bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer Model Evaluates Oil Pumping Units in Inclined Wells
Authors: Lukasiewicz S. 
Published: March 2010

Abstract
The paper analyzes the dynamic behaviour of the sucker rod string in the inclined well. In this case, due to the curvature of the tubing the rod vibrates longitudinally as well as transversally. A mathematical model of the vibrating string consisting of two coupled differential equations was developed. The paper describes the fundamental assumptions and simplifications which can be used in the numerical analysis. The examples of the results are also presented. They include the effect of the distortion of the geometry of the rod string on the plunger load-displacement diagram and the diagram of the friction forces along the rod string.

Introduction
The evaluation of pumping units in the inclined wells has been a serious problem in engineering practice. The common practice at present is the application of the program developed for vertical wells to the analysis of deviated wells. This introduces substantial errors in the calculations of the stresses in the rod string and as regards the gearbox torques. Generally, the maximum torques calculated properly for the actual geometry of the slant hole pumping unit can be up to 40% larger than the corresponding values obtained from the calculations for vertical units. Besides, the application of the program for vertical wells to the evaluation of inclined, wells gives results in which all the friction forces from the rod string are concentrated at the plunger. This gives false prediction of high compressive forces at the bottom of the rod string and can be the reason for the wrong conclusions regarding the rod stability.
The rod in the inclined well is under different static and dynamic forces than in the vertical one. It is supported by the tubing of wheeled couplings but it is also transversely loaded by its own weight. Therefore, the dynamic behaviour of the sucker rod in the deviated well is much more complicated and different from a vertical one. The differences are caused by the friction between the rod string and the tubing and the rod curvature. If the tubing is curved, the dynamically loaded rod string deforms and comes into contact with the wall of the tubing. The curvature causes the lateral displacements of the rod inside the tubing. It couples the longitudinal vibrations with the transverse vibrations. The axial compressive forces at the bottom of the well can buckle the rods. In this case, the problem becomes nonlinear and difficult to solve.
The need to obtain a model for use in the evaluation of pumping units and downhole equipment in the inclined and deviated wells resulted in the development of an applicable design and optimization technique. SRPUMP computer program was developed a tool that allows a high level of expert knowledge to be applied daily in the field, dealing with problems of the inclined wells.

Fundamental Assumptions
An accurate prediction of the performance of the sucker rod string and the bottomhole equipment requires careful modelling of the dynamic behaviour of the rod.
The Need For A Marketing Strategy For Alberta Bitumen
Authors: Redford David A. 
Published: March 2010

In the Alberta oil sands, Alberta has one of the three gigantic petroleum deposits in the world. The others being in the Middle East and in the heavy oil belt of eastern Venezuela. Fifteen years ago, we could produce only a small fraction of this immense deposit (perhaps 4 billion m3 from the Athabasca deposit and a small portion of the Clearwater formation in Cold Lake) and costs were high.
Over the past 15 years, government and industry have invested heavily in research and development of new technology for bitumen extraction. The results have been spectacular. Not only can we produce vast amounts of bitumen (~ 45 billion m3) from the Athabasca, Peace River and Cold Lake deposits, but it can be done in many cases at one-third to one-half the previous cost.
The application of Steam-Assisted Gravity Drainage Technology from Underground Access (SAGDUA) to the thick continuous sections of the Athabasca deposit can produce 12.6 billion m3 of bitumen for C$7.00/bbl (Fig. 1). This is the same average cost of producing conventional crude in Alberta, excluding exploration costs. At a supply cost for bitumen of C$9.00/bbl, it is estimated that up to 42.5 billion m3 (270 billion bbls) can be recovered.
Despite these spectacular gains in technology and the resulting lower cost of producing bitumen, we see no rapid increase in bitumen recovery. Indeed, most new bitumen production projects have been put on the back burner or moth-balled. Five major integrated projects have been cancelled. Why is this occurring?
Figure 2 gives the price in U.S. dollars of bitumen in Edmonton. The price is extremely variable and at times very low (C$5.00)/bbl). The field price is even lower (as low as C$3.00/bbl) With such highly variable and often very low prices, it is not surprising that investment and development has been suppressed. It also demonstrates the inadequacy of a marketing strategy for Alberta bitumen which relies on the sale of raw bitumen. Alberta is far from tide water and bitumen is not a readily transportable commodity. Alberta bitumen, therefore, cannot readily access world markets and command competitive world market price. In recent years, bitumen has been transported to the Chicago area, and more recently to Billings, Montana, by dilution with light condensate. This provides a very limited and restrictive market because only specialized conversion facilities can accept bitumen.
The dilution condensate, which goes along for the ride, commands a low value because of its high yield of low octane gasoline containing excessive aromatics. These have low demand in an increasingly more environmentally conscious world.
What are the options? The sale of bitumen in western Canada is dependent on the very limited and highly variable asphalt market and this currently contributes to the high variability of bitumen prices in Edmonton. The transport of bitumen, as an oil-in-water emulsion, while technically feasible, suffers the limitation in Canada that we live in a very cold climate.
Coil Tubing Fishing Operation On a Deep, High Pressure, Sour Gas Well
Authors: Stadlwieser J. , Best J. , Willson D. , Bloor B. 
Published: March 2010

