bluuebunny/crossref_metadata_2025 huggingface dataset:
Computer Control of Minimum Shoulder Prestress Requirements During Makeup Procedure of Premium Shoulder Connections
Authors: Marojevic S. T.
Published: December 2007

The new proposed method and computer control technique of optimal shoulder prestess value during make-up procedure of (premium) shouldered connections assures uniform stress control and optimizes utilization of tubular goods with schouldered type connections. Application of minimum shoulder prestess requirement with regard to the threshold stress-level provide the highest safety and the most efficient use of tubular goods in a corrosive environment. During make-up procedure this method helps to overcome the influence of different parameters such as: machining tolerances, dope and plating qualities with their corresponding friction losses etc; which otherwise might jeopardize connection mechanical and sealing integrity.
Gravel Packing Operations from a Floating Vessel
Authors: Zaleski T. E. , Donovan J. F.
Published: December 2007

Standard gravel packing equipment requires precise manipulation of downhole tools to direct fluid flow as desired. Floating vessels present a particular problem because the tools are generally positioned with the workstring in full tension suspended by the elevators. Without a stationary rotary table from which to measure, finding and holding each position becomes impossible when wave heights exceed a few feet. A specially designed set of gravel packing tools has been developed that allows accurate downhole positioning from all types of floating vessels.
Deep Wildcats: New Challenges to Pipe and Connection Manufacturers
Authors: van Cuyck G. H. , Dlaska H. C.
Published: December 2007

Several deep wildcats, spudded in 1984 and 1985, were drilled or are still drilling in extremely hostile environments with total depths of more than 20,000 feet. Special tubulars and connections had to be specified, manufactured and tested to reach TD with an 8-1/2″ bit size safely. Mannesmann was present with the pipe and connection technology from the initial planning stages through running of the fallowing long and heavy strings: OnshoreWeight in Air12,455 ft. 20″169#C-95Big Omega2.2 Mio.#13,970 ft. 16″146#P-110BDS-52.2 Mio.#16,695 ft. 14″106#C-110BD5-51.9 Mio.#Offshore4,919 ft. 26″266#X-56SML51.4 Mio.#11,852 ft. 18-5/8″178#C-95Big Omega2.2 Mio.#15,820 ft. 14″120#C-110HPC1.9 Mio.#20,000 ft. 10-3/4″96#C-100/P-110HPCdelivered/not run yet

Some of the measures which were taken to improve and assure product quality and performance in order to satisfy all load and environmental requirements will be discussed in this paper.
Control of Annular Gas Flow in the Deep Anadarko Basin
Authors: Matthews S. M. , Copeland J. C.
Published: December 2007

Gas channeling often occurs soon after the placement of a conventional cement slurry in wells having gas. The slurry, during and immediately after placement, will act as a true fluid transmitting hydrostatic pressure onto the gas-bearing formation, until the cement begins to gel or set. As long as the hydrostatic pressure remains above the gas formation pressure, no gas will penetrate the cement column. However, as the cement begins to set (changing from a fluid to a rigid material), it gradually loses its ability to transmit hydrostatic pressure. This process is often called the "transition period." Shrinkage compounds the problem, leading to poor bonding between the cement and formation, thereby allowing gas to flow at the interface.

A field study has been conducted on a design approach which incorporates a unique cement slurry which interacts with incoming gas to form an impermeable barrier in the cement pore spaces, thereby inhibiting further gas flow.

Seventy-seven wells in Oklahoma and the Texas Panhandle using this cement slurry were reviewed. Based on success being defined as no gas migration to surface or no indication of interzonal communication, 86% of these wells were classified as successful.

Case histories of five wells giving qualitative and well parameters used in the design are discussed, along with results.
Perforation Breakdown Improves Permian Basin Stimulation Results
Authors: Scott T. A.
Published: December 2007

Permian Basin operators have recently achieved improved stimulation results using precision perforation breakdown prior to their stimulation treatments. Precision breakdown of individual perforations is made possible by a recently developed hook wall straddle packer that isolates intervals of casing as short as 3 in.

In previously used procedures, ball sealers, temporary blocking agents and high fluid injection rates were used to break down perforations. These methods were partially successful, but in some cases were detrimental to the stimulation and well performance due primarily to the fact that the operator did not know the status of the perforations at the time of the major stimulation.

The precision perforation breakdown method uses minimal pressure and pumping rate to help prevent fracturing into unwanted gas or water, and gives a positive indication that each perforation is broken down and will accept fluid. Values such as (1) instantaneous shut-in pressure and (2) perforation breakdown pressure can be obtained for individual perforations. This data is useful for designing the stimulation job and for design of subsequent jobs to be performed in the same field.

