bluuebunny/crossref_metadata_2025 huggingface dataset:
Issues With Reservoir Geomechanical Simulations of the SAGD Process
Authors: Li P. , Chalaturnyk R.J. , Polikar M.
Published: March 2010

In the SAGD process, steam injection may result in pore pressure changes around the steam chamber in the reservoir. The magnitude of the pore pressure change depends on the steam injection pressure and the relative position of the steam chamber within the reservoir. Injected steam also increases the temperature within and adjacent to the steam chamber and thus introduces thermal expansion effects. The complex interaction of pore pressure and temperature throughout the reservoir result in varying degrees of reservoir geomechanical interactions that must be considered when contemplating reservoir geomechanical simulations of the SAGD process.

The primary geomechanical influence on SAGD recovery is associated with the volume change of the sand matrix in response to effective stress changes induced by steam injection pressures and temperatures.

Reservoir parameters and processes, such as compressibility, porosity (pore volume), absolute permeability, relative permeability, saturations, capillary pressure, enthalpy transmissibility, gas evolution, and thermal expansion effects, are all affected by bulk volume changes. In this paper, variations of these parameters due to geomechanical effect are analyzed and discussed based on related test results, calculation, and simulation. Their impacts on reservoir geomechanical simulations of the SAGD process are discussed.

Introduction

Reasonable prediction of SAGD performance by numerical simulation is an integral component in the design and management of a SAGD project. Conventional reservoir numerical simulation emphasizes multiphase flow in the porous media but generally does not take the interactions between fluid and solid into account. It applies elastic rock compressibility to characterize the coupling mechanism of multiphase flow and rock skeleton. The assumption of this treatment is that the boundary loads and temperature are constant, Δp = Δ σ'(1, 2). All analytical flow equations in petroleum engineering are based on this assumption. It is clear that the recovery process of conventional oil from sandstones and most carbonate rocks can roughly satisfy this assumption. For the SAGD process, however, volumetric deformations within the reservoir due to pore pressure and temperature changes result in variations of both in situ stress and strain. These stress and strain variations are functions of the in situ boundary conditions. Due to different directional deformation in response to in situ heating, the total stresses in vertical and horizontal directions may also vary. Moreover, the SAGD process is mainly applied in friable or uncemented (unconsolidated) oil sands that geomechanically behave differently to their cemented counterparts. Under these conditions, the assumption used in conventional numerical simulation is no longer effective because the total stress changes within the reservoir.
Multiphase Equilibria Calculation by Direct Minimization of Gibbs Free Energy Using the Tunnelling Global Optimization Method
Authors: Nichita D.V. , Gomez S. , Luna-Ortiz E.
Published: March 2010

In this paper, we advocate the use of the Tunnelling global optimization method for phase stability analysis and for multiphase equilibria calculations. The method had been successfully used for solving a variety of phase-equilibrium problems. The Tunnelling method has two steps. First, a minimum (which may not be the putative global minimum) of the objective function is found by a local bounded minimization algorithm. In a second step, the method checks for global optimality. If the minimum found in the first step is only a local minimum, a feasible initial estimate for a new minimization is generated in another valley of the objective function.

Cubic equations of state are used, but any thermodynamic model for the Gibbs free energy can be used (the method being model-independent). The proposed method has proven to be an efficient and reliable tool for multiphase equilibrium calculation.

Introduction

The methods for multiphase equilibria calculation based on the equality of chemical potentials cannot guarantee the convergence to the correct solution since the problem is non-convex (i.e., several local minima exist), and such methods can find only one minimum for a given initial guess. Moreover, the global optimization methods currently available are generally very time consuming.

A global optimization method(1, 2), called Tunnelling, able to escape from local minima and saddle points, is used in this work for the direct minimization of the Gibbs free energy and of the tangent plane distance function (TPD). The Tunnelling method has two phases. In phase one, a local bounded optimization method is used to minimize the objective function. In phase two (tunnelization), either global optimality is ascertained or a feasible initial estimate for a new minimization is generated.

