bluuebunny/crossref_metadata_2025 huggingface dataset:
Miscible Displacement of Crude Oil by CO2/SO2 Mixtures
Authors: Sayegh S. G. , Krause F. F. , Fosti J. E.
Published: December 2007

Slim-tube displacement tests on a Pembina Cardium stock-tank oil using CO2, SO2, and four CO2/SO2 mixtures as the flooding agents demonstrated that the mixtures have lower minimum miscibility pressures- (MMP's) than both pure components. More oil was recovered from Berea sandstone cores when CO2 and a CO2/SO2 mixture were the flooding agents than when SO2 was used. Carbon dioxide and the CO2/SO2 mixture recovered comparable quantities of oil from Indiana limestone, while a severe loss of permeability was observed in the corresponding SO2 flood. Rock/fluid interactions characterized by mineral dissolution and precipitation were observed with all flooding agents in both rock types. New mineral phases formed abundantly in CO2/SO2 and SO2 corefloods of Indiana limestone and account for the severe loss of permeability noted in the latter corefloods.
The Impact of Oil Aromaticity on CO2 Flooding
Authors: Monger T. G.
Published: December 2007

This paper investigates the role of oil aromaticity in mis-cibility development and in the deposition of heavy hydrocarbons during CO2 flooding. The results of phase equilibrium measurements, compositional studies, sand-pack displacements, and consolidated corefloods are presented. Reservoir oil from the Brookhaven field and synthetic oils that model natural oil phase behavior are examined.

Phase compositional analyses of CO2/synthetic-oil mixtures in static PVT tests demonstrate that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. The results of tertiary corefloods performed ,with the synthetic oils show that CO2-flood oil displacement efficiency is also improved for the oil with higher aromatic content. These oil aromaticity influences are favorable.

Reservoir oil experiments show that a significant deposition of aromatic hydrocarbon material occurs when CO2 contacts highly asphaltic crude. Solid-phase formation was observed in phase equilibrium and displacement studies and led to severe plugging during linear flow through Berea cores. It is unclear how this solid phase will affect oil recovery on a reservoir scale.
An Accurate Numerical Technique for Solution of Convection-Diffusion Equations Without Numerical Dispersion
Authors: Fleming P. D. , Mansoori J.
Published: December 2007

A technique is presented that optimizes the accuracy of numerical solutions to convection-diffusion equations while eliminating the detrimental effects of numerical dispersion. Such equations arise in the simulation of EOR processes where front smearing as a result of numerical dispersion can distort the sharp displacement fronts that are such an important part of the processes. Such front smearing can also lead to false predictions of breakthrough times. More accurate, and hence more reliable, simulation of oil recovery processes should facilitate the assessment of the economics of EOR processes. Our technique uses a parameterized, third-order-correct algorithm and Fourier analysis. The Fourier analysis allows for analytical solutions of both the differential equation and the algorithm. This enables the formulation of a concise method for requiring that the numerical solution conforms as closely as possible to the correct solution. The method is illustrated by performing the optimization on several examples with different degrees of convection and dispersion. The solutions have no numerical dispersion and little truncation error. Our method can serve as a starting point for generalization to the solution of more complicated equations that occur in multicomponent, multiphase reservoir simulators. Suggestions for such generalizations are presented.
History Matching and Predicting GOR Behavior With Analytical Functions
Authors: Çhang D. M. , Haldorsen H. H. , Kirwan P. A.
Published: December 2007

A study initiated in 1982 examined gas production mechanisms in Prudhoe Bay. The results we report represent only a part of this effort and deal mainly with developing analytical techniques for GOR prediction.

Traditionally, a well's producing GOR is history matched and subsequently predicted by numerical reservoir simulation. We demonstrate how GOR history in gas underrunning and coning wells may be described by rate-, time-, and cumulative-offtake-dependent analytical functions. The coefficients in the equations are determined by a nonlinear parametric least-squares regression approach. For each well, after an empirical GOR match is achieved, the analytical functions are used for short-term GOR forecasting as an integral part of a comprehensive production availability forecast (PAF) computer model. We conclude that the parametric studies have produced viable analytical models for the matching and predicting of GOR in wells that have a history of high GOR.
Use of Pressure Derivative in Well-Test Interpretation
Authors: Bourdet Dominique , Ayoub J. A. , Plrard Y. M.
Published: December 2007

A well-test interpretation method based on the analysis of the time rate of pressure change and the actual pressure response is discussed. A differentiation algorithm is proposed, and several field examples illustrate how the method simplifies the analysis process, making interpretation of well tests easier and more accurate.
Pulse Testing With Wellbore Storage and Skin Effects
Authors: Ogbe David , Brigham William
Published: December 2007

A mathematical model for pulse testing is presented that examines the influence of wellbore storage and skin effects on pulse-test data. Two new correlations are provided for correcting the storage-dominated response amplitude and time lag to within 3% of the values expected without wellbore storage. The formation transmissivity and storativity can be determined from the corrected response amplitude and time lag. Proposed correlations are applicable to pulse testing with wellbore storage at the active or observation well. Examples illustrate use of the new correction technique.
Analysis of Pressure Buildup Data Influenced by Wellbore Phase Redistribution
Authors: Thompson Leslie G. , Jones Jack R. , Reynolds Albert C.
Published: December 2007

This work considers the influence of wellbore phase redistribution effects on the analysis of pressure buildup data.

