bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Storage in the Midwest - 1966 Review
Authors: Nelson Carl G.
Published: December 2007

1966 Eastern Regional Meeting, Nov. 10–11, 1966, Columbus, Ohio

I -Introduction

In the spring or 1964 I reported on the status or "GAS STORAGE IN THE MIDWEST" at an A.P.I. meeting in Evansville, Indiana. Your program chairman asked me to review this paper for you and to bring it up to date. My talk today will compare storage volumes, operations, and fields in 1966 vs 1962 in the rive state area or Indiana, Illinois, Iowa, Kentucky, and Missouri; it will discuss the economics of gas storage; it will discuss differences between depleted gas field storage and aquifer type storage.

II - STATUS OF STORAGE IN THE MIDWEST

In my last talk on this subject, the data gathered showed that the five (5) state area covered had experienced a steady growth in the volume or gas in storage and the number of storage fields during the rive (5) year period 1958–1962. Review or this matter shows that this upward trend is still present. Slide 1, shows the gas storage volumes for the various states - 1958–1965. These figures were obtained from yearly reports prepared by the Committee on UNDERGROUND STORAGE or the AMERICAN GAS ASSOCIATION. The state with the most gas in storage is Illinois with 175.3 billion cubic feet in storage. This incidentally is something less than one half or the total storage volume or Ohio, which had 428 billion in storage in 1965. It is interesting to note that Kentucky, which had a leveling off or stored gas in 1961–63, has again started increasing its storage gas volume. Talking with various operators in this area reveals that their increase in storage volume is connected with the conversion or recently round gas fields in Kentucky to storage fields.

P. 1^
The Use of Alcohol in Gas Well Stimulation
Authors: McLeod H.O. , Coulter A.W.
Published: December 2007

Alcohol when added to stimulation fluids will reduce or eliminate waterblocking following these treatments. Although waterblocking can occur in clean, well consolidated sandstone, it is more likely to occur with other forms of damage such as particle blocks or rock wettability changes. Waterblocking is most severe in heterogeneous formations particularly where high permeability variations are in series such as in crossbedded sediments. Alcohol has been successfully used in waterblock removal, matrix acidizing, and hydraulic fracturing. Properties of alcoholic fluids and detection of heterogeneity are discussed. Guidelines for selecting the best alcoholic treatment are presented.

INTRODUCTION

Aqueous stimulation fluids containing alcohol have proven to be highly successful in stimulating gas production from problem wells in sandstone formations. The primary advantage of alcohol is to obtain better and more rapid clean up. It is most useful in gas producing formations, particularly those with a high clay content.

Many stimulation treatments in sandstone which would otherwise be quite successful are spoiled by a very slow water clean-up. This clean-up problem is often a result of water block in the critical matrix surrounding the wellbore. In a gas well, about one-half the total pressure drop in the formation takes place within 15 ft surrounding the wellbore. The addition of alcohol to the aqueous fluid can often prevent this water blocking problem.
Correlation of Oilwell Cement Performance with Cement Characteristics
Authors: Polkowski G.
Published: December 2007

Oil well cements meeting American Petroleum Institute (API) specifications can have considerable differences in performance characteristics when blended with common cement additives. Reasons for such variations can be explained by observations made by reflected light microscopy, X-ray diffraction, energy dispersive X-ray spectrometry, and particle size analysis. Six cements meeting API specifications were studied.
New Technology in Gas Migration Control
Authors: Sykes R. L. , Logan J. L.
Published: December 2007

Recent research investigating causes and control of annular gas flow has resulted in new concepts pertaining to gas migration. Previous investigations have identified that the combined effects of fluid loss volume reductions and static gel strength development control the actual pressure loss – and ultimately gas flow – in a cement column. The recently developed concept describes delayed development of cement gel strength as a means of preventing gas flow. Delaying gel strength development allows the cement column to transmit essentially full hydrostatic pressure, and thus prevent gas entry into the cement column, for an extended time period. Test results are presented showing that fluid loss rate decreases with time so that most volume losses due to fluid loss occur during the delayed gel strength period. Thus, stringent slurry fluid loss requirements for probable gas flow situations may be relaxed.

The conclusion of the delayed gel strength phase is followed by rapid progression to the set state thus helping prevent gas entry into a cement column. Another feature of delayed gel strength development, shutdown safety factor, is also presented. Pumping of delayed gel strength cements can be restarted without excessive horsepower or pressure requirements in the event of a shutdown during placement.