Subject paper discusses the conditions and circumstances under which precision perforation breakdown may be used to good advantage. Actual job logs and tool schematics illustrate the use of the precision breakdown method.
Determination of Formation Water Resistivity Using Shale Properties
Authors: Dusenbery R. A. , Osoba J. S.
Published: December 2007

A new method is presented to determine formation water resistivity (Rw) in sandstones. This procedure does not use the Spontaneous Potential (SP) log. Instead formation Rw is obtained from the overlying shale zones.

To understand the correlation between shale and sandstone waters, consider that during deposition their salinities are approximately equal. After compaction the waters in both shales and sandstones are in equilibrium. Because shales are impervious to drilling fluids a true value of water resistivity and salinity in the shale can be obtained from Archie's equations. The formation water resistivity is determined from the shale salinity and a relationship developed from core data.

The shale method is simple to use requiring only the shale resistivity and porosity. This makes it ideal for field use. It also is accurate for both normal and geopressured wells.

The presented technique is compared to other interpretation methods on several wells. The results compared well with other data.
A Complete Integrated Model for Design and Real-Time Analysis of Hydraulic Fracturing Operations
Authors: Crockett A. R. , Okusu N. M. , Cleary M. P.
Published: December 2007

A new comprehensive model of hydraulic fracturing is presented which has been developed for the Gas Research Institute (GRI) mobile fracture monitoring and analysis facility. The main purpose of the model is to simulate the hydraulic fracturing process in real-time, that is on-site during the fracturing operation, but the model can also be used for pre-fracture design and post-fracture analysis. Sensor data obtained during the course of the job — such as wellhead pressure, flow rates, frac-fluid viscosity, and proppant staging — can be received directly by the model as input, superceding the pre-frac job design schedule, and making possible more accurate model estimates of current fracturing conditions and predictions of final fracture geometry, as the job proceeds.

The overall model has four major components describing:

— flow of fluids and slurry in tubular goods — creation and propagation of the hydraulic fracture — transport of proppant, deposition, and fracture closure — heat and fluid exchange between fracture and reservoir.

This fully-integrated, numerically robust model of the hydraulic fracturing process takes directly into account as much of the essential physics as possible, given the computational limitations of the real-time application. Additional information, pertaining to very complex reservoir characteristics, can be indirectly supplied to the model through data-based results obtained prior to the job from other more comprehensive (e.g., 3D, cross-sectional) fracture simulations. Having thereby embedded more elaborate fracture analysis into a simple lumped model, accurate predictions are achieved at execution speeds faster than real-time, allowing on-the-job analysis and even real-time history matching for unknown reservoir parameters.

Sample results are presented from model simulations of a fracture treatment performed in the Travis Peak formation of East Texas. Actual sensor data from the job was used as input and model predictions are compared with field measurements.
A Continuous Mixture Computational Algorithm for Reservoir Fluids Phase Behavior
Authors: Du P. -C. , Mansoori G. A.
Published: December 2007

Development of compositional reservoir simulators is presently hampered due to the complexity of the existing computational algorithms of reservoir fluid phase behavior calculations. Through the application of the theory of polydisperse fluid mixtures we have developed a new algorithm for reservoir fluid phase behavior calculations. In this algorithm a reservoir fluid is considered to consist of a continuous mixture with a defined molecular weight/composition distribution. The proposed algorithm requires less computational time than the time required by the existing pseudocomponent VLE calculation methods. It is also shown that the new algorithm is applicable to varieties of equations of state and mixing rules. Results of the proposed technique are compared with results of the other existing techniques, and with the simulated multi-pseudocomponent reservoir fluid mixture data.
Stabilization of Naturally Flowing Oil Wells Using Feedback Control
Authors: Blick E. F. , Boone L.
Published: December 2007

Some naturally flowing oil wells will experience flow instabilities (heading) characterized by regular or irregular cyclic variations in tubing pressure and flow rate. In order to analyze this phenomena, the unsteady equations of motion for flow out of the reservoir, flow out of the annulus and flow up the tubing are derived and then solved by the LaPlace Transform method. This analysis produces a characteristic equation whose coefficients allow one to determine if a particular well is stable or unstable. If the well is unstable it is possible to use a feedback controller which varies the tubing head choke diameter to stabilize the well. Various combinations of proportional, derivative and integral controllers are shown to theoretically control some unstable wells.
In-Situ Heat and Paraffin Inhibitor Combination Prove Cost Effective in NPR #3, Casper, Wyoming
Authors: McSpadden H. W. , Tyler M. L. , Velasco T. T.
Published: December 2007

Recent application of an in-situ heat and nitrogen generating system has led to a cost effective method of paraffin control for the Department of Energy at the Naval Petroleum Reserve (NPR) #3 in Casper, Wyoming. The combination of in-situ heat, solvent and paraffin inhibitor has not only prolonged productivity but also effectively stimulated the producing zones.