First, we show that the pressure responses observed when phase redistribution effects exist consist of three distinct types and delineate the conditions under which each type exists. Second, we investigate the reliability of Fair's type curves for analyzing pressure data. Third, for each type of pressure response, we provide rules for determining when the conventional semilog straight line will begin on a semilog plot of pressure data vs. time.

We also consider general procedures that are based on Duhamel's principle for analyzing pressure data when sandface flow rates are also available. We discuss the application of these methods to analyze pressure data influenced by wellbore storage effects and investigate the effect that errors in the measured sandface rate have on the analysis.
Laboratory Study of Foaming Surfactants as Steam-Diverting Additives
Authors: Duerksen J. H.
Published: December 2007

Steam-foam processes to improve the efficiency of steam stimulation and steamflooding are being developed. The objectives of the laboratory study were to develop a steam-foam surfactant for field testing and to elucidate the mechanisms of steam-foam EOR. More than 50 commercial and experimental surfactants were screened for foamability; some were also screened for thermal stability at steamflood conditions.

Results showed that: many sulfonate surfactants have good thermal stability; foam requires constant regeneration to be effective; foamability varies inversely with temperature and directly with gas-phase nitrogen concentration; foamability is adversely affected by brine but is relatively insensitive to foam liquid volume fraction (LVF); and effective foam can be generated at reservoir flow rates. One of our proprietary sulfonates was selected for field testing on the basis of good thermal stability, superior foaming performance, significant reduction of steamflood residual oil saturation, and good solubility characteristics.
Optimal Injection Policies for Enhanced Oil Recovery: Part 2—Surfactant Flooding
Authors: Fathi Zohreh , Ramirez W. Fred
Published: December 2007

The optimal control theory of distributed-parameter systems has been applied to the problem of determining the best injection policy of a surfactant slug for a tertiary oil recovery chemical flood. The optimization criterion is to maximize the amount of oil recovered while minimizing the chemical cost. A steepest-descent gradient method was used as the computational approach to the solution of this dynamic optimization problem.

The performance of the algorithm was examined for the surfactant injection in a one-dimensional flooding problem. Two types of interfacial tension (IFT) behavior were considered. These are a Type A system where the IFT is a monotonically decreasing function with solute concentration and a Type B system where a minimum IFT occurs at a nominal surfactant concentration. For a Type A system, the shape of the optimal injection strategy was not unique; however, there is a unique optimum for the amount of surfactant needed. For a Type B system, the shape of the optimal injection as well as the amount injected was unique.
A Propellant-Based Technology for Multiple-Fracturing Wellbores To Enhance Gas Recovery: Application and Results in Devonian Shale
Authors: Cuderman J. F. , Northrop D. A.
Published: December 2007

A propellant-based technology has been developed that permits control of borehole pressurization to obtain multiple radial fractures around the wellbore. The objective is to connect nonintersecting natural fractures in a reservoir to the wellbore and to stimulate increased production. Techniques are presented for specifying the pressure pulse required for producing multiple fractures and for choosing propellants to achieve the desired pressure pulse. The multiple-fracturing technique was developed specifically for application in naturally fractured Devonian-shale gas reservoirs. A stimulation experiment in a Devonian-shale gas well successfully increased production from 6,700 to 22,000 cu ft/D [190 to 620 m3/d].
Fracture Diagnostics Results for the First Multiwell Experiment's Paludal Zone Stimulation
Authors: Hart C. M. , Engi D. , Fleming R. P. , Morris H. E.
Published: December 2007

A dual seismic system designed to monitor the growth of hydrofractures was fielded during the first stimulation at the U.S. DOE-sponsored Multiwell Experiment (MWX) during Dec. 1983. The MWX consists of three 8,000-ft [2438-m] wells drilled in low-permeability gas reservoirs. The wellbores are spaced less than 200 ft [61 m] apart over most of their length. With this configuration, microseismic activity created by the fracture treatment in one well could be observed with downhole geophone packages in the two adjacent wells.

Responses of the two triaxial borehole seismic tools (BST's) were monitored in real time. Upon detection of a seismic event of known location, orientations of the BST's were determined from the polarization of the compressional wave arrivals. From knowledge of the horizontal and vertical angles of incidence and an empirical estimate of seismic velocities, the locations of the fracture-induced seismic sources were estimated. Thus the location of the microseisms could be estimated and, in turn, the fracture height and extent inferred.

