bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Data Analysis Brings Large Benefits in Hydraulic Fracturing in a Moderate Permeability Oil Reservoir in Kazakhstan
Authors: Shaoul Josef R. , Folmar Edgar , Arman J. V. , van Gijtenbeek Klaas 
Published: December 2007

Abstract
Real-Data/Real-Time analysis of fracture stimulation data is a valuable tool for fracture engineering in the field, especially in fields where there is a large variation in well to well behaviour. The differences in behaviour can be due to reservoir heterogeneity, differences in depletion, lateral heterogeneity, different fracture growth mechanisms and varying completion types. In such cases, a standard "cookbook" fracture design is not possible.
In this paper, the authors present a case study based on 12 fracture treatments in 10 wells in the Arman field, a moderate permeability oil reservoir with significant water and gas production. The field is also under water flood in some zones, leading to large variations in reservoir pressure from zone to zone. We first look at using real-data analysis to calibrate a fracture growth model by comparing predicted results for a fracture treatment design with the actual pressure data recorded during the treatment. We also give examples of dealing with such real-world issues as operational problems, reservoir heterogeneity, tortuosity, multiple fractures, high spurt loss and calibration of tip-screenout behaviour, and show the successful application of a fracture modelling tool to deal with these issues.
Hydraulic Fracture Spacing in Horizontal Chalk Producers: The South Arne Field
Authors: Wesnæs Ken , Hasbo Klaus , Ginty William R. 
Published: December 2007

Abstract
Horizontal producers completed with multiple hydraulic fractures have proved cost effective in several North Sea low permeability chalk fields1,2,3,6,7. This paper describes the evaluation of the optimal stimulation type and spacing for five South Arne pre-drilled producers that were planned to fill the process design capacity.
The initial design work consisted of both analytical and numerical simulation methods. These were calibrated using a South Arne porosity to permeability transform, stimulation design software predicted fracture geometries and offset field production experience.
Most wells were drilled in a direction that was parallel to the hydraulic fracture orientation. Propped fractures placed in a near tip to tip fashion were found to be the optimal design. Based on this and the initial production data a batch completion operation was performed and the platform capacity reached. A comparison with two years of production history has been made which supports the main initial design assumptions and results. Earlier papers on the stimulation and completion work of the South Arne development1,6,7 are complimented by the reservoir engineering issues covered in this paper.
Effect of Initial Water Saturation on Spontaneous Water Imbibition
Authors: Li Kewen , Chow Kevin , Horne Roland N. 
Published: December 2007

Abstract
The effect of initial water saturation on gas recovery by cocurrent spontaneous water imbibition and imbibition rate was investigated both theoretically and experimentally. Equations correlating initial water saturation, gas recovery, imbibition rate, rock/fluid properties, and imbibition time were derived and used to conduct the theoretical analysis. These equations foresee that gas recovery and imbibition rate could increase, remain unchanged, or decrease with increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to about 50%. Water phase relative permeabilities and capillary pressures were calculated using the experimental data of spontaneous imbibition. The effects of initial water saturation on residual gas saturation, water phase relative permeability, and capillary pressure were also studied experimentally. The results in different rocks were compared. It was found that the residual gas saturation by spontaneous imbibition in a fired Berea sandstone sample (clay was removed by firing) was lower than in a natural Berea sandstone sample (clay was not removed). This demonstrates significant wettability alteration caused by firing. In other words, there may be significant wettability differences among different gas-liquid-rock systems.
A Case History: Use of a Casing-Conveyed Perforating System to Improve Life of Well Economics in Tight Gas Sands
Authors: Eller J. Gary , Garner J. Jay , Snider Phil , George Kevin 
Published: December 2007

Abstract
This paper provides the first technical review of a casing-conveyed perforating technique to fracture stimulate multiple sands in a single wellbore. This is an alternate well completion methodology to improve life-of-well economics. Two wells in Kenai, Alaska were recently completed using this system. The system consists of perforating guns mounted external to the casing and integral valves in the casing for zonal isolation. All equipment is remotely actuated without wellbore intervention. The first well was completed with 15 perforating modules and the second with 12 modules, each placed over a 1,700’ (520M) gross interval. This case history recounts the installation of these completions and their subsequent perforation and fracture stimulation. Both completions are considered technical and economic successes.
The casing-conveyed perforating technique was chosen for these Beluga Sand wells in an effort to improve life-of-well economics and total hydrocarbon recovery. An exhaustive characterization study of this multiple-pay environment recognized that conventional completion techniques were not adequately developing the resource. Low-quality Beluga sand bodies represent a large potential target of reserves, but the economics of conventional completion techniques never allowed this potential resource to be stimulated and properly evaluated. Use of this new completion technique meant that all pay sands, even those low-quality sands that had conventionally been ignored, could now be effectively and economically stimulated. Minifrac data, tracers, and production logs are used to evaluate the productive potential of these low-quality Beluga Sands.
Permanent Fiber Optic Monitoring at Northstar: Pressure/Temperature System and Data Overview
Authors: Kragas Tor K. , Turnbull Bill F. , Francis Michael J. 
Published: December 2007

