bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Simulation and Reservoir Characterization of Multiphase Fluid Flow in Naturally Fractured Formations
Authors: Nakornthap K. , Evans R. D.
Published: December 2007

A numerical simulation model is developed for characterizing three dimensional multiphase fluid flow phenomena in naturally fractured reservoirs. This new model treats the reservoir as a double porosity medium consisting of heterogeneous, isotropic primary rock matrix, and an anisotropic, heterogeneous fracture system. The statistical distribution in space and orientation of the fracture system is manifest in terms of a fracture permeability tensor. Such an approach provides a model which permits flow through the rock matrix and the fractures to be described simultaneously. A fluid interaction term is utilized to couple the flow between the rock matrix and the fractures. Gravity effects, capillary forces, and the fluid velocity in the fractures are also taken into account in the simulator model.
A Tensor Model for Anisotropic and Heterogeneous Reservoirs with Variable Directional Permeabilities
Authors: Leung W. F.
Published: December 2007

Permeability tensor is used to model fluid flow in complex reservoirs with multiple zones of directional permeability. The orientation and magnitude of the principal permeabilities may, in general, vary between different zones in the reservoir. This type of reservoirs cannot be studied with conventional simulators, which assume that the orientation of the principal permeability axes are fixed in the reservoir; thus, the coordinate axes can be oriented in the same direction as these principal axes.

Cross permeability effect arises when the coordinate axes are offset at an angle to the principal permeability axes. The cross permeability effect has been analyzed with theory and with numerical simulations. The importance of this effect has been established. Consistent nine- and nineteen-point finite-difference schemes, applicable to two- and three-dimensional simulations, respectively, are derived for the tensor formulation. The numerical tensor model has been validated with analytical solution for two single-phase flow problems.

The tensor model is used to study the grid orientation effect for a pattern flood in an anisotropic reservoir. Minimum grid orientation effect is observed with the tensor simulation. Finally, the tensor model is used to analyze the complex flow behavior of a reservoir with multiple zones of directional permeabilities. It is demonstrated that the conventional simple anisotropy model, which does not account for the cross permeability effect, could lead to serious error in interpreting the well response.
Pump-In Test Correlation Predicts Proppant Placement
Authors: Shelley R. F. , McGowen J. M.
Published: December 2007

An empirically derived correlation has been proposed to assist operators in optimizing proppant placement in formations where treating pressures are unpredictable. By observing the pressure decline after an injection test, the average fracturing treatment parameters can be obtained to aid in optimizing the treatment design. A correlation between the pump-in test, the average fracture treatment leakoff rate, and the average treatment pressure increase rate has been established. From these averages, the maximum recommended job size and the critical sand concentration are determined.

This technique has proven to be a valuable tool to pinpoint proppant placement difficulties and has assisted in realizing the most effective stimulation treatments.
Improvement of Primary Cementing Bonding, Powder River Basin, Wyoming
Authors: Reeves N. K. , Wickham J. F.
Published: December 2007

Historically, the major cause of poor cement bonding in the Powder River Basin has been the high permeability and low pressure of some zones. Drastically reducing the fluid loss of the cement slurry gave little improvement in bonding and increasing fluid loss material levels led to undesirably long thickening times and poor strength development. Physical shrinkage of cement was still suspected even when thixotropic and conventional expanding cement slurries were used, since cement continued to lose fluid to the formation after it was in place. Other accepted practices for bonding improvement, such as mud conditioning, rotation of the pipe, centralization, preflushing, and pumping in turbulent flow were also used. Even with these techniques, logging showed that bonding was less than adequate.

These problems with cement bonding have led to the use of a new additive. With this new additive, we have seen improvement in the bonding of cement to the formation faces and to the pipe. This additive (1) can be dry-blended with cement, (2) its reactivity in cement slurries is controllable over a wide range of temperatures without the use of special additives, and (3) is also compatible with most retarders and fluid loss additives.
Treatment Optimization of Acid Fracturing in Carbonate Formations
Authors: Olsen T. N. , Karr G. K.
Published: December 2007

The use of alternating stages of gelled water and acid to obtain deeply penetrating, highly conductive fractures is common practice in carbonate formations.5 By monitoring bottom-hole pressure during this type of treatment, and using a pseudo-threedimensional simulator, a history match of stimulation pressure response can be made to help quantify various effects of the treatment, and to proceed a step closer to optimization. This paper presents bottomhole pressure data from several wells during acid fracturing. The data include treatments with various acids and varying proportions of pad-to-acid. The results of the simulations indicate that once acid is introduced into a hydraulic fracture system, certain parameters (which are assumed constant during conventional fracturing) can vary greatly. Therefore, onsite interpretation of bottom-hole fracturing pressure becomes more difficult. The potential may also exist to apply this information to proppant fracturing of carbonate formations. Acid may be used to etch the fracture face to reduce fracture friction pressure, thus creating an artificial control upon fracture height growth.
A Comparison of Solvent/Acid Workovers in Embar Completions—Little Buffalo Basin Field
Authors: Douglass B. C. , King G. E.
Published: December 2007