This paper presents the results of fracture diagnostics by use of this borehole seismic system for the first MWX stimulation. This information is compared and combined with the results obtained from other diagnostic techniques to provide an integrated estimate of the fracture geometry resulting from the stimulation.
Stress-Dependent Permeability and Porosity of Coal and Other Geologic Formations
Authors: McKee C. R. , Bumb A. C. , Koenig R. A.
Published: December 2007

Fundamental relationships have been derived for permeability, porosity, and density as a function of effective stress. The primary formation parameter is pore compressibility, and formulas are derived for both constant and variable pore compressibility. The grains are assumed to be incompressible. The Carman-Kozeny equation is assumed valid, and changes in tota porosity are proportional to changes in porosity effective stress.

These relationships fit laboratory and field data. Eight laboratory core tests (four coal, one granite, two sandstone, and one clay are used to illustrate the applicability of the permeability and porosity theory. Additional clay and shale core samples yielded an excellent match with the theoretical density formula. In cases in which the correlation coefficient was applicable, it was above 0.95. A number of field permeability data points from the Piceance, San Juan, and Black Warrior basins were fitted to the theory. The correlation coefficient ranged from 0.85 to 0.92 in these cases. Mudstone porosity data from borehole lithologic logs also yielded excellent fits to the theoretical formulation. Of the 13 examples reviewed, only 2 (which were core tests) required a variable pore compressibility.

Further improvements to the derived relationships will be required to include the effects of structurally enhanced permeability.
Generalized Minimum Miscibility Pressure Correlation
Authors: Glasø Ø.
Published: December 2007

This paper presents a generalized correlation for predicting the minimum miscibility pressure (MMP) required for multicontact miscible displacement of reservoir fluids by hydrocarbon, CO2, or N2 gas.

The equations are derived from graphical correlations given by Benham et al.1 and give MMP as a function of reservoir temperature, C7+ molecular weight of the oil, mole percent methane in the injection gas, and the molecular weight of the intermediates (C2 through C6) in the gas. CO2 and N2 are represented in the current correlation by "equivalent" methane/propane- and methane/ethane-mixture injection gases, respectively.

The study shows that for hydrocarbon systems, paraffinicity has an effect on MMP. In the equations, the C7+ molecular weight of the oil is corrected to a K factor of 11.95, thereby accounting for varying paraffinicity.

An additional temperature effect on N2 MMP is related to the API gravity of the oil. The N2 correlation, however, is not tested against measured MMP data other than those used to develop the equation and should be used with care.

A correlation that accounts for the additional effect on CO2 MMP caused by the presence of intermediate components in the reservoir oil is presented.

Predicted MMP's from the correlations developed are compared to experimental slim-tube displacement data from the literature arid from our displacement tests on North Sea gas/oil systems. These displacement tests have been performed with a packed slim tube, where the effect of viscous fingering is reduced to a minimum.
Floating Drilling-Barge Operations
Authors: Nicolson K.M.
Published: December 2007

The successful operation of floating drilling barges has established that this type equipment will find general acceptance for drilling and completing offshore wells. The floating barge supplements, rather than replaces, the more conventional offshore equipment and allows a much broader scope of operations. The application of floating-barge drilling has been somewhat restricted in the past while equipment development was progressing. The outlook for the future, however, is quite broad. Present stage of development favors exploratory drilling where probability of completion is small. As completion and production techniques are improved, development drilling will become more attractive. Applications will be most favorable for conditions which are expensive with conventional equipment such as deep water or very soft bottom. The inherent economy of the floating-barge method will also bring this equipment into competition with conventional methods in shallow water. Floating-barge drilling operations have been performed by the Standard Oil Co. of California offshore of California, the Gulf Coast, Trinidad and Ecuador. The results have compared favorably with conventional offshore drilling methods, and costs have been lower. The next indicated phase of development is completion and production. The problems here are of greater magnitude than those already solved concerning drilling. The economic incentive demonstrated in past performance, assures that these problems will be attacked and eventually solved.

Introduction

The increasing number of successful, floating drilling-barge operations has established that this method will find general acceptance for the drilling and completion of offshore wells. The floating drill barge supplements, rather than replaces, conventional offshore equipment and broadens the scope of operations to a considerable degree. It is the purpose of this paper to review the experience of floating drilling-barge operations to date, outline the limitations and advantages associated with this method and indicate the possible future scope of application of this type operation.
Prefracture Testing in Tight Gas Reservoirs
Authors: Kabir C. S. , Hasan A. R.
Published: December 2007

A pressure transient test run before a fracture job in a tight gas reservoir is an invaluable part of the total testing program necessary to evaluate the efficacy of such a fracture job. This paper addresses the problem of treating the pressure-sensitive viscosity/compressibility (μct) product while analyzing the prefracture test data.

A large variation of μct with pressure occurs in a typical low-flow-capacity (kh) well. These pressure-sensitive gas properties lead to a nonlinear gas flow equation. Use of the pseudopressure function partially linearizes the gas flow equation, while introduction of pseudotime and pseudopressure functions causes the complete linearization. This linearization permits a valid type-curve analysis. However, a semianalytical solution of the diffusivity equation that considers only the pseudopressure function suggests that the problem of nonlinearity is insignificant.