Subject paper presents laboratory test results and field case histories documenting use of delayed gel strength cement for prevention of gas migration.
Self-Excited Vibrations in Drillstrings
Authors: Zamudio C. A. , Tlusty J. L. , Dareing D. W.
Published: December 2007

Vibrations created by drag bits can cause premature failure of drillstring components and fracture cutters. Unfortunately, there has been no theory that adequately explains how drag bits excite drillstrings. Our paper shows that these vibrations are self excited by the interaction of drillstring, bit, and formation. Results show that drag bit design and bit rotational speed dictate conditions of dynamic instability. In general, large drag bits are unstable at low rotational speeds.
New Flowmeters for Kick and Loss Detection During Drilling
Authors: Orban J. J. , Zanner K. J. , Orban A. E.
Published: December 2007

Well kicks and fluid losses during drilling are potentially dangerous. Early detection would result in a significant increase in drilling operation safety. Reliable measurements would allow the use of lower mud weights, resulting in faster drilling, less formation damage, and lower drilling costs.

This paper describes a newly developed flowmetering system built to detect any difference between flow-in and flow-out of the well greater than 25 Gpm (1.5 L/s) This is a significant improvement over existing wellsite measurements.

The flowmeters operate in both water and oil based muds, over the commercial range of mud weight and viscosity. The flow-in sensor is installed at the discharge of the triplex pump. The flow-out sensor is installed in the return line, just like the familiar paddle, with minimal modification of the rig equipment. Unlike the electromagnetic meter this flow-out sensor does not increase the risk of blockage by cuttings, because the mud flow path is neither modified nor restricted.

Extensive testing has been performed on these systems. Several lab results are discussed, and results of full scale calibration with a wide range of mud properties are presented. Finally, field tests have confirmed the ability of the system to respond quickly and accurately to gain or loss during actual drilling operations.
A Case History of Underwater Wild Well Capping: Successful Implementation of New Technology on the SLB-5-4X Blowout in Lake Maracaibo, Venezuela
Authors: Adams N. J. , Hansen A. , Stone A. D. , Voisin J. A. , Quiroz G. A. , Clements S.
Published: December 2007

This paper describes the new technology used to kill an underwater, deep, high-pressure blowout.

A new method of offset subsea capping extinguished a fire and killed a blowout in 95 ft of water. Success of the methods for subsea well capping proved that safe and cost-effective work is possible adjacent to a burning blowout. This project proved concepts in underwater work, firefighting, and snubbing. A unique general-contractor approach enhanced communication and efficiency.
Relief Well Planning and Drilling for SLB-5-4X Blowout, Lake Maracaibo, Venezuela
Authors: Voisin J. A. , Quiroz G. A. , Pounds R. , Wright J. , Bierman K.
Published: December 2007

This case history describes relief well planning and execution for a deep, high volume, underwater blowout in Lake Maracaibo, Venezuela. Key achievements include designing a deep, large diameter relief well, locating and tracking the target casing using an active AC current injection magnetic ranging technique, and establishing survey procedures and tight quality assurance which generated an accurate wellbore position ellipse of uncertainty. The relief well team, consisting of Lagoven, Eastman Christensen, and Shell, had placed its well within 25 ft of the blowout by the time simultaneous well capping succeeded in stopping the blowout.
A Three-Axis Laser Gyro System for Borehole Wireline Surveying
Authors: Gibbons F. L. , Hense U.
Published: December 2007

A 5 inch diameter high accuracy borehole surveying instrument has been developed using a full 3 axis inertial navigation system (INS).

It has the following features: 3 Ring Laser GyrosNo mechanical gimbalsReal-time surface readoutObtains position data directly without the need for intermediate depths stops.Requires no stopping for drift checksUses wireline velocities up to 600 ft/minReduces INS's typical drift error to less than 6 ft/hr.

This tool achieves a survey accuracy that is close to that of the 10" INS tool, while at the same time offering a smaller diameter and continuous survey capability.
A Method To Analyze Directional Surveying Accuracy
Authors: Holmes A.
Published: December 2007

Borehole surveying uncertainty owing to tool inaccuracies, is a function not only of the instrument errors themselves, hut also of factors such as well geometry, well location and the accuracy to which the magnetic field strength and dip angle are known or can be calculated.

A program has been developed to investigate surveying instrument accuracy which takes all of these parameters into account. It models errors in the raw tool data, and generates distances, areas and volumes of uncertainty for varying probabilities. The program is capable of calculating probability circles and spheres in addition to the more usual ellipses and ellipsoids of uncertainty for any borehole trajectory.

The validity of the technique has been checked by comparisons of program results with actual field surveys. The surveys were obtained using a state of the art electronic multishot system run in conjunction with high accuracy gyro benchmark surveys. These are used to demonstrate the accuracy and reliability of the program.
Interaction of Water With Organophilic Clay in Base Oils To Build Viscosity
Authors: Schmidt D. D. , Roos A. F. , Cline J. T.
Published: December 2007