A comparison of acid/solvent workovers in 24 wells completed in the Embar Formation, Little Buffalo Basin Field, has shown an alcohol-aromatic solvent mixture to be superior to ethylene glycol monobutyl ether (EGMBE) for enhancing acid stimulation of oil-producing wells. The alcohol-aromatic solvent mixture assists acid stimulation by breaking emulsions, as well as dispersing asphaltenes and sludges. Data are presented on comparative job costs and pretreatment production versus performance three months after treatment.
Automated Core Measurement System for Enhanced Core Data at Overburden Conditions
Authors: Keelan D. K.
Published: December 2007

A new automated, computer-directed, core measurement system furnishes porosity, air permeability, equivalent non-reactive liquid permeability (Klinkenberg), and Forcheimer (turbulence) factor at programmable, sequential overburden pressures from 500 to 10,000 psi. The system is accurate, precise, and flexible and furnishes enhanced routine core data. Capabilities and limitations of the system are discussed. Data are presented for selected rock types and a graphical technique is proposed to relate the system measured porosity and permeability values to uniaxial strain conditions.
Fracture Diagnostics in East Texas and Western Colorado Using the Hydraulic-Impedance Method
Authors: Holzhausen G. R. , Egan H. N.
Published: December 2007

The growth of a hydraulic fracture changes the hydraulic impedance at the point where the fracture intersects the well. The components of impedance can be defined in terms of fracture dimensions using elasticity relationships for a suitable fracture model. When these components are derived from measurements of pressure oscillations, the dimensions of the fracture can be calculated. This method was applied during minifracture testing in a tight gas sand well in East Texas and a coal seam methane well in Colorado's Piceance Basin. In both tests we observed shifts in oscillation frequencies and decay rates consistent with theoretical predictions. We were able to closely duplicate measured oscillations at different stages of fracture development using numerical models. Calculated fracture dimensions are in the 70 – 120 ft range. The tests established that the impedance method can be used for fracture evaluation under both cased-hole and open-hole conditions.
Stratigraphy and Petroleum Production of Middle and Upper Devonian Shales, Northwestern West Virginia
Authors: Sweeney J. , Filer J. , Patchen D. , Hohn M.
Published: December 2007

Middle and Upper Devonian subsurface rocks in six counties in northwestern West Virginia can be divided into formal units of organic-rich black shales overlain by inorganic gray and greenish-gray shales. The section thickens west-to-east from 2,000 to 4,000 feet, including some fine sandstones and siltstones in the upper part.

Drilling since 1980 has discovered several productive intervals in this thick sequence. Generally, younger siltstones and shales down to the Huron Shale produce oil and gas; below the Huron, gas dominates. In map view, three broad oil and gas plays can be related to facies changes and to the Burning Springs Anticline. West of this structure, both organic-rich and inorganic shales produce gas; on and immediately east of the anticline, transitional facies (including black and gray shales, and younger siltstones) produce oil and gas; and farther east, siltstone bundles produce gas and some oil. Thus, completion-zone thickness ranges between 30-2,000 feet, with varied completion techniques.

Under a current Gas Research Institute contract, we are seeking possible relations among stratigraphy, completion intervals and techniques, initial potential (IP), and production. Preliminary studies in three counties indicate that gas IPs are highest when three or more formations are completed using nitrogen-fracturing. In one first year production study, the average shale oil well east of the Burning Springs Anticline is short-lived, declining by 95% of IP after one year before leveling off. A similar first year production study for 3 adjacent counties indicated less rapid decline of oil wells located along the Burning Springs Anticline.
Interference Testing of a Coalbed Methane Reservoir
Authors: Koenig R. A. , Stubbs P. B.
Published: December 2007

The Rock Creek Methane from Multiple Coal Seams Completion Project is a research and development effort to advance the technology for economical production of methane from coal seams. Interference testing of a coalbed methane reservoir in the Warrior Basin near Birmingham, Alabama, gives insight into the unique characteristics of coal seams which influence production techniques and strategies. Permeability anisotropy, scale-dependent permeability and a large porosity-compressibility product were observed, all of which have important implications for well field and stimulation design.
Risks and Rewards of Well Drilling in the Devonian Shale
Authors: Yost A. B.
Published: December 2007

This paper addresses the risks and rewards associated with Devonian shale gas wells in West Virginia, Ohio, and Kentucky. In the development thereof, both geo-science and geostatistical studies were pursued. A geoscience approach was used to identify the plays or groups of counties in each of the three states having similar geology. Within these plays, data from existing wells were acquired to quantify reservoir parameters (pressure, depth, well spacing, and productive interval), Afterwards, a dual-porosity, single-phase simulator was used to forecast expected performance from stimulated wells. Using these curves, reserves were estimated for each play.