This paper describes paraffin treatments with the in-situ heat generating system in the NPR #3. Case histories showing candidate selection, pre and post treatment production levels and economics are presented.
Testing and Evaluation of an Arctic Fractured Carbonate: The Lisburne Formation, Prudhoe Bay
Authors: Fisher D. W. , Clutterbuck P. R.
Published: December 2007

The Lisburne Group is a Pennsylvanian-Missisippian age carbonate sequence which underlies the main Permo-Triassic producing horizon at Prudhoe Bay. During the last three years, delineation and appraisal efforts have accelerated leading to financial commitment to field development. Production startup is scheduled for December 1986.

This paper discusses the details of well planning and implementation necessary for the evaluation of this complex, fractured, low permeability limestone and dolomite reservoir. Well operations and testing have included techniques previously uncommon or unused in the Alaskan Arctic such as lightweight mud and cement, bland and pressure coring, open-hole tests with open-hole solvent stimulations, nitrified acid treatments, nitrogen lift of cased hole tests and fracture treatments. These methods helped ensure conclusive tests in a formation that is characteristically difficult to test and also established procedures to affect commercial well completions.

Methods used in the analysis of well results are also discussed briefly to provide some insight into the use of the well data in the overall evaluation process.
A New Method for Automated History Matching of Reservoir Simulators
Authors: Dye L. W. , Horne R. N. , Aziz K.
Published: December 2007

This paper presents a new approach to automated history matching. Instead of the usual, "mathematically-oriented" approach in which the strongly non-linear reservoir responses are locally linearized, this paper describes a "reservoir engineering-oriented" approach which attempts instead to use a combination of reservoir responses that is truly linear.

Two accurate linear models of a numerical reservoir simulator's pressure and production response to permeability changes are presented. These models, which are derived from the general hyperbolic decline curve relationship, are used in a history matching scheme to estimate the permeability distribution from historical production and pressure information. Three cases are presented which test the methods presented in matching for isotropic and anisotropic permeability distributions. The cases are based upon history generated from a 72 block 7 well model, and include both anisotropic and isotropic history matching problems.

A method of simultaneous determination of absolute and relative permeabilities is. also presented. The method is based upon the isotropic linear permeability model developed and tested in the paper.

The history matching technique presented requires only two or three simulation experiments to accomplish the match. This is approximately one-tenth the CPU cost required for the optimal control theory automatic history matching methods described in the literature.
A Study of Multiphase Flow Behavior in Vertical Oil Wells: Part II—Field Application
Authors: Kabir C. S. , Hasan A. R.
Published: December 2007

In the second part of the paper, we show the application of a vertical multiphase flow model, developed from first principles. Estimation of gas void fraction, or mixture density – leading to pressure gradient estimates in each flow regime, and transition from one flow regime to another are modeled rigorously. An appropriate model is also used to handle flow in a tubingcasing annulus. Parameters, such as, tubing to casing-diameter ratio and the equivalent diameter of the flow channel, developed from our experimental work, are incorporated in the model. Thus the model is capable of handling flow in both circular and annular channels.

Standard oilfield correlations are used for estimating PVT properties of oil and gas: Standing's correlation for solution gas-oil ratio; Katz's correlation for oil formation volume factor; Standing's, and Chew and Connally's correlations for dead and live oil viscosities, respectively; and Lee et al.'s correlation for gas viscosity.

Computation on test data gathered from some 115 oil wells, involving all the two-phase flow regimes, indicates that the proposed model performs better than the other models considered: Aziz et al., Orkiszewski, Duns and Ros, Beggs and Brill, Hagedorn and Brown, and Chierici et al. Calculations also reveal that bubbly and slug flow are the dominant flow mechanisms in most cases, while churn and annular flow are associated with high flow rate wells.

Hydrostatic head contributes to the most of the pressure drop (90 % +) when the flow is essentially restricted to the bubbly and slug flow. However, the frictional head becomes significant in annular flow. The test data bank used in this study is that previously used by other authors; thus, validation of the proposed model is made with an independent data set.
Rediscovering an Abandoned Reservoir: The Lakota Formation at Lost Soldier Field, Sweetwater County, Wyoming
Authors: Schmechel D. J. , McGuire M. J.
Published: December 2007

The Lakota reservoir at Lost Soldier Field was discovered in 1922. The Lakota produced about 5 MMBO between 1922 and the early 1950's, when the reservoir was abandoned. Since 1979 32 wells have been completed or recompleted in the Lakota formation. These wells should produce about 1 MMBO. The rediscovery of the Lakota reservoir at Lost Soldier Field points out a wide opportunity--to reenter abandoned reservoirs and develop overlooked reserves.
In-Situ Stresses: A Comparison Between Log-Derived Values and Actual Field-Measured Values in the Travis Peak Formation of East Texas
Authors: Whitehead W. S. , Hunt E. R. , Finley R. J. , Holditch S. A.
Published: December 2007

Knowledge of in-situ stress distribution within reservoir sandstones and the surrounding formations is recognized as one of the most important factors in the design and analysis of hydraulic fractures. Stress contrast between various layers of rock ultimately controls the vertical fracture growth and, thus, directly affects fracture length and width. Even though the importance of stress distribution is evident, these data are rarely measured due to the associated expense, interpretation problems and mechanical risks.

