bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching and Predicting GOR Behavior With Analytical Functions
Authors: Çhang D. M. , Haldorsen H. H. , Kirwan P. A. 
Published: December 2007

SummaryA 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

SummaryA 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

Summary
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

Summary
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

Summary
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

Abstract
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

Summary
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

Summary
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

Summary
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

Abstract
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

Abstract
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

Summary
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

Summary
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

Summary
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

Summary
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

SummaryThis 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

AbstractThis 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

Summary
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

Abstract
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.