We show that both the contentions presented in the literature are correct: complete linearization is required when the data are affected by wellbore storage, whereas partial linearization is quite adequate for a valid semilog analysis.

Large variations of the μct product also cause the wellbore storage to last a long time, even in the presence of a downhole shut-in tool. We demonstrate that the convolution approach, for which the sandface rate measurement is required, shortens the testing time by orders of magnitude and yields the desired formation parameters of kh and skin.
Case History of Acid Stimulation in the Fryburg Zone, Western North Dakota
Authors: Shreder L. A.
Published: December 2007

Acid stimulation has been used successfully in the Mystery Creek leases in the TR field, Fryburg zone of the Mission Canyon formation in western North Dakota. The Fryburg zone is a carbonate reservoir consisting of alternating layers of limestone and dolomite. Since 1982, the Fryburg wells have undergone an acid-stimulation program that has resulted in substantial increases in oil and gas production.
Time and Shear Effects on Rheological Properties of Crosslinked Fluids—An Evaluation Method
Authors: Shah Subhash N. , Watters Larry T.
Published: December 2007

This paper presents a new method for evaluating time and shear effects on flow properties of crosslinked polymer fluids. An apparatus has been designed and assembled to simulate crosslinking the fluid on the fly and fluid flowing down the well, through perforations, and in the fracture. Laminar and turbulent flow properties can be evaluated simultaneously.

The results—such as turbulent friction pressure, effect of pipe and perforation shear on the rheological properties of fluids in the fracture, viscous properties in the fracture, and temperature stability of fluids—can be obtained from the data gathered with the apparatus. Several different polymer-crosslinker systems have been evaluated. Results show that a hydroxypropyl guar (HPG)/delayed titanate crosslinker system exhibits practically base-gel friction pressure in turbulent flow, excellent viscous properties, and good temperature stability in fracture flow. Perforation shear has almost no effect on the rheological properties of the HPG/delayed crosslinker system. Also, this system exhibits better viscous properties at lower fracture flow rates.
Wellbore Heat Transmission and Pressure Drop for Steam/Water Injection and Geothermal Production: A Simple Solution Technique
Authors: Durrant A. J. , Thambynayagam R. K. M.
Published: December 2007

This paper presents a straightforward iterative procedure for the wellbore heat transmission problem during upward or downward flow of a steam/water mixture. The mathematical model is taken directly from the literature and is based on material and momentum balances in the wellbore and a heat balance on the entire system including the surrounding media. The transient heat conduction equation is solved analytically by the application of successive Fourier and Laplace transforms. A simple superpositioning in the time domain permits a matching procedure similar to multiphase flow calculations in pipelines. This is in contrast to standard numerical schemes that involve the direct solution of a set of algebraic and ordinary and partial differential equations typical of reservoir stimulation. The pressure-drop calculations in the wellbore account for the slip concept and the prevailing flow regimes by means of standard two-phase correlations. The validity of the method is demonstrated by comparison with results of other numerical simulation studies and actual field data for both steam injection and geothermal production.
A General Analysis of Fracturing Pressure Decline With Application to Three Models
Authors: Nolte K. G.
Published: December 2007

This paper presents the basis for determining the parameters that quantify the creation of a hydraulic fracture from the fracturing pressure decline after a fracture treatment. The analyses are generally applicable to the standard models used in fracture design—i.e., Perkins-Kern (PK), Khristianovitch-Geertsma- de Klerk (KGD), and the penny or radial models. The parameters that can be determined, as shown in an example, include the fracture's dimensions, fluid-loss coefficients, fluid efficiency, and fracture closure time.
Unsteady-State Spherical Flow With Storage and Skin
Authors: Joseph Jeffrey A. , Koederitz Leonard F.
Published: December 2007

This paper presents short-time interpretation methods for radial-spherical (or radial-hemispherical) flow in homogeneous and isotropic reservoirs inclusive of wellbore storage, wellbore phase redistribution, and damage skin effects. New dimensionless groups are introduced to facilitate the classic transformation from radial flow in the sphere to linear flow in the rod. Analytical expressions, type curves (in log-log and semilog format), and tabulated solutions are presented, both in terms of pressure and rate, for all flow problems considered. A new empirical equation to estimate the duration of wellbore and near-wellbore effects under spherical flow is also proposed.
MONA, An Accurate Two-Phase Well Flow Model Based on Phase Slippage
Authors: Asheim Harald
Published: December 2007

In two-phase flow, both holdup and pressure loss are related to interfacial slippage. A computation model based on phase slippage has been developed that allows a priori estimation of the slip parameter values. By parameter optimization, the accuracy of the model can be improved. The model was tested with production-well data from the Forties and the Ekofisk fields and flowline data from Prudhoe Bay. It was considerably more accurate than the standard models that were used for comparison.
A New Method of Restoring Water Injection Capacity to Wells Plugged with Iron Sulfide and Free Sulfur
Authors: Barnard Paul
Published: December 2007

A method has been developed to restore injection capacity to wells that have been damaged by plugging with iron sulfide and free sulfur. It consists of(1) making the plugging material water-wet with a non-ionic detergent, (2) acidizing to remove the iron salts, (3) making the remaining free sulfur oil-wet with a surfactant, (4) dissolving the free sulfur with a suitable solvent, and (5) flushing all fluids into the formation.