The Tunnelling method has shown its ability in efficiently solving difficult non-convex, highly non-linear problems. Different kinds of phase equilibrium problems were solved using Tunnelling(3–6).

The problems addressed here are vapour-liquid and liquid-liquid two-phase equilibria, three-phase vapour-liquid-liquid equilibria, and three-phase vapour-liquid-solid equilibria for a variety of representative systems.

We use in this work a general form of cubic equation of state (EOS), incorporating the Soave-Redlich-Kwong (SRK) and Peng- Robinson (PR) EOS.

Multiphase Equilibrium Equations

Phase Splitting

According to the second law of thermodynamics, at the equilibrium state, a system of nc components of composition z = (z1, z2,...,znc)T has the lowest possible Gibbs free energy from all possible states. The dimensionless Gibbs free energy is expressed as:
Design and Analysis of a Conveyor Lift Pump
Authors: Garg D. , Bhagavatula R. , Lea J.F. , Cox J.C.
Published: March 2010

The Conveyer Lift Pump uses viscous drag to lift liquids. The pump utilizes a flexible continuous rope or conveyer, affixed about a sheave at the top and bottom of the well moving upward inside the production tubing, viscously dragging or lifting the fluid from the well. Presented here are mathematical derivations for the flow rate, the quantity of fluid to be lifted, the required drag force at the rope surface, the power input required by the system, and efficiency of this lift system. Concentric and eccentric solutions are presented.

Introduction and Discussion

Presented here is an analysis of an artificial lift concept, which is to "rope-lift" liquids out of the wellbore, based on viscous drag between the moving rope and a liquid column in the annular space of the inner tubing wall and the rope (Figure 1). This differs from other methods of lift with details in References (1) and (2), and other methods summarized by Brown(3).

Possible applications include lifting of oil/water from relatively shallow wells, the removal of liquids from gas wells to eliminate liquid loading(2), and the possible application of the concept to the lifting of viscous oil.

The foundation of the process is based upon mathematical models with the rope being centred in the tubing and being offcentre to varying degrees. For further details, see Reference (1) [Lea(2)] with a model of a downhole pump requiring similar analysis, and Crafton(4).

The tubing on the upper end delivers the fluid that has been viscously dragged along with the rope, providing the rope speed and rope and tubing diameters and the fluid viscosity are selected to yield positive production. A rope housing supports the rope during its downward travel to prevent wear from rubbing on the casing. The fluid at the surface may have to undergo a slight "scraping" effect to prevent produced fluid from being carried back downhole.

It appears that this could be used for sandy production as no sliding metal surfaces are employed, such as those found in a downhole beam pump. Also, it may be useful for high viscosity production, as the basic concept depends on fluid viscosity for lift to occur. If treating fluids need to be pumped downhole, those fluids can be conveyed to the sandface via the return protective tubing. Another application might be to pump relatively small amounts of liquid from a producing gas well to help eliminate liquid-loading. Full-scale field experience is in short supply. One weakness appears to be depth. Some of the illustrations below indicate the force needed at the surface of the lifting rope is calculated to be excessive as deeper wells are considered. Use of the models presented here should help the user evaluate the potential of this lift concept for various production scenarios.

Models and Sample Result

Models for the rope-lift pump were developed, including the rope being concentric in the tubing and also at various degrees of eccentricity.
What is Stewardship?
Authors: Maynard Brian
Published: March 2010

When the Canadian Association of Petroleum Producers (CAPP) launched its Stewardship initiative in 1999, it was the first of its kind in the world-a stated commitment by CAPP members to responsible and balanced resource development and continuous improvement in environmental, health, safety, and social performance.

In the six years since then, CAPP has worked with our members to develop the initiative and better address issues of importance to our stakeholders. Today, the core Stewardship values are engrained in CAPP's 150 member companies, and the data we collect confi rms we are well along the path of continuous improvement. We're proud of our accomplishments and we've set ambitious goals for the future.

However, a lot of people-even those in the oil and gas industry- have never heard of CAPP or its Stewardship initiative. It's not surprising. While our members apply the principles of Stewardship to their own business models and operating environments, it is not something they talk about.