A geostatistical approach was used to rank and quantify the risk (probability of production) associated with drilling and producing Devonian shale wells in selected plays. The rewards associated with new well drilling ventures were addressed in the economic parameters of payout time and return on investment. This study should be of interest to Appalachian independents and businesses considering development of shale gas wells. It should reduce considerable uncertainty relative to areas worthy of drilling and, within them, options for stimulation.
An Integrated Reservoir Description Method for Naturally Fractured Reservoirs
Authors: Gatens J. M. , Olarewaju J. S. , Lee W. J.
Published: December 2007

This paper presents a method to estimate reservoir properties and gas in place using both pressure transient test and production data from naturally-fractured reservoirs. The reservoir engineer needs to determine reservoir characteristics and gas in place to design and evaluate stimulation treatments and to predict performance. We attempted to estimate these properties for naturally-fractured reservoirs using only production data, and we have found that it is rarely possible to develop a unique reservoir description due to the insensitivity of most routine production data to the dual-porosity reservoir characteristics. If both long-term production and pressure transient test data are available, a better reservoir description is possible.

We present one theoretical and two field examples to illustrate application of the method The field examples are for Devonian Shale gas wells but the method is applicable to any naturally-fractured oil or gas reservoir.
Strategies for Adding Low-Cost Natural Gas Reserves
Authors: Kuuskraa V. A. , Wicks D. E.
Published: December 2007

During this period of natural gas surplus and declining prices, gas production, transportation, and distribution companies need low-cost reserves to maintain market share and assure economic survival. This paper discusses the attractiveness of three new sources of natural gas -- tight formations, methane from coal seams, and Devonian shales -- as options for low-cost gas reserves. In particular, the paper examines the role of improved extraction technology for increasing the recovery efficiency for improving the economics of unconventional gas, and for making these new sources competitive with conventional supplies.

The paper addresses three key questions of concern to managers of gas supply: How does unconventional gas compare economically with conventional gas from the Lower-48 onshore and offshore?How do the various unconventional gas sources compete among themselves?How might one formulate a "least cost" investment and production strategy for future natural gas supplies?
A Multi-Phase, Multi-Dimensional, Variable Composition Simulation of Gas Production From a Conventional Gas Reservoir in Contact With Hydrates
Authors: Burshears M. , O'Brien T. J. , Malone R. D.
Published: December 2007

A two-phase, three-dimensional numerical model was developed to simulate the dissociation and formation of hydrates (composed of water and any mixture of methane, ethane, or propane). This model was developed in order to address fundamental questions regarding the feasibility of production schemes for the utilization of this unconventional energy resource, gas hydrate, whenever a gas reservoir is in contact with a hydrate cap. These questions are also important in the design of conventional hydrocarbon resource production schemes from geologic zones in which hydrates are predicted to be thermodynamically stable. Results of the simulations indicate that massive hydrate can be dissociated without an external heat energy source, and that the water evolved from hydrate disassociation does not impose limits on the producibility of the reservoirs. Additionally, gas from hydrates was shown to contribute significantly to the produced gas stream. These results support the continued evaluation of gas hydrates as a potential resource, and indicate that conventional in situ recovery schemes may be effective in releasing gas from zones of hydrate stability.
The Characterization of High-Energy Chemical Sources for Fracturing Devonian Shale
Authors: Mniszewski K. R. , Westcott P. A.
Published: December 2007

To find more effective means to enhance permeability in Devonian shales and other unconventional, tight, or naturally fractured reservoirs, new stimulation methods are being pursued that have the ability to create multiple radial fractures. The desired result is to create several fractures of sufficient length that intersection with the natural fracture system is highly probable.

Methods were developed for experimentally testing high-energy materials through the use of pipe tests and a borehole simulator. The results of these tests have shown that central initiation of the charges provides the best control and most consistent performance. Simulation of water tamped charges showed that water could significantly reduce performance due to quenching of unburned propellant. Recommendations are presented for obtaining maximum use of the available energy, consistent combustion behavior, and packaging considerations.
Geology and Production Potential of the Devonian Rhinestreet Shale: A Case Study of Three Wells
Authors: Kirr J. N. , Eddy G. E. , Locke C. D. , Smith J. B.
Published: December 2007

The BDM Corporation, under contract to the Department of Energy/Morgantown Energy Technology Center, is collecting geologic and engineering data on Devonian shales from 10 sites in the Appalachian, Michigan and Illinois Basins. As part of that project, three wells were drilled into, collected up to 60 feet of oriented core, and tested the Devonian Rhinestreet Shale in the Appalachian Basin. Those wells were: L. B. Southwick #1, Crawford County, Pennsylvania; P. D. McCartney #1, Mahoning County, Ohio; and A. B. Wilson #19, Wirt County, West Virginia.

