bluuebunny/crossref_metadata_2025 huggingface dataset:
Mechanism of Transit Time Increase and Its Interpretation After Water Injection into Reservoir M in the Lao Jun Miao Oil Field
Authors: Hao Zhi-xing , Shen Lian-di
Published: December 2007

Reservoir M in the Lao Jun Miao oil field is a very massive sandstone oil reservoir about 60 m [200 ft] thick. Within the reservoir, there are no evident shale barriers and no interlayer standard water zones. This reservoir is classified as a fractured porous reservoir. The reservoir rocks have a high shale content; montmorillonite is the main clay mineralwith a maximum percentage content of up to 60%. After water injection, the sonic transit time was increased substantially in the flooded rather than in the nonflooded intervals.

This paper gives an idea of the mechanism for the increase in sonic transit time in flooded intervals of the reservoir on the basis of the measurement and analysis of the noninvaded cores. Study results show that the increase in sonic transit time after flooding is linked to the rock texture in relation to the high montmorillonite content.

It is well known that montmorillonite expands when it absorbs water and can plug the formation. However, it is possible to have better communication in the pores locally. These concepts are important and useful for better oilfield development and in the evaluation of the sweep efficiency of waterflooding.

This paper also gives an in-house measurement technique for samples with high montmorillonite content.

On the basis of core analysis and well testing data, we propose a comprehensive interpretation technique for determining flooding or nonflooding intervals that uses the transit time from sonic logging as the main data. Good results have been obtained.
Hydraulic Programs for Maximum Hydraulic Horsepower and Impact Force on the Rock Surface of the Hole Bottom in Jet Drilling
Authors: Zhang Shao-Huai , Yao Cai-Yin
Published: December 2007

In this paper, empirical formulations have been developed to calculate, from full-scale experimental results, the hydraulic horsepower and impact force at the rock surface. Two new hydraulic programs were established to optimize bit hydraulics on the rock surface of the hole bottom. The new theory and methods, when tested in oilfield drilling practice, have increased rate of penetration (ROP) and reduced drilling cost.
Temperature and Common Ion Effects on Effective Acid Penetration in a Fracture
Authors: Ren Shu-Quan , Xiong Hong-Jie
Published: December 2007

The effective acid penetration distance, an important parameter in acid-fracturing-treatment design, has a great influence on the effectiveness of the treatment. The temperature in a fracture and the acid/rock reaction products simultaneously affect the acid penetration greatly. But until now, no information concerning this aspect has been published.

To satisfy practical calculation requirements in the treatment design, this paper develops a new mathematical model for the reaction of acid flowing in the fracture by considering the principal factors impacting the effective penetration of the acid. This model was combined with the model of temperature distribution in a fracture, the model of velocity field, and the model of acid/rock surface reaction kinetics to give a simultaneous solution, and a corresponding computer program was developed to perform the calculation. By analyzing and correlating figures and tables of data on the influences of common ion effect, acid concentration, formation temperature, and heat generated by the acid/rock reaction on effective acid penetration distance have been obtained.

The computer program and conclusions in this paper can be used in practical acid-fracturing-treatment design.
Problems Relating to the Fracturing of Deep Wells in the North China Region
Authors: Li Guo-Cal , Zhu Zhao-Ming
Published: December 2007

The oil and gas fields of the Tertiary Sand formation in north China are of complicated structure. The permeability of the pay zone ranges from 0.1 to 50 md, and the porosity approaches 13%. During development, hydraulic fracturing is necessary to stimulate well productivity to achieve satisfactory economic benefit. This paper discusses fracturing fluids and solid leakoff additives, proppants and types of propping, fracture height and diverting fractures, and fracturing pressure for the formation in this area.
Study of Pressure Attenuation of a Submerged, Nonfree Jet and a Method of Calculation for Bottomhole Hydraulic Parameters
Authors: Shen Zhonghou , Sun Qingxiao
Published: December 2007

The pressure attenuation of a submerged, nonfree jet has been studied with a simulated wellbore. Equations describing pressure attenuation along the centerline and the cross-sectional pressure distribution of the jet are given. With these equations, bottomhole hydraulic parameters can then be calculated. Also, an optimal design of a jet-drilling hydraulic program based on bottomhole parameters has been developed.
Scaling Laws for Laboratory Flow Models of Oil Reservoirs
Authors: Perkins F.M. , Collins R.E.
Published: December 2007

Publications concerning laws for laboratory flow models of oil reservoirs indicate that the relative permeability and capillary pressure relations must be the same functions of saturation in the model and its prototype. In this paper, the relative permeabilities and saturations are redefined in a way which permits one to have different relative permeability and capillary pressure relations in the model and prototype. The development of the new scaling criteria is demonstrated by deriving scaling laws for one simple flow problem.