Rheological measurements together with microscopy observations were used to provide an understanding of the mechanisms of viscosity changes in oil muds. The rheological behavior of mixtures of base oils, organophilic clays, and water (or brine) were studied as a function of oil type, water concentration, organophilic clay concentration and type, shear history, addition of polar activators (such as xylene), addition of calcium chloride and addition of emulsifiers. Examination of these mixtures under an optical microscope showed that there is a relationship between rheological behavior and microscopically visible interactions between organophilic clay and the dispersed aqueous phase. These interactions build structure in the oil that gives thixotropic properties. Dispersion of the organophilic clay, necessary for efficiency in thixotropy building, is affected strongly by the shear history and by the compositions of the base oils, organophilic clays, emulsifiers, and aqueous phase.
The Relationship Between Immiscible and Miscible Displacement and Applications
Authors: Yortsos Y. C.
Published: December 2007

In this paper the relationship between two-phase, immiscible displacement and miscible displacement including equilibrium adsorption in porous media is investigated. It is shown that the two processes are mathematically equivalent in any flow dimensions, provided that gravity and compressibility effects are ignored. This extends the analogy between the two processes that is known to exist in 1-D flows and in the absence of dissipative terms (theory of coherence1, fractional flow theory2) to higher dimensions and in the presence of dispersion and capillarity.

Motivated by the above equivalence certain applications are discussed. First, it is shown that two exactly solvable 1-D models pertaining to two-phase, capillary displacement and single-phase adsorption-convection-dispersion processes follow this equivalence. Then, the linear stability of two-phase, immiscible displacement is shown to be identical to that of miscible displacement in the presence of adsorption. Long-wave asymptotics are developed for the latter and they are used to infer the effects of mobility contrast and transition zone width on the linear stability of miscible flows. Finally, certain implications regarding the effects of flow stratification and the connection of immiscible displacement to reactive and non-equilibrium systems are discussed.
Numerical Simulation of Foam Flow in Porous Media
Authors: Marfoe C. H. , Kazemi H. , Ramirez W. F.
Published: December 2007

The use of foam as a mobility control agent has received increasing attention over the past few years. While many laboratory studies have been done to understand foam rheology in porous media, relatively few efforts have been made towards the mathematical simulation of foam flow. The mathematical formulation presented here provides a simple way of representing foam behavior in porous media which is easily applied to large scale simulators while still providing a realistic simulation of foam behavior.
Chemical Gels for Diverting CO2: Baseline Experiments
Authors: Martin F. D. , Kovarik F. S.
Published: December 2007

Large-scale reservoir heterogeneities, such as fractures, channels, or high-permeability streaks, can cause early breakthrough of injected CO2 which will reduce oil recovery efficiency. This paper describes the first part of a multiple-part study on the effect of some commercial gelants on the reduction in CO2 permeability. A methodology is presented of testing gelants in vial tests, core tests, and with two-dimensional flow visualization studies in high-pressure micromodels. Test conditions were selected to match some west Texas/southeast New Mexico reservoirs: 1500 psi and 105°F (CO2 MMP ≈ 1200 psi). The gelants used included some commercially available crosslinked polymer systems.

In the core tests, gel stability and polymer-gel interactions were assessed by monitoring the permeability of repeated water/CO2 WAG cycles. The high-pressure micromodel studies were valuable in assessing the mechanisms responsible for permeability reduction at the pore level.
Estimating Field-Scale Micellar/Polymer Performance
Authors: Giordano R. M.
Published: December 2007

A study has been completed on the effects of pattern type, micellar slug size, heterogeneity, and process timing on micellar/polymer flooding. In designing a field-scale enhanced recovery process, one generally knows the laboratory-scale performance of the process, the area of reservoir to be developed, its physical properties, and the number of wells that can be afforded. With these "givens", a simple model has been developed for determining the optimum pattern type and optimum micellar slug size as a function of the "field-scale capillary number", the Dykstra-Parsons coefficient, and the discount rate.

Results show that, on an equal-area-per-well basis, five-spot and staggered line drive patterns are favored over seven- and nine-spot configurations. The optimum slug size for a homogeneous five-spot was found to be the amount required to satisfy about 90% of the surfactant adsorption requirement of the reservoir. The optimum slug size decreased with increasing heterogeneity. Oil recovery in low-permeability fields or those in which the well-spacing is large can be significantly enhanced by utilizing a surfactant whose interfacial tension against oil is less than 10−3 dynes/cm.
Stochastic Modeling of Underground Reservoir Fades (SMURF)
Authors: Haldorsen H. H. , MacDonald C. J.
Published: December 2007

This paper presents algorithms for generating idealized large-scale reservoir architecture representations. Discontinuous sands suspended in mud are discussed first. The accessible and floodable fractions of total pay are evaluated in 2-D and 3-D for specified conditions (well spacing, [N/G]-ratio,..). Next, a hybrid approach to the modelling of discontinuous permeability barriers such as shales is presented. Finally, stochastic modelling of faults, aquifers, and fractures is discussed. The authors conclude that a need exists for devicing approximate, yet realistic, computer-based methods for generating idealized reservoir representations for subsequent evaluation of the chance of success of proposed development schemes. Unless the reservoir architecture and hence the reservoir plumbing system is described in a quantitative (geometrical) manner, forecasting tools cannot be expected to yield realistic recovery factor estimates. The stochastic approach must always be guided by a geological/sedimentological model, as well as core, log, test, production, outcrop and seismic data.
Conditional Simulation of the Geometry of Fluvio-Deltaic Reservoirs
Authors: Matheron G. , Beucher H. , de Fouquet C. , Galli A. , Guerillot D. , Ravenne C.
Published: December 2007

