bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Correlation Of Viscosity And Molecular Weight
Authors: Closmann P.J. , Seba R.D. 
Published: March 2010

Abstract
Data have been obtained for molecular weight as a function of oil viscosity for a range of crude oils and bitumen fractions from 2.85 mPa.s (cp) to 1.23 X 1012 mPa.s (cp) at 25 °C (77 °F). A correlation based on these data has been useful in some compositional numerical simulations as well as in other studies, especially when viscosiry and molecular weight data are not easily obtained. The values are listed in Table l, along with density values. Much of the data consists of measurements on the residuals left behind after gas distillation or fractionation of Peace River bitumen. In this latter work, nitrogen was bubbled through Peace River tar in a succession of increasing temperatures. After each temperature step, a sample of the residual tar was removed and its viscosity, density, and molecular weight (by vapour pressure osmometry with toluene) measured. For the higher molecular weight samples, because of the high viscosities, it was necessary to make measurements at temperatures higher than room temperature (25 °C, 77 °F). The resulting values were then plotted on the standard ASTM viscosity chart and the curves extrapolated to 25 °C (77 °F). The value of the additional data on very heavy residual fractions lies in providing some possible numerical values for viscosity of the non-volatile component present in some compositional numerical simulations. The data for complete crudes and residual fractions are plotted on the extended graph (Fig. 1), along with some data for pure compounds in the low molecular weight region (normal paraffins plus benzene and toluene)(1), as indicated in the figure. Because of the wide range of the data and the variable nature of the samples, a visual estimate of the best curve was drawn through the data points below the viscosity value of 18 300 mPa.s.
Because viscosity data were obtained on the distilled fractions as well as the residuals, these values were plotted in Figure 1 for comparison. (One point is left off the plot. It appears anomalous when compared with other similar data.) On the molecular weight-viscosity plot, most of the distillate fractions fall slightly below the curve obtained for original oils and tar residues. (They correspond to a temperature about 1 °C lower, but this is not expected to be significant.) Possibly a greater fraction of polar molecules in the original crudes cause the latter to exhibit a higher molecular weight than the compounds removed by distillation.
In extending the plot beyond the value of 18 300 mPa.s we were guided by the published relation of Dunstan and Thole(2,3)
Equation (Available In Full Paper)
where µ is viscosity, M is molecular weight, a is a general constant, and b is a constant characteristic of any given homologous series. In this case we used a least squares fit to a straight line beginning at the point at µ = 18 300 mPa.s (cp) and increasing.
Optimizing Electric Submersible Pump Replacement Costs
Authors: Kupsch Nathan W. 
Published: March 2010

Abstract
Electric submersible pumps (ESPs) have made a significant contribution to the petroleum industry as an economic means of artificial lift. As current depressed oil prices linger, it has become especially critical that casts associated with operating ESPs be kept to a minimum. One method, which has resulted in a great deal of success for Amoco Canada, has been qualifying used motors and pumps for re-use through cleaning and testing procedures.
Among Amoco Canada's operations are two large fields; the South Swan Hill Unit and the Nipisi Gilwood Unit No.1. Together, a total of 235 electric submersible pumps are in service. As ESPs fail downhole, equipment is examined/or potential testing application. To the end of June 1989, 457pumps have been cleaned and tested while 221 motors have also been put through the test program. A high requalification rate and inexpensive testing cost have combined for substantial savings over traditional repair procedures, The success of the program has been further enhanced by encouraging ESP performance from equipment rerun subsequent to being cleaned and tested.

Introduction
Amoco Canada Petroleum Company Ltd. is the Unit Operator of two major miscible flood projects. The locations of these fields are shown in Figure 1. The South Swan Hills Unit is located 225 km northwest of Edmonton, Alberta, and comprises ISS producing wells with 70 injection wells. The 124 electric submersible pump locations account for almost 97% of the 30 000 m3 per day average fluid volume. Production is from the Swan Hills formation of the Beaverhill Lake Group, a limestone reef complex. Bottom hole temperature averages 112 °C at a depth of 2 500 m KB.
The Nipisi Gilwood Unit No. 1 is located approximately 350km north of Edmonton. The average Unit fluid production is 23 500 m3 per day. Included in the 230 producing wells are 111 ESPs which are responsible for 93% of this volume. An additional 74 wells are used for injection. The producing reservoir is the Gilwood (sandstone) formation at a depth of 1 700 m and BHT of 60 °C.
During the Past few years, an average of 125 ESP replacements have taken place annually in the above locations. Included in the $55,000 average replacement cost were ESP equipment expenses of $28,000 each. This resulted in an annual expenditure of approximately $3.500,000 for ESP repair and/or purchase. In April 1987, a used pump and motor testing program was initiated, similar to that described by D.L. Divine(1). In the 26 months since that time, ESP replacement expenditures have been reduced by almost $2 million.

