bluuebunny/crossref_metadata_2025 huggingface dataset:
Geologic Problems Related to Characterization of Clastic Reservoirs for EOR
Authors: Szpakiewicz M. , McGee K. , Sharma B.
Published: December 2007

Geologic problems encountered in four U.S. DOE-sponsored EOR projects in clastic reservoirs were analyzed. The reservoir heterogeneities were grouped into four categories: depositional, diagenetic, structural, and formation-fluid composition/distribution. Each category had a variable effect on the performance of the EOR projects.

Requirements for developing one static geologic model for each category of heterogeneity are proposed. The interrelationship of geologic factors and the effect of heterogeneities resulting from the origin and timing of geologic events are described.

Besides heterogeneities associated with the depositional environment, which has a significant effect on EOR performance, diagenetic effects resulting from geochemical alterations and different types and polymorphs of clays are also important but are often neglected. The structural component of the model needs to be improved through the application of new methodology or improvements in existing technology (e.g., remote sensing, high-resolution seismic). A realistic prediction of fluid movement in clastic reservoirs subjected to EOR requires the integration of the four models that define all the heterogeneities.
Completion of a Deep, Hot, Corrosive East Texas Gas Well
Authors: Schulz R. R. , Stehle D. E. , Murall J.
Published: December 2007

A 19,011-ft [5795-m] wildcat in Houston County, TX, was successfully completed in March 1984. It tested the Lower Cotton Valley sand, which produced 14.5 MMscf/D [411×103 std m3/d] at a flowing tubing pressure of 8,671 psig [59.8 MPa]. The produced gas contained 4.9% CO2 and 24 ppm H2S. A bottomhole temperature (BHT) of 400°F [204°C] and bottomhole pressure (BHP) of 17,000 psig [117.2 MPa] intensified the corrosion potential. Tubular corrosion protection was provided by a 13% Cr production liner and a combination tubing string of 13 and 22% Cr alloys. The high pressure necessitated a 6,200-psig [42.7 MPa] underbalance liner top test. This paper outlines the completion and the supporting logic. It includes a discussion of the liner cementing, hole displacement, packer selection, tubing design, perforating, wellhead selection, and flowline design.
Evaluation of Reservoir Compaction and Its Effects on Casing Behavior
Authors: Chla Y. P. , Bradley D. A.
Published: December 2007

Many reservoirs along the gulf coast are overpressured and undercompacted. Depletion of these reservoirs usually results in a large pore-pressure drop and sediment compaction. Because casing strains with sediment, significant casing deformation may occur in the vicinity of reservoirs. Such a potential casing failure poses a serious threat to petroleum production from overpressured reservoirs. An axisymmetric finite-element model was developed to simulate sediment deformation, fluid flow, and casing deformation simultaneously. This model includes a section of 7-in., 35-lbm/ft [17.8-cm, 52-kg/m] casing from 11,400- to 12,800-ft [3475- to 3900-m] depths, a 2-in. [5-cm] -thick cement annulus, and a 3,400-ft [1036-m] radius of sediment. Frictional slippage was considered along the interface between cement and soil. Data from core measurements were used for various physical properties of soils.

Single-well production from three sand reservoirs interbedded with shale formations was modeled. The results indicate that depletion causes severe vertical compaction in the sand reservoirs. Sediment compaction also occurs in confining formations as the pore fluid flows from shales into sand reservoirs. As a result, high axial compressive stresses and strains are developed in the casing string, not only in the depleting reservoirs, but also within the adjacent shale formations. However, slippage of soil against cement and casing tends to reduce the axial casing strain greatly. This model allows assessment of sediment compaction and casing deformation during reservoir depletion and provides criteria for designing the well completion against casing failure.
The Bighorn No. 1-5: A 25,000-ft Precambrian Test in Central Wyoming
Authors: Collins J. C. , Graves J. R.
Published: December 2007

Between Oct. 1983 and Aug. 1985, Monsanto Oil Co. drilled a 24,877-ft [7583-m] -deep well on the Madden anticline in Wyoming's Wind River basin to evaluate the unexplored potential below the 17,000-ft [5182-m] -deep Cretaceous Cody formation. Three casing strings from surface and four liners were run, including a record depth and weight 16-in. [40.6-cm] string. The well tested at 20 MMcf/D [566 × 103 m3/d] with minimal drawdown from the Mississippian Age Madison formation at 23,800 ft [7254 m].
A Three-Dimensional Semianalytical Model of Hydraulic Fracture Growth Through Weak Barriers
Authors: Luiskutty C. T. , Tomutsa L. , Palmer I. D.
Published: December 2007