Currently, there are log analysis techniques available which can provide calculated values for mechanical properties and in-situ stresses. These techniques are based on classic theories of elastic stress-strain relationships and appear to be reliable in tectonically relaxed areas. In geologically active areas, however, external horizontal stresses may be present which cannot be calculated by these static techniques. In such formations, empirical field corrections must be included to accurately determine the in-situ stresses.

This paper summarizes the results from a study where actual field-measured values of in-situ stress have been compared to log-derived values. The study was conducted on wells completed in the Travis Peak (Hosston) formation of east Texas. A discussion of the regional geology is presented which describes how fluvial-deltaic depositional patterns and local facies variations control the sandstone geometry and distribution of possible fracture barriers.

In-situ stresses within sandstones, siltstones and shales were actually measured on three wells. Empirical corrections to the log-derived values were necessary in order to fit the measured data. The resulting correlations between log-derived values of stress and field-measured values of stress should be of benefit to the industry. The ultimate goal for all concerned with the problem is to learn how to reliably evaluate stress distribution from logs for fracture treatment design purposes.
A Method for General Reservoir Behavior Simulation on Digital Computers
Authors: Sheldon J.W. , Harris C.D. , Bavly D.
Published: December 2007

A large-scale computer method for reservoir simulation in two dimensions is described. The physical effects taken into account are gravity component parallel to bedding plane, solubility and compressibility for two flowing phases, which may be oil and water or oil and free gas. Fluid flow is treated optionally as either homogeneous or segregated. A new numerical method for treating gravity in the two-phase flow equations is presented. The member to be simulated is described in terms of cells. A material balance is obtained for each cell. The cells may be chosen of variable size so that small cells can be used in the oil-bearing regions and large cells in the aquifer. A data-handling system to facilitate problem preparation and display of results is described. Applications of the simulator, particularly to the Arab-D member of Saudi Arabia, are discussed.

Introduction

Reservoir Behavior Simulation

We define reservoir behavior simulation to be the response of an analogous model to disturbances corresponding to fluid withdrawals and infections. The model we call the reservoir simulator. In this paper, our main interest is to describe a particular reservoir behavior simulator. We also describe an example of production member behavior. However, this is only for illustration. Our main interest is the simulator itself.

A Discussion of Reported Methods of Simulation

Reports of reservoir behavior simulation appear frequently in the Journal of Petroleum Technology. The incentive for all this work is economic. The engineer believes he can plan more efficiently development of a reservoir when its behavior can be simulated.

Probably the earliest attempts at simulation are characterized by the term "case histories". Here, the investigators report the behaviors of reservoirs together with a description of the reservoirs. These reports are of interest to other persons if they have a similar reservoir at hand.

The first quantitative simulation of reservoir behavior seems to have been gained by omitting all consideration for spatial behavior. Only the principles of thermodynamics (temperature-pressure-volume relations) and conservation of matter are employed. No flaw dynamics are simulated. This model is now called the "Schilthuis" equations.
Formation Evaluation in the Devonian Shale
Authors: Campbell R. L. , Truman R. B.
Published: December 2007

A Devonian shale – specific geophysical log interpretation model was developed to extract as much geological and reservoir data as possible from a suite of air- or gas-filled-hole logs. Development of the methodology and evaluation of the geological and reservoir properties was supplemented with core data, formation tests, mud logging data, temperature logs and borehole TV logs acquired in Devonian shale wells.

This new analysis technique improves the identification of hydrocarbon bearing intervals and the types of formations associated with production. As a result, the analysis when combined with other data, allows a more effective selection and treatment of the hydrocarbon productive intervals.

Examples are shown which compare the computed lithology and porosity with core measurements. The computed results are also compared to mud logs; noise logs; temperature logs; borehole television data; production logs; and production tests.
Geologic Parameters Controlling Natural Gas Production From a Single Deeply Buried Coal Reservoir in the Piceance Basin, Mesa County, Colorado
Authors: Decker A. D. , Seccombe J. C.
Published: December 2007

Commercial exploitation of gas occluded in coal reservoirs has been hampered by appropriate exploration, drilling, completion and production methods. The Deep Coal Seam Project located at the Red Mountain Site, Mesa County, Colorado is a field laboratory experiment directed to develop, improve, evaluate and communicate the technology required to produce gas from a deeply buried coal reservoir.

Regional geologic studies have established the Red Mountain Site as representative of the majority of the coalbed methane resource within the Piceance Basin. The project is focused on the D coal seam, belonging to the Cameo Coal group of the Williams Fork Formation, Upper Cretaceous Mesaverde Group. Thickness of the D coal seam ranges from 16 to 20 feet (5 to 6.5 m) throughout the site with an average drilling depth of 5500 feet (1800 m). This coal seam is medium-volatile bituminous in rank with an average gas content of 250 scf/ton (8 scc/gm).

