bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Fractal Wormhole Model for Cold Heavy Oil Production
Authors: Liu X. , Zhao G. 
Published: March 2010

Abstract
Wormholes are believed to be generated during the process of cold production and are responsible for enhanced production rates. Understanding the wormhole patterns generated inside the reservoir formation is critical to improve the recovery efficiency and to model the fluid flow behaviour in the cold production process. In this paper, we have proposed that the wormhole growth can be described by the Diffusion-Limited Aggregation (DLA) model, which naturally relates to a broad variety of branchinggrowth patterns through the physics of the processes. The physical processes that were described using fractal models include the following: the growth of a drainage network; the formation of cavities; the dissolution of porous materials; and, the growth of random dendrites in the thin films. The DLA model has important implications in petroleum geology and engineering.
Based on the experimental results published in the literature, which were specifically designed to investigate the wormhole dynamics by a Computed-Tomography X-Ray scanner, the wormhole diameter distribution along the wormhole path has been analyzed using the Area Version of Gaussian Function. Then, the material balance method has been applied to the sand production data to determine the possible range of the wormhole structure around the wellbore, assuming that the sand particles are solely produced along the paths of wormholes. Finally, a numerical method has been developed to analyze the field sand production data.
The studies have shown that the fractal wormhole model can be used to diagnose the characteristics of the wormhole structures, and that it can be applied to optimize well placement in cold heavy oil production. The model will greatly enhance the analyses of the inflow performance and the pressure response of wells in wormholed reservoirs. Results acquired from this study can also be implemented in field scale numerical simulations for the cold flow process.

Introduction
Cold production is a non-thermal process in which sand is aggressively produced to reach a higher oil production rate. In the cold flow process, sand and oil are produced together under primary conditions and oil production rates can typically increase by a factor of 10 or more(1–5). For example, primary oil production rates of 8 – 12 m3/d are roughly 10 times greater than those calculated for the radial flow in the Celtic field using Darcy's law(2).
The unusual sand production in cold production was observed in several oil fields. Records have indicated that the production of about 708 m3 of sand in the first four months, and in nearly all the wells in S.E. Pauls Valley Field, Oklahoma, produced 10 – 50% sand initially, declining a few months later to 0.1 – 2%, regardless of completion method(5). The cumulative gross fluid production of about 9,000 m3 with an associated sand production of 200 m3 within a period of 1,000 days was observed in the Lindbergh and Frog Lake Fields, Alberta(1).
Modelling of Sucker Rod String
Authors: Hojjati M.H. , Gittins S.A. 
Published: March 2010

Abstract
This paper presents a new technique to analyze dynamic behaviour of a sucker rod string used in the oil well industry. The main concept of the proposed approach is to replace the actual complicated system by a simpler one. This needs the output or one-time accurate solutions of the actual system. This problem is solved using D‘Alembert's solution of systems equation and the adaptive filter matrix method developed by the authors. The developed computer program performs the calculations in very short real time with reasonable accuracy, and without extensive hardware and software requirements. It has been proven that it is possible to use the transfer matrix to calculate load-displacement relations a hundred or more times in one stroke. This could be very advantageous in building new well-head controllers and other tools to control the oil wells.

Introduction
Rod pumping is the oldest and still the most common method of artificial lift used extensively in the oil well industry(1,2). The literature devoted to the analysis of this system is very extensive. There are different computer programs aimed at the analysis and troubleshooting of rod pumping systems(3–5), however, they require fully equipped computer hardware to perform the calculations. These calculations usually take an amount of time that is longer than the period of pumping (one stroke) and cannot be directly used to control the well in real time.
In this paper, a transfer matrix method has been proposed to model the dynamic behaviour of the rod of the sucker string. The main concept of the method is to replace the solution of the mathematical model by a simple matrix operation in which the bottomhole force-displacement values are obtained as the product of the vector of the data at the polished rod end by a transfer matrix. This is an extremely fast mathematical operation, which can be performed hundreds of times during the period of one stroke and does not require any sophisticated software. The system transfer matrix for any given oil well is defined only once in advance using the filter matrix method(6–8). The matrix does not change with time and replaces the mathematical model of the analyzed system. Using this technique, the calculations of the bottomhole values can be performed very fast and in a very simple way. These calculations are easy to implement in one microprocessor. In the studies presented here, we found that to create the system transfer matrix, it is enough to replace the real system by a two-segment rod. The simplified model is solved using D‘Alembert's method(9). Using the equivalent model, the transfer matrix is created.