Abstract
The use of coil tubing in fishing operations has been limited to date. This paper discusses a coil tubing fishing operation on a 4000 m, 30% H2S gas well with 27 MPa surface pressure. A 12.5 metre wireline tool string was stuck inside the production tubing at 1770 m, with 76 m of elemental sulphur fill on top. The need for 23 m of lubricator during coil tubing fishing operations was eliminated by designing a pump through Pressure Deployment System, along with a pump-off sub. Problems encountered with the Pressure Deployment BOPs will necessitate periodic inspection of the BOP stack on future high pressure, sour well work.
Advances in coil tubing technology have made coil tubing an economical alternative for many oil field operations. Fishing operations can now be performed on live wells without long sections of lubricator. Coil tubing has increased to 88.9 mm (3 1/2") in size, has become more H2S resistant and is now continuous without butt welds. The components of the coil tubing unit, such as the injector have also increased in strength allowing work in deeper and higher pressure wells.

Introduction
Esso's Obed Field near Hinton, Alberta is comprised of five sour gas wells, three of which are completed in the Nisku formation and the remaining two in the Leduc formation. A gauge ring with a junk catcher was run into Esso et al. Obed 11-13-54-23 W5 in an attempt to determine the amount of sulphur and iron sulphide scale buildup on the 114.3 mm tubing.
The gauge ring became stuck due to sulphur scale buildup at 1770 m and was left in the hole. An unsuccessful attempt was made to fish for the gauge ring using braided line. During the fishing attempt the fish could not be pulled free and the fishing tool would not release from the fish so the braided line was pulled out of the rope socket. This left a resulting fish of 12.5 m in the well. An impression block run later revealed that 76 m of sulphur had piled on top of the fish.
This 4000 m, 8% CO2, 30% H2S gas well had a bottom hole pressure of 38 MPa and 27 MPa surface pressure. Figure I is a schematic of the well,
FIGURE 1: Subsurface schematic: Esso et al. OBED 11-13-54-23 WSM. (Available in full paper)
wellbore, shear events near the well bore (combined P and S phases, too close to be distinguished), or shear events far away from the wellbore (S phase only, P phase completely absorbed). It is interesting to note that most of the signals are oriented within the N30–40 °E window (Figure 6). which is close to the expected orientation of the main fracture. The results also show that the best polarization is obtained within the first quarter-period of the wave and degenerates quickly afterwards. This can be explained if one assumes that the events are occurring close to the wellbore. The first part of the waveform would be mostly a P-wave that would become gradually contaminated by S-waves.
Reservoir Pressure Analysis: Art Or Science?
Authors: Mattar L. 
Published: March 2010

Introduction
Measure the pressure in a gas well using high resolution electronic recorders (resolution better than 1 kPa). Produce IE6 m3 of gas. Shut the well in until complete buildup and measure the pressure again. It is 100 kPa lower than the initial pressure. Does this mean depletion? The material balance relationship for a gas pool is an equation of a straight line. All you need is two pressure/production measurements to define this line. The ends of this line give you the initial pressure and initial gas in place. Does this mean we don't need to measure the initial pressure anymore. because we can determine it, a posteriori, from any two measurements'? Two pressure recorders (electronic, high sensitivity) sitting one metre (vertically) apart show a difference of 1 kPa. Is the fluid between them gas or water'?
From a science perspective the answers to the above three questions are very obvious: yes, yes, gas: but from an engineering perspective, the answers are: sometimes, no, maybe either. These examples are typical of the issues we face as engineers (particularly reservoir engineers), dealing with inaccurate data and trying to estimate unknowns, and sometimes "unknowables."
With the advent of the computer age, we have lost something precious; we have thrown out the baby with the bath water. Not only did engineers throwaway their slide rule, but with it some of us threw away the slide rule mentality - the art of approximation and judgment. I remember with the early electronic calculators the square root of 4 was not 2, it was 1999 It is also apparent that, with the advent of digital watches, time is no longer a continuum. but it occurs in discreet quantities such as seconds! (As seen on the LED display of the digital watch). This is the dilemma of our age.