The target areas for drilling the wells was based on data from the past EGSP. Shale thickness, thermal maturity, organic content and stress distribution were factors considered in target selection. Data collected from the wells confirmed the presence of the required factors in the target areas. Petrophysical testing of samples collected from the core indicate the porosity and permeability for the shale is low. The maximum porosity found was 6.8 percent and maximum permeability (at reservoir pressure and for a non-fractured sample) was 7.24μd.

Production testing in the wells yielded mixed results. The L. B. Southwick #1 initially had a production of 3,000 cf/d, but eventually fell off to 800 cf/d. Core samples from the P. D. McCartney #1 had large volumes of gas initially desorbed, but the well yielded no production when tested one week after completion. The A. B. Wilson #1 was able to maintain a flow rate of 8 Mcf/d.

The L. B. Southwick has been stimulated using explosives. Preliminary indications are that it had minimal effect on production. Plans are in progress to foam fracture the P. D. McCartney.
The Rock Creek Methane From Multiple Coal Seams Completion Project
Authors: Boyer C. M. , Popvich G. S. , Schraufnagel R. A.
Published: December 2007

The Rock Creek Methane From Multiple Coal Seams Completion Project is a multi-year joint venture between the Gas Research Institute and United States Steel Corporation. The project objective is to evaluate and recommend methods to profitably produce gas from shallow, multiple coal seams. Overall project plans and specific results in the areas of geology, reservoir characterization, drilling and completion, and economic analysis are presented.
Poroelastic Concepts Explain Some of the Hydraulic Fracturing Mechanisms
Authors: Detournay E. , McLennan J. D. , Roegiers J. -C.
Published: December 2007

This paper reviews the role of coupled diffusion/deformation phenomena in the various facets associated with hydraulic fracturing: breakdown, propagation and closure, and the assessment of these effects by means of Biot's linear theory of poroelasticity.

The poroelastic concepts are first recalled and emphasis is placed on the fundamental parameters needed. The importance of the coupling terms in the elasticity and diffusion equations is also stressed. The general equations are then simplified for two particular applications: one-dimensional column and radial symmetry.

It is then shown that the reservoir history as well as the percolation occurring prior to hydraulic fracture initiation affects the breakdown pressure value. Poroelastic models also explain the decrease of propagation pressure with pore pressure, as has been often reported in the field. Finally, the fracture closure is considered and the coupling mechanisms clearly demonstrate the width decrease as well as the increase of shut-in pressure with time.
The Drilling Performance Curve: A Yardstick for Judging Drilling Performance
Authors: Brett J. F. , Millheim K. K.
Published: December 2007

The Drilling Performance Curve (DPC) is a simple yet powerful tool to assess the drilling performance in any given area where a consecutive series of similar wells have been drilled. All the information that is needed to perform the analysis is the sequence numbers of the well and the time it takes to reach a given depth.

This paper presents some typical examples of DPC's covering a study of over 30 different areas (onshore and offshore) including over 2000 wells. From the data, a simple model for the overall drilling performance was derived.

Three constants C1, C2 and C3 are unique to the DPC. From the numerical value of the constants, the drilling performance can be derived. For example, the C1 constant indicates how well an operation is prepared to drill a given location and/or how difficult the area is to drill. The C2 constant directly reflects the rate of learning. The C3 constant indicates the level of technology and organization for drilling in a particular area. This paper will present cases from poor to excellent drilling with the associated coefficients.

It will be shown that the DPC can dictate the strategy for a drilling program and what the economics of drilling a sequence of wells should be in a given area. It is suggested that the DPC become the yardstick for evaluating drilling, much as the decline curve is for production.
A Simplified Model to Predict Heterogeneity Effects on WAG Flooding Performance
Authors: Genrich J. F.
Published: December 2007

A steady-state, analytical model is presented to estimate ultimate recovery from water-miscible gas floods in heterogeneous reservoirs. The model is used to investigate miscible flooding performance as a function of well spacing, rock-fluid properties, and reservoir description.

Results show that layers or streaks of relatively high vertical permeability within an otherwise homogeneous formation cause little change in overall recovery. Flooding performance, however, is generally improved by low permeability heterogeneities, depending on their relative vertical position. Discontinuous shales near the bottom or the middle of the reservoir enhance vertical sweep efficiency, while such shales near the top have much less effect on oil recovery.
Mixing During Two-Phase, Steady-State Laboratory Displacements in Sandstone Cores
Authors: Bretz R. E. , Welch S. L. , Morrow N. R. , Orr F. M.
Published: December 2007

This paper examines the changes in fluid distributions and the mixing that occurs in immiscible phases flowing in a porous medium with changes in phase saturations and flow rates. We report experimental results for steady-state displacements with saturations established by secondary drainage, for one outcrop and one reservoir sandstone. Displacements were performed using immiscible liquids of matched density and viscosity at six saturations ranging from residual oil to low initial water saturation. Flow rates at a given saturation were usually varied by more than an order of magnitude.

