-gies included sandstones, mudstones, shales and siltstones. The quality of strain recovery data was excellent in most cases. Calculated orientations for maximum horizontal stress direction fell into three groups. Three samples yielded an orientation of 69 ± 10 deg. Seven samples yielded an average orientation of 116 ± 10 deg. One sample indicated an orientation of 28 deg. The average orientation of the maximum horizontal stress (excluding the 28 deg sample) was 102 ± 24 deg.
Semianalytical Modeling of Pressure Transients in Fractured Reservoirs
Authors: van Kruysdijk C. P. J. W.
Published: December 2007

By combining the boundary-element technique introduced by Cinco-Ley with the Laplace transform, a powerful technique has been developed for modelling transient flow in complex reservoir geometries. Applied to a finite-conductivity fracture in an infinite (if desired, dual-porosity) reservoir, the technique offers both a robust and fast algorithm for calculating the transient pressure response. Furthermore, it describes flow impairment in the vicinity of the fracture and fracture-wall damage in terms of a fracture-wall skin factor. As shown by the model, the presence of this phenomenon is clearly indicated by a. distinct hump on the pressure-derivative plot (t∂p∂t versus t). An application of the technique to actual field data demonstrates the importance of the fracture-wall skin factor in well-test analysis. The speed of the algorithm enables automatic type-curve matching by least-squares methods. Since the solution is given in Laplace space, it is possible to handle multi-layer fractured reservoirs at very low cost. Furthermore, convolution to obtain variable-rate solutions can be performed in Laplace space. The same technique has also been applied to a two-fracture system and to a horizontal well intersecting a zone of natural fractures.
Estimation of Matrix Block Size Distribution in Naturally Fractured Reservoirs
Authors: Belani A. K. , Jalali Y.
Published: December 2007

Interporosity flow in a naturally fractured reservoir is modelled by a new formulation incorporating variability in matrix block size. Matrix block size is inversely related to fracture intensity. The size of matrix elements contributing to interporosity flow is expressed as a distribution in the source term of the diffusivity equation. The pressure transient response for uniform and bimodal distributions of block size is investigated. Both pseudo-steady state and transient models of flow are analysed. It is shown that features observed on the pressure derivative curve can yield the parameters of the distribution. Thus, observed pressure response from fractured reservoirs can be analysed to obtain the matrix block size distribution in the volume of the reservoir investigated by the test.

The solution to the uniform distribution can be extended to more general distributions. Other sources of information, like logs and geological observations, can give an estimation of the shape of the distribution, and this model can be used to compute the reservoir parameters.
A Computational Model of Well Completion Design
Authors: Dunn-Norman S. , Peden J. M. , Bedford D. R.
Published: December 2007

The design of well completions is a complex process which requires the engineer to select, rationalize and integrate a large number of design elements. In the literature, it has been recognized that a systems approach to well completion design must be adopted if optimum and cost-efficient completions are to be generated. Historically, diagrammatical representations, such as logic diagrams, have been used to model and implement the systems approach for well completion design.

This paper discusses, as an alternative, a computational model of well completion design developed through an industry sponsored collaborative research project. The model formalizes the relationships and interaction between conventional computations for completion design, such as tubing hydraulics or stress analysis, and design knowledge gained through design and operating experience.

This model provides a comprehensive representation of the systems approach to well completion design, and serves as the basis for a computerized implementation. The implementation integrates both conventional and expert systems programming techniques. Program development and the advantages of using a computer design program to provide a rational and consistently optimum design capability are discussed.
Application of Electrical Submersible Pumps in Natural and Artificial Water-Drive Reservoirs
Authors: Whiting R. L.
Published: December 2007

A comprehensive review of theory and laboratory research pertaining to the recovery of oil from porous media is presented leading to the conclusion, contrary to earlier views, reservoir rocks are considered to have heterogeneous wettability. Because of this, oil will flow at very low oil saturations and hence yields much lower residual oil saturation. Further immobile oil may be made mobile and residual oil saturation decreased by increasing the pressure gradient in' the reservoir.