Quantitative methods taking into account the sedimentological characteristics will answer the needs of reservoir engineers. We propose here a geostatistical method for the conditional modelling of the facies of a sedimentary fluvio-deltaic series. This model was elaborated jointly by I.F.P. and the Paris School of Mines, with the aim of modelling reservoir heterogeneities. From the sedimentological study contained in the paper by C. Ravenne et al., we present several simulations, conditioned by "drill-core" taken from the outcrop. The block permeabilities are then calculated from the values given to the facies.
Analyzing Well Test Data from Linear Reservoirs by Conventional Methods
Authors: Larsen L. , Hovdan M.
Published: December 2007

Straightforward methods of analyzing linear-flow data on √t plots are presented. The methods are similar to the conventional semilog methods being used to analyze radial-flow data, with some modifications included to increase the amount of information that can be extracted from √t plots. The modifications are based on the use of pressure derivatives and on equations deduced from this approach to √t analysis. A combination of semilog and √t analyses is, however, undoubtedly best suited to determine flow capacity, skin, reservoir width, and well location.

Methods of determining the initial pressure from extrapolated buildup data are also presented in the paper, along with methods for determining the distance to an intersecting no-flow boundary, and for determining the radius of investigation and length of uniform properties along the linear reservoir. These parameters cannot readily be obtained from conventional semilog methods.

The methods apply to single- and multiple-rate flow and shut-in data. This is accomplished by introducing an equivalent drawdown time based on √t expressions. The relationship to Agarwal's logarithmic form of an equivalent drawdown time is direct.

Applications to field data are included in order to illustrate the simplicity and power of the methods.
The Effect of Formation Absorption on the Thermal Neutron Porosity Measurement
Authors: Ellis D. V. , Flaum C. , Galford J. E. , Scott H. D.
Published: December 2007

Compensated thermal neutron porosity devices provide reliable estimates of formation porosity in standard borehole conditions. Departure from these conditions perturb the measurement and it is necessary to apply corrections to determine the true porosity. One common perturbation is due to the salinity of the formation water.

As the salinity of the formation water increases, its hydrogen density (or index) decreases. By itself, this would cause the apparent porosity reading to decrease, reflecting a lower hydrogen content. The additional chlorine, however, causes an increase in the thermal neutron capture cross section (Σ) that depresses the thermal neutron flux in the formation. This, in turn, tends to increase the apparent porosity. Empirical correction charts have been established for these two competing trends. They are sufficient for correcting porosity readings for salinity effects. However, the presence of additional thermal neutron absorbers associated with either the rock matrix or the pore fluid can result in a residual error on the porosity estimate even after salinity correction. This arises because the correlation between Σ and porosity, used to derive the salinity correction, is no longer valid.

An analysis of the response of a compensated thermal neutron device has been made in terms of the slowing-down length, and diffusion length. It provides a simple method of describing salinity, absorption and lithological effects, and results in a predictive model of the tool response that separates neutron absorption effects from changes in hydrogen index. The model is shown to conform to established salinity corrections as well as to measurements made in laboratory formations with large values of Σ. It provides a means of correcting apparent neutron porosity values for variations in formation Σ not associated with salinity.
Quantitative Flood Monitoring Utilizing a New Pulsed Neutron Tool Modeling Concept
Authors: Smith M. P. , Wyatt D. F.
Published: December 2007

A new flood monitoring technique is presented that models both the capture cross section (sigma) and ratio/porosity responses of a pulsed neutron logging tool using known reservoir, hydrocarbon and flood agent properties. Open hole logs and pulsed neutron logs acquired before, during and after flooding are combined to determine individual hydrocarbon, saltwater and flood agent saturations. This new model uses total neutron migration length and direct ratio computations1 to compute the flood agent volume fraction. Improved accuracy of the computed fluid saturations and the ability to handle specific flood agents are two enhancements to flood monitoring provided by this new approach. Accuracy is especially important because often the results from a limited number of monitor wells are used to project the sweep efficiency and economics of the flood process for an entire reservoir.

This new method is applied to a CO2 flood and the resulting fluid saturations for oil, saltwater and CO2 are analyzed and discussed. These results are compared with those based on the older excavation effect method.2,3,4
A New Flowmeter for Production Logging and Well Testing
Authors: Piers G. E. , Perkins J. , Escott D.
Published: December 2007

There are two primary reasons to utilize a flowmeter. One reason is to measure total flow rate at different depths in a well. Total flow is then used for a single phase flow profile or used in conjunction with other sensors to produce a multiphase flow profile. Measurement of transient rate in conjunction with pressure transient testing is another use of the flowmeter. The analysis of these transients then yields reservoir parameters such as permeability, skin, and reservoir pressure. In either case, flow rates must be accurately measured or gross errors in the final interpretation will result.