Trapped, dendritic and flowing fractions were determined for each phase by fitting effluent composition data to the Coats-Smith model as modified by Salter and Mohanty. The oil phase and, contrary to previous investigations, the brine phase both exhibited trapped saturations. That for the brine phase was found to be independent of flow rate for both core samples. The volume of trapped oil phase was also independent of flow rate for the reservoir sample, but the outcrop sample showed velocity dependence at the higher values of oil saturation. The stagnant volume fraction at a given saturation was essentially independent of velocity. Thus, in cases where trapped oil saturation changed with velocity, there was an equal but opposite change in the flowing fraction.

The fits of displacement results to the modified Coats-Smith model were also used to investigate changes in mixing as phase saturations and flow velocities changed. The parameters of that model represent mixing in terms of dispersion and mass transfer coefficients. Those parameters were determined as functions of displacement velocity at each saturation. Dispersion coefficients in both phases were linear functions of velocity at any given saturation. Brine dispersion coefficients were indistinguishable from those obtained in stable, single-phase displacements on the same core. Oil phase dispersion coefficients were, in general, greater than those for the brine phase, but decreased as oil saturation increased, and at low water saturation were the same or less than those for the brine phase. Mass transfer coefficients were also linear functions of displacement velocity and had similar values for both phases.

The differences in displacement results between the two core samples are interpreted in terms of pore structure and changes in fluid distribution with changes in saturation and flow rate. Finally, we discuss the implications of the mixing results for the performance of EOR processes.
Scaling Laws for Immiscible Displacements with Capillary and Viscous Fingering
Authors: Lenormand R.
Published: December 2007

Multiphase reservoir properties are generally extrapolated from laboratory measurements, and scaling laws are based on dimensionless numbers obtained from macroscopic flow equations. This approach is not valid when fingering occurs on the macroscopic scale because of an unfavorable viscosity ratio or capillary effects. We describe a more general scaling technique taking this fingering into account.
Phase Behavior Calculations Near the Critical Point
Authors: Kossack C. A. , Hagen S. , Munkerud P. K.
Published: December 2007

Phase behavior studies have been performed using three component, six component and twenty-two component mixtures. These studies have been performed in such a way that the critical points for the mixtures are approached, either by increasing the temperature while keeping the composition constant or by changing the composition while keeping the temperature constant. It has been shown that regression on the data from these types of experiments gives a better Equation of State (EOS) match, and thus will allow a better simulation of slim tube displacements.

The phase behavior has been calculated using the Peng-Robinson EOS and a comparison between the calculated and experimental results is shown. A comparison of the quality of the phase match, especially the pressure – temperature behavior, is made as a function of the number of regression variables. In all cases substantial improvement, in the EOS's ability to simulate PT-x data was seen as the number of regression variables increased. As a result of the fact that a system with more components has more regression variables available, the twenty-two component system had the best match and the three component system the poorest match. The conclusion was that the two parameter EOS as it is normally used lacks flexibility to calculate phase behavior in the entire, phase space. The phase matches were used to predict additional data at different temperatures and compositions to evaluate the ability of the EOS to extrapolate the phase match. The result was that the EOS did surprisingly well in some cases and very poor in other cases.
On-Site Completion/Workover Fluid Analysis Using a Portable Laser Particle Size Counter
Authors: Underdown D. R. , Newhouse D. P. , Fisher C. B.
Published: December 2007

The frequent use of clear brines as completion/workover fluids has increased the need for improved methods of solids removal during these operations. Studies in recent years, relating formation damage with particle size distribution in completion/workover fluids, magnify the need to make the brines as solids-free as possible (1–8). This fact has led the industry to re-examine the filtration process on completions.

Presently, there are no methods commonly used to determine the particle size distribution in fluids at the rig site. On-site measurements of solids generally involve centrifuging a sample of fluid to determine the percent by volume of solids or monitoring solids content by turbimetric methods. The volume percent of solids is important; however, knowledge of the particle size distribution and population density is important in order to minimize formation damage. Tests can be run in the laboratory on several types of instruments to determine particle size distribution, but these represent "after the fact" data.

In other industries, a small laser particle counter is being used to determine size distribution and actual particles per cubic centimeter in clear fluids. The instrument is interfaced with a PC computer or hand-held calculator to compute the size distribution and the population density of the particles. The instrument is portable, precise, and practical for use in the oilfield. It gives field personnel an opportunity to check the solids distribution of the fluid going into the well and the efficiency of the filtration equipment on-site. The data obtained using the laser particle counter together with the reservoir data is a good means of detecting potential formation damage associated with the solids found in the completion/workover fluids.