A high minimum in-situ stress contrast between pay and bounding zones can be very effective in restricting vertical fracture- height growth. For a highly elongated fracture, the fracturing-fluid flow can be approximated by one-dimensional (1D) flow along the pay-zone direction. If the stress contrasts are smaller (i.e., weak barrier), however, the height growth is greater and two-dimensional (2D) fluid flow needs to be incorporated into the modeling. This major difficulty has been solved only recently by a fully numerical solution. The goal of this research was to develop a fracture model for length/height ratio ≤ 4 that includes 2D flow (and a line source corresponding to the perforated interval) but makes approximations that allow a semianalytical solution, with large computer-time savings over the fully numerical model. The height, maximum width, and pressure at the wellbore in this semianalytical model are calculated and compared with the results of the fully three-dimensional (3D) model. There is reasonable agreement in all parameters, the maximum discrepancy being 24%. Comparisons of fracture volume and leakoff volume also show reasonable agreement in volumes and fluid efficiencies. The values of length/height ratio, in the four cases in which agreement is found, vary from 1.5 to 3.7. The model offers a useful first-order (or screening) calculation of fracture-height growth through weak barriers (e.g., low stress contrasts). When coupled with the model developed for highly elongated fractures of length/height ratio ≥ 4, which are also found to be in basic agreement with the fully numerical model, this new model provides the capability for approximating fracture-height growth through barriers for vertical fracture shapes that vary from penny to highly elongated. The computer time required is estimated to be less than the time required for the fully numerical model by a factor of 10 or more.
Effect of Pore Structure on Miscible Displacement in Laboratory Cores
Authors: Bretz R. E. , Specter R. M. , Orr F. M.
Published: December 2007

Observations of pore structure in thin-sections are related to the performance of stable, first-contact-miscible displacements in reservoir cores and then to simulations of displacement performance of CO2 corefloods. Results of effluent composition measurements are reported for miscible displacements in seven core samples—three sandstones and four San Andres carbonates from west Texas or eastern New Mexico. Those displacements are interpreted by fitting the measured effluent compositions to the Coats-Smith (C-S) model, which represents the flow as occurring in flowing and stagnant fractions with mass transfer between them. Observations of thin-sections, including measurements of pore-size distributions and a simple measurement of spatial correlation of pore sizes, are also reported. Comparison of displacement results and thin-section data indicates that wide pore-size distributions and preferential flow paths are characterized in the C-S model by high dispersion coefficients and low flowing fractions. Simulations of the interactions of phase behavior and flow in nonuniform pore structures indicate that wide pore-size distributions and preferential flow paths can significantly increase residual oil saturations (ROS’s) in CO2 floods over those for uniform pore structures. Thus, heterogeneities observable at the scale of a thin-section have significant effects in laboratory core but much smaller effects in displacements at field scale. Large-scale heterogeneities present in field floods, however, probably cause similar increases in residual saturation in some fields.
A Regression-Based Method for Estimating Relative Permeabilities From Displacement Experiments
Authors: Watson A. T. , Richmond P. C. , Kerig P. D. , Tao T. M.
Published: December 2007

We address the process of estimating relative permeability curves from data collected during unsteady-state displacement experiments. We introduce B-splines for use as functional representations of relative permeability curves. With B-splines, polynomial splines of any order can be conveniently implemented in the estimation procedure. This feature allows greater flexibility for incorporating inequality constraints into the parameter-estimation process.

We present a method for choosing an appropriate number of spline partitions for representing permeability curves. The method is based on considerations for obtaining the most accurate estimates of the relative permeability curves. We illustrate the method with both hypothetical and actual experimental data. We demonstrate that serious estimation errors may be encountered when relative permeability curves are represented with functions containing too few parameters—e.g., power-law functions.
Analysis and Implications of In-Situ Stress Changes During Steam Stimulation of Cold Lake Oil Sands
Authors: Wong S. K.
Published: December 2007

During steam stimulation in the Cold Lake oil-sand deposit, the reservoir is often fractured to obtain sufficient injectivity. The fracturing, pressurizing, and heating of the reservoir induce stress changes. These changes are analyzed with a finite-element program. Results suggest that the induced stress changes have implications for field operations.
Two-Point Method for Determination of Undisturbed Reservoir Temperature
Authors: Kritikos W. P. , Kutasov I. M.
Published: December 2007

The modeling of primary oil production and the design of EOR operations require knowledge of the undisturbed reservoir temperature. The drilling process, however, greatly alters the temperature of the reservoir immediately surrounding the well. In this paper, we present a method to determine the undisturbed reservoir temperature based on temperature measurements taken a short time after cessation of drilling.
Influence of Water-Desaturation Technique and Stress on Laboratory Measurement of Hydraulic Properties of Tight Sandstones
Authors: Chowdiah P.
Published: December 2007

Mercury porosimetry on unconfined sample chips and effective-gas-permeability measurements with evaporation used as the desaturating mechanism are two of the most common core-analysis measurements for tight sands. Data obtained with these two techniques have been compared with data on gas/water capillary pressure and effective gas permeability along a true drainage path at in-situ net confining stress. Results show that confining stress can have a significant effect on capillary pressure. Also, the use of evaporation to desaturate samples yields effective gas permeabilities much smaller than those obtained under true drainage conditions, suggesting that the evaporation method results in a pore-water distribution similar to that in an imbibition process.
Geologic and Engineering Implications of Production History From Five Mesaverde Wells in Central Piceance Creek Basin, Northwest Colorado
Authors: Chancellor R. E. , Johnson R. C.
Published: December 2007