Here is an example:

In January, CAPP hosted its fi rst Stewardship-related event for 2005. Natural Resources Canada Minister John Efford came to Calgary to announce that four CAPP members-Anadarko Canada Corporation, Apache Canada Ltd., Penn West Petroleum Ltd., and Suncor Energy Inc.-qualifi ed for a federal program to encourage CO2 capture and underground storage.

Greenhouse gas emissions, including CO2, have been one of the key benchmarks for Stewardship since 1999, but nowhere in the national news coverage generated by the announcement did the word "tewardship" appear, nor did anyone make the connection to Stewardship.

Stewardship isn't a label that gets slapped on a product; it's an ethic that integrates economic, environmental, and social considerations through all aspects of each company's operations. That is the real essence of the initiative. However, our industry earns its license to operate through our decisions and actions and their impacts, so it is more important than ever that CAPP work to improve Canadians' knowledge, awareness, and trust of the upstream oil and gas industry.

Canada is a major contributor to global oil and gas supplies and will be for decades to come. We are the world's third largest producer of natural gas and ninth largest producer of crude oil. Daily production in Canada is greater than half the members of OPEC and, thanks to Alberta's oil sands, Canada's oil reserves are second in the world only to Saudi Arabia.

The economic impact of oil and gas activity is evident. About one-quarter of the world's drilling rigs operate in Canada and CAPP members drill more than 20,000 new wells a year. The record level of drilling activity has brought the industry into contact with an increasing number of stakeholders and communities.

In today's fast-paced, information-based world, our stakeholders have access to a variety of information sources-some accurate and some not-and they are more engaged than ever.
Coalbed Methane Development: Practices and Progress in Canada
Authors: Gatens M.
Published: March 2010

As conventional gas supplies decline, unconventional sources of gas, like coalbed methane (CBM), will become increasingly important in Canada. Canada has over 700 Tcf of CBM gas resource in place, comparable to the U.S. resource. Canada now has the world's largest "dry" coal play and it is estimated (as shown below) that CBM will grow to 2 - 3 Bcf/d in production over the next 10 – 20 years and lead to recovery of up to 75 Tcf of gas. Since 2000, increased drilling activity has led to over 3,000 CBM wells and 150 MMcf/d of CBM production in Canada today, with both estimated to grow substantially in 2005 and beyond. CBM will become an increasingly important part of Canada's gas supply.

Introduction

Coalbed methane (CBM) is simply the natural gas that is generated by coal seams during the coalification process. It is "sweet gas" (not sour), is largely comprised of methane (>90%), and is similar to the natural gas that is burned in homes. In Alberta, the Department of Energy (DOE) refers to CBM as natural gas from coal, or NGC, to associate it with existing regulations which govern the production of natural gas. In British Columbia (BC), it is referred to by the Ministry of Energy and Mines (MEM) as coalbed gas, or CBG. Regardless of the name used, it is the same gas.

CBM reservoirs are classified as "unconventional" and have gas storage and production mechanisms that distinguish them from conventional reservoirs. Most of the gas in coal is stored in a sorbed state within the coal matrix, physically attached to the complex internal surfaces of the coal as a function of pressure, characterized by sorption isotherms(1, 2). Coals which are suitable for CBM production are naturally fractured, with closely spaced natural fractures, or "cleats," which provide pathways for gas flow from the coal matrix. In many cases, but not all, these cleats are initially full of water, which must be produced to reduce the pressure around the coal matrix allowing the sorbed gas to desorb and become free gas which can then be produced. The gas storage and production mechanisms of coals are comprehensively covered in References (1) and (2) and elsewhere in the oil and gas literature. In Canada, commercial production of CBM has only recently begun. The objective of this paper is to provide a summary of the major coal groups being targeted for development in Canada and an update on the recent evaluation and development. Predictions of future performance will also be presented.

CBM History in the U.S.