ESP Operations
Amoco Canada replaces ESPs through me most economic means available. This has historically been with new equipment purchase and/or flat rate repairs. Research into the failures experienced showed that while one component failed, companion equipment was often in good condition and could be re-used. Standby inventories have been maintained separately for each Unit in order to minimize costs and eliminate deferred production due to the unavailability of equipment.
In Situ Combustion Tests On Eyehill Cummings Reservoir
Authors: Moore R.G. , Ursenbach M. , Ursenbach D.W. 
Published: March 2010

Abstract
In early 1984, a series of four combustion tube tests were performed at The University of Calgary on restored cores from the Eyehill Cummings heavy oil pool, located near Lloydminster, Saskatchewan. The tests provided a useful comparison of normal vs enriched air in situ combustion. Important observations arising from this test series were:water injection decreased the oxygen requirements;increased oxygen enrichment resulted in increased oxygen storage in the swept zone behind the combustion/ rant; andwater injection resulted in an increase in (swept zone) oxygen storage.
The dry enriched air test showed some oxgyen breakthrough near the end of the test which resulted in an increase in viscosity of the produced oil. Increased sulphate levels in the produced water during that test also reflected the oxygen breakthrough.

Introduction
In recent years, laboratory combustion tube tests have become the customary method of determining the feasibility and the design parameters of an in situ combustion project. These tests, which utilize oil and homogenized core from the proposed reservoir, provide a relatively inexpensive method of predicting the type of problems which will be encountered in the field. They also give a qualitative indication of the "burn" performance of a specific reservoir, because it has been found that the results from one reservoir are rarely applicable to another.
In addition to providing the air or oxygen and fuel requirements for an in situ combustion project, combustion tube tests also determine the properties and compositions of the produced fluids (oil, water and gas). Moore, el at. (1984) showed that the burning mode (low or high temperature oxidation) and the location of the burn front could, to some degree, be inferred from the composition of the produced gases, as well as by the viscosity and asphaltenes content of the produced oil and the pH and sulphate ion concentration of the produced water.
In 1984, Murphy Oil Company and the Canadian Government's Department of Energy, Mines and Resources (EMR) contracted with the In Situ Combustion Research Laboratory at The University of Calgary to perform four combustion tube tests using core,oil and brine from the Eyehill Cummings heavy oil pool. This research group, located in the university's Department of Chemical and Petroleum Engineering has conducted over 230 such tests on over 50 different reservoirs world wide. This paper summarizes the results of the series of four combustion tube tests and compares the combustion process characteristics in various operating modes.

Experimental

Equipment
The core holder used for this test series was a 10 cm (4 in.) diameter, 1.83 m (6 ft) long thin walled (1 mm) Type 600 Inconel tube. The tube was wound with twelve 1000 W heaters, forming twelve heating zones, each 15 cm (6 in.) in length, thus allowing for near adiabatic operation of the combustion test. A thirteenth heater was wound around the injection end of the tube to aid the ignition process.
Equipment And Procedures Shortcut Results In Uncontrolled Flow — A Case Review
Authors: Reid J. , Berndtsson N.G. 
Published: March 2010

Abstract
It is imperative that a completed well be adequately equipped to fully control the flow of any fluid from the well at all times. Regardless of the nature, size or type of equipment that an operator may be running in or out of the wellbore, the procedure must assure that the wellhead, blowout prevention equipment and any other ancillary equipment be capable of providing that control. Two accepted practices are to either fill the wellbore with a fluid of sufficient density to create a hydrostatic head that exceeds or balances the pressure of formation open to the wellbore, or to perform live well servicing. The latter involves snubbing the production tubing or working string into and out of the well under pressure. The snubbing method is used when there is a concern that kill fluids could damage the formation inflow capacity of the well. This case reviews a failure to control a gas well while snubbing out a working string with variable diameter tools being used to retrieve a tubing conveyed perforating gun from a well in Alberta. The well had been perforated, briefly flow tested and was being prepared for a fracture stimulation treatment.

