bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Improved Method for Gas Lift Allocation Optimization
Authors: Nishikiori N. , Redner R. A. , Doty D. R. , Schmidt Z. 
Published: December 2007

Abstract
A new method for finding the optimum gas injection rates for a group of continuous gas lift wells to maximize the total oil production rate is established. The new method uses a quasi-Newton non-linear optimization technique which is incorporated with the gradient projection method. The method is capable of accommodating restrictions to the gas injection rates. The only requirement for fast convergence is that a reasonable estimate of the gas injection rates must be supplied as an initial point to the optimization method. A method of estimating the gas injection rates is developed for that purpose.
A computer program is developed capable of implementing the new optimization method as well as generating the initial estimate of the gas injection rates. This program is then successfully tested on field data under both unlimited and limited gas supply. The new optimization technique demonstrates superior performance, faster convergence, and greater application than the standard "equal slope allocation" procedure.
Experimental Study of Hydraulic Fracture Geometry Initiated From Horizontal Wells
Authors: El Rabaa W. 
Published: December 2007

Abstract
Horizontal wells drilled in tight formations are likely to be stimulated by acidizing and/or propped fracturing to increase productivity. Normally, to control the placement of induced fractures in these wells, they are completed for later stimulation, i.e., cement cased and perforated. Unlike vertical well fracturing, fractures in horizontal wells can be induced along, or inclined to, or crossing the horizontal section. This orientation depends on deviation of the horizontal section from the minimum stress direction.
An experimental study of fracture geometry from horizontal wells at various well azimuth deviations was conducted. Experiments were performed by applying triaxial loading conditions to rock blocks 6 × 12 × 18 in. surrounding cased and perforated boreholes. The borehole directions varied from 0 to 90 degrees from the applied minimum stress. Also, length of perforated interval was the second variable parameter in this study. After each experiment, rock blocks were sawed to observe the shape of induced fracture. The study showed that fracture geometry near the horizontal well is controlled by well deviation and length of perforated interval. From a stimulation viewpoint, the combined effects of these two parameters, if not investigated beforehand, may cause critical problems during fracturing. Laboratory observations indicated the following stimulation related problems: Creation of multiple fractures from the same perforated interval.Created fractures are nonplanar, with rough walls.Communication of fluid between the perforated section and fracture can occur through small channels.Interference between fractures conducted from separate perforated interval.
Based on this study several recommendations are presented to help eliminate some of these stimulation related problems.
Drilling and Completion of a Horizontal Lower Spraberry Well Including Multiple Hydraulic Fracture Treatments
Authors: White C. W. 
Published: December 2007

Abstract
The John Snowden Well No. 7 is a multiply hydraulic fractured horizontal Lower Spraberry well.
The principle stress directions were determened and the well was drilled in the direction of the least principle stress. This was done so that multiple fractures would radiate out at right angles from the horizontal well bore.
Isolation for the multiple fracture treatments was achieved by a cemented liner, tubing conveyed perforating, and bridge plugs.
Frac sand production was eliminated through perforating technique and tailing in the frac treatments with curable resin coated sand in the cased hole portion of the horiaontal well. An open hole section of the well required sand screens to eliminate the frac sand production.
The frac load water was produced from the well and then the open hole and four perforated intervals were individually swab tested.
Real-Time Fracturing Fluid Rheology Measurements With the Helical Screw Rheometer
Authors: Lord D. L. , Shackelford D. 
Published: December 2007

Abstract
The increasing complexity of hydraulic fracturing fluids has intensified the need for improved on-site quality control methods. The helical screw rheometer (HSR), considered by many to be merely a laboratory curiosity, is shown to have unique features which make it an ideal on-line fluid sampling and testing device for use during hydraulic fracturing treatments. These features are exploited in an HSR unit which has been successfully adapted to function in the field environment. Since its operation is based on microprocessor technology, implementation of instrument control, data acquisition, and data analysis functions have all required special consideration. This paper describes how these various instrument functions were made operational. Data acquisition and analysis functions are further illustrated with viscometric data collected with a number of different fracturing fluid base gels.
Underbalanced Perforating Design
Authors: Crawford H. R. 
Published: December 2007

ABSTRACT
A review of perforating regimes is presented followed by equations and tables which provide provide design guidelines for: the minimum underbalance pressure necessary to provide clean perforations, andthe maximum underbalance pressure which can be tolerated without causing sand production.an underbalance pressure which is recommended.
The properties of the reservoir and of the adjacent formations are the independent variables of the equations. The work of previous investigators provides the foundation for these equations.
Several case histories are presented. They generally confirm the validity of the equations. They show the remarkable production increases that are obtainable with underbalanced, high density, perforating.
Data are presented which show the damage caused by killing a well which originally had clean perforations. Some of this damage was temporary. Laminated formations and perforating overbalanced are discussed.
A recommended method for selecting the perforating method and conditions is highlighted.
Comparison of HEC and XC Polymer Gravel Pack Fluids
Authors: Underdown D. R. , Calvert A. L. , Newhouse D. P. 
Published: December 2007