The geologic conditions responsible for gas productive coal reservoirs are not fully understood. Data suggests that changes in coal maturation with time and burial depth can create a wide diversity of coal reservoir conditions. Drilling, completion and production methods should be tailored to coal reservoir characteristics, and accurate prediction of coal reservoir conditions need to precede coalbed methane exploitation.

The amount of gas accumulated in a coal seam will be a function of gas generation during the maturation process. Recovery of the gas will be a function of water saturation, cleat permeability, gas desorption characteristics, reservoir pressure, and diffusion rates.
A New Algorithm for Automatic History Matching Production Data
Authors: Watson A. T. , Lee W. J.
Published: December 2007

We present a new algorithm for automatically history matching production or well test data. The algorithm is designed to be robust and efficient for history matching problems which have moderate to small numbers of unknown parameters.

The algorithm is based on Marquardt's modification of the Gauss-Newton method for minimization of least-squares functions. The implementation of the algorithm differs significantly from that of Marquardt. The performance of the algorithm is evaluated by history matching actual production data using an analytical dual-porosity model. Its performance is compared to the Gauss-Newton and steepest descent algorithms. We have found that our algorithm is very effective for these problems, but that Gauss-Newton and steepest descent are not suitable.
The Use of Pseudotime: Wellbore Storage and the Middle Time Region
Authors: Spivey J. P. , Lee W. J.
Published: December 2007

The gas flow equation is often linearized to allow liquid type curves to be used to analyze transient tests of gas wells. In the absence of wellbore storage, drawdown tests are best analyzed using the pseudopies-sure-time linearization. Buildup tests, however, require the pseudopres-sure-pseudotime linearization for best results. If wellbore storage is present, both time and pseudotime should be used in a combination analysis for drawdown.
An Approach for Determining the Drainage Boundary of the Gas Wells Producing From Low-Permeability Gas Reservoirs
Authors: Shariff A. J.
Published: December 2007

The Pictured Cliffs Sandstone is a large, low permeability, gas producing reservoir. It is considered to belong to a class of reservoirs known as volumetric or bounded cylindrical reservoirs where the wells are surrounded by impermeable (or semi-permeable) boundaries.

In the Pictured Cliffs reservoir, the advancement of the drainage radius is shown to reach its maximum limit at the end of the transient period of the pressure decline versus time curve.
The Development, Testing, and Application of a Comprehensive Coal Seam Degasification Model
Authors: Sung W. , Ertekin T. , Schwerer F. C.
Published: December 2007

A series of mathematical and numerical models to simulate the simultaneous flow of methane and water in a coal seam are presented. Transportation of methane is described using multi-mechanistic flow concept whereas desorption of methane from coal grain surfaces is formulated by a quasi-steady state kinetic model.

The simulator employs a two-dimensional, rectangular coordinate, point-distributed grid system and has options to accommodate a number of hydraulically fractured or unstimulated wells. In order to describe the flow in hydraulic fractures, a secondary one-dimensional grid is superimposed over the primary grid system. Flow equations in the matrix and finiteconductivity fracture have been solved simultaneously. The coupling between fracture and matrix flow equations is established via a "fluid loss" term.

The model is also capable of handling a number of horizontal boreholes. Multiple boreholes can originate from the bottom of a common shaft or from different shafts and they are allowed to intersect each other. Furthermore, options exist to include a number of impermeable geological barriers within the system.

An assortment of boundary conditions can be imposed on the system at its external boundaries as well as at its internal boundaries. Along these lines a special algorithm is devised and implemented successfully in order to be able to specify methane drainage rate from a virgin coal seam which has macropores that are originally 100% saturated with formation water.

The simulator has been tested under stringent conditions and found to be stable. Finally, the validity of the developed model has been verified against some existing field data.
Production Characterization of Tight Lenticular Gas Sands in the Rulison Area of Western Colorado
Authors: Mercer J. C. , Frohne K.-H.
Published: December 2007

The U.S. Department of Energy's (DOE) Morgantown Energy Technology Center has performed an extensive reservoir simulation study on gas production from tight gas sands in the Rulison Field area of the Piceance Basin in western Colorado. Production behavior was modeled for the low permeability gas sands of both the Wasatch Formation and the lenticular portion of the Mesaverde Group. The study forecasted total gas production for Township 6S, Range 94W for 25 years, based on current well spacing regulations (160 acres [6.5 x 105m2] for Wasatch wells, 320 acres [1.3 x 106m2] for Mesaverde wells). The study also predicted the effects on gas recovery of reducing the well spacing to 80 acres (3.2 x 105m2) and 160 acres (6.5 x 105m2) for the Wasatch and Mesaverde, respectively. The reservoir study utilized a dual porosity, single-phase gas simulator to characterize reservoir behavior by history matching actual production performance from 23 Wasatch and 12 Mesaverde wells in the Rulison Field.