Mathematical Modelling
To analyze the performance of the oil well, the force and displacement at the polished rod are measured using a dynamometer. Then these data are used as the boundary conditions for the calculation of forces and displacements at the bottom of the rod string that defines the conditions of the pump, effectiveness of pumping, production rate, etc.
Development and Field Experience of a New Concept in Sucker Rods Technology
Authors: Lozano A. , Boeri J. , Zalazar B. , Olmos D.E. , Ameglio A. 
Published: March 2010

Abstract
The Cerro Drag?n oilfield, operated by Pan American Energy, has producing oil wells that use rod pumping systems with average depths of 2,440 m (8,000 ft) and fluid rates as high as 200 m3/d (1,300 bfpd). In this oilfield, the pulling operations exhibited a high incidence of pin breaks, generally located in the 22.23 mm (7/8 in) OD taper that we concluded to be the weakest part of the entire string, as we will show. In order to solve this problem, a new sucker rods design was developed by creating a new non- API 22.23 mm (7/8 in) sucker rod with ends of 25.4 mm (1 in) in order to reinforce the string.
This technical work describes the development of this technology, as well as the experience in the field, with excellent results p to the present.

Introduction
erro Drag?n is an oilfield located in the Golfo San Jorge Basin (see Figure 1). This field has 1,800 oil producing wells, with 1,642 wells lifted by rod pumping systems. Average pump depths are 2,440 m (8,000 ft) with oil producing rates as high as 200 m3/d (1,300 bfpd).
In 1988, a secondary recovery project was started. The water injection rate was raised (Figure 2), resulting in higher production rates and consequently higher loads to all of the components (rods, pumping units, etc.) of the lift system.
Associated with this increase in the production rates, an increase in failure rates was observed. It was determined that the main cause of this failure rates increase was connection failures; in particular, the 22.23 mm (7/8 in) pin failures. Approximately 18% of the failures were caused by 22.23 mm (7/8 in) pin breaks. As a result, a team was established between the rod supplier and the operating company to work together to improve the fatigue resistance of the 22.23 mm (7/8 in) connection. The result of this teamwork was a new non-API sucker rod with a 22.23 mm (7/8 in) diameter and a threaded connection of 25.4 mm (1 in).
Currently, there are 60 rod strings installed, the oldest ones with an operating service life of about four years, and there has been just one failure (the oldest one failed after 1,499 days in service). The installation of the improved sucker rods in 160 wells (thosewith the higher failure rates) will result in savings of almost US$2 MM/year. This paper describes the development of the rods, as well as the experience in the field.

Failures History
Due to the increase in the IPA (index of interventions per well per year) for wells lifted by rod pumping (Figure 3), work was conducted to understand the different causes of the failures. The first conclusion was that the sucker rod failures were growing at a constant rate, corresponding to the increment in the production rates.
Henry's Law Near the Critical Point of Water-Applications in Solvent Co-Injection With SAGD
Authors: Thimm H.F. 
Published: March 2010

Abstract
In the last 10 years, substantial progress has been made in the theoretical treatment of gas dissolution in water, near the critical point of water (374 °C). An asymptotic behaviour of Henry's law for a variety of gases (the noble gases, methane, ethane, nitrogen, oxygen, carbon dioxide, and hydrogen sulphide) already governs the behaviour of these gases at temperatures above approximately 180 °C, well below the critical point. This behaviour has been used to develop a theory of gas production in SAGD, according to which gas production in SAGD largely occurs via dissolution of gas in the steam condensate.
Further recent developments in this area of solution thermodynamics have extended the knowledge of this phenomenon to various light hydrocarbons, from butane to dodecane, and the aromatics such as benzene and toluene.
In the present paper, data for the distribution coefficients (Kvalues) of light hydrocarbon solvents in water are presented, and the application for prediction of solvent returns in SAGD enhanced by solvent co-injection is discussed. Optimal choice of solvent composition to maximize solvent returns is possible.