Introduction

The successful application of information gathered through bench-scale model studies to the prediction of multi-phase fluid flow behavior in petroleum reservoirs requires careful consideration of the scaling criteria. The requirements which must be met for a small-scale model to duplicate the behavior of a much larger reservoir prototype have been discussed by Leverett, et al, Rapoport, and Geertsma, et al. According to these authors, the relative permeabilities to water, oil and gas and the dimensionless capillary pressures must be the must have the same values in the model and prototype. Furthermore, they point out that the viscosity ratios must have the same values in the model and prototype. In addition to these requirements, other scaling criteria are given which, when considered, usually dictate a much higher permeability in the model than exists in the reservoir.

Since the more permeable model sands may have connate-water and residual oil saturations quite different from those in the prototype, the scaling requirements pertaining to the dependence of relative permeabilities and dimensionless capillary pressures on saturation usually are not met. Also, if the model fluids are selected to give equal viscosity ratios in the model and prototype, one may find greatly different mobility ratios in the two cases and, therefore, may expect grossly different flow patterns. For this reason, Craig, et al, correlated the results of their model studies with mobility ratio rather than with viscosity ratio. As yet, however, no satisfactory method has been advanced which permits use of anything other than the scaling requirements outlined in the previously mentioned papers.

The purpose of this paper is to present a method of developing a set of scaling criteria which permits different relationships between saturation and relative permeability or capillary pressure in the model and prototype. Rather than attempt to report scaling criteria for a variety of practical situations, this paper demonstrates by use of one simple example how the modified scaling criteria are derived.
A Wireline Completion Technique for Sand Control
Authors: Lanmon C.P.
Published: December 2007

A new wireline technique provides fast, economical and sand-free completions in zones noted for sand-production problems. On a single trip in the well, the wireline sand consolidation tool perforates the casing with two holes ]and squeezes consolidating plastic into the formation. The entire operation is performed in 3 hours or less, and the well can immediately be put on production through the treated perforations. One or two pairs of treated perforations are usually adequate for allowable production.

Introduction

The purpose of any sand consolidation treatment is to convert the loose sand behind the casing into a strong. permeable, synthetic sandstone filter. This filter allows fluid production into the casing but prevents surrounding formation sands from flowing. The filter is formed by injecting plastic into the formation. The plastic cements the sand grains together, but still provides interconnecting pore spaces to permit free flow of fluid. By its very nature, the consolidated formation sand makes a filter perfectly sized to keep the unconsolidated sand from filtering through. When treating a well by conventional sand consolidating methods, up to several hundred gallons of treating fluids are pumped through multiple perforations into the formation. This is usually done by pumping the treating fluid from the surface through the tubing. With the wireline technique, 4 1/2 gal of treating fluid contained in the wireline tool are injected directly into perforations made by the tool. There is no opportunity for contamination of the plastic. Each perforation is treated independently. This provides good assurance that each perforation will receive plastic and that none will go untreated. The 4 1/2 gal of treating fluid consolidate a sphere roughly 18 in. in diameter adjacent to the perforations. This consolidated mass has a compressive strength of at least 1,000 psi and retains 60 to 75 percent of the sand permeability. production is from perforations made with this tool. No additional perforating is done. Experience has shown that high production rates can be obtained through these perforations.

Description of Tool

A new wireline tool was designed for this service. The external appearance of the tool resembles a wireline formation tester (Fig. 1). It has two main parts: the mechanical section and the treat section. The mechanical section contains the internal hydraulic system to set the tool in the casing and to operate the control valves. It also contains the perforating gun block. The treat section consists of a pressure amplifier and chambers which contain the fluids to be injected. In operation. two doughnut-shaped packers are forced against the casing by the back-up shoe. The packers prevent contamination of the plastic or loss to the wellbore during injection. Two shaped charges are located in the packer section. one behind each packer. After a seal is effected between the tool and the pipe, the shaped charges are fired, perforating the casing and thus establishing communication between the tool and the formation.

JPT

P. 741ˆ
Effects of Reservoir Heterogeneity on Chemically Enhanced Oil Recovery
Authors: Gupta Akhil Datta , Pope Gary A. , Sepehrnoori Kamy , Shook Mike
Published: December 2007

A three-dimensional (3D), multiphase, multicomponent micellar/polymer flooding simulator has been used to investigate the process performance under different conditions of reservoir heterogeneity (stratifications) and mobility ratios. The significance of crossflow has been studied by relating chemical flood recoveries to the effective length-to-thickness ratio and the transverse dispersion number of the reservoir. A long-standing question in micellar/polymer flooding concerns whether small, high-concentration chemical slugs are preferred to large lower-concentration slugs. This aspect of slug size vs. slug concentration has been studied in 3D in the presence of heterogeneity. Finally, chromatographic separation of surfactant and alcohol has been investigated and discussed. It is found that a salinity gradient can be tailored to minimize this separation tendency and that this in fact is the single most important factor, even when compared with adsorption and partitioning. This is a highly favorable result that can and should be exploited to improve the practical design of micellar/polymer floods.
Detailed Simulation of Unstable Processes in Miscible Flooding
Authors: Christie M. A. , Bond D. J.
Published: December 2007