Five gas wells completed in low-permeability rocks of the Upper Cretaceous Williams Fork and Iles formations in the central part of the Piceance Creek basin, northwest Colorado, have been on continuous production for about 2 years. A general comparison is made between these wells and the Dept, of Energy 's Multiwell Experiment (DOE MWX) wells about 30 miles [48 km] to the southeast. The five wells were completed with gelled KC1 water/sand fractures in various intervals over a 3,000-ft [910m] section of largely fluvial and paludal rocks of the Williams Fork and Iles formations of the Mesaverde group. Flow has apparently stabilized at low flowing tubing pressures at a rate of 30 to 125 Mcf/D [0.84 to 3.5 × 103 m3/d] per well, with minor water and variable condensate volumes. On the basis of production information to date, attempts to select intervals with better-than-average effective permeabilities by state-of-the-art techniques were not successful. The study points out several important differences in the Mesaverde group between the area of the five wells and the MWX site. Formation temperatures are higher and levels of thermal maturity are lower in the area of the five wells than at the MWX site. High formation pressures were encountered in the lower part of the Williams Fork and Iles formations at the MWX site, while thus far, only near normal to slightly below normal pressures have been encountered in the Mesaverde group in the area of the five wells. Gas shows and gas production characteristics in the area of the five wells appear to be related in part to the availability of gas-generating source rocks. Gas shows are sparse in the upper 1,000 to 1,700 ft [305 to 520 m] of the Williams Fork formation, where good source rocks are uncommon. Gas shows generally occur in only the upper parts of sandstones in this interval, suggesting that discrete gas/water contacts (GWC 's) are present. Completion attempts in this interval are commonly hindered by higher-than-average volumes of formation water. In contrast, almost continuous gas shows occur throughout the remainder of the Williams Fork formation and underlying Iles formation, where good source rocks are abundant. Discrete GWC 's are rare in this interval. Completions in this part of the section are capable of sustaining continuous gas production. The differences in the Mesaverde group between the MWX site and the area of the five wells point out the need to expand the MWX data base to include other gasproducing areas in the Piceance Creek basin.
Improvement of Hydraulic Fracture Predictions by Real-Time History Matching on Observed Pressures
Authors: Crockett A. R. , Willis R. M. , Cleary M. P.
Published: December 2007

A new, fully integrated model of hydraulic fracturing can be used to compare measured and calculated pressures for parameter determination during the fracture treatment to improve the prediction of hydraulic fracture geometry. Sensor data obtained during the course of the treatment—such as wellhead flow rates, fracturing-fluid viscosity, and proppant concentration—are received directly by this model, which takes into account all the essential physical phenomena that influence the pressure response associated with hydraulic fracture growth. At any point during the treatment, the model can be rerun, faster than real time, changing reservoir and treatment parameters until the difference between calculated and measured wellhead or bottomhole pressure (BHP) histories is minimized. Updated predictions of final propped fracture geometry can then be made by running the model faster than real time, using the remaining treatment schedule as input and adopting the parameters that correspond to the best history match; these predictions may differ substantially from that of the job design, thus providing field personnel with an improved estimate of the final fracture geometry before the treatment is completed, while remedies can still be implemented.

Results show history matches of the pressure response and associated fracture geometries for three treatments performed in the Travis Peak formation of east Texas and one performed on a coal seam in the Piceance Creek basin near Collbran, in western Colorado. In addition, this work is contrasted with previous efforts to deduce fracture geometry from pressure-response profiles.
A Note on the Duration of the Transitional Period of Responses Influenced by Wellbore Storage and Skin
Authors: Vongvuthipornchai S. , Raghavan R.
Published: December 2007

Several correlations are available for computing times at which storage effects can be considered to be negligible. The times given by these correlations are not in agreement principally because the criteria used to determine times for storage effects to become negligible are different. This paper clarifies the reasons for the differences and provides a unified treatment of the rules proposed in the literature. We show that correlations that specify the duration of the various flow periods depend on the manner in which the estimates are computed and on the tolerance used to obtain the estimate.

A new correlation to determine the time for the start of the semilog straight line is presented. This correlation is based on the slope of the pressure trace and ensures that the slope of the semilog straight line will be correct within a specified tolerance.
A Drilling Reporting and Evaluation Data System
Authors: Woie Rune , Sirevaag Roald B.
Published: December 2007

The BORE system is a drilling reporting and evaluation data system specially designed for drilling engineering. It reports drilling information from the rig site to the drilling department office and to license partners and authorities. The system provides valuable well information on previous drilling experience to be considered when new drilling activity is planned and in the daily follow-up of operations. The BORE system is easy to use and powerful for fast, complete data presentation when particular problems are considered and for special studies.
Core Preservation With a Laminated, Heat-Sealed Package
Authors: Hunt P. K. , Cobb S. L.
Published: December 2007

A core preservation package was developed to maintain the reservoir characteristics of core samples and consequently to improve the quality of data obtained through laboratory core analyses. The package is a heat-sealable plastic/aluminum laminate similar to those common in the food-packaging industry.