Introduction
In 2001, Thimm(1) proposed that gas production in SAGD proceeds via a mechanism whereby gases are dissolved in the produced liquids, and enter the wellbore in that form. No case has been reported so far where it has been necessary to postulate free gas entering the SAGD production well in order to explain the observed GOR and produced gas compositions. Gases are considered to separate from the liquids in the wellbore and facilities.
The solubility of gas in a liquid is governed by Henry's Law, which may be stated as:
Equation (Available In Full Paper)
In 1989, Japas and Levelt Sengers(2) provided the theoretical basis for observations made at that time and since, that for all solvents- gas pairs, the distribution coefficients for gases in general declines as the critical point of the solvent is approached. In fact, Japas and Levelt Sengers showed that all values of K approach unity towards the critical point.
In the case of water, this asymptotic behaviour governs gas solubilities above 180 °C or so, and maybe considerably earlier in the case of some gases. Harvey and Levelt Sengers(3) published a power law for a variety of gases in water, valid between the triple point and the critical point of water:
Equation (Available In Full Paper)
For the case where the solvent is water, all values of density and also the fugacity term in this equation may be found in or derived from steam tables. The values of A, B, and C are published by Harvey and Levelt Sengers. Other authors have published coefficients of the same kind, notably Suleimenov and Krupp(4) for hydrogen sulphide. Thimm(1) has shown that this approach, when applied to simulated oil and water production forecasts in SAGD or to actual production data, yields GOR and produced gas composition data in good agreement with actual results. Such data have been published previously(5, 6).
Field-Scale Compositional Simulation of a CO2 Flood in the Fractured Midale Field
Authors: Malik S. , Chugh S. , McKishnie R. A. , Griffith P. J. , Lavoie R. G. 
Published: March 2010

Abstract
A stimulation test using electric heating was conducted on a single oil production well in the Schoonebeek reservoir in The Netherlands during 1989 and 1990. The performance of the test and its interpretation is described.
The Bentheim reservoir sands are 31 m thick with a porosity of 0.3 and a permeability in the range 0.2 - 4 µm2; the oil has an in-situ viscosity at 160 mPa.s and is waxy with a cloud point very close to the reservoir temperature of 40 °C. The reservoir pressure of about 7000 kPa is supported by a strong edge aquifer. The objective of the test was to stimulate oil production with heat and, particularly, to melt wax that was suspected to be present either near the wellbore or uniformly throughout the reservoir.
Prior to stimulation the oil production rate was 13 m3/d at a water cut of 35%. As the surface power dissipated was increased above 60 kW, the oil production rate increased abruptly to 30 m3/d with a bottomhole temperature in the range 54 to 60 °C; at higher power levels no further increase of production rate was observed.
Analytical methods proved very useful for understanding the electric healing process, particularly for tracing the electric current flow path in the reservoir and for modelling the heat distribution and production response. Numerical simulations of the well's performance showed that the observed abrupt increase of oil production rate was compatible with the melting 01 wax at 60 °C and partial removal of a skin (of approximately 27) but not of a wax deposited uniformly throughout the reservoir.

Introduction
Though electrical heating has been used to stimulate well productivity al various times over the last 25 years, it is not widely applied. A lest of the stimulation method was recently completed on Well SCH-280 in the RW2-E area of the Schoonebeek oil reservoir of The Netherlands (see Figs. 1 and 2) by the Nederlandse Aardolle Maatschappij B. V. (NAM). In this paper we describe the properties of the Schoonebeek reservoirand the characteristics of Well SCH-280 and review the objectives, test programme and actual performance of the electric heating stimulation (EHS) test. In several respects, the information required to interpret the test unambiguously was not available. To circumvent these limitations, methods were developed for inferring the electric current flow path and heat distribution in the reservoir, Using both analytical and numerical simulation methods, a broadly consistent interpretation of the test was developed and this is described herein.

FIELD PERFORMANCE OF OTHER ELECTRIC HEATING TESTS
Over the last 25 years there have been a number of reports in the literature of planned or executed field tests of the electric heating process, mostly based on the ohmic dissipation of electric energy in the formation. Electrothermic Co., for example, stimulated four wells of the Little Tom field in South Texas. The reservoir there contains 8 - 12 °API gravity oil with a high pour point [1,2].
Should You Trust Your Heavy Oil Viscosity Measurement?
Authors: Miller K.A. , Nelson L.A. , Almond R.M. 
Published: March 2010