The study followed two extensive DOE field testing programs, a multiwell experiment and a special Mesaverde test well drilled in Naval Oil Shale Reserve No. 3. These DOE field tests provided geologic information and values for reservoir parameters that control production from this unconventional gas resource. In addition to the results from the two field experiments, the study used a detailed geologic analysis to help characterize the producing formations.
Add Reserves in Existing Shallow Wells by Deepening With Slimhole Drilling Operations
Authors: Hoffman C. M. , Lawrence P. W.
Published: December 2007

Since the mid nineteenth century, over 500,000 wells have been drilled in the Appalachian Basin. While many of these wells have been plugged and abandoned, approximately 185,000 wells are still active producers. A majority of these active wells were drilled during the last ten years at depths averaging approximately 3,200 ft [975.4 m]. The recent decrease in oil and gas prices has made it increasingly difficult for producers to Justify new shallow drilling programs. There are, however, deeper productive horizons in many existing wells that have remained untapped. A number of unique procedures have been developed which allows the deepening, economically, of existing wells through existing casing as small as 4-1/2 in [114 mm].
Hydraulic Fracture Stimulation and Openhole Testing of a Deeply Buried Coal Seam in the Piceance Basin, Colorado
Authors: Logan T. L. , Seccombe J. C. , Jones A. H.
Published: December 2007

Deeply buried coal seams (greater than 3000 ft [914 m]) are difficult and sometimes hazardous to test and complete due to coal sloughing, formation pressure anomalies and coal fine generation. Data collected during testing and stimulating two deep coalbed methane wells located at the Gas Research Institute/Resource Enterprises, Inc. "Deep Coal Seam Project" test site in the Piceance Basin, Colorado, is presented in this paper. A single thick coal seam was completed openhole in each well: Core data, reservoir data, in-situ stress measurements, and pre-stimulation calibration test data were collected at the site to use in the design of the fracture stimulation treatments for both wells. A nitrogen foam fracture fluid treatment was selected for the first well and a linear gelled water for the second well. Treatment pressures were monitored with a downhole quartz pressure transducer. Atypically high treating pressures were observed possibly indicating coal fines plugging at the fracture tip or increase in fluid viscosity caused by interaction of the generated coal fines with the fracture fluid. In addition, a comprehensive fracture diagnostic effort was employed during the fracturing of the second well; namely, triaxial borehole seismic, seismic televiewer, hydraulic impedance monitoring, gamma ray log (in conjunction with radioactive additives in the sand), and temperature log. The results indicate a vertical fracture was created parallel to the face cleat as expected.
Tailored-Pulse Fracturing in Cased and Perforated Boreholes
Authors: Cuderman J. F.
Published: December 2007

A propellant-based technology, High Energy Gas Fracturing (HEGF), has been applied to fracturing through perforations in cased boreholes. The use of propellants that deflagrate or burn, rather than high-order explosives that detonate, permits controlled buildup of pressure in the wellbore. The key to successful stimulation in cased and perforated wellbores is to control the pressure buildup of the combustion gases to maximize fracturing obtained, without destroying the casing. Eight experiments have been conducted in a tunnel complex at the Department of Energy's Nevada Test Site. This location provided a realistic in situ stress environment (7 MPa [1000 psi] overburden stress) and access for mineback to directly observe fracturing obtained. Primary variables in the experiments include propellant burn rate and amount of propellant used; presence or absence of liquid in the wellbore; in situ stress orientation; and perforation diameter, density, and phasing. Fracture surfaces propagate outward along lines of perforations, then gradually turn toward the hydraulicfracture direction. Fracture lengths of 3m (10 ft) or more are observed. It is shown that such fractures, with proper choice of propellant and perforation design, can be created with no attendant casing damage.
Measurement of Coalbed Properties for Hydraulic Fracture Design and Methane Production
Authors: Boyer C. M. , Stubbs P. B. , Schwerer F. C.
Published: December 2007

A single-zone coalbed methane well was installed in the Mary Lee Coal Group in the Warrior Basin, Alabama for research purposes. Laboratory and field tests were conducted to establish criteria for containment of an induced hydraulic fracture. Following production from the well, a wing of the induced fracture was mined-out and observed directly.
Coalbed Methane Geostatistical Analysis: A Method for Ranking Well Productivity
Authors: Pratt H. R. , Robey E. H. , Wojewodka R. A. , Mercer J. C.
Published: December 2007