The laminated core preservation package acts as an impermeable barrier to water vapor and gases, and is resistant to chemical alteration and degradation by core fluids. These performance characteristics result in effective core preservation by maintaining the fluid content of the core. Other advantages of the laminated package are that it is fast and simple to use and eliminates the cumbersome dip-coat step used in some core preservation methods.

Controlled experiments comparing core samples preserved by hot-dipping and those preserved with the laminated package were conducted. Warehoused core samples lost as much as 80% of their original water content during 2 years of storage when B-60 Hot Melt Peel Coat Type II™ preceded by aluminum foil and plastic wrap was used as the preservation package. Less than 10% moisture loss occurred over the same period of time when the new package was used. The hot-dip package also exhibited significant decay of the aluminum and plastic-wrap layers, whereas the laminate used to form the heat-sealable packages did not show any visible degradation.
Pseudocomponent Characterization for Hydrocarbon Miscible Displacement
Authors: Wu R. S. , Batycky J. P.
Published: December 2007

A technique has been developed for lumping hydrocarbon pseudocomponents to simulate enriched-gas displacement processes. The proposed technique takes the reservoir temperature and the enriched-gas solvent compositions into account and then applies a mixing rule that proportions the molar- and weight-fraction weighting factors within the Peng-Robinson (PR) equation of state (EOS).

This technique was successfully applied to one condensate and three oil reservoirs by reducing the original multicomponent characterizations to only four pseudocomponents. The resulting oil characterizations matched the bubblepoint pressures, GOR’s, and atmospheric flash liquid and gas compositions. Also, solvent/oil phase behavior predictions at reservoir pressures—i.e., the accurate construction of the gas/liquid two-phase envelopes in pseudoternary diagrams—closely matched the multicomponent data. The mixing rule proportioning factor was found to be insensitive to pressure. For the condensate, the pseudocomponent pressure/temperature phase envelope representation matched the multicomponent representation. Finally, a match of the slim-tube displacement test data is presented for one oil as a further test of the technique’s validity.
Test of a High-Resolution Spectroscopy Logging Tool to Measure Chlorine in a Low-Salinity Reservoir
Authors: Neuman C. H.
Published: December 2007

A series of tests was conducted to evaluate the usefulness of neutron-induced gamma spectra recorded by a detector cooled to the temperature of liquid nitrogen. These tests were conducted in an oil well that had been evaluated with core and other logging techniques. Results showed that measurements of carbon abundance were not accurate enough to enable useful estimates of oil abundance, but measurements of chlorine abundance could be used to estimate brine saturation if data were accumulated long enough.

The commercial logging equipment tested consisted of two different tools that combined a high-resolution detector with both chemical and 14-MeV pulsed neutron sources. Methods were developed to process and display the 4,000-channel spectra recorded. Use of the spectral data to measure chlorine abundance was developed by recording spectra at depths opposite formations containing saline and fresh water. Effects of brine in the casing were evaluated by recording spectra before and after brine in the casing was displaced by fresh water.

Predicted statistical uncertainty and variations between repeat runs indicated that a measurement of chlorine abundance that discriminates between 30 and 50 saturation units (s.u.) of oil requires 1-hour station measurements for 11,000-ppm brine. Chlorine abundances calculated from the spectral data were consistent with saturations measured from cores and openhole logs. Spectra of gamma rays from inelastic scattering of neutrons produced by a pulsed source had no detectable carbon peaks.
New Findings on Leak Resistance of API 8-Round Connectors
Authors: Schwind B. E. , Wooley G. R.
Published: December 2007

This paper covers research funded by the API Production Research Advisory Committee (PRAC) on leak resistance of API 8-round connectors. It details the sensitivity of leak resistance to variations in makeup turns, pipe diameter, grade, and applied tension. Findings show that the leak resistance of the connector relative to pipe-body ratings increases with the number of makeup turns and decreases as diameter and yield strength increase. Finally, tension is found to lower leak resistance in a manner that renders hydrotesting insufficient for defining leak resistance in typical service conditions.
The Effects of Wellbore Storage, Skin, and Turbulence Intensity on Early-Time Transient Flow of Real Gas Through Porous Media
Authors: Oren Paul E. , Lee Robert L. , Tek M. R.
Published: December 2007

This paper represents the first contribution in quantifying the effects of wellbore storage along with those of skin and turbulence intensity on deliverability from gas wells. A decay factor, WD, has been introduced to account for the contribution of sandface flow rate to early-time transient production from the gas wells. Generalized charts for type-curve studies on gas wells, based on pseudopressure and pseudotime concepts, along with wellbore storage, are presented with applications and support from field data.
Simulation of Pressure Buildup in a Multiphase Wellbore/Reservoir System
Authors: Winterfeld P. H.
Published: December 2007