Abstract
Heavy oil viscosity is one of the few criteria available to help predict if cold production will give economic rates, or if thermal processes will be required to reduce the oil viscosity to achieve the required rates. If cold production is selected, viscosity is again used to help determine whether vertical or horizontal wells should be used. Viscosity data are also used to adjust cold production exploitation strategies if the production rates are significantly lower than expected.
Petrovera conducted an extensive viscosity data collection project in a newly developed Elk Point area reservoir with lower than expected, and more erratic than expected, cold production rates. Oil samples collected over short periods of time resulted in viscosity values for the same well varying by a factor of four or more, with similar variations between close-spaced wells. Collection of repeated samples and submission of those samples to several commercial labs resulted in similar viscosity measurement scatter. To further evaluate viscosity data scatter, multiple samples were collected from one well at the same time using the same procedures. These samples were then submitted to several labs in triplicate using three different well names to achieve an unbiased test. Reported viscosity scatter was again large.
The objectives of this article are to:display the results of the study to bring this issue to the forefront for discussion; and,encourage commercial labs to develop an industry-wide standard method of heavy oil sample cleaning and viscosity measurement.

Introduction
Why Is It Important to Know Heavy Oil Viscosity Accurately?
Heavy oil exploitation is an important segment of the oil and gas industry in Canada(1) and a number of other countries(2). Motivating factors for exploitation of Canadian heavy oil and bitumen are the large volumes of resources in place and the high historic demand for asphalt-based products that are more readily obtained from heavy oil and bitumen.
Western Canadian heavy oil and bitumen reservoirs (Figure 1) have been exploited with varying degrees of success for more than 60 years(3). Early workers in the field of heavy oil and bitumen exploitation quickly determined that primary production responses (also called cold production responses) varied greatly from field to field. They also discovered that the addition of heat in the form of steam often greatly increased the production response. Viscosity became one of the most valued criteria in their efforts to predict production response from a new field using easily measured parameters. The popularity of the viscosity screening criterion has been demonstrated by the fact that virtually all technical papers on heavy oil production response or production process development include a discussion of oil viscosity.
What is missing from the literature is an industry-wide standard of viscosity ranges and the corresponding recommended exploitation processes. This is because each company has its own 'best exploitation process vs.
Analysis of Crude Oil Electrostatic Desalters Performance
Authors: Zeidani K. , Bahadori A. 
Published: March 2010

Abstract
New equations covering a wide range of oil types are developed to estimate the treating rate and treating temperature for dual polarity electrostatic desalters and AC conventional electrostatic desalters in Iranian oil fields. Production of wet crude had been a growing problem that affected the quality of produced oil in Iran. Application of the correct technology and the installation of proper desalting facilities were required to solve this problem. Therefore, it was decided to install electrostatic desalting plants progressively in Iranian oil fields. By the end of 2004, more than 20 desalting plants with a total capacity of 207,000 standard cubic metres per day of treated crude have been installed. The performance of the majority of these desalting plants have been tested and found satisfactory. It is expected that the rate of wet crude production will increase to 366,000 standard cubic metres per day in 2007.
This study shows that a dual polarity electrostatic desalter may operate at a minimum crude oil inlet temperature, resulting in extra fuel savings and eliminating the need for a heating system in the vessel. In addition, the treating rate for a dual polarity electrostatic desalter is more than for an AC conventional electrostatic desalter.

Introduction
The production of salty wet crudes had affected the quality of Iranian crudes and a number of wells had to be shut in for lack of treatment facilities(1). The water produced with crude in Iranian oil fields contains salts in concentrations of 150,000 to 220,000 ppm. In almost all cases, the salt is found dissolved in the water that is dispersed in the crude oil. This salt water is present in the crude in the form of emulsion and its separation is not an easy task.
The installation of current desalting plants within the existing facilities in Iran called for considerable changes in the facilities and other utility systems. These changes have been successfully carried out and the performance of the majority of the desalting plants have been tested and found satisfactory(1, 2).
When the produced formation water is highly saline as in the case of Iranian fields, then straight dehydration is not the solution and the crude has to be desalted as well. Dehydration means removing only that water which is in the crude when crude is produced. The term desalting means the addition of comparatively fresh water to the crude. This addition of fresh water dilutes the original brine so that the salt content of the water that remains after treatment is within acceptable limits. In general, the dehydration system can be divided into three classes: gravity, electrical, and chemical, or a combination thereof(3). Therefore, the process adopted in Iran for treating wet crude is a combination of dehydration and desalting. It employs chemical demulsifies, heat, and an electrostatic field to dehydrate the crude.
All treaters utilize gravity to separate the phases; however, this is the basic method used to remove the impurities from the crude oil.