ABSTRACT
Several service companies are promoting the use of XC polymers to replace HEC polymers in gravel pack fluids. The XC polymer system 1s advertised as providing better gravel carrying capacity and less formation damage than HEC polymer systems.
Results of laboratory and field tests with XC and HEC polymers show that the final properties of the fluid system are dependent upon mixing procedures. Hydration and shearing of the XC polymer system prior to the addition of the salt gives a gravel pack fluid with the most consistent fluid properties. High shear and filtration through too fine a filter causes severe loss of gravel carrying capacity and viscosity for both the HEC and XC systems. Filtration through a ten (10) micron absolute cartridge filter is the last step in the preparation.
Formation damage studies show that initial exposure to a XC polymer system causes minimal damage. The formation damage is minimized by proper mixing, proper filtration of the system and the proper amount of breaker. However, testing has shown that repeated exposure of the formation to the XC or HEC polymer systems after breaking causes substantial formation damage even with the proper mixing, filtering and breaker systems.
Successful Proppant Fracturing of Ultradeep Sour Gas Reservoir
Authors: Ely J. W. , Cobb W. J. , Elkin B. , Bell D. D. 
Published: December 2007

ABSTRACT
During the past 3 years, a successful stimulation program has been completed with the fracturing of four wells in the Smackover formation. The four wells were stimulated in the Johns Field in Rankin County, Mississippi. The Smackover formation is located at 19,000+ feet and has a bottomhole temperature of about 330° F. The natural gas in the Johns Field contains about 31% H2S and 4% CO2.
Three of the four wells in the field had been fracture treated upon initial completion with moderate volume treatments and low concentrations of proppant. It was determined that procedures used in cleaning up these wells combined with the excessively large overburden pressure had reduced the effective fracture conductivity to essentially zero. The high bottomhole temperature (330° F) and high fracturing pressures (19,000 psi) essentially represents the current limits of both fluid technology and pumping equipment. A major effort was made to assure quality control of the fracturing fluid above and beyond that normally done on typical fracturing treatments. On site evaluation of all fracturing fluid using Fann 50 viscometers combined with normal quality control procedures was very beneficial in assuring that quality fluids were mixed and pumped.
Intensive reservoir and economic studies were made to evaluate the economic viability of the stimulation treatment prior to each treatment. All of the fracturing treatments have been financial successes and the productivity of the Johns Field has been increased by more than 300%. In fact, further drilling is underway based upon the results of these fracture treatments.
Reanalysis of the MWX Fracture Stimulation Data From the Paludal Zone of the Mesaverde Formation
Authors: Miller W. K. , Smith M. B. 
Published: December 2007

ABSTRACT
To investigate Western U.S. tight gas sands, and in particular lenticular sandstone formations, DOE established the Multi-Well Experiment (MWX) near Rifle, Colorado. The field research facility consisted of three closely spaced wells drilled through the lenticular Mesaverde formation for the purpose of establishing production potential from lenticular reservoirs, and improving existing production technology for this unconventional gas source.
This paper presents a review and re-analysis of the fracture stimulation data from the Paludal zone. Two of the main objectives of the Paludal experiments were 1) to determine fracture geometry and "predict" behavior in a lenticular environment and 2) to successfully stimulate lenticular sandstones in a complex, coal-bearing interval. While the original Paludal testing and analysis was mainly successful in addressing these, there remained some questionable aspects; one being the unexpected, abnormally high treating pressures during the fracture tests and propped fracture treatment. These first Paludal zone tests were, in fact, one of the early observations of "abnormal" high fracture treating pressures.
To establish the seemingly abnormal fracture behavior, much of the raw stress data was reviewed and good correlations found to exist between in situ stress and lithology (gamma-ray) and acoustic velocity (sonic log). From the lithology correlation, a detailed stress profile was derived and used in a pseudo 3-D fracture simulator to history match the two minifracs and main treatment. While much of the re-analysis was in good agreement with previous work, some significant differences were found with respect to the stress profile, fluid leak-off, and prediction of bottomhole treating pressure (BHTP). In fact, from the re-analysis, the prediction of BHTP was relatively straight forward and the calculated fracture height from the simulator closely approximated that observed with post-frac logs and borehole seismic data. The results suggest another possible (and fairly simple) mechanism for the unexpected high treating pressures observed and noted in several recent publications - that is, vertical and lateral variations in fracture closure stress.
Applications of Transient Pressure Interference Tests to Fractured and Nonfractured Injection Wells
Authors: Cooper K. J. , Collins R. E. 
Published: December 2007