Multiphase flow, especially in deviated wells, often results in an unpredictable flowmeter response. Most wells are multiphase downhole with a high percent of water present even though little or no water is being produced at the surface. This downhole condition makes it difficult to derive an accurate flow rate from a measured spinner speed. Petal basket flowmeters attempt to force fluids into a flow regime that can be measured but fail because all of the flow is not diverted through the metering section.

A new flowmeter is described that has a linear, predictable response in single and multiphase flow and results in a much better measurement of downhole flow rates. Flow loop data are presented, comparisons are made of the new flowmeter response with other flowmeter responses and the results of field tests are discussed.
Design, Execution, and Analysis of a Stimulation to Produce Gas from Thin Multiple Coal Seams
Authors: Hanson M. E. , Nielsen P. E. , Sorrells G. G. , Boyer C. M. , Schraufnagel R. A.
Published: December 2007

A single hydraulic fracture stimulation was designed to contact several thin coal seams in a broad vertical interval overlying a narrow open hole section. The design was based on a large water prepad to create the required height growth. Analyses of extensive fracture diagnostics confirm that significant height growth occurred through the interval.
Evaluation of Initial Reservoir Data to Estimate Devonian Shale Gas Reserves
Authors: Vanorsdale C. R. , Boring P. A.
Published: December 2007

This study analyzes the Devonian shale gas reservoirs of the Appalachian Basin and the applicability of using initial test data to assign reserves in this reservoir system. Data has been collected on over 500 such wells and recovery has been related to initial test data to assess the reliability of reserve estimation. This study concludes that there is no true linear relationship between recovery and initial test data.
Oil Production from the Troll Field: A Comparison of Horizontal and Vertical Wells
Authors: Kossack C. A. , Kleppe J. , Aasen T.
Published: December 2007

Oil production from thin oil columns in deep water environments, such as one finds in the Troll Field in the North Sea, presents difficult coning problems at economical production rates. A pattern of oil production wells must effectively drain a designated area at a high oil production rate. If too few vertical wells are drilled, the wells will be shut in due to high gas-oil ratio before the oil recovery is satisfactory. If two many wells are drilled they interfere with each other and may cone gas even earlier. The drilling of horizontal wells has been proposed as a possible solution to this problem.

This paper investigates numerically the performance of various patterns of vertical wells and compares the results with the performance of a pattern of horizontal wells. The effect of the length of the horizontal wells, their location relative to the fluid contacts, the change in performance with production rate, and the effect of an oil saturation in the rock below the water-oil contact are all investigated. The most significant results found were that a 1500 foot horizontal well would produce the same amount of oil as two vertical wells in a typical sector pattern when the sector is produced at a constant oil production rate, and a 2000 foot horizontal well would perform much better than three vertical wells. Also, specially designed production schedules were determined that would increase the life of the horizontal wells significantly, and yield oil recoveries of up to 30%.
Designing Gyp Scale Removal Treatments Based on Chemical Characteristics to Optimize Field Performance
Authors: Schutte R. W.
Published: December 2007

In recent years, gyp (calcium sulfate) scale removal techniques have become increasingly complex and the number of fluids and additives have continually grown. The purpose of this paper is to provide the field engineer with the fundamental understanding of the calcium sulfate removal procedures and the roles different fluids and additives play in this process so that a more cost effective treatment can be planned.

Cost effectiveness can be achieved by minimizing the number of treatment phases necessary to complete a chemical calcium sulfate scale removal treatment. Also, the success of the treatment can be enhanced by minimizing residual chemical compounds left in the formation.
Turbulent Flow of Stimulation Fluids: An Evaluation of Friction Loss Scale-Up Methods
Authors: Lord D. L.
Published: December 2007

Uncertainty exists in our industry over selection of the most appropriate means to satisfy the simplest of scale-up requirements. The requirement in question being conversion of isothermal pressure loss measurements made with "simple" fluids in smooth laboratory pipes to appropriate values for field-size tubing and casing. These fluids are classified as "simple" because they comprise the time-independent, homogeneous, linear polymer-in-water solutions that form the nucleus of most stimulation fluid formulations. It is only after determination of an appropriate scale-up method that our industry can make real progress toward solution of more difficult problems dealing with the effects of non-isothermal conditions, pipe roughness, non-homogeneity, and time and/or energy dependency. Addressing these more difficult problems will permit development of more reliable correlations to be used in making bottomhole treating pressure estimates for real-time analysis.