This paper describes applications of linear and nonlinear simulations to unstable miscible flooding. The first section describes a method of calculating linear growth of unstable modes by use of finite differences in the direction of flow and Fourier decomposition perpendicular to flow. This work extends the previous long- and short-wavelength analytic results to cover the whole wave-number range. Results obtained are used to help validate a two-dimensional (2D) code to study nonlinear evolution of viscous fingers and to identify likely fingering regimes in the computed solution by identifying the range of wave numbers that dominates the linear growth behavior. The second section describes the numerical scheme for calculations on a fine grid of the nonlinear development of an instability. Results are presented on calculations of nonlinear growth at several mobility ratios and levels of diffusion. Comparisons with Blackwell's experimental data are presented. Good agreement is obtained, suggesting that the physical processes governing fingering are being correctly modeled.
Use of Dispersion Relationships To Model Adverse-Mobility-Ratio Miscible Displacements
Authors: Young Larry C.
Published: December 2007

Improved predictions of petroleum reservoir performance are needed to reduce the risks associated with field-scale miscible flooding. A major shortcoming of established prediction techniques is their failure to model accurately the effects of mobility ratio and viscous fingering on volumetric sweep and displacement efficiency. This paper establishes the feasibility of using physical dispersion relationships to account for fluid mixing associated with viscous fingering. The dispersion relationships use an additional parameter to incorporate a dependence on the local viscosity gradient. Adverse viscosity gradients increase mixing, while favorable viscosity gradients decrease mixing. The dispersion relationships reduce to the normal form when no viscosity gradients are present. The dispersion parameter needed is determined with published data for flow in a long, sandstone core system. Once established, the dispersion relationships are used to predict the performance of a much more complex displacement of reservoir oil by CO2. The simulations reproduce all the salient features observed experimentally and establish the validity of the approach. In particular, the effect of system length is modeled correctly.
An Empirical Model for Microemulsion Phase Behavior
Authors: Robertson Steven D.
Published: December 2007

An empirical model for microemulsion phase behavior has been developed that is based on proper choice of pseudocomponents. Previous attempts to represent phase behavior of surfactant/oil/brine systems with three pseudocomponents have been unsuccessful. One of the problems has been salt fractionation between the microemulsion and excess water phases. It was found that through the use of a sulfonate/water pseudocomponent, this effect could be handled, and the system then exhibited true ternary behavior. When this pseudocomponent was used, a single set of Vo/VS and Vw/Vs-vs.-salinity curves was found to be valid for a wide range of overall compositions. These solubilization-parameter curves were fit with empirical equations, and it is these that comprise the model. The basis for a sulfonate/water pseudocomponent is discussed using electrical double-layer theory. In addition, solubilization-parameter curves generated from spherical microemulsion models are compared with the experimental curves.
Well Interference
Authors: Warren J.E. , Hartsock J.H.
Published: December 2007

An asymptotic solution to the equation that describes the flow of a slightly compressible fluid in an infinite porous medium has been used to estimate the interaction between two adjacent wells producing from a common reservoir. A direct method for approximating the interference time defined by Stevens and Thodos has been suggested. An alternative definition for the time of interference, based on the minimum pressure change in the interference region, has been proposed; also, a direct method of determination has been prescribed. Examples have been employed to illustrate the use of both methods.

Introduction

The pressure behavior associated with a completely penetrating well in a uniformly thick, homogeneous, horizontal reservoir containing a single, slightly compressible, mobile fluid is described by the radial form of the diffusion equation. A useful asymptotic solution to this equation is the continuous line-source solution obtained from the basic formulation of Lord Kelvin.

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

In the derivation of Eq. 1, it is assumed that a well of infinitesimal radius is producing at a constant rate from an infinite reservoir. Because of the assumption of a vanishing well radius, the solution is valid only for large values of time. Horner discusses the limitations on the use of this equation; Elkins presents field data which support Horner's conclusions. If two or more wells are producing from the same reservoir, the resulting pressure distribution is obtained by the superposition of the solutions for the individual wells.

The object of this paper is to develop approximate techniques for determining the time and the place at which pressure disturbances originating from two adjacent wells begin to interact, or interfere, significantly. Two distinct approaches will be followed. First, the effect due to each well will be considered separately; then, the cumulative effect of the two wells will be examined.
A Method for Predicting Oxygen and Air Fireflooding Performance
Authors: Kumar Mridul , Garon A. M.
Published: December 2007

This paper presents a simplified procedure for predicting oxygen and air fireflooding performance. Results indicate that oxygen injection may substantially increase oil productivity so that projects may be completed more rapidly in productivity-limited reservoirs. However, oxygen/oil ratio (OOR), or cost per barrel of produced oil, is also higher with oxygen injection. Wet combustion may reduce OOR, especially for oxygen injection and high-pressure reservoirs.
Phase Equilibria in the SACROC Oil/CO2 System
Authors: Chaback J. J. , Williams M. L.
Published: December 2007

Phase-equilibrium measurements on SACROC oil/CO2 mixtures show this system to display liquid/vapor (L/V) criticality at a composition of 60 mol% CO2 with a pressure of 2,560 psia [17.65 MPa] and a temperature of 131°F [328.15 K]. In the vicinity of the critical region, liquid quality lines show three- and four-fold pressure multiplicities for a given composition. These multiplicities are a consequence of two effects: (1) the solvent power of supercritical CO2 to extract liquid-phase hydrocarbons at pressures below the saturation pressures of the overall mixtures and (2) the sensitivity of the L/V phase distribution to changes in pressure when the saturation pressure of the overall mixture is in the vicinity of its critical point.