The order of applying these steps should not be varied. However, the mechanics of applying the treatment and the necessary volume of chemicals depend on well characteristics, operating conditions and economics. Certain safety rules and precautions must be followed when these chemicals are used.

This treatment was devised when standard methods such as acidization, fracturing, or recompletion were not successful in restoring injectivity to wells plugged with iron sulfide. The problem was approached on the theoretical basis of the chemistry of the injection fluids in the well. Field tests have proved the method to be practical, economical and successful.

It should be emphasized that this is not a permanent cure. It will only restore injection capacity. Well plugging can be prevented by stabilizing the injection water before injection. Since it is difficult to stabilize waters containing iron sulfide, economics should determine whether stabilization is more desirable than repeated well clean-out. Usually, the most economical solution is partial stabilization to reduce the frequency of well treatment.

Introduction

The industry has always been plagued with plugging difficulties when injecting waters containing sulfides into waterflood or disposal wells. Ordinary remedial measures such as acidization, fracturing, reperforation, recompletion, or backwashing were partially successful for the first few treatments. Apparently a portion of the plugging material remained in the wellbore following these treatments because each successive treatment became less effective. This restricted injectivity forced curtailment of production. Therefore, we needed to determine the reasons for this ineffective clean-up in order to improve treatment or to design new methods. Extensive laboratory and field study led to a method which proved to be satisfactory in one type of injection well. During the past year, this method has been modified and improved to make it applicable to various types of injection wells.
Use of MWD for Turbodrill Performance Optimization as a Means To Improve ROP
Authors: de Bruijn H. J. , Kemp A. J. , van Dongen J. C. M.
Published: December 2007

Field tests were carried out to monitor the performance of turbodrills driving polycrystalline-diamond-compact (PDC) bits. Separate tests with miid-pulse measurement-while-drilling (MWD) tools involved measurement of the rotational speed of the bit and downhole torque. The results show that turbodrills are not always operated at the manufacturer's claimed maximum efficiency, resulting in disappointing rates of penetration (ROP's). On the basis of observed reduction in turbodrill runaway speed from the manufacturer's value, it is estimated that thrust-bearing friction can consume up to 50% of the net turbodrill power output.

In an 8½-in. [21.6-cm] hole, improvements in ROP of up to 100% could be obtained by use of the measured bit rotational speeds to monitor power output of the turbodrill. It was difficult to control bit rotational speed from the weight on bit (WOB), however, at the low average WOB's necessary for current PDC bit designs.

It was apparent that the measurement of downhole torque has limited field application because no distinction can be made between true reactive torque at the bit and additional torque from the turbodrill's thrust bearings and stabilizers.

The possible effect of flow-rate variations through the turbodrill during negative mud pulses was investigated with a flow loop. This proved to be insignificant.
Low-Toxicity Oil Muds: A Knowledge of Downhole Rheological Behavior Assists Successful Field Application
Authors: Bailey T. J. , Bern P. A. , McEwan F.
Published: December 2007

The introduction of oil-based drilling fluids has led to significant improvements in drilling efficiency for many North Sea operations. The original formulations that were based on diesel are generally being replaced by the lower-toxicity mineral oils. One factor crucial to the successful application of mineral oils has been a knowledge of their downhole rheological characteristics. This paper describes a purpose-built viscometer capable of simulating realistic downhole temperature (300°C [572°F]) and pressure (100 MPa [1,000 bar]) conditions. Results from this study are used to indicate how surface-fluid rheologies can be tailored to provide adequate downhole viscosities, thus reducing total system pressure losses.
Numerical Simulation Results for the Electrical Heating of Athabasca Oil-Sand Formations
Authors: Hiebert A. D. , Vermeulen F. E. , Chute F. S. , Capjack C. E.
Published: December 2007

Electrical preheating has been proposed as a method of overcoming many of the problems inherent in using a steamdrive in very viscous oil reservoirs—such as the Athabasca oil sands of Alberta, Canada. A numerical simulator was developed to study the process of electrically heating oil reservoirs consisting of several layers with different electrical resistivities. This simulator was used to study the effects of electrode placement on the final temperature contours resulting from electrically heating realistic reservoirs. Three cases illustrating the development of a hot-oil communication path low in the formation are described.
Calculation of High Temperature Crude-Oil/Water/Vapor Separations Using Simulated Distillation Data
Authors: Langhoff J. A. , Wu C. H.
Published: December 2007

High-temperature crude-oil/water/vapor separation takes place in steamflooding and in-situ combustion processes. It also takes place in hydrocarbon recovery from deep volatile oil and condensate reservoirs. A practical procedure that uses the Holland and Welch method and sirilulated distillation data was developed to calculate crude-oil/water/vapor separations at 387 and 456°F [197 and 236°C]. The overhead yields obtained from the calculations were expressed as a function of the steam distillation factor. The Vw/Voi results were compared with laboratory crude-oil steam distillation data. The approach satisfactorily predicted the overhead yields of 13 out of 16 crude oils with an average error of 12% (±3.6% in yield). This is within experimental error of crude-oil steam distillation.