During the past forty years the author has been active in evaluating the performance of petroleum reservoirs. Use of electrical submersible pumps (ESP) has been demonstrated to increase oil production rate, ultimate oil recovery, and economics based on evaluations of strong bottom and edge water drive and waterflood operations at high fluid withdrawal rates. This paper presents the state-of-the-art and science of theory, laboratory research and field studies on this subject.

The scope of ESP field applications presented includes operations in eight countries and eight U.S. states. A wide range of structures, formation, rock and fluid properties, types of drive, oil and total fluid production rates, and ESP capacities are included.

Two production performance type-curves (percent oil cut-cumulative oil production and oil production rate-cumulative oil production) for ESP operations are presented and explained in accordance with theory and laboratory studies.

Production performance curves for seven fields in which ESP have been used for increasing oil production rate, ultimate oil recovery, and economics are presented.

A comparison of the economics including lifting costs, pump life, and payout of ESP operations in 78 Indonesian fields and 14 U.S.

fields is included. Comments from thirteen major companies worldwide are included citing their favorable results from use of ESP.
General Model of Fluid Flow (Leakoff) From Fractures Induced in Injection Operations
Authors: Settari A.
Published: December 2007

The paper describes a new general model of leak-off from fractures. The model is an extension of earlier work, generalized to handle multi-phase flow conditions, influence of reservoir boundaries and faults, well interference and voidage replacement in a pattern, and the compressibility of the injected fluid. The model was successfully incorporated in a 3-D fracture simulator. The capabilities of the method are demonstrated on examples of fractures in waterflood injector, in tar sands and in a WAG injection scheme.
Multiple Fluids, Proppant Transport, and Thermal Effects in Three-Dimensional Simulation of Hydraulic Fracturing
Authors: Clifton R. J. , Wang J-J.
Published: December 2007

Realistic simulation of hydraulic fracturing requires the modeling of the flow of the fluid and proppant when multiple fluids, proppants and proppant concentrations are injected in a single fracturing treatment. Furthermore, the temperature of the fracturing fluid is required throughout the fracture for realistic modeling of the rheological properties of temperature-sensitive fluids. Such a detailed model for two-dimensional flow of fluid and proppant in a vertical fracture is presented in this paper. This flow is coupled to a fully three-dimensional elasticity model for the propagation and opening of the fracture. Fluid and proppant particles are tracked during their flow in order to allow the determination of which of the fluids and proppants being injected are at a given position in the fracture at any time. Each fluid is modeled as a non-Newtonian, power-law fluid. Modeling of proppant transport includes the effects of proppant diameter and crack opening; empirical relations are used to account for the effects of proppant concentration, including bridging. Temperature distributions within the fracture are calculated by solving a two-dimensional heat equation obtained by averaging across the width of the fracture. This equation includes the primary effects of convection within the fracture and heat exchange between the fluid and the reservoir. Secondary effects of heat conduction and heat dissipation in the fluid are included for completeness. The numerical method used for fluid tracking, proppant transport, and heat transfer involves integration along backward-drawn streamlines through the nodes at which the respective quantities are being evaluated. Numerical results are presented for representative types of fracture treatments in order to illustrate the nature of the above effects on the fracture geometry, proppant distribution, and injection pressure in the various types of hydraulic fractures.
New Test Kit for Rapid Detection of SRB in the Oil Field
Authors: Horacek G. L. , Gawel L. J.
Published: December 2007