On a CO2-free basis, retrograde liquid produced by flashing C02-enriched reservoir oil at 3,000 psia and 131°F [20.68 MPa and 328.15 K] was found to be similar in composition to other west Texas oils. Under conditions of repeated CO2 contact, this retrograde liquid was found to revaporize like other west Texas oils.
Calculation of Minimum Miscibility Pressure
Authors: Luks Kraemer D. , Turek Edward A. , Baker Lee E.
Published: December 2007

An algorithm is presented for the calculation of the thermodynamic minimum miscibility pressure (TMMP) consistent with an equation-of-state (EOS) -based fluid description. This algorithm handles both condensing and vaporizing miscibility mechanisms. TMMP calculations are included for a ternary mixture of pure components, as well as a reservoir-oil/CO2 system.
A Study of Displacement Efficiency in the Redwater Field
Authors: Willmon G.J.
Published: December 2007

WILLMON, G.J., IMPERIAL OIL LTD., EDMONTON, ALTA., CANADA

The Redwater field, Alberta, Canada, discovered by imperial Oil Ltd. in 1948, has now produced approximately 25 percent of the oil originally in place. The present position of the oil-water contact in this strong bottom-water drive pool has been interpreted from borehole contact measurements in observation wells and from an analysis of producing well behavior. Based on this information, and material balance calculations of water influx, the displacement efficiency of the encroaching water is 64 percent. This value has been confirmed by a study of the residual oil and connate water saturations of the two principal rock types in the reservoir. Connate water saturations above the present oil-water contact and residual oil saturations in the water-invaded region were measured directly in cores obtained from the reservoir. in this operation we used a low-invasion, oil-base coring fluid especially developed to minimize flushing of the core by mud filtrate, with a pressure-retaining core barrel to prevent loss of fluids due to depressuring as the core was brought to the surface. Connate water saturations were also determined from conventional oil-base cores and from restored-state capillary pressure tests run at reservoir temperature using reservoir fluids.

Introduction

The Redwater field (Fig. 1) which is located 35 miles northeast of the City of Edmonton in Alberta, Canada, was discovered in 1948. Development was rapid and by the end of 1951 over 900 wells had been drilled on 40-acre spacing. Most of these wells were completed openhole and generally had productivities in excess of 1,000 B/D following a small acid treatment. Production in Redwater is from the reefal Leduc limestone formation of the Woodbend group which is Upper Devonian in age. The Redwater reef covers an area of some 200,000 acres, but only the eastern or updip portion is productive. This part of the reef may be generally divided into three sections: a fore-reef zone, a biohermal zone in the center of the reef and a back-reef zone (Fig. 2). The fore-reef consists of two types of porosity: a zone of infilled clastics which has poor granular and chalky porosity, and a fragmental zone which has good granular porosity. The algal-biohermal zone has vuggy porosity while the back-reef zone has vuggy as well as some granular and chalky porosity. A detailed geological study of the core material from wells that penetrated the reef section through to the oil-water contact shows that 76 percent of the reservoir is composed of vuggy material which contains 60 percent of the total pore space. The remaining granular material contains 40 percent of the total pore volume.

JPT

P. 449ˆ
Effect of Pressure and Temperature on the Phase Behavior of Microemulsions
Authors: Skauge Arne , Fotland Per
Published: December 2007

The optimal salinity of three different anionic microemulsions was found to increase as a function of increased hydrostatic pressure. This is equivalent to a phase transition from an upper [Winsor II(+) (WII+)] microemulsion to a lower [Winsor II(-) (WII-)] microemulsion. Increased pressure induces a compressibility effect that is consistent with the observed phase transition. Increasing temperature also leads to increasing optimal salinity. Prediction of temperature effects is complicated by temperature-dependent interactions and entropic contributions caused by dispersion. Fluid models that account for temperature effects are needed; therefore, no attempt was made to develop a theoretical interpretation of this effect. The temperature range is 0 to 100°C, and the pressure was varied from 0.1 to 50 MPa.
Strategy for Alkaline/Polymer Flood Design With Berea and Reservoir-Rock Corefloods
Authors: Potts D. E. , Kuehne D. L.
Published: December 2007

This paper discusses the differences between fired Berea and reservoir-rock corefloods using an alkaline/polymer chemical system to recover an acidic California oil. Integrating Berea and reservoir-rock results was necessary in this study because of a limited supply of reservoir core material. Berea corefloods were adequate for initial screening and comparing different injection strategies but gave unrealistically high tertiary oil recoveries.