The current uncertainty associated with scale-up is fostered by availability of a wide variety of methods, each of which appears to be unique in its formulation. In this paper, we provide comparisons among various scale-up procedures in use and/or available to industry. These comparisons are made using laboratory data collected from turbulent flow experiments conducted in nominal 3/4 to 2-in. [1.905 to 5.08-cm] Schedule 40 pipe using 0.36 to 0.95 weight percent hydroxypropyl guar in water solution. Complicating this analysis is the fact that a non-trivial scale-up method does not exist, i.e., it is necessary to determine unique, method-dependent parameters for each fluid formulation using turbulent flow pressure loss measurements obtained with the fluid in question. Each scale-up procedure evaluated is shown to produce a diameter invariant correlation of the type necessary to facilitate scale-up. Using these various diameter invariant correlations (all developed from the same data base), conflicting predictions for large diameter friction loss are produced. At a fixed fluid velocity and with increasing pipe diameter, percent friction reduction below that of water was predicted by the various methods to either increase, decrease, or remain the same. The significance of these variations in terms of their impact on stimulation operations is discussed.
Gravel Pack Studies in a Full-Scale, High-Pressure Wellbore Model
Authors: Schroeder D. E.
Published: December 2007

The low perforation efficiency in many gravel pack completions suggests that current technology used in these completions could be improved. A full-scale, high-pressure visual wellbore model has been built to study the gravel packing process. This 100 ft long model is capable of operating at pressures up to 1,000 psi. It has 280 perforations over a 35 ft zone to accurately simulate a typical 500 md Gulf Coast well.

Excellent reproducibility has been obtained with the model. Model experiments show that the circulating/squeeze pack method performs better than the squeeze method, and that standard HEC carrier fluid is superior to crosslinked CMHEC. As reported by other investigators, highly deviated wells are more difficult to pack than vertical wells. End effects observed in this model show that conclusions drawn from shorter models could be highly erroneous.
An Investigation of Analytical and Numerical Sucker Rod Pumping Mathematical Models
Authors: Schafer D. J. , Jennings J. W.
Published: December 2007

This paper details a study made of the analytical (diagnostic) and numerical (predictive) models commonly used today in the analysis and design of sucker rod pumping systems. The results should help the user of this technology in selecting appropriate values for the several parameters used in applying the models.
Analysis of Flow of Gas and Water in a Fractured and Non-Fractured Low-Permeability Reservoir Under Production
Authors: Arastoopour H. , Chen S. T. , Hariri M. H.
Published: December 2007

We modified Black Oil Applied Simulation Tool (BOAST) Program for gas Reservoirs, and successfully applied it to simulate production of gas from fractured and non fractured low permeability reservoirs. Our modification results in significant decrease in computational time and storage requirements, and allows us to reduce the designated grid blocks to the size of the fractures. Thus the fractures were only distinguished from the matrix By their physical properties. Pressure and saturation of gas and water were calculated at different locations in the reservoir during the production. Our calculation shows that the coproduction of gas and water and presence of the induced fractures significantly enhance the economical production of gas from low permeability reservoirs.
Sweep Efficiency in Multilayered Porous Media: Contrast Between Stable and Unstable Flow
Authors: Soucemarianadin A. , Touboul E. , Bourlion M. , Nittmann J. , Lenormand R.
Published: December 2007

In this paper, we study fluid displacements in layered porous media and focus particularly on the effects of viscous instability and of capillarity. We first present several series of experiments of miscible and immiscible displacements in a three-layer cell with two different permeabilities. We cover a large range of viscosity ratios in the two cases of unstable and stable miscible displacements. The fluid boundaries are followed by visualizations and quantitative saturation data obtained by ultrasonic mapping. The second part of the paper is devoted to the description of a pore network simulator and a stochastic model which are suitable for describing viscous instability. Both models not only reproduce the experimental patterns very closely but are also in good quantitative agreement with experimental data for the ratio of the volumes of fluid injected in the two different layers.
Early Performance and Planning of One-Well Upstructure Drainage Projects in Solution-Gas-Drive Reservoirs at Mississippi Canyon 281
Authors: Lewis L. R.
Published: December 2007

This paper will review the early performance, model predictions, and planned expansion of one-well upstructure drainage projects for improved recovery in solution-gas-drive reservoirs in the Mississippi Canyon 281 Field. This is an innovative secondary recovery process in which significant incremental oil volumes are obtained from relatively small one-well reservoirs at low incremental costs.
Methodology Used in Estimating the Raman Reservoir Fracture System Data for Simulation
Authors: Sener I.
Published: December 2007

Reservoir modelling of a fractured reservoir with any dual porosity/permeability simulator requires three basic fracture properties – fracture porosity, permeability, and average fracture spacing – to be provided as part of the reservoir description. Theoretically, any two of these are sufficient to determine the remaining third. In many instances, however, direct measurements on these properties or good pressure test data are missing or unreliable, making it virtually impossible to infer the fracture properties.