A new test method for detecting and enumerating sulfate-reducing bacteria (SRB) often associated with the petroleum environment has been developed and field tested. The new test method rapidly and accurately defects SRB at concentrations as low as 1,000 cells/cm3. Results are available in fifteen minutes compared to the three to four weeks required by the standard API RP 38 culture method. In addition, the new test method detects SRB species that do not grow on culture media used in the oil field. The method is not limited by unique growth or environmental conditions which may be required by the particular SRB species being assayed. The new test method uses an immunoassay which is specific for an enzyme system found only in SRB. The new method is not affected by oil, sulfides, iron, common oil field chemicals including biocides, or any other constituent of oil field water. The test method is a joint development of Conoco and Du Pont; a field test kit version is marketed by Conoco Specialty Products Inc. This paper substantiates the above performance claims through field comparison testing between the new test method and the industry standard API RP 38 method.
Helical Screw Rheometer: A New Tool for Stimulation Fluid Evaluation
Authors: Lord D. L.
Published: December 2007

The helical screw rheometer (HSR) is a new rotational viscometer with many unique features which provide distinct improvements in operation over those found in conventional couette, cone and plate, parallel plate, or other rotational type viscometers. Unlike these other rotational viscometers, the HSR response to rotation rate is measured in terms of pressure drop rather than torque. Access to a bank of multi-range pressure transducers external to the HSR provides a means for obtaining wide rangeability with this device. To achieve similar rangeability with a conventional rotational viscometer, it would be necessary to change the torque transducer, which is often an integral part of the instrument.

With an open discharge, the HSR acts as a single screw extruder capable of circulating test fluid and/or drawing a new fluid sample for testing. Viscometric measurements are made by first closing the HSR discharge and then measuring pressure drop response as a function of rotation rate. Fluids containing particulates create measurement problems for conventional rotational viscometers. Particle settling leads to erroneous torque readings with these instruments. In contrast, HSR operation promotes mixing and prevents sedimentation.

Although the HSR is an instrument applicable to a number of industry fluids, the scope of this paper is limited to the characterization of time independent, isothermal, power-law model stimulation fluids. A 2-in. diameter, square-pitch HSR with 0.1-in. thread depth was used to evaluate rheological properties of several different hydroxypropyl guar (HPG) solutions. Analysis procedures used to convert pressure drop versus rotation rate data to power-law n' and K'v values are described.
Prediction of Dispersion Viscosity of Oil/Water Mixture Flow in Horizontal Pipes
Authors: Martinez A. E. , Arirachakaran S. , Shoham O. , Brill J. P.
Published: December 2007

A pipe viscometer facility was constructed to investigate the flow of oil-water dispersions in horizontal pipes. Pressure drop, liquid mass flow rate, mixture temperature, input water fraction, and mixing intensity data were obtained for 490 oil-water tests. Mixture velocities ranged from 2.5 to 15.5 ft/sec, while input water fractions ranged from 0.0 to 0.35. Mixture temperatures ranged from 60 °F to 90 °F. A refined oil with a viscosity of 85 cp at 80 °F was used.

Data analysis showed that when the phase inversion point was reached, mixture viscosities were considerably higher than the viscosities for single-phase oil. Also, the frictional pressure gradients were found to be strongly dependent on whether oil or water was the continuous phase of the dispersions.

A model was developed for the prediction of the oil-water mixture frictional pressure gradient in horizontal pipes. The model assumes homogeneous flow and a power-law rheological behavior for the dispersion. The application of the model to the design of a non-Newtonian pipeline system is also presented.
The Membrane Alternative for Natural Gas Treating: Two Case Studies
Authors: Markiewicz G. S. , Losin M. S. , Campbell K. M.
Published: December 2007

Separex® membrane systems are a commercially proven technology for gas treatment that is an attractive alternative for many treatment requirements. This paper presents case histories of two natural gas treating facilities designed to sweeten and dehydrate gas to meet pipeline specifications. The Separex plant at a Major gas producer's facility near Baton Rouge, Louisiana is an excellent example of the type of innovative and economic solutions achievable with membranes to meet gas treating requirements. The membrane system replaced existing amine and dehydration plants to lower treating costs by as much as 8.5%. The Separex membrane unit at another Major gas producer's well in South Texas demonstrates the unattended operability of membrane systems. Production costs associated with the remote membrane system are lower than the previous gas blending option utilized. Membrane system design, process selection criteria and economics, and operation are discussed.
Design Alternatives for Sweetening LPG's and Liquid Hydrocarbons With Amines
Authors: Fleming K. B. , Spears M. L. , Bullin J. A.
Published: December 2007