Science and Art - Theory and Practice
Computers now calculate at the rate of millions of instructions per second. They have given us the ability to arrive at the answer faster. Usually the answer will be wrong! But if we are good engineers it will be the best possible answer. This underlies the essence of engineering (particularly reservoir engineering). We are usually working with extremely complex real life situations, idealized (simplified) models, precise but inaccurate data, incomplete data sets and conflicting data. We can study and compute multiple options based on several assumptions, each leading us to different conclusions. But, at the end of the day, in spite of the numerous solutions, we usually only have a choice of one of these options to act on.
Science and computers have provided us with the theory. However, superseding all this theory, must be the practice. Often this is a gut feeling, procedure based on experience of real life behaviour of systems. In other words, it is an art." Good engineering is an art based on both science and experience, theory and practice.
Coalbed Methane In Alberta
Authors: Byrnes T.L. , Schuldhaus K.F. 
Published: March 2010

Abstract
Alberta's coalbed methane (CBM) resource has been estimated to be comparable in size to that of the province's conventional natural gas resource base. Although only limited drilling for CBM targets has occurred in the province to date, considerable interest in how development of this resource might proceed has been shown by the gas and coal industries, the public, and regulatory agencies. Because CBM is a form of natural gas, it is regulated in the same manner as other natural gas. An overview of CBM in Alberta is given, including the potential resource base, elaboration on the application of natural gas regulations to CBM, activity to date, and some of the main regulatory issues and initiatives that have arisen. It is shown that there is a need to collect Alberta specific CBM data before decisions can be made on the necessity of regulatory change specifically for CBM development.

Introduction
Numerous papers and articles have been published over the past few years on various aspects of CBM. The growing number of CBM wells and increasing amount of CBM production in the United States (USA) has caused somewhat of a surge in published case histories and field experiences for the major CBM basins ill that country. Much less CBM field experience currently is available for Alberta, but the potential CBM resources of the province have not been overlooked.
Early investigations into the production of CBM in Alberta date back to the late 1970's, but interest waned in the early to mid 1980's with falling gas prices and a levelling in gas demand. The more recent interest in CBM development ill Alberta was spurred on by the surge in CBM activity that occurred in parts of the USA from 1989 to 1992.
A summary of the current CBM situation in Alberta is given in this paper. The province's CBM resource potential and regulatory framework are overviewed along with activity to date and some of the issues that have been raised regarding the development of this resource.

Why the Interest in Coalbed Methane in Alberta?
The recent interest in CBM in Alberta can be attributed to three main factors:the large CBM resource potential of the province.the large amount of recent CBM development activity in the USA, andenvironmental concerns regarding the development of CBM in Alberta.

Alberta's Coalbed Methane Resource Potential
CBM is a naturally occurring hydrocarbon gas, consisting largely of methane, that is generated by and stored in coal seams. Because Alberta has extensive coal deposits, it follows that the CBM resource associated with these deposits has the potential to be significant.
Coals of varying thermal maturity, or rank, underlie about 45 per cent of the province(1), with essentially all of the coals being located south of Township 75 as shown ill Figure I. These coals are associated with Upper Jurassic, Cretaceous, and Lower Tertiary strata as shown in Figure 2, and much of it may be of suitable rank to hold potential for CBM development.
Co-polymer Beads Reduce Friction In Horizontal Wells
Authors: Bird J. , Garrett C. 
Published: March 2010