Twelve pseudocomponents of crude oils were selected and characterized with simulated distillation data for the calculations. The physical properties of the pseudocomponents were determined from existing correlations and from matching laboratory steam distillation data. The use of simulated distillation data eliminates the uncertainty and assumptions normally involved in the selection of crude oil pseudocomponents with U.S. Bureau of Mines distillation data, and thus improves the reliability of the proposed computational approach.

The proposed approach eliminates the need to conduct experimental steam distillation tests if simulated crude oil distillation data are available. It is easy and fast to calculate the overhead yields ahd densities without use of the equation of state (EOS) and uncertain pseudocomponent critical properties and interaction parameters. The proposed approach will provide useful information for the numerical simulation and design of thermal recovery processes and for the prediction of hydrocarbon recovery from high-temperature volatile oil and condensate reservoirs.
A Composite System Solution in Elliptic Flow Geometry
Authors: Obüt S. Tanju , Ertekin Turgay
Published: December 2007

A new well-test analysis technique that can be used in locating the flood-front position during secondary and/or tertiary recovery processes with the data taken on vertically fractured injection wells is described. In the development, an infinite-conductivity vertical fracture was assumed, together with the assumption of a stationary position for the flood front during the testing period.
Comparative Evaluation of Vertical and Horizontal Drainage Wells for the Degasification of Coal Seams
Authors: King Gregory R. , Ertekin Turgay
Published: December 2007

A two-phase, single-well, numerical simulator capable of modeling the performance of either vertical or horizontal wells (drilled from a shaft bottom) has been developed. For vertical wells, the model allows for the prediction of postfracture performance. The hydraulically induced fractures can be specified as either infinite conductivity or finite (constant) conductivity, so that conventional, as well as massive, treatments can be modeled. Although the simulator allows for multiple fracture wings, only the classic, two-wing, hydraulic fracture is considered in this paper.

For coal seams, the formation to be modeled is a dual-porosity reservoir. The natural fracture network of the coal seam (the butt and face cleat) has been assigned an effective porosity and permeability. A time-dependent, quasisteady-state sorption term has been included to describe the phenomenon of gas desorbing from the formation matrix and diffusing into the fracture network.

The model was used to sift through the many parameters associated with the two production schemes to determine those that affect production most significantly. Where possible, these parameters, along with their effects, are put into dimensionless form. Type curves for estimating recovery were generated from these dimensionless groups. Finally, a comparison between the performance of vertical and horizontal boreholes was made with actual field data.
Review of U.S. Oil and Gas Production 1964
Authors: Lindsly R.R.
Published: December 2007

Editor's Note: R. R. Lindsly, with Phillips Petroleum Co. in Bartlesville, Okla., heads one of SPE's hardest-working but least-publicized standing committees. As chairman and domestic vice-chairman of the Society's Production Review Committee for 1965, Lindsly has collaborated with Foreign Vice-Chairman James E. Fender, of Mobil International Oil in New York City, to gather vital data from throughout the Free World for inclusion in IOSA's INTERNATIONAL OIL AND GAS DEVELOPMENT, YEAR BOOK 1965, a two-part volume covering worldwide exploration and production during 1964. The following article by Lindsly will appear in Part 2 on Production, expected to be available for sale in early December.

Introduction

The petroleum industry supplies approximately 74 per cent of the nation's energy requirements, and its domestic capital expenditures total more than $6 billion annually. The producing segment of the industry accounts for around 65 per cent of these capital expenditures, and domestic production amounts to approximately 80 per cent of the nation's liquid raw material supply. The producing industry, which is important to national security, had reserve producing capacity Jan. 1, 1965, of approximately 2.8 million B/D of crude oil and natural gas liquids, based on IPAA estimates. The productive capacity of natural gas on Jan. 1, 1964, as estimated by NPC in its 1965 report, indicates 57.7 billion cu ft/day of capacity over and above the average production for 1963.Total petroleum demand in 1964 averaged 11.06 million B/D, up 302,000 bbl, or 2.8 per cent from 1963.Gasoline, which makes up approximately 42 per cent of demand, experienced a healthy 4.2 per cent increase. Total petroleum supply in 1964 averaged 11,071,000 B/D. of this total, domestic crude production (69.2 per cent of supply) averaged 7,664,000 B/D, up 1.6 per cent; natural gas liquids production (10.4 per cent of supply) averaged 1,147,000 B/D, up 4.5 per cent; and imports of crude and products (20.4 per cent of supply) averaged 2,260,000 B/D, up 6.5 per cent from 1963.Demand for natural gas continued its upward trend in 1964 as reflected by production, which totaled 15.3 trillion cu ft, or 5.5 per cent increase over the 14.5 trillion cu ft produced in 1963.Fig. 1 shows supply trends of petroleum and natural gas for the past 10 years (1955 to 1964).