Drilling and Initial Completion History
A well license was issued on January 23, 1986, for the well, Lac ef al. Minehead 6-18-49-17 to be drilled for the purpose of obtaining production from the Cardium formation at a projected depth of 2440 m. Figure 1 shows the location of the wellsite, approximately 35 km south of the Town of Edson, in west central Alberta.
The well was spudded February 4, 1986, and drilled to total depth by March 7, 1986. As shown in Figure 2,139.7 mm casting was run to 2436 m and cemented. A 60.3 m tubing was run in the well and the Cardium Sandstone was perforated from 2385.5 m on March 18, 1986, using a tubing conveyed perforating gun (TCP). A 38 m3 liquid CO2 stimulation squeeze was conducted on March 19, 1986. A modified isochronal backpressure test and final pressure buildup were conducted during the period March 26, 1986 to April 13, 1996. The results indicated limited inflow, an AOF of less than twenty 101 m3/d with some condensate. The shut in sand face pressure was 23,270 kPa. The final tubing pressure was 16,170 kPa and the final casing pressure was 16,690 kPa.
Because of the limited flow capacity of the well it was decided that a fracture stimulation treatment was necessary to make the well capable of commercial production.
The information presented in this paper up to the section "Well Control Operations" was gathered from interviews and discussions with representatives of the licensee, some contractors, other government agencies and ERCB field staff sent to the site immediately after the initial notification of the blowout. The well control presentation is based on ERCB field staff observations and the authors were on site for the last two days of the well control operation.
Sucker Rod Wear In Directionally Drilled Steamflood Wells
Authors: Mottram R.J. 
Published: March 2010

Abstract
Husky Oil's Thermal Operations District in the Lloydminster, Saskatchewan area, has had extensive experience with sucker rod wear in directionally drilled steamflood wells.
Husky's two major steamflood projects, the Aberfeldy Steamflood Pilot (steam drive) and the Pikes Peak Pilot (cyclic with some post-cyclic stream drive), have drilled and produced directional wells from pads since 1983.
As expected, the frequency of wear-related sucker rod failures in directionally drilled wells is much higher than in conventional vertical wells. Through careful data gathering and analyses, Husky has attempted to quantify the degree of incremental wear as well as identify the controlling mechanism(s) (i.e. maximum dog-leg, maximum hole angle, etc.).
Rod wear-related problems are described in depth. The frequency and location in the rod string of the wear-related failures are compared with a number of parameters to determine the major factors contributing to rod wear.
The various methods and items tested by Husky to reduce and control rod wear are described and discussed.
A summary of conclusions based on the data as well as a suggested rod/tubing maintenance program are included in this paper.

Introduction
Husky Oil Operations Ltd. has been active in the Lloydminster, Saskatchewan / Alberta, heavy oil fields since 1946 and currently operates over 2000 producing wells and five active enhanced oil recovery (EOR) pilots.
The Lloydminster operators produce from a series of lower Cretaceous sands at depths between 400 m and 600 m. The sands are reasonably clean, moderately sorted, and poorly consolidated. Porosity can vary between 25% and 35%. Permeability ranges from 0.5 darcies to 8 darcies.
The oil produced in the area is dense and viscous. Density is generally between 911 kg/m3 and 980 kg/m3. Viscosity can be as high as 131 Pa •s.
The original-oil-in-place in the Lloydminster area has been estimated at 500 million m3(1). Probably less than 10% is recoverable by conventional means, EOR recoveries have been estimated at 25%.

Pad Well Completions
Husky began drilling EOR wells from pads in 1983. The advantages of pad drilling are well documented and accepted by the operating companies in the area. The close spacing used in the EOR pilots (as low as 1 ha), the reduced cost of fluid injection and production lines, the centralization of facilities, and the large reduction in surface area requirements make pad drilling of EOR wells especially attractive.
Husky currently has over 100 pad wells in its EOR pilots. Pad sizes vary between 3 and 14 wells. The wells are typically equipped with 178 mm casing, 89 mm EUE tubing, 22 mm grade C sucker rods, and 64 mm rod (insert) pumps.
When the first pad wells were brought on stream in 1983 (at the Pikes Peak Cyclic Steam Pilot), the field personnel were expecting to have significant rod wear problems. The frequency of rod wear-related servicing was higher for the new wells but not alarmingly so. The installation of rod rotators and the implementation of a rod maintenance program kept the problem under control.
Laboratory Evaluation Of Formation Damage Caused By Drilling Fluids And Cement Slurry
Authors: Rahman S.S. , Marx C. 
Published: March 2010

Abstract
A laboratory investigation was conducted to study the formation damage caused by drilling fluid and cement slurry. Investigations were performed on two different sandstone core samples typical for gas and oil reservoir in Germany. Core samples of 25 cm long and 2.5 cm in diameter were contaminated with commonly used four different drilling fluids and a typical class-G cement slurry. A 10% HCI acid was used to remove the damage of the contaminated core samples.
Damage caused by drilling fluids was evaluated by means of damage ratio and sectional damage ratio. The value of sectional damage ratio was used to determine the depth of permeability impairment. Scanning electron micrograph study along the axis of the segmented core were made to determine the depth of invasion of solid particles and polymer molecules.
The results have shown that the current practice of using low-solid drilling fluid weighted by ground calcium carbonate can cause about 40% reduction in permeability of the core samples extending over 20 cm. The permeability damage of the core samples caused by bentonite polymer drilling fluid was observed to be about 75%. However, this severe damage is only confined to a depth of about 5 cm which can be overcome by the perforation work.