ABSTRACT
Transient pressure interference tests have proved to be very effective for determining parameters for reservoir simulation of deep-well, hazardous waste, injection systems. These well systems provide a unique, large-scale laboratory for conducting interference tests in both fractured and non-fractured wells because disposal takes place in single-phase brine aquifers. A number of multi-well systems are described in a variety of geological settings to demonstrate the wide range of systems in which interference testing has been utilized with remarkable success.
Ultimate Recoveries and Economics of Massive Hydraulically Fractured Wells in the Hauptsand, Soehlingen Gas Field, Germany
Authors: Griffiths J. D. , Lepper U. 
Published: December 2007

ABSTRACT
Using a model consisting of a 90° segment of a radial coning simulator the behaviour of massive hydraulically fractured wells is modelled. For the Hauptsand of the field Soehlingen in North Germany, where gas permeabilities are in the microdarcy range, the model has been successfully used to determine rate profiles and ultimate recoveries and, in conjunction with an economic program, to investigate the economic viability of MHF-projects.
For effective gas permeabilities in the microdarcy range, the study shows the importance of achieving a maximum fracture length, of the relationship between formation permeability and economic viability, and of assessing the areal permeability trends in the drainage volume.
The model is used to establish a relationship between gas permeability and drainage volume for the life-expectancy of the well. This allows ultimate recoveries, and hence reserves, to be estimated simply if the average formation permeability is known.
A Deconvolution Algorithm for Analysis of Variable-Rate Well Test Pressure Data
Authors: Mendes L. C. C. , Tygel M. , de Franca Corrèa A. C. 
Published: December 2007

ABSTRACT
Reservoir parameters and flow patterns may be better characterized by well test analysis when bottomhole pressure and sandface flow rates are available. Pressure data which would result from production at constant rate, can be obtained by deconvolution, thus allowing the use of standard interpretation techniques.
This work presents a deconvolution procedure based on the approximation of pressure and rate measurements by combinations of cubic spline functions and the use of Laplace transforms for these approximations. The inversion from Laplace space to real space is carried out by standard numerical algorithms.
Comparison has also been made with three other methods available in the literature. The first one uses the procedure described above but makes a piecewise linear approximation for both the flow rate and the bottomhole pressure, and the other two are based on linearizations of the convolution integral.
Several simulated and field examples are presented.
Technical and Economic Evaluation of Steam Injection With Horizontal Wells for Two Typical Heavy-Oil Reservoirs
Authors: Petit H. J. -M. , Renard G. , Valentin E. 
Published: December 2007

ABSTRACT
The use of horizontal wells can improve the performance of thermal recovery by steam stimulation/drive process. The aim of this study was to evaluate different steam injection strategies depending on the reservoir characteristics, as well as spatial distributions for vertical and horizontal wells.
The field development of two typical reservoirs representative of the conditions encountered in Canada and Venezuela and containing heavy-gravity oils was studied by numerical simulation. The injection strategies applied to the different patterns included the number and the duration of the stimulation cycles, starting time of steam drive, influence of the presence and duration of a following water drive on the final oil production.
The results of the 3-D simulations mainly showed that horizontal well patterns improved productivity, so that projects can be completed in a significantly shorter time in fields where oil productivity is limiting (thin, viscous-oil reservoirs with low initial mobility). It is shown that reservoir conditions (depth, pay zone thickness) have a considerable effect on the injection strategies and therefore, on the oil productions. The extension of the heated zones and the evolution of the steam fronts depending on the spatial distributions of the wells and main reservoir characteristics are also presented in this paper.
The injection strategies applied to the different vertical and horizontal well patterns were compared on an economic point of view, which considers the recoveries and field costs for the processes. Specific advantages of certain well configurations are presented. The economic interest of using horizontal wells for deep heavy-oil reservoirs where steam injection would be economically unprofitable or marginal with vertical wells is shown.
Well Test Analysis in Oil Reservoirs with Gas Caps and/or Water Aquifers
Authors: Al-Khalifa A. J. , Odeh A. S. 
Published: December 2007