Amine solutions are often used to treat LPG streams that contain acid gases. In this work, the selection of an amine and the method of contacting the amine with a 50 gpm [189 lpm] LPG stream containing 7.7 mol% as CO2 are evaluated. A packed contactor is compared to a static mixer and MEA, DEA, and MDEA are compared as potential solvents. A static mixer using 70 gpm [2 65 lpm] of 25 wt.% DEA is chosen for the final design. The operating data reveal 0.10 mol% CO2 in the sweet LPG compared to the design value of 0.16 mol%.
Corrosion Monitoring in Sour Gas Production Systems – Principles, Practice and Field Experience
Authors: Brier B. B. , Bowman R. W. , Rose G. , Perkins A. J.
Published: December 2007

Two case histories present recent field experience with corrosion monitoring programs in sour gas production facilities. Comparative data from different methods are presented.

Also included are a review of the theory of operation of available corrosion monitoring methods, a review of the types of corrosion encountered in sour gas service and recommendations for an optimized corrosion monitoring program.
Dynamic Simulation of Slug Catcher Behavior
Authors: Genceli H. , Kuenhold K. A. , Shoham O. , Brill J. P.
Published: December 2007

A mathematical model has been developed for a gas-oil separator system, and a computer program has been written to simulate the behavior of the system. The separator is assumed to operate under slug flow conditions at the end of a two-phase flow pipeline. The liquid level and the pressure of the vessel are controlled by proportional integral controllers.

An optimization program has been written based on a linear model of the separator system. The program applies linear control theory to optimize the gains and reset times of the controllers.

The optimization and simulation programs can be used to design the smallest possible separator that will handle given gas and liquid flow rates in slug flow production. A sample design case is given.
Inducing Multiple Hydraulic Fractures from a Horizontal Wellbore
Authors: Overbey W. K. , Yost A. B. , Wilkins D. A.
Published: December 2007

A series of stimulations were designed to open and propagate natural fractures known to exist along a 2000 foot horizontal well in Wayne County, West Virginia. The stimulations were also designed to induce fractures in the formation as well as propagate the natural fractures by manipulating pressure and injection rates. A number of radioactive tracers were used to determine where fractures were opened and propagated at different injection rates. The tracers were found in fractures in zones other than the one pumped into, a fact considered prima facie evidence that natural fractures with two or more orientations had been opened and propagated. Pressure testing and gas sampling of the isolated zones confirm that fracture communication was accomplished along nearly 1000 feet of borehole by stimulation of one 400 foot long section. A technique for inducing multiple hydraulic fractures with multiple orientations was demonstrated.
Laboratory Study of Proppant-Pack Permeability Reduction Caused by Fracturing Fluids Concentrated During Closure
Authors: Hawkins G. W.
Published: December 2007

One of the key challenges in hydraulic fracturing is maximizing fracture permeability. Previously published work has shown that proppant-pack permeability is significantly impaired (damaged) by the fracturing fluid and that the impairment increases with increasing gelling agent concentration. In many hydraulic fracturing treatments, the gelling agent is often concentrated over tenfold upon fracture closure. However, measurement and removal of the permeability damage caused by these highly concentrated gelling agents has rarely been addressed. A laboratory study was undertaken to define the critical physical parameters and fracturing fluid characteristics affecting permeability in proppant-packs containing gelling agent concentrations up to 500 lbm/1,000 gal. The temperature range from 140° to 200°F was studied since it is below the range where thermal degradation of the fluid is believed to be effective.