Abstract
In-well fiber optic sensing systems offer the potential for continuous, high accuracy, high reliability data measurements. Over the past two years, permanent downhole fiber optic pressure and temperature monitoring has become an accepted new technology in the oil and gas industry. Northstar, on the North Slope of Alaska, represents the first multi-well, new field development to incorporate downhole fiber optic pressure and temperature monitoring. This paper will describe the fiber optic pressure and temperature systems being installed at Northstar. Data collection, data management, and data application will be discussed and examples of data from the first installations will be given.
Multiphase Flowmeter Applicaton for Well and Fiscal Allocation
Authors: Theuveny B. C. , Mehdizadeh Parviz 
Published: December 2007

Abstract
Traditionally, well allocation and fiscal allocation have been performed on the basis of test separator information. The technology breakthrough of multiphase flowmeters brings new solutions to allocation solutions. These new flow rate measurements have demonstrated some unexpected well behavior. These dynamic effects (instability, slugs) have shed light on the origin of some back-allocation factor issues experienced in some fields. The paper discusses actual causes for large back-allocation discrepancies and provides examples of challenges to standard test separator.
This paper also presents the decision strategies related to the implementation of multiphase flowmeters to determine allocation issues. The paper discusses the impact of uncertainties of multiphase flowmeters on the overall fiscal allocation and provides recommendations on installation methodologies and screening processes to make best use of the dynamics of these new measurements.
The understanding of the different needs for well test information and allocations is illustrated and the impact to the allocation factors is shown. The distinction between well-specific tests and diagnostic information from pad/manifold fiscal allocation is important to the hardware selection process and to the back-allocation issues. The impact of the frequency of the measurement is also quantified. The paper concludes with a series of recommendations to improve back-allocation factors on existing installations
The Effects of Magnetic Treatment on Calcium Sulfate Scale Formation
Authors: Farshad Fred F. , Linsley J. , Kuznetsov O. , Vargas S. 
Published: December 2007

Abstract
The problem of scale deposition in oil wells, gas wells, surface production equipment, and also the scale deposition in the flow lines, has presented a challenge to the petroleum industry since the first wells were drilled more than one hundred years ago. Although scale deposition is a major problem that interferes with the production of oil and gas, it is not the only large problem. There is the second problem concerning the treatment and removal action of scale deposits, which greatly adds to the overall cost of oil and gas production. These two problems often make marginal wells uneconomical. The petroleum industry has long sought more effective ways of dealing with this problem and the historical treatment methodologies remain relatively unchanged. Significantly, these alternatives merely inhibit, but do not prevent the precipitation and deposition of scale. Therefore, producers and operators must endure the ongoing operating costs and problems associated with these control methods in order to continue producing, transporting and processing their scale-infected oil and gas wells. Magnetic technology that prevents scale deposition in oil and gas wells will reduce well operating expenses which is important when considering the large number of low volume stripper wells, both offshore and onshore, in the United States that could benefit from this technology. Magnetic technology will also benefit the petrochemical, paper, food processing, mining, electrochemical, pharmaceutical, electronic, biochemical, metallurgical, nanotechnology, and all the other industries where water is used in the processing of products.
Pressure Behavior of a Well in an Anisotropic Reservoir
Authors: Guira Bendekim , Djebbar Tiab , Escobar Freddy H. 
Published: December 2007

Abstract
Transient pressure tests used to define linear boundaries within a reservoir are affected by anisotropy. This anisotropic behavior of the flow in natural rocks can create major obstacles in characterizing the reservoir. In their mathematical development, conventional methods of analysis use the principle of superposition and direct mirror imaging of wells, which are normally applicable only to isotropic systems.
The method of images was used to generate type-curves for a well located in various multiple-sealing-fault systems and inside closed rectangular reservoir. The transient pressure behavior of a well located anywhere between two parallel sealing boundaries can also be analyzed by type curves. Some research studies have considered anisotropic flow regions.
This paper is concerned with well imaging in anisotropic media for (a) a single well near a single no-flow boundary, and, (b) a single well near a constant pressure line. An imaging method is used to find the image well location, and then a general step-by-step solution is derived which accounts for wellbore storage and skin effects.
Type-curve plots of dimensionless pressure and dimensionless pressure derivative are generated. They clearly show the effect of the anisotropy ratio on the transient pressure response. The application of the proposed general solution is carried out by solving some simulated examples. The calculated distance from well to boundary was found to be in good agreement with the input value of distance to the boundary for the simulated cases.
A Simulation Study of Enhanced Recovery of Schrader Bluff Heavy Oil by Immiscible and Miscible Gas Injection
Authors: Madarapu R. R. , Khataniar S. , Patil S. L. , Dandekar A. Y. 
Published: December 2007