Results of lab tests, yard tests, and field data have shown applicability of the laser particle counter to analyze clear brines on-site. Scanning electron microscopy was used to determine the type of material passing through the filters. Comparison of the field and lab tests has given a better understanding of the limitations of the currently available filtration equipment.
Reducing Formation Damage through Two-Stage Polymer Filtration
Authors: Houchin L. R. , Hudson L. M. , Caothien S. , Daddazio G. , Hashemi R.
Published: December 2007

Formation damage resulting from the use of unfiltered polymers during gravel pack completion operations has been addressed as it relates to НЕС completion fluids.1–5 However, other filtered polymer systems exhibit properties which, in specific applications, may out perform НЕС systems. Thus, the performance characteristics of six commonly used polymer systems, hydroxyethyl cellulose (НЕС), clarified xanthan gum (XC), HEC/XC blends, crosslinked carboxymethyl hydroxyethyl cellulose (CMHEC), hydroxypropyl guar (HPG), and standard xanthan gum (XCD), required additional evaluation. Fluid modelling was employed using a new two-stage filtration process (gel filtration) in which the viscosified fluids were optimally sheared and fine-filtered to improve sand placement efficiency and reduce formation damage. The data obtained from this study establishes mixing and filtration design criteria for optimizing completion techniques such as gravel packing, sand washing, polymer diverting, and lost circulation control.
Development of a Gravity-Assisted Gravel Pack System
Authors: Stiles R. F. , Colomb G. T. , Farley D. L.
Published: December 2007

This paper describes the development of a new gravel pack system that is designed to produce higher quality gravel packs in deviated wells. In deviated wells, gravel pack sand deposition is not uniform and a "duning" effect is observed. This duning phenomena has been identified in several studies and results in an incomplete pack of the screen-casing annulus.

In conventional gravel packs, the sand is pumped from the top of the interval to the bottom. This new technique, termed Bottom-Up, reverses this flow and the gravel pack sand is pumped from the bottom of the interval to the top. This changes the way in which gravity acts on the sand particles and prevents "dunes" from forming. This allows for uniform placement of the sand in the screen-casing annulus.

This new concept has been tested extensively in a full scale model to study the flow characteristics and packing efficiency. Several field jobs have recently been completed with deviations ranging from 0 to 67 degrees and intervals lengths from 20′ to 100′. In all cases the gravel pack evaluation log has shown 100% annular packing from the sump packer to directly below the top packer. These wells have also demonstrated high productivities during testing and production.
Rheology of Oil-Base Muds
Authors: Houwen O. H. , Geehan T.
Published: December 2007

The rheological behaviour of invert emulsion muds has been studied at pressures up to 1000 bar and temperatures up to 140° C, Rheological parameters were calculated for the Bingham, Herschel-Bulkley and Casson rheological models. The Herschel-Bulkley and Casson models both give good fits to the experimental rheograms. The Casson model is more reliable for extrapolation purposes than the Herschel-Bulkley model. A pair of two similar exponential expressions were found to be able to model the pressure and temperature behaviour of the two parameters of the Casson model. The expressions, which are based on the relation for pure liquids derived theoretically by Eyring, contain temperature dependent pressure coefficients. The simplifications inherent in the temperature and pressure model are discussed in the light of the temperature and pressure behaviour of the viscosity of common base oils and their constituent hydrocarbons. Field application of the model requires measurement of the rheology of the mud at two or more temperatures and knowledge of the pressure coefficients relating the behaviour of the plastic viscosity to that of the yield point, or the Casson high shear viscosity to that of the Casson yield stress. Pressure measurements or other information are then not required. Applications can be based on Casson or Bingham rheological measurements. The relationships between the parameters of the Casson and Bingham models are disussed.
Pressure Transient Analysis in Finite Linear Reservoirs Using Derivative and Conventional Techniques: Field Examples
Authors: Wong D. W. , Mothersele C. D. , Harrington A. G. , Cinco-Ley H.
Published: December 2007

In this paper, we present a new type curve to be used in the pressure transient analysis of rectangular reservoirs penetrated by a well with skin. The type curve uses the pressure derivative behaviour to aid in behaviour recognition and match confidence and reduces all the wellbore pressure reductions caused by skin and "pseudo-skin" during linear flow to one unique case. Cartesian plot techniques complement the type curve match calculations and ensure reservoir parameter and dimension correctness. The new techniques are applied to two field cases; both a gas and an oil well. The paper concludes that the type curve and cartesian plot techniques can be used to methodically investigate all possible rectangular reservoir configurations and well positions.
The Effect of Trace Quantities of Surfactant on Nitrogen/Water Relative Permeabilities
Authors: Sanchez J. M. , Schlechter R. S. , Monsalve A.
Published: December 2007

This paper proposes a single capillary model incorporating the mechanisms of foam generation, propagation, and rupture. It includes new features not heretofore noted and results in predictions for the influence of variables such as the gas rate, pore geometry, liquid rate, and surfactant concentration on the relative permeability to gas. Since the model is a simple one, only qualitative trends are predicted. Nevertheless apparently contradictory results can be understood in terms of the qualitative trends and new phenomena associated with the behavior of foams generated in situ are predicted.