A pressure-buildup test is simulated in a system consisting of a wellbore and a reservoir and containing multiphase fluid. Wellbore flow is governed by conservation of matter and momentum, and reservoir flow by conservation of matter and Darcy's law. Finite-difference versions of the flow equations are solved on a discretized system. A single-phase example illustrates wellbore storage and wellbore fluid inertia shortly after shut-in. Two-phase examples illustrate phase redistribution, and one shows a "hump" caused by phases segregating. Buildup and other data from a field case are also matched.
Glenn Pool Surfactant Flood Pilot Test: Part 2—Field Operations
Authors: Bae J. H. , Syed E. U.
Published: December 2007

A surfactant flood pilot test was conducted in a 20-acre [8.1 -ha], four inverted five-spot pattern in the Glenn Pool field. The field had been waterflooded and the pay zone, the Upper sand, was at a depth of 1,500 ft [457 m]. The crude oil had a viscosity of 4.0 cp [4 mPa-s] at a reservoir temperature of 95°F [35°C]. The process consisted of sequential injection of 35% PV of preflush, 10% PV of sulfonate slug, and 35% PV of polymer solution, followed by drive water. Injection operation was smooth; no injection well plugging was observed during sulfonate and polymer solution injection. On the other hand, production operation was somewhat hampered by plugging of producers. Low-equivalent-weight sulfonate precipitated out around the producers and contributed to the plugging problem. Solvent treatment corrected this situation effectively.

Although a large oil bank was observed in the two observation wells and all other observation-well behavior indicated a successful process performance, the total oil production was disappointing. About 63,000 bbl [104 m3] of incremental oil was produced. During the test, it was established through reinterpretation of existing data and a pulse test program that there was no clear separation between the Upper and Middle sands. The impermeable shale streaks separating these two zones were not continuous. The implication was that injected fluids were not confined in the Upper sand. This made the interpretation of field data very difficult.
PDC Applications in the Gulf of Mexico With Water-Based Drilling Fluids
Authors: Gault A. D. , Knowlton H. , Goodman H. E. , Bourgoyne A. T.
Published: December 2007

This paper presents the results of a recent study conducted to determine application and operating requirements for polycrystalline diamond compact (PDC) bits in the Gulf of Mexico. This study evaluated PDC-bit usage in Miocene sections of the Gulf of Mexico and has resulted in a saving of more than $1.4 million based on 22 bit runs. As a result of this study, operational guidelines for PDC bits were established and drilling costs per foot were significantly reduced. In addition, a relationship was found between shale reactivity, strength, and density. This proved to be an effective aid in bit selection and determination of hydraulic requirements and verified the results of the study.
Laboratory Drilling Performance of PDC Bits
Authors: Warren T. M. , Armagost W. K.
Published: December 2007

A laboratory study of polycrystalline diamond compact (PDC) bit designs has generated data that give an insight into PDC-bit performance in the field. The tests reviewed in this paper include those for rate of penetration (ROP), torque response, hydraulic energy sensitivity, balling tendency, dull-bit performance, and bit performance after the removal of selected cutters. A total of four bit designs was tested. The designs included flat-faced profiles and parabolic profiles.
Numerical Simulation of Naturally Fractured Reservoirs
Authors: Sonier F. , Souillard P. , Blaskovich F. T.
Published: December 2007

The most important and difficult aspect of modeling a naturally fractured reservoir is the correct calculation of the exchange of fluids between the matrix rock and the surrounding fractures. Several authors have published alternative techniques for handling this problem over the past few years. However, because each of these alternatives has some limitations, a new and more general technique has been developed. This new technique is used to simulate matrix/fracture exchange with special emphasis on the gravity forces included in the exchange terms. The exchange terms and the gravity forces within the exchange terms simulate the behavior of a single matrix block surrounded by fractures that may contain several different fluids. The gravity forces are internally calculated as functions of saturation. This technique has been incorporated into a new three-dimensional (3D), three-phase, fully implicit model for simulating fluid flow in a naturally fractured reservoir. The description of the porous medium might include highly fractured, microfractured, and nonfractured regions. Several examples explain the use of a new naturally fractured reservoir model and the essential differences between the new approach and those used in earlier naturally fractured reservoir models.
Fluid-Loss Mechanism for Gels and Suspensions
Authors: Medlin W. L. , Massé L.
Published: December 2007

We present a new model of fluid loss with wall building that applies to gelled fracturing and drilling fluids. Our model separates leakoff into two parts: an invasion phase and a wall-building phase. The invasion phase begins with Darcy flow, which carries residue into pore spaces near the rock face. This phase ends when sufficient residue has accumulated to allow the formation of a wall on the rock face. Once the wall has formed, it dominates the fluid-loss mechanism through its extremely low permeability. During the wall-building phase our model predicts a hyperbolic rather than a linear relation between leakoff volume and t. We made laboratory fluid-loss measurements for a variety of fluids and rock materials to test this model. We monitored effluent volume produced by flowing a gel or suspension through a fully saturated core sample. We found that the new model fit these measurements over periods of several hours, whereas the conventional Cw model did not. The Cw method can lead to large errors in fluid-loss estimates for long-term operations, such as massive fracturing and drilling. Our model requires the measurement of three leakoff parameters. We collected enough measurements to determine some general relations between these parameters and fluid and rock properties. These relations are discussed in terms of practical applications.
Earth Stress Measurements in the South Belridge Oil Field, Kern County, California
Authors: Hansen Kirk S. , Purcell W. R.
Published: December 2007

