bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiple Contact Phase Behaviour In The Displacement Of Crude Oil With Nitrogen And Enriched Nitrogen
Authors: Sayegh S.G. , Wang S.T. , Najman J.
Published: March 2010

Phase behavior tests were carried out on a Nisku crude oil (a candidate reservoir for nitrogen flooding) with nitrogen and nitrogen mixed with carbon dioxide or propane. These measurements were carried out in a batch wise multiple contact mode to simulate what occurs when gas displaces oil in a porous medium. None of the mixtures achieved miscibility with the oil in four contacts at pressures up to 35 MPa. Nitrogen and methane were exchanged between the gas and oil phases in an almost 1:1 ratio, while gas enrichment with C2–5 hydrocarbons proceeded at a much slower pace.

The experimental data were matched using the Peng-Robinson equation of stale. Good agreement between experimental and calculated results was obtained in most cases. This applies to the equilibrium phase compositions, as well as to the liquid phase densities and gas/oil ratios. The largest deviations were in the amount of heavy ends found in the vapour phase.

Introduction

Nitrogen may be applied for enhanced oil recovery (EOR) in several modes, e.g. pressure maintenance, cycling condensate reservoirs, attic oil production, producing gas-cap gas, chase gas for hydrocarbon or carbon dioxide slugs and miscible displacement of oil.

These applications were discussed by Clancy et al.(1) and reviewed in detail by Sayegh et al.(2). Recently Leonard(3) summarized EOR activity worldwide. From this article it was noted that there are seven nitrogen injection projects in the U.S.A., four of which have already showed profit, while it is too early to tell the remaining three. In addition, there are three flue gas injection projects. In Canada, two ongoing floods utilize nitrogen. The first is in a Pembina Nisku reef, wherein the injection gas consists of a mixture rich in nitrogen along with carbon dioxide and light hydrocarbons. The second is the Willisden Green flood, where nitrogen is being used as a chase gas for a hydrocarbon slug.

The advantages of using nitrogen for EOR include: widespread availability from air liquefaction, non-toxicity, non-flammability and non-corrosivity.

In addition, the price of nitrogen appears to be competitive with that of dry hydrocarbons, although it is difficult to give more precise estimates because of the many variables involved in costing. Wilson(4) noted that nitrogen has some disadvantages in its use for enhanced oil recovery, which include:The cost of separating nitrogen from the produced hydrocarbon gases. This is offset if the produced gases are recycled into the reservoir.Nitrogen asphyxia.If air separation units are used to produce nitrogen, then a by-product stream rich in oxygen is produced. This stream has to be well separated from any hydrocarbon streams in the vicinity.

In summary, the use of nitrogen in enhanced oil recovery has many advantages that can outweigh its disadvantages. This is a new topic, and there are many gaps in the information available for its proper application. It is the purpose of this work to try and fill in some of these gaps.
Logging With A Coiled Tubing System
Authors: Latos Jeff , Chenery Dale
Published: March 2010

A completion technique has been developed for highly deviated wells which uses a conductor cable placed inside coiled tubing. All conventional cased hole logging and perforating tools C(In be run. The advantages of this system include a shorter completion time, precise positioning of the downhole tools, the ability to maintain an even logging speed, the ability to circulate fluid while logging, and the elimination of a workover rig.

This paper reviews a successful completion program performed on three gas wells in the Bantry Field of southern Alberta, and presents details on open hole logging procedures conducted on two wells in England. Aim being presented and discussed are the equipment modifications that were necessary, and possible future developments of this innovative technique.

Introduction

The major problems associated with highly deviated wells have been logging(l) and completions(2). Logging has traditionally been accomplished using drill pipe conveyed systems(3) or pump down techniques(2). Completion of horizontal wells has been accomplished through the use of slotted liners or with tubing conveyed perforating guns.

Electric wireline conductor cable placed inside coiled tubing creates new possibilities in well logging and completions. The method involves running downhole electrical tools in and out of the hole with conventional coiled tubing. The tools are linked to surface by the conductor cable inside the tubing. A coiled tubing / wireline method for open hole logging and casing inspection was earlier presented by Howell et al.(4), but their system had not been put into practice.

The system presented in this paper was initially developed to log wells in Germany and France(5,6). Similar equipment was then used to log and complete three Medicine Hat/Milk River gas wells with deviations as great as 78.25 degrees. These zonesare normally produced from shallow vertical wellbores, but irrigation dictated that minimal land be used. The three wells weredirectionally drilled from a single location.