Reserves

To supply the ever-increasing demand for petroleum and natural gas, adequate reserves must be maintained through continuous exploratory efforts, development drilling, and improved recovery techniques. Therefore, it is pertinent to note the changes in underground inventory during 1964.Proved reserves of crude oil at year-end 1964 stood at 31 billion bbl, up less than 0.1 per cent from the previous year. This upturn, though slight, contrasts with a net decrease in crude reserves in three of the four previous years.

JPT

P. 889ˆ
Rapid Measurement of Minimum Miscibility Pressure With the Rising-Bubble Apparatus
Authors: Christiansen Richard L. , Haines Hiemi Kim
Published: December 2007

The minimum miscibility pressure (MMP) for a gas/oil pair can be measured within 1 hour with the rising-bubble apparatus (RBA). Development of miscibility between a gas bubble and an oil can be observed visually. The measurements of the MMP with the RBA compare favorably with those based on slim-tube experiments and predictions from phase-behavior studies.
Prediction of CO2 Flood Performance: Interaction of Phase Behavior With Microscopic Pore Structure Heterogeneity
Authors: Dai K. K. , Orr F. M.
Published: December 2007

This paper describes simulations of the effects of microscopic heterogeneity present in rock pore structures or resulting from high water saturations on the performance of one-dimensional (1D) CO2 floods. In the simulations, microscopic heterogeneity was represented by dividing the nonaqueous portion of the pore space into flowing, dendritic, and trapped fractions. A 1D simulator, previously shown to model quantitatively the effects of phase behavior in slim-tube displacements, was modified to include effects of the isolated or trapped fraction unavailable for mixing with injected fluids and the dendritic fraction, which exchanges material with the flowing fraction by mass transfer. Model formulation, numerical solution, and validation tests are described.

Results of simulations with no water present indicate that performance of a 1D CO2 flood is sensitive to deviations from complete local mixing. Calculated oil recovery decreases as the flowing fraction, Peclet number, and Damkohler number decrease. Comparisons of calculated and measured residual oil saturations (ROS's) in CO2 corefloods support this observation. Simulations of secondary and tertiary displacements by continuous CO2 injection and alternate and simultaneous injection of CO2 and water are compared. Performance of secondary displacements is not strongly affected by incomplete local mixing. In tertiary displacements, however, total oil recovery and the rate of recovery are reduced if effects of trapped and dendritic saturations are included.
Numerical Simulation of Sandstone Reservoir Models
Authors: Poston S. W. , Gross S. J.
Published: December 2007

Sandstone reservoir rocks are not necessarily formed by random natural occurrences. These rocks are usually the result of an ordered series of depositional events that may be represented by known depositional environments. A review of the geological literature has shown that these environments are well documented by modem examples. Sand bodies found in sandstone reservoirs may be broadly divided into regressive, transgressive, serrated, and homogeneous sequences.

This paper discusses the results of a cross-sectional computer study on the depletion of an oil reservoir composed of the four basic depositional models. The studies indicate that recoveries under pressure depletion or water-drive conditions may be greatly affected by the type of sand body present in the reservoir. Geologists and engineers must be aware of the effect of depositional environment on ultimate recovery from oil reservoirs. This knowledge illustrates the usefulness of electric log and core analysis for furnishing an insight into the major flow paths in a reservoir. Additionally, the study shows how the depositional history of a reservoir may affect ultimate recovery.
An Approximate Model With Physically Interpretable Parameters for Representing Miscible Viscous Fingering
Authors: Fayers F. John
Published: December 2007

An approximate viscous fingering model is derived with physically related parameters. Plausible assumptions are made about some limits on finger fluid mixing, and the use of a fingering function is suggested. It is shown that for the horizontal linear problem, a hyperbolic partial-differential equation governs the solvent fractional flow behavior. Satisfactory agreement with classic miscible displacement experiments is demonstrated for a reasonable choice of parameters. When gravity is introduced into the equation, the same model gives adequate agreement with the rate dependency observed in a vertical displacement experiment. Recommendations are made concerning extension of the model for use in three-dimensional (3D) compositional simulations.
Calculation of Water Influx for Bottomwater Drive Reservoirs
Authors: Allard D. R. , Chen S. M.
Published: December 2007

This paper presents a new water influx model that differs from traditional approaches in that it includes the effect of vertical flow at the reservoir/aquifer interface. The results are presented in the form of dimensionless groups, which makes the model readily applicable to a wide range of systems. The paper concludes with a sample calculation showing how the predictions of this new model can be significantly different from those of conventional radial flow models.
Dynamic Fluid-Loss Characteristics of CO2-Foam Fracturing Fluids
Authors: Harris Phillip C.
Published: December 2007

High-quality CO2-foam fracturing has recently become a very popular stimulation tool. Dynamic fluid-loss measurements were performed on a broad range of core samples to measure the effect of several parameters on CO2-foam fluid-loss coefficients. The parameters tested were core permeability, foam quality, gelling-agent concentration in the aqueous phase, and core temperature. Measurements were performed in a recirculating fluid-flow test loop.