Commercial development of CBM began in the U.S. in the 1980s. Initial efforts to remove the gas from coals were funded by the U.S. Bureau of Mines primarily to improve mine safety. As natural gas value increased, the research began to focus on capturing the CBM for commercial use, and hundreds of millions of dollars were dedicated to research and development projects by the U.S. DOE, the Gas Research Institute (GRI), and the industry(3–7).
A Fractal Wormhole Model for Cold Heavy Oil Production
Authors: Liu X. , Zhao G.
Published: March 2010

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

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

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

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

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

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

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.
West Delta Block 84-Methodology and Analysis of a Previously Orphaned Field
Authors: Kimbrell W.C. , Wojtanowicz A.K.
Published: March 2010

This paper describes the effort to justify, document, and confirm proven, unproven, undeveloped, and bypassed remaining oil and gas reserves in West Delta Block 84 Field; at one time an orphaned field off the coast of Louisiana. The methodology used for the evaluation provides an insight into how to quickly and efficiently identify worthwhile and economic marginal properties, even with incomplete or missing information. This methodology is being used as a part of the development of an expert system for the evaluation of marginal and/or orphaned wells, reservoirs, and fields.

West Delta Block 84 is located off the coast of Plaquemines Parish, Louisiana, near the mouth of the Mississippi River in about 20 ft of water. Conoco discovered it in 1955 with the drilling of the SL 2551 No. 1 well to a total depth of 14,500 ft. It has produced over 9.8 MMSTB of oil and 21 BCF of gas. It was shut in for a period of almost ten years while languishing in and out of bankruptcy court from 1990 to 2000, and was actually orphaned by the state at one point during this time.

Available data was organized and pieced together for the field, but was still lacking in completeness. As in most cases when dealing with older marginal fields, an ability to deal with missing and incomplete information was necessary to complete the analysis.

Introduction

There are reportedly 343,030 inactive, shut-in, and/or orphaned wells nationwide, of which 34,355 are in Louisiana. In many cases, these wells are idle and orphaned, not because their resources have been depleted, but because of other factors. These factors might include low product price, high cost of operations, unrelated financial problems, or the inability or lack of resources to properly describe the reservoir and identify the potential for additional recovery, among other things. It is simply not known, with any accuracy to an outside party looking in, exactly why a well is shut in or orphaned.

Historically, small and large independent producers have entered into fields previously operated and owned by the major oil companies. These underfinanced and understaffed independents find themselves working off cash flow and unable to find the financial resources to work over the idle wells, much less do the research that many of the wells and reservoirs deserve and need. The wells may have potential, but no one has the time or the money to pursue these presumably marginal targets.

There is an incentive to identify potential in these shut-in/orphaned wells since their plugging would be terminal and, in the case of orphaned wells, would cost taxpayers money. In a period of four years, from 1996 to 2000, there were reportedly 712 wells plugged in Louisiana for US$14,090,000, which is an average cost of US$17,890 per well. Presently, there is a new powerful incentive for not plugging wells that might be returned to production as the processing price of oil has reached US$56/STB with no signs of leveling or dropping in the future.
Simulation of Erosion in Drilling Tools for the Oil and Gas Industry
Authors: Arefi B. , Settari A. , Angman P.
Published: March 2010

Erosion is a form of wear that has been found on the drilling tools used in the oil and gas industry that can, in some cases, severely shorten the life of the tools. In spite of its importance, there has been virtually no attention paid to it in drilling engineering research. This paper focuses on the modelling of erosion and the application of the developed models to improve the design of drilling tools. The mechanism of erosion, which is controlled primarily by the impact velocity and angle, has been formulated based on experimental and theoretical work done in material science. These algorithms were developed for transient simulations of the erosion of any surface in 2D geometry. Based on these, an "Erosion Simulator(1)" has been written, which is able, in combination with any computational fluid dynamics (CFD) software, to simulate erosion in downhole tools. Actual data from TESCO Corporation casing drilling tools(2) has been used to calibrate the physics of the process and validate the software. The simulator has been used to modify the geometry of the under-reamer casing-drilling tool, which resulted in a substantial decrease in erosion rate and therefore an increase in the tool's life.