In a recently completed study on the Raman reservoir in Turkey, the spatial variations of the fracture system properties were estimated using a method developed for this purpose. The technique utilizes reservoir structure and layer net thickness data, production information, and some qualitative geological input on the nature of the fractures. The generated fracture system description was later used in successfully history matching close to 40 years of reservoir performance with a fractured reservoir simulator.

This paper presents the principles involved and the methodology that was developed to estimate the required fracture description.

Fracture data before and after the history match are compared to show the extent of the modifications that were needed.

The proposed technique is suitable for the Raman reservoir and others like it. Its application to another situation may require appropriate modifications.
Recent Advances in Polycrystalline Diamond (PCD) Technology Open New Frontiers in Drilling
Authors: Sneddon M. V. , Hall D. R.
Published: December 2007

Recent developments in polycrystalline diamond (PCD) technology have led to breakthroughs in PCD bearing designs and PCD insert cutting structures. The authors suggest that the next major step in bit technology will be to combine these two innovations in a new generation roller cone bit, capable of sustained operation with a PDM or turbine.

Other potential areas of innovation are now made possible with this new technology. One of the first areas will be an integrated high-speed downhole drilling system consisting of the next generation roller cone bit, turbine, and MWD. Another area for development will be a downhole mudhammer for percussion drilling of petroleum wells. A more distant potential development is called the Robotic Advanced Drilling System (RAD), which uses a flexible drillstem and a downhole thrusting mechanism to give WOB and real-time drilling control.
Use Of Log-Derived Parameters For Completion Design Enhancement In The Medina Formation
Authors: Davis R. J.
Published: December 2007

Production in the Appalachian Basin comes primarily from "tight" gas and oil sands of the Devonian and Silurian period. The primary target in Northwestern Pennsylvania and Southwestern New York is the Lower Silurian Medina Formation. Nearly all of these wells are stimulated by hydraulic fracture treatment. Proper treatment of these wells is critical for economic results; therefore, knowledge of reservoir rock properties to enhance the completion design becomes increasingly important.

For improved completion design, measurements of rock mechanical properties need to be obtained. This can be accomplished either with a mini-frac or the use of log values. The optimized completion treatment design would use these properties to accurately determine many important variables including perforation selection, transport fluid type and viscosity, treatment volume and pumping rate, and proppant type and amount (all of which can be related to closure stress). These factors can be determined using the FracHite* Log output of gross fracture height, closure stress gradient, and treatment pressures.

This paper will deal with the application of log-derived parameters in modifying completion design strategy in the Medina formation. These modified completions will be compared with the "cookbook" completions as well as the production results of several wells treated with and without these vital parameters.
Measurement and Analysis of the Pressure Drop in a Vertical Annulus in a Simulated Air Drilling Operation
Authors: Supon S. B. , Adewumi M. A. , Fairchild N.
Published: December 2007

It is important to immediately clear cuttings from the face of the bit and to efficiently carry them to the surface in any drilling operation. Cuttings removal is especially critical in air drilling operations because of the relatively low viscosity of the gas compared to drilling mud. Air can effectively clear and remove cuttings, however, if the proper volumetric flow rate and injection pressure are used.

One important feature of pneumatic conveying of solid particles in vertical pipes is that pressure drop initially decreases as the air velocity decreases, reaches a minimum, and then increases with further drops in air velocity. Eventually, the air flow can attain such a low velocity that the result is a sharp increase in pressure drop often accompanied by flow instabilities and vibration.

The purpose of this study was to experimentally verify the presence of this minimum pressure drop in a simulated air drilling operation and to accurately determine it. The eventual goal is to develop a predictive capability for the velocity that yields this minimum pressure drop since this is an important parameter in optimizing the power requirements.

A plexiglass wellbore model was constructed with air and sand feed lines at the bottom. The air-sand mixture flowed through a cyclone at the top to separate the two components and then recycled back into the feed line at the bottom. The pressure drop across the wellbore model was measured at various sand feed rates and air velocities.

One of the findings of this study is that a minimum pressure drop does indeed occur at all sand feed rates as the air velocity decreases. We also found that there is a velocity at which the air moves too slow to lift any of the particles. No more pressure readings are possible when air is moving at the choking velocity.

This study is the first in a series of studies designed to foster a better understanding of the air drilling process. Our goal is to better understand the mechanics of air drilling and, ultimately, to be able to select the proper surface equipment for an optimized operation.
Suitcase-Size Data Recording System Improves Fracturing Operations
Authors: Weightman G. H. , Roberts T. H.
Published: December 2007

The quality and economy of fracturing operations can be enhanced by using a portable, computerized data acquisition system to monitor and record treatment data on an on-site and real-time basis. Improvements can be realized in equipment and operator performance, job documentation, and post-job analysis on nearly every stimulation job.
Improved Fracturing Technique Yields Increased Production Potential
Authors: Church D. C. , Peters B. A.
Published: December 2007

A new technique is presented for proppant apportionment during hydraulic fracturing which has the potential to increase production through improved placement of conductivity in the fracture. A "ramped" proppant schedule versus a "stair step" design is discussed to show the advantage of ramping the proppant stages. Additionally, case histories are presented which reflect increased hydrocarbon production where this technique has been applied when compared with the conventional "stair step" design.