A variation of one order of magnitude in CIII for two-orders-of-magnitude change in permeability was observed from 0.02 to 10 md. For permeability below 1 md, foam quality had no effect. Fluid-loss control improved as gelling agent concentration in the liquid phase increased. CIII increased with increasing temperature as a result of temperature thinning of the aqueous phase.

Passage of CO2 foams through porous media caused a significant modification in quality from the input to the effluent fluid. The ratio of liquid to gas passing through the core was measured as a function of core permeability, quality, and gelling-agent concentration. In low-permeability cores, flow proceeded as separate phases, whereas in higher-permeability cores, the foam structure remained more nearly intact.

CO2 foams were found to be very similar to N2 foams with respect to the above parameters.
Cycling With Air and Other Nonhydrocarbon Gases
Authors: Striefel M. A. , Ahmed T. H. , Cady G. V.
Published: December 2007

Injecting lean gas into condensate reservoirs is a practice currently used to increase recovery. The process reduces condensation and increases liquid recovery by revaporization. However, delaying natural gas sales for long periods of time is economically unattractive. The purpose of this paper is to investigate the effectiveness of nonhydrocarbon gases (i.e., air, N2, and CO2) for improving recovery from retrograde condensate reservoirs. A compositional model that uses the Peng-Robinson equation of state (PR-EOS) was developed to evaluate condensate reservoir performance. A 15-component hydrocarbon system and extensive experimental data were used in the study. The simulator was tuned to match the available experimental data. The model shows that nonhydrocarbon gases can vaporize hydrocarbon liquids effectively, with CO2 the most effective nonhydrocarbon for vaporizing heavy fractions.
Introduction of a Pore Geometrical Factor Defined by the Capillary Pressure Curve
Authors: Thomeer J.H.M.
Published: December 2007

A method is presented that provides a mathematical description of capillary pressure curves and, probably, of differences in pore geometry of samples. The technique is based on the observation that the location and shape of a capillary pressure curve reflect characteristics of the pore structure of the sample.

Introduction

It has been noted that the observed differences in shape and location of capillary pressure curves reflect some basic properties regarding the pore geometry of the samples. For example, according to basic concepts of capillarity, the following statements can be made regarding the location and shape of a capillary pressure curve.

The location of the curve with respect to the (Vb)pc and Pc axes is a measure of the interconnected pore volume and of the cross-sectional area of the pore first entered by mercury, respectively. The shape of the curve depends on the interconnection of the pores and the sorting of the pore sizes.

It has been the object of this study to use this information as a starting point in an attempt to find a unique mathematical description of the Pc - (Vb)Pc relations of different samples. It may be expected that parameters in such a relation can then be used to describe differences in pore geometry of these samples. For a practical description of the Pc - (Vb)Pc relation, however, it appears desirable to describe each curve (i.e., each sample) by a limited number of parameters so that the curves taken from all samples form a family, each member of which is uniquely determined by one single combination of values of all parameters.
A Correlation for Interference Testing With Wellbore-Storage and Skin Effects
Authors: Ogbe D. O. , Brigham W. E.
Published: December 2007

A new correlation and set of pressure-response and pressure-derivative type curves are presented for interference test analysis. The influence of wellbore storage and skin effects at active and observation wells on interference pressure response is examined. In the case of wellbore storage and skin in one well, the correlating parameter [CDe2s]CD/rD2 is used to combine wellbore storage and skin variables in a way that makes it possible to display, on a single type curve, all interference test data that would ordinarily require a number of type curves for various combinations of CD/rD2 and CDe2s. The product of the correlating parameter is used when wellbore storage and skin effects are active at both wells. The difference in the shapes of the single-well storage type curves compared to the two-well storage case at early times can be used as a diagnostic feature in interference testing.
Three-Cone Bit Selection With Sonic Logs
Authors: Mason Kenneth L.
Published: December 2007

Formation hardness and compressive strength correlate with calculated shear travel time, which has led to the development of a correlation between economical roller-cone bit selection and calculated shear travel time. Upper and lower shear-travel-time limits are then placed on steel-tooth and tungsten-carbide bits as a guide to help minimize the cost per foot when a well is preplanned.
Effects of Thermal and Mechanical Loading on PDC Bit Life
Authors: Glowka D. A. , Stone C. M.
Published: December 2007

Results of numerical analyses to determine the effects of thermal and mechanical loading on the integrity of poly crystalline-diamond-compact (PDC) cutters during deep-hole drilling are presented. Cutter-temperature distributions for several drilling environments are combined with the appropriate mechanical cutting loads to predict stress distributions for the study of cutter wear mechanisms. A discussion of wear mechanisms acting on the cutting structure is presented. Suggestions based on these analyses are presented for the operation of PDC bits to increase bit life in hard, abrasive rock drilling. Microstructural design considerations for the cemented carbide that supports the diamond layer are also discussed.