Both sodium/hydrogen and sodium/calcium ion exchanges were higher in reservoir rock than in Berea. Higher alkali concentrations were required in the reservoir cores to prevent chromatographic separation of alkali and polymer. Excessive exchange of hardness ions was a major cause of lower oil recovery in reservoir corefloods. Recovery improved dramatically when extensive preflushing was used to remove hardness.
Modeling of Three-Phase Liquid/Liquid Equilibria
Authors: Negahban Shahln , Paul Wlllhlte G. , Walas S. M.
Published: December 2007

This paper describes a model developed from thermodynamic principles for correlating phase behavior of two-and three-phase systems. The model is based on the representation of excess Gibbs energy with the UNIQUAC equation. A set of computational algorithms is described for estimating the UNIQUAC model parameters from regression of the equilibrium phase data and for predicting phase behavior throughout the entire composition range. The model has been tested for ternary systems and a pseudoternary system. Agreement between the measured and predicted data was excellent for most systems studied. The model was able to match the ternary phase behavior of two- and three-liquid-phase systems that have not been previously simulated. For ternary systems, the estimated UNIQUAC parameters from correlation of the three-phase tie-triangle data describe the phase behavior in both two- and three-phase regions.
Interpretation of a CO2/N2 Injection Field Test in a Moderately Fractured Carbonate Reservoir
Authors: Denoyelle L. , Bardon C. , Couve de Murville E.
Published: December 2007

The Coulommes-Vaucourtois field operated by Petrorep and located in the Paris basin is near abandonment. During the 25-year production span, one-fourth of the original oil in place (OOIP) has been produced by a strong bottomwater drive. Reservoir engineering studies and laboratory measurements have shown that the reservoir characteristics were favorable for CO2 injection.

In 1983, an injection well was drilled between four existing production wells. During the spring and summer of 1984, 49 × 106 scf [1.4 × 106 std m3] of CO2 followed by 54 × 106 scf [1.5 × 106 std m3] of N2 were injected. After 2½ months of CO2 injection, gas broke through into a well located far outside the pattern area. Shortly afterward, a producing well of the pattern showed a four-fold oil production increase as gas broke through. The three other wells exhibited smoother responses, with production of minute quantities of gas. Significant WOR decreases and oil production increases were observed. Gas analyses showed that the areal extent of the gas "bubble" was 15 to 20 times larger than the pattern area and that CO2 and N2 did not spread in the same directions.

This paper tries to match the test results with the geologic description, which shows the presence of fissures, and the production history of the reservoir, which exhibits a single-porosity behavior. It also stresses the difference between the incremental oil recovery resulting from the formation of an oil bank and that resulting from the gas-lift effect.
Size-Exclusion Chromatography in the Measurement of Concentration and Molecular Weight of Some EOR Polymers
Authors: Hunt James A. , Young T. S. , Green D. W. , Wlllhlte G. Paul
Published: December 2007

Procedures that involve the use of size exclusion chromatography (SEC) for the measurement of concentration and weight-averaged molecular weight, M¯w, of some EOR polymers were developed and found to give improved detectability, accuracy, and/or efficiency. The separation of polymer from low-molecular-weight impurities by size allows unambiguous detection of polymer properties such as concentration and M¯w. A combination of an SEC column of a pore size small enough to exclude the polymer totally and a mobile phase of ionic strength of 1.5 was found suitable for the separation of Polyacrylamide, partially hydrolyzed Polyacrylamide, cationic Polyacrylamide derivative, and xanthan polysaccharide from impurities.

Concentration detection of the separated polymer sample with a variable-wavelength ultraviolet (UV) detector was found to give superior detectability over detection by refractive index difference. A wavelength of 214 nm [2,140 Å] was used for the detection of these polymers on the basis of the spectra of samples purified by dialysis. With the active polymer assay determined by reprecipitation into a nonsolvent, the detection limit by UV was determined to be <0.1 μg/cm3 for Polyacrylamide and a cationic Polyacrylamide derivative, <0.2 μg/cm3 for partially hydrolyzed Polyacrylamide, and <0.7 μg/cm3 for a xanthan polysaccharide. The linear calibration range was up to 500 μg/cm3. The precision of the concentration measurement was better than 4% for Polyacrylamide and its derivative and 5% for polysaccharide at a 95% confidence level.