The model is a steady-state one. The generation rate of lamellae which are subsequently displaced and move along the capillary tube is a constant. To conduct experiments which are intended to confirm the model predictions one must ensure that these experiments yield truly steady-state results. This is not simple and a protocol for achieving steady state is tested. It is recommended as one approach for performing meaningful steady-state experiments.

Systematic steady-state experiments are reported to demonstrate two important model predictions. The first shows the remarkable effect of even very small surfactant concentrations on the relative permeability to gas and the second set of experiments is designed to verify the model prediction that the relative permeability to gas at a fixed liquid saturation may increase or decrease with increasing liquid rates. Both trends have been reported in the literature.1,2

The correspondence between the predicted trends and those observed confirms the value of the single capillary model in understanding the complexities of mobility control using foams which are generated in situ.
Production Operations Forum
Authors: Kleckner J. J. , Dickerson R. C. , Snider P. M. , Zublin J. A. , Sphan R. L. , Menne P. F. , Van Der Lichte J. H. , Ter Horst B. H. , Akkerman N. H. , Rorden L. H. , More H. S. , Kattner J. E. , Samuels A. , Wendt R. A. , Hoh T. , Beauregard E. , Ferguson P. L. , Carnell P. J. H. , Clark H. H.
Published: December 2007

The Production Operations Forum is designed to allow the discussion of and dissemination of information about technical innovations and solutions in production engineering that are of immediate practical use but do not warrant a full-scale paper. Each subject is presented in a five to eight minute period with a discussion period of seven to ten minutes. A wide range of subjects is encompassed in the session. Abstracts of the presentations follow.

The presence of liquids in a gas flow stream, whether the liquids are condensate or formation water, requires energy to be lifted to the surface. If sufficient energy is not present, liquids will accumulate in the well bore and exert additional back pressure on the formation. This results in erratic production, poor compressor performance, and inaccurate data in multi-rate back pressure testing. In the case of low reservoir pressure, the accumulation of liquid may kill the well.

Several methods including plunger systems, sucker rod lift, liquid diverters and gas lift installations are used to successfully move liquids from the well bore. This discussion will address specifically the use of 1.25" concentric pipe (coiled tubing) as a production string to reduce cross-sectional area of flow, thereby increasing the stream velocity and continuously unloading liquids from the wellbore. In many cases the wells requiring liquid lift are low pressure gas wells sensitive to remedial work and kill fluids. Use of a custom machined spool and slip assembly in conjunction with a pump out plug and coil tubing unit injection head allows for the installation of the coil tubing without killing the well. Installation is accomplished by shutting in the well at the bottom master valve and removing the tree above the shut in valve. The spool and slip assembly is installed and a coil tubing unit with injection head is rigged up on the spool. The tubing is run to the desired depth, the slips are set, and the tubing is packed off. The tubing is cut above the injection head and the BOP's and injection head are removed. The tubing is dressed off 2-3 inches above the bowl and slip assembly and the tree is installed. The coil tubing is pressured up with N2 or gas to release the plug and the well is flowed to sales. This "no kill" method has alleviated past problems of returning low pressure gas wells to production following workovers.
New Methods for Controlled Injection of Steam Into Multiple Sands
Authors: Hong K. C. , Griston S.
Published: December 2007

Chevron has been employing two new completion methods to control steam injection into multiple oil-bearing horizons using a single injection well. The two methods, parallel tubing injection and limited entry injection, are used to improve steam utilization and to reduce the need to drill new injection wells.

One of the methods used previously was concentric injection in which steam is injected down two concentric pipes placed inside the wellbore and thereby distributed to two separate sands. The outer pipe can be the well casing itself. This method, however, proved unsatisfactory because one of the strings became plugged due to scale buildup. As a result, injection into both sands was no longer possible. For this reason, the concentric injection method is no longer used. Instead, parallel tubing injection and limited entry injection methods are currently used.

This paper reviews the concentric injection method and presents conceptual details of the two new methods. Theoretical calculations supporting application of these methods are also presented.
Experimental Study of Non-Darcy Flow Through Perforations
Authors: Nguyen T. V.
Published: December 2007

Results of an experimental study of non-Darcy flow through perforations are presented. Pressure drop and flow rate data are presented as functions of the perforation geometry and gravel permeability. Water and air flow data show nonlinear relations between pressure drop and flow rate. Non-Darcy flow experimental results are used to study the productivity of gas wells. Results of this study show that standard Darcy flow analysis can overpredict the productivity by as much as 100 percent.
The Use of Circumferentially Propagated Acoustic Waves in Well Logging
Authors: Guy J. O. , Fertl W. H. , Oliver D. W.
Published: December 2007

An acoustic logging system which uses circumferentially propagated acoustic waves for measuring several parameters in a borehole has been designed and tested. The detection of one type of wave whose particle motion is perpendicular to the borehole wall is used to indicate the presence of vertical or near-vertically oriented fractures in fluid-filled boreholes.