A study was conducted which demonstrated the use of geostatistical techniques for identifying correlations between geologic parameters and gas production for 38 coalbed methane wells completed in the Blue Creek coal seam of the Oak Grove (U.S. Steel) field in Alabama. Data used in the study consisted of production information for these wells along with geologic information for the area of interest. Results indicated that four geologic parameters showed statistical correlations with gas production: the well elevation (a proxy variable for permeabilty), the number of lineament intersections within 250 feet (76 meters), the thickness of the Blue Creek coal seam, and the length of the nearest lineament. The study suggested that the results obtained for wells in the primary degasi-fication grid could be extrapolated to wells in an adjacent area having lineament orientations similar to the primary grid. A method by which each well could be characterized based upon its production profile (i.e., production versus time relationships) rather than a simple one-number summary, such as 4-year cumulative production, was also identified.
Propagation of Hydraulically and Dynamically Induced Fractures in Naturally Fractured Reservoirs
Authors: Blanton T. L.
Published: December 2007

The purpose of this project has been to provide a basis for selecting fracturing treatments that will cross and connect as much of the natural fracture system to the wellbore as possible. Interactions between induced and existing fractures have been examined in scaled laboratory experiments under different angles of approach and states of stress. For hydraulic fractures, when the angle of approach was 30 degrees, existing fractures tended to open, diverting fracturing fluid and preventing the induced fracture from crossing. At angles of approach of 60 and 90 degrees, hydraulic fractures tended to cross existing fractures when the differential stress was high enough. Dynamic fracturing tests were run for conditions where hydraulic fractures opened existing fractures to determine if more constructive crossing interaction could be obtained, but triaxial stresses tended to suppress cross-cutting dynamic fractures, and no crossing behavior was observed. An elastic solution for the stresses in the interaction zone has been used as a basis for a hydraulic/natural fracture interaction criterion. The criterion compares favorably with the experimental results. It has been used to delineate areas where crossing and opening interactions could be expected in Devonian shales of the Appalachian Basin by combining it with existing data on the state of stress and fracture patterns. Under preliminary assumptions, the criterion predicts opening of natural fractures in the central and western parts of the basin. In the northern and southern parts of the basin, there are zones where crossing interaction can be expected. Tectonic models were used to extrapolate fracture patterns from site-specific core data gathered from 33 EGSP wells. Fracture systems oriented for crossing appear to be associated with two tectonic features: a Precambrian failed rift system that has been reactivated periodically and deformation associated with the Appalachian orogeny.
The Influence of Crack Velocity During Brittle Fracture
Authors: Krugman D. G.
Published: December 2007

This paper investigates the effects of different commercially available processes for fracturing consolidated rock structures by applying the concept of Brittle Fracture. Brittle Fracture occurs when there is little or no plastic deformation of the material before the material fails.

The available commercial fracturing processes are grouped into three categories, namely (1) Hydraulic fracturing treatment using pump trucks and fluids, (2) High Energy Gas Fracturing (HEGF) treatment utilizing propellent mixtures deflagrated in situ to generate a fast pressure surge of gases and (3) Explosive-based treatment that makes rubble of the rock in the wellbore vicinity.

The fracturing processes vary in the duration of the energy-loading process and the maximum pressures achieved during the event (See Fig. 1 and Ref. 1). Figure 1 illustrates the order of magnitude of difference in time and pressures of the different fracturing processes.

The "Mechanism of Brittle Fracture of Rock" (Ref. 2) as developed by Dr. Z. T. Bieniawski and widely accepted in the mining industry as a basis for understanding rock failure, is applied to oilfield wellbore and reservoir conditions to evaluate the fracture geometries and penetrations of the different fracturing processes. The concept of Brittle Fracture also is applied to the mine-back and pressure-time records of open-hole and cased-hole tests of the fracturing processes conducted by Sandia National Laboratories at the Nevada Test Site (Ref. 3, 4 and 5).

The effect on wellbore and reservoir stimulation is investigated by applying Darcy's modified radial and linear flow equations (Ref. 6) to reservoir flow conditions. By applying the most applicable fracturing process for the wellbore and reservoir condition, one can maximize the evaluation and stimulation efforts of a well completion attempt.

Radial flow enhancement is best achieved by fast fracturing processes such as High Energy Gas Fracturing and explosive-based treatments, while linear flow enhancement is best achieved by hydraulic fracturing treatments. Radial flow enhancement treatments may stimulate reservoir productivity by 1 to 3 times, while linear flow enhancement treatments may stimulate reservoir production by 6 to 10 times.
Gravel Pack Repair with Wireline Devices
Authors: Carroll J. F. , Neal M. R. , Parker W. B.
Published: December 2007

Gravel pack logs have been used previously to detect voids in gravel pack completions. These voids must be eliminated to achieve an optimum completion. Techniques using wireline repair devices are generally faster than conventional repair techniques, and formation damage resulting from fluid loss could therefore be reduced.