On-line measurement of M¯w of four different types of EOR polymers was made by connecting a low-angle laser-light-scattering (LALLS) detector to the SEC system and interfacing the detectors to a computer. The polymer sample was dispersed in the SEC column to give a concentration profile while being separated from the impurities. Continuous measurement of concentration and Rayleigh ratio of the dispersed slug by UV and LALLS detectors allows the calculation of the M¯w for the whole sample. The precision of this measurement is expected to be better than ±5% at a 95% confidence level. The M¯w determined for a Polyacrylamide molecular-weight standard was in good agreement with the reported value (0.98 million compared to 1 million). Such a procedure substantially minimizes the interference by dust and requires only a single injection, thereby improving both the accuracy and efficiency of the M¯w measurement.
Experimental and Theoretical Investigation of Time-Setting Polymer Gels in Porous Media
Authors: Hubbard S. , Roberts L. J. , Sorbie K. S.
Published: December 2007

This paper comprises studies of the kinetics of the xanthan/chromium gel system. The central objective of this work is to perform well-characterized core flow experiments with a simple gelling system that may then be mathematically simulated to obtain a detailed knowledge of the processes that are occurring. Gamma-labeled51 Cr is used so that in-situ chromium profiles may be observed during gel emplacement. These are required to distinguish between different kinetic/transport models because effluent profiles alone are insufficient for this purpose. A generalized multicomponent transport equation including terms describing the crosslinking reaction is used to simulate the experiments.
Development of a Mechanistic Foam Simulator: The Population Balance and Generation by Snap-Off
Authors: Falls A. H. , Hirasaki G. J. , Patzek T. W. , Gauglitz D. A. , Miller D. D. , Ratulowski T.
Published: December 2007

The mobility of a foam depends heavily on its texture, which is the distribution of bubble sizes in the dispersion. To incorporate this variable in a mechanistic simulator, the usual conservation equations are coupled with balances on the densities of flowing and stationary bubbles in the foam. This approach to modeling foam flow is illustrated with a simulation of a displacement in which foam is generated in situ by capillary snap-off.
Theoretical Stability Analysis of Flowing Oil Wells and Gas Lift Wells
Authors: Blick E. F. , Enga P. N. , Lin P. C.
Published: December 2007

The unsteady equations of motion for flow out of naturally flowing and gas-lift wells are derived and then solved by the Laplace transform method. This analysis produces a characteristic equation with coefficients that allow determination of the stability of a particular well.
Factors Affecting Waterflood Pattern Performance and Selection
Authors: Crawford Paul B.
Published: December 2007

A review is given of the results of early work showing sweep efficiency and steady-state injection rates for various types of patterns which may be used for waterflooding programs. This early work indicated that the sweep efficiency may be near 72 per cent for the five-spot pattern, 56 per cent for the direct, line-drive square pattern and may range from 45 to 90 per cent for the nine-spot pattern. The results were calculated on the basis that the mobility ratio was one, the reservoir was uniform and homogeneous, steady-state conditions existed, and gravity and capillary effects could be neglected. In actual flooding operations it is found that all reservoirs are heterogeneous, steady-state conditions do not exist, the mobility ratio is not one, and gravity and capillary phenomena undoubtedly play a role.

Theoretical calculations show that rock heterogeneities can cause the sweep efficiency of both the five-spot and direct, line-drive square patterns to vary from near zero to 100 per cent. Actual laboratory data have been obtained to show that the oil recovery by water flooding in depleted reservoirs results in the production of substantially the same quantity of oil for the five-spot, direct, line-drive square pattern and nine-spot pattern for a wide range of initial fluid saturations. The experimentally observed sweep efficiency of the five-spot pattern is shown to depend on the initial connate-water saturation and oil saturation.

Introduction

It is believed quite likely that many of the decisions affecting the selection of the pattern to be used in water flooding are based largely on information and conclusions which were made many years ago. The purpose of this paper is to review this early work and include recent work showing various factors which affect the performance of pattern-type floods. In the mid 1930's Muskat and his associates presented the first analytical solutions showing the sweep efficiency and injectivity for the five-spot, direct, line-drive, staggered, seven-spot and nine-spot patterns.
Steam-Foam Pilot Project in Guadalupe Field, California
Authors: Mohammadi Shane S. , McCollum Thomas J.
Published: December 2007

This paper describes the use of a formulated alkyl toluene sulfonate (ATS) as a foaming agent for improving mobility control in a mature steamdrive. Selection of ATS was based on laboratory experiments and a series of field injectivity tests. The field results show production response to both the injectivity tests and the 9 months of continuous ATS injection. Overall, ATS was found to improve steam mobility and result in incremental oil production.
Stability of Nickel-Coated Sand as Gravel-Pack Material for Thermal Wells
Authors: Sacuta Alec , Nguyen D. M. , Kissel G. A.
Published: December 2007

Laboratory flow tests have been carried out to study the stability of various nickel-coated sands under aqueous steam temperature and pH conditions that may exist in thermal recovery operations. Other gravel-pack materials tested include Ottawa sand, sintered bauxite, cement clinker, zirconium oxide, and nickel pellets. A comparison was made between the performances of these materials after exposure to identical thermal and hydrolytic conditions.

Test results indicate that nickel-coated sands are highly resistant to dissolution at temperatures as high as 300°C [570°F] and to solution pH's from 4.75 to 11. Weight losses measured after a 72-hour period were less than 1%. In contrast, weight losses from sintered bauxite, zirconium oxide, and Ottawa sand dissolution tests were 30 to 70 times higher under the same conditions. Cement clinker losses were in the intermediate range under alkaline conditions.