Proppant-packs formed after hydraulic fracturing treatments were simulated using a modified API-type fracture conductivity cell which permitted fluid-loss through a low-permeability core, concentrating the fracturing fluid. Twenty-forty mesh northern white sand was used as proppant. Special experimental care allowed the measurement of proppant-pack clean-up within the first few pore volumes. Parameters investigated included gelling agent concentration (within proppant-pack), proppant concentration, closure stress, shut-in time, displacement fluid (aqueous and/or hydrocarbon), and displacement fluid flowrate. Un-crosslinked, borate-crosslinked, and metal-crosslinked HPG, and gelled hydrocarbon fracturing fluids were studied. The effects of a fracturing fluid breaker was also determined.

Even at relatively low gelling agent concentrations within the proppant-pack, significant proppant-pack permeability damage was observed. High displacement (well flow-back) rates only marginally removed the damage. High breaker concentrations were necessary to significantly reduce permeability damage.
Recovery of Condensate From a Heterogeneous Reservoir by the Injection of a Slug of Methane Followed by Nitrogen
Authors: Kossack C. A. , Opdal S. T.
Published: December 2007

The process of injecting gas into a gas condensate reservoir during production is vital to maintain the reservoir pressure so that the heavy hydrocarbon fractions will be recovered. One would like to inject a gas into the reservoir that is cheaper than methane, but recent one-dimensional studies have shown that the injection of nitrogen into gas condensate at reservoir conditions will result in the loss of much of the condensate liquid. This is a result from the liquid dropping out of the gas phase when nitrogen mixes with the condensate. A solution to this situation is the initial injection of a slug of methane (or dry gas) followed by the injection of nitrogen for pressure maintenance. If the methane slug is large enough it will separate the nitrogen from the condensate and the liquid recovery will be high. The physical processes that tend to destroy the integrity of the methane slug are mixing due to rock heterogeneity, fluid fingering, and bypassing.

This paper studies the two step injection process numerically with a three-dimensional EOS compositional simulator. The gases are injected into a heterogeneous quarter five spot. The recovery of liquid condensate is studied as a function of the composition of the injection gas, the methane slug size, and the magnitude of the permeability variations (heterogeneities) of the porous media. A fine grid involving 8,000 blocks is used to allow the proper description of the heterogeneities and to keep numerical dispersion, which simulates sub-grid block dispersion, at a reasonable level. Monte Carlo simulations are performed on realizations of reservoirs. The results show that the heterogeneities allow the nitrogen to mix with the condensate when the methane slug is small (5% to 10% of a porevolume) but the incremental recovery over the injection of nitrogen is large enough to pay for the cost of the methane. Economics are given to allow one to size a methane slug for a real heterogeneous reservoir so as to maximize the profit of the project.
Analysis of CO2 Pressure Transient Data With Two- and Three-Region Analytical Radial Composite Models
Authors: Tang R. W. , Ambastha A. K.
Published: December 2007

The results from this study show that pressure transients influenced by the interaction of fluid flow and phase behavior can behave as a three region composite reservoir. The intermediate region in this study was a high compressibility region that resulted from CO2-oil interaction.

Although two-region models have been applied successfully in thermal EOR and geothermal projects, a two-region model is unable to explain pseudo-steady state behavior observed in some miscible gas injection falloff tests. Three-region modeling combined with compositional simulation may be appropriate if pseudo-steady state response is observed, especially when mobility ratio is not large enough to manifest in a pseudo-steady state behavior based on two-region models.

A series of injection falloff tests were performed at a West Texas reservoir in an effort to establish injectivities and in situ flow parameters during water and CO2 injection. The results from the field tests in combination with laboratory tests will provide part of the engineering basis for design and operation of future CO2 EOR projects at a West Texas reservoir.