A study was made under laboratory conditions to develop wireline tools that could be used to eliminate these voids in order to save the rig time associated with conventional methods of repair. The tools, which were developed under laboratory conditions, were run in field completions. Field gravel pack logs have confirmed the success of wireline devices to repair gravel pack voids.
Replacement Costs of Domestic Oil and Gas Reserves
Authors: Kuuskraa V. A. , Godec M. L. , Morra F.
Published: December 2007

The costs of adding new reserves of oil and gas have changed dramatically over the past several years. Changes in the costs of drilling, the prices for oil and gas, and the sources for new oil and gas supplies have combined to fundamentally alter the economics of replacing reserves. This paper provides a historical perspective on these changes, a review of the current situation, and a look into the future on this key area of concern to the petroleum industry.
Theoretical Study of Coning Toward Horizontal and Vertical Wells in Anisotropic Formations: Subcritical and Critical Rates
Authors: Chaperon I.
Published: December 2007

Stable cones created by a horizontal well drilled with maximum clearance from the unwanted fluid are studied (Muskat9 type approach, using pertinent viscous flow potential), yielding practical values for the critical rate per unit length of a horizontal well, and for the critical cone elevation, depending on both vertical and horizontal permeabilities, oil thickness, both fluid gravities, and oil viscosity. Critical rate weakly decreases when vertical permeability decreases.

The same type of analysis is repeated for a vertical well completed over a very short interval (modelized as a point source) also with maximum clearance from the gas cap or water table, yielding values of critical rate and cone height for the vertical well. In this case the critical rate slightly increases when vertical permeability decreases.

The outcome of a comparison between both types of wells shows that a critical cone comes closer to the horizontal well than to the vertical well. Also horizontal wells generally allow higher critical rates than vertical wells, however this advantage lessens with increased anisotropy. Very simple formulas are provided to evaluate what gain in critical rate may be obtained from a horizontal well.
The Determination of Optimum Completion and Production Conditions for Sand-Free Oil Production
Authors: Peden J. M. , Yassin A. A. M.
Published: December 2007

It is important for the selection of optimum completion conditions and the evaluation of optimum production conditions to understand the factors contributing to and controlling sand production. Many factors such as the geometry of the perforation, the inherent formation strength and the effective-stress distribution in the vicinity of the perforation tunnel during production must be considered to determine the maximum sand free rate possible from a given well.

A prediction model has been developed to predict sand stability in friable formations from stress analyses around a perforation tunnel. Failure or instability of the perforation tunnel was studied in terms of the conditions for failure initiation.

The application of the model allows evaluation of the optimum completion characteristics of shot density and pattern, tunnel length and diameter, and production conditions, to achieve a maximum sand free production rate. The concept of a ‘stability ratio’ is introduced to predict the degree of instability which can be anticipated under specific production conditions.
Application of Multilayer Testing and Analysis: A Field Case
Authors: Kuchuk F. J. , Shah P. C. , Ayestaran L. , Nicholson B.
Published: December 2007

Recently developed well testing and analysis techniques for multilayered reservoirs to estimate individual-layer permeabilities, skin factors, and pressure are discussed with regard to their applications to a two-layered reservoir. The multilayer testing technique consists of a number of sequential flow tests with downhole flow rate and pressure measurements at the top of each layer using the production logging tool.

The analysis techniques are based on convolution and the use of nonlinear regression to fit the measured downhole flow rate or pressure data with a layered reservoir model.

This paper presents a field example that is used to estimate layer parameters. The results are compared to those from conventional analyses.
The Effect of Oil on Foam Stability: Mechanisms and Implications for Oil Displacement by Foam in Porous Media
Authors: Nikolov A. D. , Wasan D. T. , Huang D. W. , Edwards D. A.
Published: December 2007

Foam stability in the presence of Salem crude oil and pure hydrocarbons is investigated as a function of chain length of α-olefin sulfonates and electrolyte concentration. Interactions between aqueous foam films and emulsified oil droplets are observed using transmitted light, incident light interferometric and differential interferometric microscopic techniques. Foam destabilization factors are identified including the pseudoemulsion film tension and the surface and interfacial tension gradients. Results from foam-enhanced oil recovery experiments in Berea Sandstone cores are presented using the combined gamma ray/microwave absorption technique to measure dynamic fluid saturation profiles.
CO2 Foam Flooding Performance vs. Rock Wettability
Authors: Lescure B. M. , Claridge E. L.
Published: December 2007

CO2 flooding projects have shown large potential for oil recovery but in many cases the volumetric sweep efficiency is greatly limited by gravity tonguing and/or viscous fingering. To reduce these effects foam could be used as an alternative to WAG CO2 injection.

Experiments on the CO2 foam process were conducted in a 1/4 5-spot reservoir model in order to investigate the effect of rock wetting state and total CO2 slug size on secondary and tertiary extra-oil recovery.

Laboratory model results show that the process is more successful in an oil-wet medium than in a water-wet medium due to larger surfactant adsorption in the water-wet medium. Also, requirements for optimal CO2 slug size are smaller than in the WAG process, with larger extra oil recovery for both secondary and tertiary floods.