API standard crushing and acid-solubility tests for proppants also were performed on nickel-coated sands. These results were favorable in that they exceeded the recommended standards.

This study of nickel-coated sand stability and mechanical strength has demonstrated its high potential for application as either a gravel-pack material or proppant in thermal recovery operations.
The Influence of an Immobile or Mobile Saturation Upon Non-Darcy Compressible Flow of Real Gases in Propped Fractures (includes associated papers 19901 and 21622 )
Authors: Evans E.V. , Evans R.D.
Published: December 2007

The effects of immobile and mobile liquid saturations on the non-Darcy flow coefficient in propped fractures have been investigated. It was observed that an immobile liquid saturation of up to 20% PV can triple the non-Darcy flow coefficient and a small mobile liquid saturation will increase the non-Darcy flow coefficient by nearly an order of magnitude (over that of the dry case). The linear relationship between the logarithm of the non-Darcy flow coefficient and the logarithm of the proppant permeability for propped fractures, as proposed by Cooke, is shown to be invalid in the presence of an immobile or mobile liquid saturation. Constants are presented that can be used to obtain a more accurate approximation than has previously been available on the non-Darcy flow coefficient for single-phase flow in fractures propped with 10/20- and 20/40-mesh Ottawa sand. The experimental data obtained from this research are compared with those of others reported in the literature.

Introduction

In the past several years, there has been considerable interest in the optimization of flow in high-capacity gas wells. As a result of this interest, much attention has been directed toward the phenomenon of non-Darcy flow in porous media, which is very important in high-capacity gas wells.

Viscous flow, where the pressure gradient is proportional to flow velocity, is described by Darcy's equation:

In 1901, Forchheimer proposed an equation that described the additional pressure drop observed in non-Darcy flow at high flow velocities:

For predominantly viscous flow at low flow rates, the first term (or Darcy term) is important, while the second (or non-Darcy) term is negligible. But at higher flow rates, the non-Darcy term becomes significant and may eventually dominate the Darcy term.

Non-Darcy flow effects are much more significant in gas wells than oil wells, chiefly because of the higher flow velocities as a result of the much lower viscosity of the gas. This is especially true in hydraulically fractured gas wells because the velocity in the highly conductive fracture can be very high, resulting in large pressure drops owing to non-Darcy flow. Failure to consider these pressure drops leads to error in the design of hydraulic fracturing treatments and optimum well spacings, which reduces the efficiency of completion methods for these reservoirs.

Work has been reported by both Cooke and Koh to analyze the non-Darcy flow effect in hydraulic fractures quantitatively. However, both investigated the non-Darcy flow effect for single-phase gas flow only, with no immobile or mobile liquid saturation present.
Fracture-Gradient Prediction for Offshore Wells
Authors: Constant W. David , Bourgoyne A. T.
Published: December 2007

A key parameter required in the design of offshore wells is the fracture gradient of the formations to be penetrated. Existing fracture-gradient correlations have been developed largely on the basis of empirical data gathered on land and in the nearshore marine environment. They have been extended to deepwater areas through an equivalent intergranular stress concept. In this study, offshore data from several operators were obtained and a new fracture-gradient correlation procedure, based on an assumption of an exponential decline in average porosity with depth in normally pressured formations, was applied. The technique is ideally suited for implementation on a hand-held calculator or personal computer.
An Efficient Approach to Adaptive-Implicit Compositional Simulation With an Equation of State
Authors: Collins D. A. , Nghiem L. X. , Li Y. -K. , Grabonstotter J. E.
Published: December 2007

This paper describes a robust and efficient method for solving the equations corresponding to an equation-of-state (EOS) compositional model. The method is developed for an adaptive-implicit simulator in which only a small number of blocks need to be solved implicitly while the remaining blocks are solved explicitly. The salient features of the method are decoupling of the solution of flow equations from the flash calculations and switching from explicit to implicit formulations on the basis of a stability criterion. The performance of the adaptive-implicit approach is compared with that of a hilly implicit approach and an explicit-transmissibility approach. Results show that the adaptive-implicit approach is two to three times faster than the other two methods.
Application of the Horner Method for a Well Produced at a Constant Bottomhole Pressure
Authors: Kutasov I. M.
Published: December 2007

This paper presents an analytical solution to describe the pressure buildup for wells produced at constant bottomhole pressures (BHP's) in an infinite-acting reservoir. The buildup equation is derived on the basis of an initial condition approximating the pressure profile in the wellbore and in the reservoir at the time of shut-in.
Chemical and Physical Applications in Treating Produced-Fluid Emulsions of the Bell Creek Micellar/Polymer Flood
Authors: Johnson R. E. , Kennelly R. G. , Schwarz J. R.
Published: December 2007

Unforeseen chemical and physical treating problems arose in obtaining acceptable oil and water quality when produced micellar petroleum sulfonates created unique phase changes in the produced-fluid emulsion. Production facilities had to be modified continuously to adapt to the changing emulsion characteristics.