Introduction
Divinyl benzene co-polymer beads, better known as plastic beads, have been used for reducing torque and drag in conventional drilling operations for 17 years. Over the last four years, they have also been utilized to reduce friction in horizontal wells when drill pipe is not sliding at a fast enough rate, or is not moving at all. Co-polymer beads have also gained recognition as a means of reducing friction in coiled tubing workovers.
Friction is reduced by introducing co-polymer beads between the drill string and bore hole. Laboratory testing and field experience have developed methods for reducing friction through specific application techniques. Application of the beads can vary, from spotting small "pills" in specific sections of the bore hole to carrying a concentration of beads throughout the system using a bead recovery unit.
Drill string drag is the incremental force required to move pipe up or down in the hole, and torque is the force required to rotate pipe. The magnitudes of torque and drag are related in any particular well, and high drag forces and excessive torque loads normally occur together.
There are a number of causes for excessive torque and drag. They include:tight hole conditions;sloughing hole;key seats;differential sticking;cuttings buildup because of poor hole cleaning; andsliding well bore friction.
With the exception of sliding friction, these causes are associated with problem conditions in the well bore.
Although all of these conditions can occur in horizontal wells, the primary source of torque and drag in a horizontal well with good hole conditions is sliding friction. The ability to alleviate sliding friction using co-polymer beads has proven to be extremely beneficial in horizontal drilling and workover operations, including standard pipe and coiled tubing.

Sliding Friction
Normal contact force and the coefficient of friction between contact surfaces are the two factors that affect sliding well bore friction. Another factor, capillary attraction, must be considered in open hole situations. Capillarity is described as the relative attraction of the molecules of a liquid where it is in contact with a solid. The relative attraction of molecules leads to a force of adhesion between a solid and a liquid.
The wallcake of a well bore will exert very strong capillary attraction forces on a drill string when it comes in close contact with the drill string. This is explained by the fact that the wallcake or mudcake is composed of very small particles of clay, barite, sand, or other matter, and these minute particles will have considerably more surface area exposed for wetting by liquid than would larger particles in the same section of mudcake. The smaller the particles, the more surface area exposed for liquid wetting, thus the greater the attractive capillary force exerted.
The capillary attractive force could lead to the drill string adhering to the wallcake, creating torque and drag. The beads, having a larger particle size than the solids in the wallcake, reduce this adhesive force.
Selection of PVT Properties For BLack Oil Simulation
Authors: Smith R.A.W. , Tan T.B. 
Published: March 2010

Abstract
It is generally accepted that the reservoir depletion process is a differential liberation process where the gas is removed from contact with the oil as soon it is formed, and the production of fluids through tubing and separators is a flash liberation process where the gas liberated from solution remains in contact with the oil.
laboratories commonly perform differential liberation and separator tests on the reservoir fluid and then use a correlation described by Amyx et al.(1) to arrive at a composite liberation curve for an optimum separator pressure. Engineers are often confused as to which of the two sets of PVT data, i.e, differential or composite, should be used in a black oil simulation of the reservoir. The differences between the two sets of the data becomes more substantial as the API gravity of oil increases.
The black oil simulator used in this report has a compositional formulation and has the ability to rigorously model the PVT behaviour by entering differential liberation data for reservoir conditions and using a surface separator option for the surface flash process. This paper describes a critical comparison of the three methods to enter PVT properties in a black oil simulator.
The results of using the simulator in three ways:differential liberation at reservoir, surface separator for flash,composite liberation data,differential liberation data,
are described in this paper for a medium gravity crude.
It is shown that the composite liberation data most closely represents the rigorous representation of phase behaviour as in (a). Use of inappropriate liberation data could result in significant error in estimates if oil-in-place as in (c). The paper compares the differences between composite liberation (b) and the rigorous representation (a), such as different initial pressure and saturaturation gradients due to initial density differences.

Introduction
When studying reservoirs with moderately high API gravity and gas-oil-ratio values, it becomes more important to incorporate both the differential and flash components of the PVT behaviour. In order to demonstrate the differences between using only the differential data as opposed to including the effects of the flash data, actual PVT data from the model study which is referred to as reservoir A, with an API gravity value of 34, is incorporated into the SPE Second Comparative Solution Project(2). The data of the Second Comparative Project remains the same except that the original PVT data set was replaced by the PVT data from reservoir A as shown in Table 1. Note that the differential solution gas (Rs) value if reservoir A was significantly highr that the separator flash data.

Problem Statement
Potential loss of intermediates, number of stages in the compressor design and an accurate forecast of oil and gas production are among the major concerns of any simulation study with PVT properties similar to Reservoir A. To accommodate these requirements, it would be necessary to accurately model the PVT behaviour of the fluids from the reservoir to the tanks.