Abstract
The Schrader Bluff Pool is a shallow, heavy oil reservoir in the Alaskan North Slope. Due to the absence of a significant primary drive, enhanced oil recovery methods must be considered for recovering heavy oil from the Schrader Bluff Pool. The objective of this study was to use reservoir simulation to evaluate immiscible and miscible solvent injection processes for improving oil recovery from Schrader Bluff. Typical reservoir heterogeneity encountered in the Schrader Bluff sands was incorporated into the simulation model. Performance of solvents readily available in the area was studied for different modes of injection such as continuous injection, slug and WAG injection. It was concluded that immiscible, lean gas type injectants would be ineffective for oil recovery from the Schrader Bluff Pool. The miscible WAG injection processes appeared to be promising.
Pressure Drawdown and Buildup Analysis in Gas Condensate Reservoirs
Authors: Jokhio Sarfraz A. , Tiab Djebbar 
Published: December 2007

Abstract
This paper introduces a new method to analyze pressure drawdown and buildup tests in gas condensate reservoirs producing under two-phase flow conditions. Integral method of pseudopressure is used to handle the physical properties and the phase change with pressure. The phase change is the result of the retrograde behavior of condensate fluids that occurs within the reservoir when conditions of pressure and temperature are right for it. Resulting phase change causes change in the liquid saturation thereby changing the relative permeability of that phase. To use the relative permeability as function saturation, saturation has to be known at all the times. This method, however, shows how to estimate the effective permeability of the liquid and gas phase as a function of pressure, skin factor, and the arial extent of the different regions at a given stage of the depletion. Effective permeability then can be used to project the well performance during the pseudosteady state, reserves, and well flow potential (AOF).
During pressure test period, which is very short as compared with pseudostaedy state depletion, producing gas oil ratio is assumed constant. In other words oil and gas rates are held constant. In reality it might be hard to do so in a phase changing environment. So, a sensitivity analysis is performed to see the effect of the change in the producing gas oil ratio on the estimation of pseudopressure. We see steady increase in percent error in pseudopressure with increasing pressure at certain percent increase in Rp. At 8,200 psi, 10% percent increase in Rp introduces 3.96% error in pseudopressure. However, the error is 1.49% at 4,000 psi and 0.27% at 1,000 psi respectively. The error at 5% increase in Rp at 8,200, 4,000, and 1,000 is 2.13, 0.79, and 0.14% respectively. It is also observed that the amount of error in the effective gas permeability is 3% and 9% in oil effective permeability.
This paper is divided in four parts. First the pseudopressure is simplified to separate the effective permeability terms. Second, well testing equations are modified in order to provide correlation for effective permeability of each phase. Third, the error in pseudopressure is determined in case over or under estimated GOR value is used. Finally, a field example is solved in a step-by-step manner to show the use of the technique.
A Method for Detection of Untapped Intervals in a Complex Lithology System
Authors: Anthony Taglieri , Doddy Abdassah , Iraj Ershaghi , Kim Halbert 
Published: December 2007

Abstract
This paper is a case study calibrating well log derived lithology indicators with productivity attributes from modern production logs. More than thirty wells drilled thirty years ago into the South Ellwood Field were completed based on limited understanding of the well log responses in the complex Monterey Formation. From a retrospective study of well productivity, Wylie, Ershaghi and Christensen1 presented a pattern recognition technique for identifying productive intervals. Availability of recently obtained state-of-the-art production logs has provided invaluable information about the relevance of the well log derived potential zones to positively tested productive and undamaged intervals.
This paper includes an analysis of the information processing from the Flow View and Gas Holdup Sensor Tool. A calibration of production log data and well log lithology pattern studies is the basis of designing a re-development strategy for untapped intervals not perforated in the initial completion work. Furthermore, the calibration methodology is extended to a nearby field with similar geology for reassessment of reserves potential.
Horizontal Miscible Water Alternating Gas Development of the Alpine Field, Alaska
Authors: Redman R. Scott 
Published: December 2007