This paper reviews the basic theoretical concepts and instrumentation design of the Circumferential Acoustilog® and presents laboratory data to illustrate the validity and applications of the measured parameters. Recent improvements over previous devices of this type will be discussed. One of the improvements is the incorporation of a direct fluid wave baffle which extends the range of formation velocities that can be accurately measured, and also provides the means for identifying the guided fluid wave. A recent significant improvement to the system is the addition of an orientation section which assists in determining the direction of fracture systems.

Field examples from the United States, Canada, and Europe demonstrate the application of the system in varying lithologies and borehole conditions.
A Microscopic Model of Fluid Flow in Porous Media
Authors: Hardy H. H.
Published: December 2007

A model to describe microscopic fluid flow in porous media is proposed. It offers the potential to predict relative permeability curves from microscopic rock and fluid properties. Conventional descriptions of fluid flow in porous media are based on Darcy's equations which require relative permeabilities and capillary pressure curves to be measured on macroscopic porous material. Prior to 1980, these macroscopically measured parameters could not be quantitatively related to microscopic rock properties. Recently, percolation theory has been used to relate macroscopic rock properties to relative permeabilities in the limit of capillary flow. Diffusion Limited Aggregation has been shown to simulate microscopic flow in the limit of infinite mobility ratios.

The model described in this paper is a new approach to simulating flow through porous media on a microscopic scale. It is based on a variation of diffusion limited aggregation. The model can match coreflood average saturation profiles and production histories as predicted by Darcy's equations while generating saturation distributions resembling viscous fingering. The model can also simulate the limiting cases of infinite mobility ratio and zero flow rates as previously modeled by diffusion limited aggregation and percolation theory. With some simplifying assumptions, differential equations very similar to Darcy's equations can be derived from the microscopic interpretation of fluid behavior in porous media used in this model.
Economics of Fracturing: Some Methods, Examples, and Case Studies
Authors: Veatch R. W.
Published: December 2007

This paper addresses methods for predicting economics of hydraulic fracturing treatments. Discussions focus on maximizing potential profits from accelerated production, reduced costs, and possibly increased ultimate recovery. Pertinent economic criteria are given. Examples are presented to demonstrate analysis methodologies and the sensitivity of economics to certain fracture treatment design parameters.
Fracture Characterization of Multilayered Reservoirs
Authors: Britt L. K. , Larsen M. J.
Published: December 2007

Fracture treatment optimization techniques have been developed using Long-Spaced-Digital-Sonic (LSDS) log, pumpin-flowback, mini-frac, and downhole treating pressure data. These analysis techniques have been successfully applied in massive hydraulic fracturing (MHF) of "tight gas" wells. Massive hydraulic fracture stimulations have been used to make many tight gas reservoirs commercially attractive. However, studies have shown that short highly conductive fractures are optimum for the successful stimulation of wells in moderate permeability reservoirs. As a result, the ability to design and place optimal fractures in these reservoirs is critical.

This paper illustrates the application of fracture analysis techniques to a moderate permeability multi-layered reservoir. These techniques were used to identify large zonal variations in rock properties and pore pressure which result from the complex geology. The inclusion of geologic factors in fracture treatment design allowed the placement of short highly conductive fractures which were used to improve injectivity and vertical sweep, and therefore, ultimate recovery.
Error Analysis and Design Considerations for Backpressure Testing of Gas Wells
Authors: Hinchman S. B. , Poettmann F. H.
Published: December 2007

The theoretical validity of backpressure tests has been analyzed for wells in radial flow and for wells intersected by vertical fractures. It is demonstrated that stabilized flow-after-flow and isochronal tests are valid tests. Unstabilized flow-after-flow and modified isochronal tests result in error in predicted deliverability caused by continued influence of prior flow and shut-in periods (superposition error). It is shown how the superposition error can be minimized by proper selection and design of the backpressure test.

Isochronal and modified isochronal tests are unsteady-state methods and provide the transient deliverability of a well. An extended flow period is generally used to determine the stabilized deliverability. In many reservoirs extended flow periods are unreasonably expensive and impractical. Analytical solutions for predicting stabilized deliverability are required. The calculations used in the prediction of stabilized gas deliverability are based on a radial flow geometry. When these calculations are applied to other flow geometries, errorneous conclusions result. In this study a fully-implicit, two-dimensional gas simulator was used to demonstrate the extension of radial flow theory to vertically fractured wells. The effect of fracture length and conductivity was investigated. It was observed that the performance coefficient (Ct) was inversly related to pressure. A proof is presented for the Darcy flow condition. An understanding of how Ct changes with time will allow a more precise estimate of stabilized deliverability.