Earth stress magnitudes in the South Belridge oil field, determined from integrated density logs and microhydraulic fracturing tests, indicate that the vertical stress is generally the intermediate principal stress, except possibly at the deepest zone tested (2,100 ft [640 m]), where it is approximately equal to the lesser compressive horizontal stress. Azimuth of the greater horizontal stress and of induced hydraulic fractures, as measured or inferred by several different techniques, is N15°E±15°.
Understanding and Controlling Corrosivity of Heavyweight Brines
Authors: Hudson T. E.
Published: December 2007

This paper describes methods and technology for controlling the corrosivity of heavyweight brines. The conclusions are based on more than 5,000 corrosion data points generated in the laboratory and actual field use of the technology. Brines used in this study were single-, two-, and three-salt mixtures with densities varying from 8.4 to 19.2 lbm/gal [1007 to 2301 kg/m3]. Test temperatures and pressures varied from 100 to 500°F [38 to 260°C] and 1,000 to 10,000 psi [6.9 to 69 MPa], respectively. The tests varied in length from 1 to 90 days, and the tubing materials tested were 1008, J55, N80, and P110 steel.
Delineation and Evaluation of a North Sea Reservoir Containing Near-Critical Fluids
Authors: Neveux A. R. , Sakthikumar S. , Nolray J. M.
Published: December 2007

A newly delineated reservoir in the North Sea Viking graben contains fluids that are at near-critical conditions. This paper presents a global approach for the delineation program, fluid correlation, and subsequent reservoir simulation studies. The delineation history and fluid sampling are detailed first. Fluid data correlation is presented, based on the use of an equation-of-state (EOS) program. Then, the compositional simulator, which provided satisfactory fluid representation for full-field studies and proved to be reliable and cost-efficient, is described.
TLP Production Risers for 1200-m Water Depth
Authors: Delgado J. H. , Erb P. R. , Moe G.
Published: December 2007

A number of technically feasible alternative riser systems exist for tension leg platform (TLP) production systems in deep water. These include conventional steel, steel with added buoyancy, titanium, and carbon-fiber composite. The last three of these options provide substantial reductions in required riser tension for a 1200-m [3,935-ft] depth. For a minimum-size TLP, these reduced tensions translate into substantial reductions in fabricated steel weight. Replacing conventional top tensioners with a hard-mount or gimbal arrangement requires a relatively small increase in top tension, which would be balanced out by weight savings on the tensioning equipment. Operational concerns related to pressure and temperature changes must be addressed to ensure feasibility of the hard-mount or gimbal approach.
Chromium (III) Propionate: A Crosslinking Agent for Water-Soluble Polymers in Hard Oilfield Brines
Authors: Mumallah N. A.
Published: December 2007

Reservoir heterogeneity and channeling have limited the success of many EOR projects because the injected fluids are preferentially transported through the path of least resistance. Current technology uses water-soluble polymers gelled with a suitable crosslinker to block, either partially or totally, channels and high-permeability zones. Most of the known gel systems are not usable in hard brines because the crosslinking chemicals are either incompatible or unstable in those brines.

This reports on the new chromium (III) (Cr+3) propionate gel system that was found suitable for in-depth, as well as near-well, gel treatments in both fresh water and hard brines. Laboratory coreflood testing of this gel system in various brines with hardness (calcium) levels up to 14,000 ppm resulted in high, long-lasting residual resistance factors (RRF’s). The stability and performance of Cr propionate in hard brines will extend gel treatments to reservoirs that have been excluded from consideration because fresh water was not available.
A Semianalytical Approach to Pseudopressure Calculations
Authors: Klins M.A. , Biterge M.B.
Published: December 2007

Real-gas pseudopressures allow rigorous analytical solutions to the nonlinear mass/momentum equations for gas flow in porous media. These solutions, however, are in terms of pseudopressure rather than reservoir pressure. To convert pseudopressures to their complementary reservoir pressures, one of three techniques is traditionally applied: numerical integration, table look-up, or curve-fit analysis. All three interject some numerical error into the m(p) calculations. This paper introduces a new, "exact" procedure for making the pseudopressure/pressure conversion. It is applicable to a wide range of reservoir properties including, sour gases, temperatures up to 460 degrees F [238 degrees C], and pressures to 10,000 psia [70 MPa]. Sample calculations are shown and comparison with a number of other pseudopressure estimates is made.

Semianalytical Approach to Pseudopressures

Al-Hussainy et al. introduced the notion of pseudopressure, m(p), to analyze real-gas flow phenomena in porous media. Since that time, at least three approaches have been presented that convert reservoir pressures to their complementary pseudopressures: numerical integration, table look-up and interpolation, and curve-fit approximation.