Abstract
The Alpine oil field is located approximately 60 miles west of the Prudhoe Bay oil field on the North Slope of Alaska. It contains 430 million barrels of recoverable reserves and 1 billion barrels of oil-in-place. The Alpine reservoir is a Jurassic, marine sandstone with 40-degree API gravity oil with an average thickness of 50 feet. Daily production rates have ramped up from 40,000 barrels in November 2000 at startup to over 90,000 barrels per day in July 2001.
This paper summarizes the development plan evaluation for the Alpine oil field, which is drilling all horizontal wells and flooding the reservoir using a Miscible Water Alternating Gas (MWAG) process. Horizontal wells were selected over vertical wells based on higher expected productivity and improved recovery efficiency compared to vertical wells. Additional horizontal well considerations included aligning wells parallel to potential conductive fractures, using all open-hole completions and selecting an optimum well spacing. The Miscible Water Alternating Gas recovery process was found to be superior to either gas flooding or water flooding for this reservoir. Reservoir strategy considerations included pre-injecting an optimal water volume prior to gas injection, injecting gas prior to water breakthrough at the producers, and optimum distribution of the miscible gas among the injectors.
Approximate Solutions For Flow On Non-Newtonian Power Laws Fluids Through Porous Media
Authors: McDonald Alvis E. 
Published: December 2007

Abstract
Individual well modeling with r-z geometry is often done with a small number of radial cells (e.g. 6 or 7). This usually leads to small space truncation error for black oil systems. for power law fluids a finer grid is required. An example problem is readily solved using 20 radial cells. Coarser definition leads to unacceptable truncation error.
A method is shown to improve finite difference accuracy by space differencing the time derivative. An analytical solution to the difference equation is developed, and used to validate approximate numerical solutions.
Three figures, five tables illustrate results.

1. SUMMARY AND CONCLUSIONS
A small number of radial cells (e.g., 6 or 7) is usually adequate for individual well models using r-z geometry. Our results indicate that solution errors are small for such models when the fluid is a black oil. But errors are not small for power law fluids. The problem discussed here requires 20 radial cells to reduce truncation errors to be acceptable levels. Improved accuracy in the space dependent approximation can be obtained by a suitable space differencing of dp/dt. With such improved accuracy it becomes tenable to use a reduced number of radial cells to model power law behavior. power law behavior. II.

Introduction
Recent papers, developed the following equation describing radial flow of a non-Newtonian power law fluid in a porous medium: power law fluid in a porous medium:
........(1)
A Layered Pattern Simulator For Non-Newtonian Fluids In Graded Viscosity Banks
Authors: Claridge Elmond L. 
Published: December 2007

Abstract
In order to provide a reservoir simulator capable of meeting the needs of a non-Newtonian graded-viscosity bank displacement simulation in heterogeneous petroleum reservoirs, a specialized simulator has been developed. Instead of a finite-difference representation of partial differential equations, the simulator uses integral equations over successive fluid regions in each layer (no cross-flow representation). The Newtonian or non-Newtonian character of the fluids in each region is explicitly represented in the integral for that region. Power-law (pseudoplastic) viscosity behavior is assumed for the non-Newtonian fluids, but the viscosity and the power-law exponent vary with polymer concentration. The required series of terms in the integral equation for each layer is automatically formed by the program as the injection and production history unfolds. A simple example of a polymer flood in a three- production history unfolds. A simple example of a polymer flood in a three- layer five-spot pattern is used to illustrate the application of the program. It calculates very nearly the same rates, but a somewhat program. It calculates very nearly the same rates, but a somewhat different recovery efficiency than does a finite-difference simulator which was adapted as closely as possible for making the comparison.
Aggressive Tip Screen-Out Designs Give North Slope Satellite Field Production a Boost
Authors: Young J. P. , Smith B. W. , Coker M. , Abel J. 
Published: December 2007

Abstract
Over 400 wells have been very successfully hydraulically fractured on the Kuparuk Sand for the Kuparuk River Unit Field (KRU)1. Comparatively smaller petroleum deposits of the Kuparuk Sand have recently been developed in the adjacent Prudhoe Bay Field. These satellite pools, namely the Aurora and Borealis, similarly benefit from fracturing. Significant productivity increases from aggressive Tip Screen-out (TSO) fracture designs have delivered over 40, 000 bopd from 11 wells.
This paper describes the rationale, events and lessons learned leading up to the final very aggressive TSO designs for these satellite wells.
In many cases, fracturing fluid efficiencies measured during datafracs for the satellite wells were approximately two times higher than the Kuparuk Sand analog in the KRU area. Pad volumes during fracturing were as little as 3% of the total treatment volume with modeled proppant concentrations of 5 lbs/ft2 placed.
The majority of wells were S-shaped to minimize fracture complexity. Directional drilling costs, NWPL’s and production results are shown.
Bottom hole pressure gauge data is presented allowing refinement of the designs via net pressure analysis and times to start TSO. Production and pressure transient analysis results are also presented.