Falloff data and interpretation are presented along with experimental and compositional simulation results. In situ parameters such as mobility ratio, swept volume, and average CO2 saturation in the swept region were estimated from the falloff data. The falloff analyses results are in good agreement with laboratory measurements and theoretical predictions. Therefore, this type of injection testing may be desirable in most EOR projects.
A Compositional Simulation Evaluation of the Santa Rosa, Colorado EF Reservoir, Eastern Venezuela
Authors: Zambrano G. , Granado A. , Rincon A.
Published: December 2007

This report presents the results of a simulation study of the Santa Rosa Colorado EF, RG-14 reservoir located in Eastern Venezuela. The objectives of this study were to determine the quality of the hydrocarbon gas accumulated in the reservoir and to predict oil recoveries under a variety of operating modes. The reservoir contains a condensate gas cap that overlies an oil leg. Depth of the reservoir varies from 6560 ft (1999 m) subsea, at the crest of the dome to 11150 ft (3399 m) subsea on the northern flank.

In order to match field performance history, a significant effort was made in developing a geological model based on the depositional environment concept. A fluid characterization model was also constructed for both, reservoir oil and gas condensate using the Peng-Robinson equation of state.

A satisfactory history match for 36 years of reservoir performance was achieved using a three dimensional, three phases, multicomponent, compo-sitional simulator. The results at the end of the reservoir history match, indicated that the gas present in the reservoir is mainly methane.

A total of five prediction cases were then studied, all intended to provide performance data for technical and economic analysis. The main effects analyzed were: higher gas-oil ratio limit, additional wells, partial and full pressure maintenance and reservoir blowdown.

The main conclusions drawn from the results of this reservoir simulation study were that drilling and reactivating wells in the oil leg and re-locating the injection wells would increase the cumulative production of oil by approximately 9.1 × 106 bbl (1.447 × 106 m3).
On the Investigation of Gravity-Assisted Inert Gas Injection Using Micromodels, Long Berea Sandstone Cores, and Computer-Assisted Tomography
Authors: Chatzis I. , Kantzas A. , Dullien F. A. L.
Published: December 2007

Downward displacement of oil by inert gas injected in a reservoir either at initial oil and connate water conditions or, in a reservoir depleted by waterflooding, results in very high oil recovery efficiencies under strongly water-wet conditions in both unconsolidated and consolidated porous media respectively. Advances made in directional drilling technology and increased understanding of the mechanisms and conditions that maximize recovery efficiencies can make the inert gas injection process of oil recovery1–3 feasible for a wide variety of oil reservoirs. This paper presents experimental results and discussion of a series of experiments designed for the study of: 1) production characteristics under immiscible inert gas driven gravity drainage conditions; 2) microscopic mechanisms of displacements and the determination of the rate of production by gravity drainage in capillary tubes having square cross-section; and 3) fluid distributions and oil bank formation using the x-ray computer tomography (CT) scanning facilities we recently established in our laboratory.
Representation of High Rate Gas Wells in Reservoir Simulation
Authors: Temeng K. O. , Horne R. N.
Published: December 2007

The paper presents an analysis of nonlinear Darcy flow of gas in reservoirs. The equations employed in the analysis are derived from an integration of the fundamental equations describing the flow of real gases in homogeneous porous media. The equations are derived in terms of squares of pressure for radial steady and pseudo steady flow systems.

The analysis indicates that the squared-gradient nonlinearity present in the gas flow differential equation results in a pressure drop and rate relationship symptomatic of non-Darcy flow. The magnitude of the nonlinear contribution to pressure drop is similar to that computed on the basis of non-Darcy theory. This raises the possibility that observed nonlinearities may not be due to non-Darcy effects but merely a result of fluid property variations.

The implication of the findings to the simulation of gas wells is also discussed. The results suggest that for a typical radial grid system with fine grids near the well, it may be unnecessary and incorrect to include additional terms to account for deviations from Darcy flow. In large and rectangular grids however, nonlinear terms are required for correct representation. These additional terms are shown to relate to grid size and shape, and are necessary not because Darcy's law is invalid but because the grids are of finite size.
A Model for Development and Analysis of Gas Reservoirs with Partial Water Drive
Authors: Saleh S. T.
Published: December 2007

In common reservoir analysis computations, the average gas reservoir pressures are erroneously used in the Van Everdingen-Hurst unsteady state equation (VEHE) to calculate water influx. The VEHE requires the pressure at the original gas/water contact (GWC). The incorrect use of the average oil reservoir pressure in the VEHE can lead to a significant error in the results. This study was performed to show the quantitative potential of the error, using a mathematical model.