Of these three, the most commonly applied approach is numerical integration by use of known gas correlations for viscosity and supercompressibility. Its major advantage is that it allows the user to select the and z correlations of his/her choice before numerical integration. The drawbacks are that it requires a large number of and z calculations to create a table of p/ z vs. pressure, that a numerical integration procedure and accompanying and z programs must be developed, and that the magnitude of error inherent in numerical integration is unknown and depends on the number of data points used in the integration.

The semianalytical approach, then, involves the actual solution of the m(p) integral defined in Eq. 1. If the viscosity and compressibility terms in Eq. 1 are replaced with selected correlations. the real-gas pseudopressure equation can be solved analytically and an exact solution (for the correlations chosen) of m(p) obtained.

Model Development.

Real gas pseudopressure with a zero base pressure of integration is defined as

= ...................(1)

Substitutions for p/z, dp, and p with Eqs. 5, 9, and 10 can be made with a change in the variable of integration from p to pr introduced.

By using the imperfect-gas law, we can calculate gas densities:

= ..............................(2)

and

= ..............................(3)

where Dranchuk et al. assume that the critical gas con pressibility factor is 0.27 and

= ..............................(4)

Then it follows that

= ....................(5)

and

= .........(6)

With the Dranchuk et al. correlation for z factors,

= ....................(7)

P. 468^
Discussion of Application of Oil Muds
Authors: Bloemendal J. W.
Published: December 2007

I would like to comment on three oil-mud papers: "Behavior of Oil Muds During Drilling Operations," "Low-Toxicity Oil Muds: A Knowledge of Downhole Rheological Behavior Assists Successful Field Application," and "Magnesium Oil Mud Provides Gauge Hole in Bischofite/Carnallite Formations" (April 1986 SPEDE, Pages 97–106, 107–14, and 115–21, respectively).

I fully agree that an oil mud is superior in drilling unstable, deviated, or water-sensitive formations. I have serious doubts, however, about the practical and economical application because of the disadvantages mentioned by most authors but not discussed enough to convince me to give up my opposition to oil-based muds (OBM's).

I question the higher rate of penetration claimed for relaxed API-WL OBM's compared with water-based fluids, because the improved performance of OBM's might be largely or entirely a result of the beneficial effects of polycrystalline-diamond-compact bits, higher API-FL, lower effective bottomhole density, better lubricity (which results in higher weight on bit), higher revolutions per minute, more favorable rheological properties, and probably many more effects that cannot be recognized easily in practice. Maybe we still have our equipment for laboratory drill tests rigged up to investigate the isolated effect of OBM's while the other factors are changed one at a time.
Analysis of Productivity of Inclined Wells and Its Implication for Finite-Difference Reservoir Simulation
Authors: Lee S. H.
Published: December 2007

A boundary-integral method was used to study the productivity of inclined wells. The previous analytical equations for productivity indices were derived mainly for two-dimensional (2D) or three-dimensional (3D) radial flow and a line source or sink in an unbounded domain. Even when a simple impermeable plane boundary exists near a well, the analytical solution becomes a complicated infinite series of functions. Hence, it is desirable to develop a simple, general method to analyze accurately the Darcy flow around inclined wells in an arbitrary reservoir geometry. Use of Green's function allows a general solution of the Darcy equation to be expressed in the form of a Fredholm integral equation of the second kind. This integral equation has been solved numerically by a collocation technique.

This boundary-integral method was used to analyze the effects of reservoir boundaries, anisotropic permeability, well location, and inclination angle on well productivity. Finally, the commonly used well-productivity equation for a finite-difference method was carefully examined by comparison with accurate numerical solutions from the boundary-integral method. This study indicated that the equation can yield erroneous results for an inclined well. The well productivity calculated here can easily be incorporated in finite-difference simulation for inclined wells.
Analysis of Radial Transport of Reactive Tracer in Porous Media
Authors: Falade G. K. , Brigham W. E.
Published: December 2007

This paper presents some new close-form analytical solutions to equations describing radial transport of reactive tracers in porous media under conditions of tracer adsorption, nonuniform convection, and variable dispersion coefficient. Three different types of variable dispersion coefficients were considered and exact solutions presented in Laplace space. The special case where shear mixing or convection dominates dispersion, which is important for tracer test studies, was programmed on a computer to obtain concentration profiles for the continuous- and slug-injection test models.
The Importance of Correct Running and Handling Procedures for Premium Tubular Goods
Authors: Walstad D. E. , Crawford D. W.
Published: December 2007

The demand and requirements for tubular goods to handle deeper wells with more hostile environments have resulted in increased popularity and widespread use of proprietary sour-service steel grades and corrosion-resistant alloys (CRA's) with premium connections.

Because of the great potential economic disasters that could result if damaged tubulars are run in hostile environments, obtaining maximum performance from the tubulars is imperative. Improper handling and running damage can cause (1) unnecessary and excessive damage to the threaded areas, requiring field repair or rethreading; (2) failure of the tube—i.e., collapse, burst, small leaks, or fatigue; (3) leaks or connection parting (failure); and (4) catastrophic failure—such as blowouts, loss of well, loss of equipment, or loss of life.