Abstract
This paper proposes a new solution for analyzing well tests run in oil reservoirs underlain by water aquifers or overlain by gas caps.
The presence of a gas cap and/or a water aquifer alters the pressure response of wells penetrating the accompanying oil sands. Only a single phase flows into the wellbore while a segregated multiphase flow predominates in the formation. Neither single-phase nor multiphase conventional pressure transient solutions apply for such an environment. Type curves, published in the literature, were developed assuming constant pressure at the gas-oil or oil-water interface. For most practical cases, this assumption appears to distort the physics of flow and results in non-accurate answers.
In this study, a finely-gridded coning model was used to simulate more than a hundred drawdown, buildup and injectivity tests. In contrast to the constant-pressure assumption, the semilog plots of pressure vs time exhibited straight lines reflecting pseudo-radial flow across the entire formation thickness. The semilog slopes were then used to yield the total system transmissibility, (kh/µ)t.
This paper also explains a time-lapse technique which uses successive tests run in the same system to track the location of the oil-water or gas-oil contacts with time. The same technique may also be used to obtain an estimate of the end point relative permeability in the swept zones.
Simple Performance Plots Used in Rate-Time Determination and Waterflood Analysis
Authors: Lijek S. J. 
Published: December 2007

Abstract
The logarithm water-oil ratio or the Ershagi watercut function plotted versus cumulative oil production or oil recovery are commonly used as indicators of waterflood performance because of their inherent linearity. Less well known but similarly justified is the water-oil ratio (more precisely, [1/WOR]+WOR) versus cumulative injection or pore volumes injected plots. Analytical methods by which oil rate as a function of time can be obtained, which is consistent with these performance plots, is shown. With additional correlations for estimating injection or gross (oil and water) production rate, predictions are possible for either the constant rate or constant producing pressure (variable rate) operating strategies.
It is shown that oil rate decline curves obtained using these methods are either hyperbolic or harmonic depending on whether gross rate is constant or variable. Decline curves are simple to calculated and retain their consistency with the performance indicators over a wide span of time.
Application of these methods to the Wilmington Field are shown to be useful in understanding how changing conditions in the reservoir are reflected in performance. Oil rate can be estimated by sand interval based on pore volume injection versus time trends, and on correlations for water-oil ratio as a function of pore volume injection. Thereby the impact of improved verticle sweep efficiency on overall performance can be determined.
Understanding Minimum Sales Price and Maximum Purchase Price
Authors: Daley G. C. , Elmer D. R. 
Published: December 2007

ABSTRACT
Should the federal income tax consequences of an acquisition or disposition of a property affect the price that a buyer should pay or a seller should receive?
Capital gains tax paid on a property sold is a definitive cash consequence which the seller pays. The tax impacts the net cash received and must be included when compared to value given up in the disposition of a property. In order to have sufficient cash to pay the capital gains tax and receive the present value of the future cash flows of a property, the sales price must be a multiple of the present value. The required sales price (or minimum sales price, "MSP") has been reduced to one of three single equations depending on the tax position of a firm. A non-dimensional one line graph is used to depict the relationship between sales price and present value when the capital gains tax rate is the same as the ordinary income tax rate. A complete overview of MSP and the factors which influence its computataion (present value, tax rate, recapture, "lax clawback", investment tax credit, and current tax basis) is presented.
Similarly, the purchase of a property will allow the purchaser certain tax benefits which generate more after tax value than only the present value of the cash flows of the purchased property prior to sale. The purchase price is allocated to tangibles and intangibles for tax purposes and is then depreciated and depleted on the tax books. This decreases the amount of income tax that the buyer is required to pay, and results in a purchase price which is a multiple of the present value prior to sale. Two non-dimensional graphs assist the reader in understanding the MPP process and the factors which influence its computation (present value, tax rate, property life, production decline, and the fractional allocation between tangibles and intangibles).
These concepts are used by most major oil companies and some independents. An understanding of how these concepts operate will give the reader an insight into why large properties are purchased and sold at values different than their present value of operations.
An Integrated Approach to Developing a Small Offshore Field: Scapa Field, North Sea
Authors: Chen H. K. , McGann G. J. , Romani R. S. 
Published: December 2007

Abstract
The Scapa Field is located 112 miles north east of Aberdeen in the U.K. sector of the North Sea. The field was discovered in 1975. It is developed with an integrated production/injection subsea template system, tied back to the main Claymore platform. Production commenced in 1985. Initial reserves are estimated at 65 million barrels. Current production is about 27,000 B0PD from four production wells with pressure maintenance through four injectors. A total of seven appraisal wells have been drilled.
The field is located in a SE-NW trending syncline, with onlap termination of the lower Cretaceous reservoir to the north onto the Claymore High. Faults terminate the field to the west and south.
The reservoir in the field is the Scapa Sandstone Member which is typically 100’ thick, at a mean depth of about 8300’. The sands are turbidites, typically fine to medium grained with permeability averaging about 200 md. The reservoir section is characterized by abundant calcite cemented concretions. The average reservoir bed thickness is about one foot.