The mathematical model combines the material balance equation (MBE) for a partial water-drive gas reservoir and the VEHE. The model generates pressure-production data for a conceptual partial water-drive gas reservoir, and for the following two cases: Case A: using average reservoir pressures in the VEHE.Case B: using pressures at the original GWC elevation in the VEHE.

The error is defined as the difference in the calculated pressure performances between cases A and B.

The results of this study showed that the error increases as the aquifer size increases and as the permeability decreases. The maximum error was found to be 14% in the range of reservoir and aquifer conditions studied. This study also showed that gas recovery increases as the permeability decreases, a result which is also reported by Agarawal, Al-Hussainy, and Ramay.8

This paper presents the procedure used to correct average gas reservoir pressure to the original GWC elevation.
Production Forecasts for Alternative Completion Methods in Low-Permeability Gas Reservoirs: Simulation of High-Angle and Horizontal Wells
Authors: Duda J. R. , Kumar H. K.
Published: December 2007

Recently, there has been a heightened interest in the use of horizontal wells to more efficiently drain both oil and gas reservoirs and to compensate for negative producing situations such as coning. The potential applications of horizontal and high-angle wells have led to increased efforts to quantify the expected production increase from these types of completion methods in a variety of geologic settings. Simulation of these alternative completion methods using mathematical models provides a cost-effective method of predicting their performance and allows for sensitivity analysis of reservoir properties.

The performance of horizontal and high-angle completions was simulated for marginal marine and lenticular low permeability gas reservoirs of the Upper Cretaceous Mesaverde Formation underlying the east-central Piceance Basin. Results of the simulations show that production from horizontal wells of intermediate length can be expected to be four times higher than that of vertical, stimulated wells draining large areas. The advantages of high-angle wells in lenticular sandstone environments remain unquantified, but a reasonable potential exists, especially when methane from deeply buried coals is considered.
Validation of Water/Oil Displacement Scaling Criteria Using Microvisualization Techniques
Authors: Sincock K. J. , Black C. J. J.
Published: December 2007

Displacement tests on reservoir core samples provide a direct method for assessing the microscopic displacement efficiency of specific recovery processes in particular reservoirs. They also provide an effective source of data for the comparison of alternative processes.

This paper demonstrates the validity of scaling criteria developed to provide unambiguous relative permeability data from favourable mobility ratio water-oil displacement tests on strongly oil wet and water wet reservoir systems. Microvisualisation techniques were used in conjunction with core displacement tests. These techniques allow a better mechanistic understanding of displacement processes and the location and distribution of residual oil to be established.

Displacement experiments were performed on oil wet and water wet reservoir systems and the resulting pressure and production histories compared with water displacement of solidifiable oil analogues. After solidification of ’residual oil’, water was also replaced by a solidifiable analogue. Good agreement between water-oil displacement characteristics and water-oil analogue displacement characteristics demonstrate maintenance of wettability. Static contact angle tests were also used to ensure wettability alteration was not induced during the fluid replacement technique.

Direct microscopic observation of the fluid distributions at initial and residual saturation using UV fluorescence illumination techniques are presented. The location of initial water saturation is shown to be generally associated with water filled clays and microporous minerals. 'Classical' pendular rings and surface water do not account for the bulk of Swi.

Residual oil in the water wet systems was largely located as discreet blobs as expected. In the oil wet reservoir system examined, residual oil was associated with clay (mainly kaolinite) filled pores. In this case the clays were apparently oil wet. Previously determined scaling criteria and analysis procedures are described and validated.