Although the production facilities were adapted to meet the changing phase concentrations of the produced fluid, their undersized capacity would not allow the retention time necessary to break the oil and water emulsions effectively in the presence of sulfonates. Conventional reverse chemicals and demulsifiers proved ineffective in treating the produced-fluid emulsion. New chemicals had to be developed to treat the sulfonated production in an environment conducive to the undersized production facilities.
Controls on Reservoir Quality in Tight Sandstones of the Travis Peak Formation, East Texas
Authors: Dutton Shirley P. , Finley Robert J.
Published: December 2007

Most sandstone in the gas-bearing Travis Peak formation has undergone compaction and extensive cementation during its burial history, resulting in low porosity and permeability. Diagenetically induced permeability variations are superimposed on original permeability variations produced by depositional processes. Sandstones range from fluvial-channel to shallow-marine, bay, and tidal-flat deposits. Three types of sandstone that differ in their original permeability distribution and lateral continuity are distinguished.

Travis Peak sandstones have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite, and the introduction of reservoir bitumen, were the most important causes of occlusion of primary porosity and reduction of permeability. Porosimeter measured porosity is the best predictor of permeability, and there is a statistically significant inverse correlation between total volume of cement and permeability. Permeability decreases with depth in the Travis Peak, suggesting that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation did not operate as completely on sediments deposited near the top of the formation.
Transient, Semisteady-State, and Steady-State Flow
Authors: Matthews C.S.
Published: December 2007

Technology Today Series articles provide useful summary informationon both classic and emerging concepts in petroleum engineering. Purpose:To provide the general reader with a basic understanding of a significantconcept, technique, or development within a specific area of technology.

Transient Flow

The pressure behavior at a well producing at constant flow rate is shown inFig.

During early producing times, the pressure behavior is essentially thesame as that in an infinite reservoir. This is the transient flow period. Thepressure at the well can be described by the following equation for most timesof practical interests:

well pressure = initial pressure - A [log (producing time)-B], where A and Bare constants.

During this period, the plot of well pressure vs. the logarithm of time willbe a straight line. On Cartesian coordinates (Fig. 1) the well pressure willdecline rapidly at first, then less rapidly with time.

Semisteady-State Flow

Curves of pressure in the reservoir vs. radial distance are shown in Fig. 2. If there is no flow across the drainage boundary as more producing timeelapses, the pressure behavior will begin to deviate producing time elapses, the pressure behavior will begin to deviate from the infinite-reservoir case. At a time shown as "late transient" in Fig. 2, the pressure at points insidethe drainage boundary will begin to decline at a rate higher than that in aninfinite reservoir. Finally, as shown in Fig. 2, if compressibility is smalland constant, the rate of pressure decline becomes equal through the drainageboundary. This is the semisteady-state period. All pressures in the drainagearea of the well now decrease by the same pressures in the drainage area of thewell now decrease by the same amount in a given time. The difference betweenaverage reservoir pressure and wellbore pressure remains constant during thisperiod. pressure and wellbore pressure remains constant during this period.

JPT

P. 385
Effect of Salt Composition on Clay Release in Berea Sandstones
Authors: Kia S. F. , Fogler H. Scott , Reed M. G. , Vaidya R. N.
Published: December 2007

The effect of salt composition of fluid injected into clay-bearing Berea sandstones on the water-sensitivity phenomenon has been studied. Experiments were carried out with solutions of sodium and/or calcium ions, which are the ions commonly found in the formation. Freshwater flooding of sandstones previously exposed to sodium salt solutions results in the release of clay particles and a drastic reduction in permeability. The permeability reduction is lessened, however, when calcium ions are also present in the salt solution. Formation damage is virtually eliminated when the solution composition is adjusted to give calcium surface coverages greater than a critical value of 75 %. The effect of the fluid composition on the damage process is explained by the double-layer interactions between the surface of the clay particles and the pore walls.
Comparison of Alternating Direction Explicit and Implicit Procedures in Two-Dimensional Flow Calculations
Authors: Coats K.H. , Terhune M.H.
Published: December 2007

Analysis and example applications have been performed to compare the accuracy and computing speed of alternating-direction explicit and implicit procedures (ADEP and ADIP) in numerical solution of reservoir fluid flow problems. ADIP yields significantly greater accuracy and requires about 60 per cent more computing time than ADEP, not 300 or 500 per cent more as reported elsewhere.

Introduction

Several recent papers discuss an alternating-direction explicit difference approximation (ADEP) to the diffusion equation. Example applications of ADEP and ADIP were reported to support conclusions that ADEP is comparable in accuracy to ADIP and requires one-fifth to one-third the computing time of ADIP. Applications of ADEP in calculation of two-phase flow in reservoirs was also proposed. This study was performed to compare further the relative merits of ADEP and ADIP in simulation of two-dimensional flow of one and two fluid phases in reservoirs. Since two-phase flow equations are often essentially elliptic rather than parabolic, the efficiency of ADEP in solving the elliptic equation was also examined.