This paper is limited to hydraulically induced fractures that are in the vertical plane. Further, that deeply penetrating fractures with a constant confined height are desired.
Non-Graphical Solutions for Average Reservoir Pressure from Production or Buildup Data
Authors: Azari M.
Published: December 2007

Simple equations were developed for determination of the distance from wellbore at which the reservoir pressure is the same as average formation pressure. This volumetric averaging method was derived for both constant boundary pressure and no-flow across boundary type of reservoirs. The technique was then extended to transient flow equations to obtain mathematical relationships for determination of average reservoir pressure during either production or buildup periods without the need of a Horner plot or any other published graphs. These equations were then reduced to much simpler forms, by which approximate values of average reservoir pressure could be assertained within 0.01%, provided that rinv/re ratio were greater than seven. Two example problems at the end of this paper compare the results of the proposed equations with the ones obtained by using Miller-Dyes-Hutchinson1, Matthews-Brons-Hazebroek2, Dietz3, and Ramey-Cobb4 methods. Furthermore, the examples show that the approximate equations are still providing very accurate results (within 0.1%) inspite of the rinv/re ratio being much less than seven.
Pressure Transient Behavior of Non-Newtonian/Newtonian Fluid Composite Systems in Porous Media With a Finite Conductivity Vertical Fracture
Authors: Ertekin T. , Cicek O. , Adequmi M. A. , Daud M. E.
Published: December 2007

This study simulates the pressure transient behavior of flow of Newtonian/Newtonian and non-Newtonian /Newtonian fluid composite systems in porous media with a finite-conductivity vertical fracture. The main objective of this study is to determine the location of the flood front, reservoir rock and fluid properties and fracture parameters via history matching of the test data. It is assumed that the injected fluid front propagates in the form of an ellipse whose focal length is equivalent to the fracture length, and single-phase flow conditions exist behind and ahead of the flood front. The viscosity of the non-Newtonian fluid in the flooded region was formulated as a function of the average flow rate. Both the injected and the reservoir fluids are treated as being slightly compressible.

It is assumed that flow inside the matrix is two-dimensional, and one-dimensional inside the fracture. Two different fluid flow equations, one for the matrix and the other for the fracture, are used to describe the single-phase flow conditions. The equations are coupled through a fluid loss term from the fracture into the matrix and/or from the matrix into the fracture. Four different fluid loss models in three different flow geometries (elliptical, linear and radial) are considered. These two non-linear equations are linearized numerically, and the resulting two systems of linear equations are solved simultaneously using the alternating direction implicit procedure.

Extensive testing and validation of this generalized formulation was conducted by using it to study nine special cases previously reported in the literature. A parametric investigation was conducted using dimensionless groups such as non-Newtonian power-law fluid exponent, fracture conductivity, elliptical interface location and mobility and diffusivity ratio. The results indicate that as the power-law index increases, the dimensionless bottomhole pressure increases for a given injection rate. In cases of mobility ratios greater than unity, smaller elliptical interface locations, which represent initial amounts of injected fluid in the reservoir, give greater dimensionless bottomhole pressures, and in cases of mobility ratios less than unity, smaller elliptical interface locations give smaller dimensionless bottomhole pressures. Greater mobility ratios yield greater dimensionless bottomhole pressures; increasing dimensionless fracture conductivities result in decreased bottomhole dimensionless pressures. It is observed that this decrease is not significant for dimensionless conductivities larger than five hundred.
Predicting Gas Well Performance Under Altered Conditions
Authors: Aminian K. , Ameri S. , Beg N. , Yost A. B.
Published: December 2007

Forecasting production rates from gas wells has always been of considerable importance to the natural gas industry. The conventional method of predicting the performance of gas reservoirs requires data which are often unavailable. This is particularly the case when dealing with low permeability gas reservoirs. In the absence of complete reservoir data, the production decline type curves are employed to predict the future rates utilizing production history. Generally, the production decline type curves are generated based on assumption that the operating and reservoir conditions which affected gas production in the past will remain unchanged. However, there are many instances when it is necessary to forecast the production rates under conditions which are not similar to those of the past. Typical examples of such cases are: (a) changes encountered in well spacing due to developmental drilling programs and (b) backpressure changes which occur due to compressor installations. This paper introduces a series of production decline type curves and relative methodologies which can be utilized to forecast gas production when the conditions are altered. A gas reservoir model has been utilized to simulate gas production to study the effects of changes relative to reservoir and operating conditions. The model takes into account many factors such as the non-Darcy flow effects, skin factor, and pressure dependent gas properties. The results have been utilized to develop techniques (for type curve applications) to forecast production under different reservoir and operating conditions.