For adequate tubing and casing performance, equal emphasis should be focused on running and handling procedures, tubing, casing design, and materials selection.

This paper discusses all phases of running and handling for premium tubular goods and presents supportive field data from three geographic areas.
An Overview of Free-Point Tools
Authors: Weido V. C.
Published: December 2007

Service companies traditionally have used similar types of downhole tools to locate the lowest free point in a string of pipe. Advancing technology has encouraged new concepts and innovative tool designs that are changing this specialized service.

Traditional tools make static measurements of incremental tension or torsional deviation on either side of the forecasted point at which the pipe is stuck. The speed with which the free point is located depends on the initial forecast and procedural requirements necessary for the measurement. In a sense, the operator approaches the free point by successive approximations.

This paper introduces two new tool designs to minimize interpretation error and to accelerate the location of the lowest free point. Each design provides a log record of the free-point service. One of these tools extends the concept of static measurements of incremental tensile and torsional deviation, while the other relies on the measurement of magnetic permeability and produces a continuous log. Example logs from each tool design are presented.
Evaluation of Gas-Extraction Efficiency During Mud-Logging Operations
Authors: Elder Suzanne S.
Published: December 2007

Field and laboratory tests described in this paper were designed to develop a better understanding of conditions that affect gas analysis during mud logging. The test objectives were to quantify gas losses, if any, from the mud at the bell nipple or in the flowline during drilling and to study the effects of changing mud properties on gas-trap extraction efficiency.
Interactive Computer Graphics System Improves Planning of Directionally Drilled Wells in the East Wilmington Field
Authors: Lutz T. S. , Kendle D. W.
Published: December 2007

The Long Beach Unit of the East Wilmington field contains more than 1,200 wells directionally drilled from four manmade islands and five land-based drilling sites. Planning new wells that avoid interference with existing wells becomes more difficult and time-consuming as the density of wells in the Unit increases. Improvements and modifications in design procedures have culminated in the interactive computer graphics system now in use.

The interactive computer graphics system (ICGS) permits the viewing of a proposed new well or redrill well course, together with all existing well surveys and other proposed well courses in the area of interest. Plan, section, and traveling cylinder views can be displayed to allow the identification of design problems. The significance of the problems is then minimized by use of the interactive features of the system to refine the design parameters. The system's interactive features are also used to create, edit, and plot the finalized design.

Reductions in design and drilling costs and many other less-direct benefits have been realized as a result of the system's use. The step-by-step use of the system from the user's point of view is described and examples of its graphic output are presented. To the best of our knowledge, this is the most advanced system of its kind in use today.
A Mathematical Model for the Scale-Inhibitor Squeeze Process
Authors: Hong S. A. , Shuler P. J.
Published: December 2007

A mathematical model was developed to describe the scale-inhibitor-adsorption squeeze process. The objective of this study was to create a tool that will predict the duration of a squeeze treatment, given the operating parameters and the rock and inhibitor properties.

Assuming that there is local equilibrium between the inhibitor in solution and on the rock, the mathematical model was solved analytically by the method of characteristics. Algebraic equations were derived to calculate the scale-inhibitor concentration in the produced water and the squeeze lifetime. The validity of the model is demonstrated by a comparison of its predictions with field and laboratory data. Sensitivity of the squeeze lifetime to variables associated with the process is presented. One important conclusion is that scale inhibitors should be screened on the basis of their adsorption characteristics and their effectiveness at low concentrations in preventing scale formation.

Finally, the complete mathematical model, which allows for time-dependent adsorption/desorption of the inhibitor, is solved numerically. Accurate predictions of the squeeze process require incorporation of these kinetic effects when the residence time is short compared with the time required to reach equilibrium. As demonstrated here, this can be significant, especially in laboratory tests performed to measure squeeze lifetime. Scaling up laboratory results for the field should be done with caution because these kinetic effects tend to increase squeeze lifetime. The equilibrium model gives the most conservative prediction of squeeze lifetime.
An Experimental Investigation Into the Effects of Chemical type on CO2/Heavy-Hydrocarbon Phase Behavior
Authors: Wilburn D. L. , Bankston B. A. , Monger T. G.
Published: December 2007

This paper provides PVT and compositional data for seven CO2/synthetic-oil systems. The oils were composed of light paraffins plus heavy hydrocarbons selected from three chemical types: paraffins, naphthenes, and aromatics. Results for the different oils are contrasted with a comparison basis of equivalent molar-averaged normal boiling point. This parameter is easy to calculate and provides a means by which chemical effects can be quantified in the presence of oil volatility effects.

The results demonstrate that two oil compositional effects control the extent of hydrocarbon extraction by CO2. The major effect is usually the oil volatility, but effects of hydrocarbon chemical type can be dominant. The data suggest a trend for the influence of chemical type on oil miscibility with CO2: paraffins are beneficial, aromatics are less beneficial than paraffins, and naphthenes are detrimental. The effect of chemical type on oil swelling is also significant.