Introduction
All types of porous formation act themselves on an in-depth filter. Damage is caused by drilling fluids and subsequently by cement slurry by two mechanisms:invasion of solids that plug the formation; andinvasion of filtrate that can hydrate interstitial clay, free formation fines, precipitate solids, change formation wettability, etc. (1,2).
Invasion of solids and filtrate can be reduced to an acceptable level by the formation of low permeable filter cake. During the filtration process, panicles of certain sizes bridge the formation pores and establish a base on which the filter cake can form. Particles considerably smaller than the pore opening invades the formation. However, panicles of certain critical sizes stick at the neck of the pore channel and form an internal bridge(3,4). Once the primary bridge is established, fine panicles successively fill up the interstitial spaces to form a lightly packed layer of filter cake. Thereafter, only filtrate invades the formation. In order to form an effective base for the filter cake, drilling fluid must, therefore, contain panicles ranging in size from slightly less than the largest pore size of the formation to be drilled down to about one-third of that size(3,4).
Polymers used in drilling fluid tie the solids in the filter film together and fill the smallest spaces of the filter cake. These results in a filter cake of very low permeability (2 to 5 × 10−1 md)(4). In fact, upon hydration polymers can acquire a chain length that may exceed 0.1 cm which is comparable to the width of a medium size clay. If these polymers deeply penetrate into the formation, they can cause considerable impairment(4).
Ground calcium carbonates are acid degradable and they are often used as bridging materials.
Monitoring The Performance Of Pembina Nisku Miscible Floods
Authors: Bennett F. , Geoghegan J.G. 
Published: March 2010

Abstract
Esso Resources Canada Ltd. operates gravity-stable hydrocarbon miscible floods in seven Pembina Nisku pinnacle reefs. All these floods were started between 1982 and 1985 and recovery from the more mature floods has exceeded 50% of original-oil-in-place (OOIP), During 1989 a number of infill wells were drilled to maintain productivity and reduce solvent coning. Open hole gradiomanometer logs were run in these wells to determine gas, solvent, oil and water contacts. Previous cased hole contact logging had been unsuccessful and these infill wells afforded an opportunity to assess the progress of the miscible floods with open hole contact logs.
This paper reviews the performance of the miscible floods and describes the results of the contact logging, The implications of the contact log results are discussed in regard to solvent bank dispersion, volumetric conformance and displacement efficiency, and future infill drilling and completion strategy.

Introduction
Sequence of Development
The Pembina Nisku pinnacle reefs are located approximately 160 km southwest of Edmonton. Figure 1 shows the 17 Esso working interest pools in the area of which eight are waterfloods and nine are vertical miscible floods. Esso operates seven of the miscible floods.
The Pembina Nisku G and K pools were the first pools to be miscibly flooded. After primary depletion to the bubble point pressure (between 1978 and 1979) the pools were shut in until 1981, when facilities were in place to commence miscible flooding. As shown in Table 1, the cumulative recovery to date (1989 year-end) is 56% and 50% of OOIP for the G and K pools, respectively.
The Pembina Nisku O and P pools followed with miscible flood start up in 1983. These pools have produced 40% and 44% of their respective OOIPs to date.
M pool was a Getty Oil pool, later acquired by Texaco, which also started miscible flooding in 1983. It has a recovery to date of 48% of OOIP.
Pressure maintenance in the largest of the Nisku pools, the L pool, began in 1981 with a waterflood. At that time there was a concern that a Cynthia shale tongue between the Upper and Lower Zeta Lake reef portions might be widespread laterally and disturb the solvent bank integrity in a miscible flood.. Subsequent infill drilling showed that the shale was localized in the region of the two southernmost wells. Consequently, waterflooding was suspended in 1985 and a miscible flood was started. Production of injected water also commenced that year as pan 0 f a scheme to recover residual oil in the water flushed zone.
The Q pool also began miscible flooding in 1985. The cumulative production for the L and Q pools is 48% and 36% of their respective OOIPs.
Prior to 1989 production was primarily constrained by market demands, the provincial allowable or Energy Resources Conservation Board (ERCB) maximum rate limitation (MRL) rates. In 1988 and 1989, solvent coning in wells completed at the base of porosity made it necessary to drill additional infill wells to reduce drawdowns and maintain pool productivity.