Introduction

Erosion, as a form of material wear, has been reported in many areas of the oil and gas industry. An example of erosion in drilling tools is the TESCO Corporation (hereinafter TESCO) "underreamer" tool used in casing drilling(1) (see Figures 1 and 2). Erosion in the drilling industry is important because it can lead to an increase in time and cost of operation. In the case of drilling tool failure from erosion, eroded parts must be replaced. This will cause unexpected extra rig time in order to pull out the drill string and run it with new parts into the wellbore. Besides the cost of operation, erosion may be dangerous. Tool failure can cause a blowoutand be a potential for loss of lives. This paper focuses on an erosion simulation in order to understand and predict erosion phenomena in drilling tools, with the ultimate goal of improving tool design and extending its life.

History of Erosion Research

Erosion (i.e., a form of wear) occurs when fluid containing solid particles impacts a solid surface. The intensity of erosion is commonly measured as a specific weight loss (rate of material removal from the surface) and expressed as Er (the weight of material removed by unit weight of impacting particles). During the 1960s and 1970s, a number of important experiments were done in the area of metal wear that laid the foundation for the current understanding of the phenomena. Erosion experiments during that period covered impact velocities up to 550 m/s and particle sizes of up to 1,000 μm [Tilly(3)]. Different velocities and particles can cause different types of damage. During this time, scientists and researchers determined the relationship between erosion rate, the type of material, size of particles, velocity, and angle of impact.
Determination of True Bed Thickness Using Folded Bed Model and Borehole Data
Authors: Xu S.S. , Velasquillo-Martinez L.G. , Grajales-Nishimura J.M. , Murillo-Muneton G. , Garcia-Hernandez J. , Nieto-Samaniego A.F.
Published: March 2010

The true bed thickness (t) is the actual thickness of a given formation perpendicular to the bedding plane. The value of t depends on the angle and the direction of the dip of the measured formation, as well as the drift angle and azimuth of the borehole. The traditional methods to calculate the parameter t consider only the case of monoclinal beds but not the case of a folded bed, which will cause deviations when the bed dip on the top is different from that on the bottom. To avoid these deviations, this paper shows an approach to calculate the values of t using a folded bed model. The deviations for the monoclinal bed model are positively related to the bed dip, the dip difference and the deviated angle of the wells. A case study from the Cantrell oil field complex in the southern Gulf of Mexico (offshore Campeche) is used to test the folded bed method. The results indicate that this model can yield more uniform spatial change of the values of t, whereas the monoclinal bed model will overestimate the average value of t. Compared to the folded bed model, the maximum relative deviation of t from the monoclinal bed model reaches 22.3% and the maximum absolute deviation of t reaches 34.5 m.

Introduction

In the subsurface of a bed formation, the true bed thickness can be estimated from information gathered from well logs such as the dipmeter and borehole images. The log thickness of a given stratigraphic interval can be thicker, equal to or thinner than that seen in a vertical well drilled through the same stratigraphic section because of well deviation and formation dip. Provided bed dips and well deviations do not exceed a few degrees, the simple vertical-horizontal case is approximated closely enough by the logs. But when deviations and dips do exceed about 10 °, corrections are needed. A previous method of corrections is based on the monoclinal bed model. But this assumption is approximate, because the tectonic events generally cause the beds to be not only tilted, but also folded.

True bed thickness is important in dipping beds and in deviated holes, since reservoir volume and isochore maps depend on these properties and not on the measured thickness. In this paper, a folded bed model is proposed to calculate the true bed thickness in the subsurface utilizing well log data.

Calculation of the Value of t in the Case of Monoclinal Bed

First, the case of a monoclinal bed is reviewed here. Figure 1a shows the case of a vertical well crossing a monoclinal bed. If the well enters the top of the bed at A, and leaves the base of the bed at B, the depth difference between A and B is defined as hd. The true bed thickness of the bed (t) can be expressed as:

Equation (1) (Available In Full Paper)

Figure 1b shows the case of a well deviated at an angle a from the vertical crossing a monoclinal bed.