Conventional completion methods (performed on lower zones) had been both expensive and time-consuming. A slant hole service rig had been required., and in most cases, spotting the tools required pump down techniques. Perforating guns had been limited to either tubing conveyed guns or guns with diameters small enough to fit through the tubing. Cleanout and bridge plug movement had caused multiple tubing runs and the necessity to kill the well several times during the completion. Coiled tubing/wireline proved an effective system that successfully:decreased completion time,eliminated tubing and casing wear,avoided having to kill the wells, andallowed the use of larger perforating guns

The coiled tubing/wireline system was also used to open hole log two wells in the south of England. These wells had deviations to 60 degrees. The system was required after conventional logging techniques had proven unsuccessful.
Design Considerations For Dome's David Alkali/Polymer Flood
Authors: Manji K.H. , Stasiuk B.W.
Published: March 2010

An alkali/polymer flood has been designed for the David Lloydminster ‘A’ pool in east central Alberta. The David Lloydminster ‘A’ pool was originally under waterflood from November 1978 to March 1986 and approximately 30% OO1P has been recovered. Laboratory tests were initially done which showed incremental oil recovery through the use of 2% wt caustic. Further laboratory test done by Surtek Inc. of Golden, Colorado showed increased oil recovery through the use of alkali in conjunction with polymer and surfactant. This paper presents the results of the lab tests as well as the facility design for an alkali/polymer injection system. The progression of the process from straight caustic injection to sodium carbonate/ polymer to sodium carbonate/polymer/surfactant will also be described.

Introduction

The David alkali/polymer project is located in Sections 2 and 11–41-3-W4M approximately 100 km south of Lloydminster, Alberta. The pool is in the Lloydminster formation, which is an unconsolidated (partially cemented) sand of the Upper Cretaceous period, located at a depth of about 750 m KB. The average net pay is 3.2 m with an initial oil saturation of 73%. Porosity average 29% and the OOIP is 1.35 million m3? Reservoir fluid properties and other reservoir data are shown in Table 1. Initially the David Lloydminster ‘A’ pool was under primary operations from 1969 to 1978 and approximately 6.3% of the OOIP was recovered. In 1978, a waterflood scheme was initiated and continued until March 1986, when the infill drill program was completed and 50ft water injection began. Figures 1 and 2 show the production history for the project.

In December 1983, Dome Petroleum submitted an application to the ERCD for an Enhanced Recovery Scheme which involved injection of a 2 wt % caustic (NaOH), 0.5 PV slug and Infill drilling 22 wells. A 0.1 PV slug of soft water (preflush) was to be injected to condition the reservoir prior to caustic injection. A post flush of 0.2 PV of soft water was also to be injected and a total project life of six years was anticipated.

In August 1984, Dome Petroleum received approval from the ERCB to proceed with the experimental scheme. As a result of falling oil prices the economics of the project were reviewed and it was decided to drill only 13 of the proposed 22 wells. Figure 3 shows the pattern arrangement indicating the original 12 wells and the new infill wells.

Drilling of the infill wells began in December 1985 and was finished in January 1986. Well 13D-2 was cored for further lab studies. Flowlining of the project and construction of the soft water facilities and battery expansion were completed in February 1986. In March 1986 the soft water injection began at a rate of 630 m3/d into the seven injection wells. Voidage replacement ratio for the project was approximately one.

Encouraging results from chemical/polymer lab studies done on Dome's Cessford and Grand Forks projects as well as finding from other papers(l,2,3) led to further investigations on the David Lloydminster ‘A’ pool.
Action Taken To Increase The Fun-Life Of Electrical Submersible Pumps In The South Sturgeon Lake D-3
Authors: Pucknell J.
Published: March 2010

Electrical Submersible Pumps (ESPs) used by BP Canada in the South Sturgeon Lake D-3 pool have achieved an average run-life of only 2.5 months before failing. Based on an analysis of 31 workovers, it was clear that cable and splice failures, related to the high hydrogen sulphide content of the solution gas, were the principal problem. Action taken to reduce the number of failures has included the use of surge arrestors, lead-sheathed splices and a more robust type of cable. All splices are now X-rayed as a quality control measure. As a result of such measures the average run life has been increased to four months in recent years.

Introduction

BP Canada has used electric submersible pumps in three wells producing from the South Sturgeon Lake D-3 pool in Alberta; the first ESP was installed in 1981. Table 1 gives relevant information on pump operating conditions. The hydrogen sulphide (H2S) content of the solution gas (about 10%) and the high bottom hole temperature (89 °C) mean that conditions are not ideal for ESPs. However, the high flowrates (over 100 m3/day) and the depth of the reservoir (2550 m below ground level) mean that wells cannot be pumped off using conventional pumpjacks.

Frequent workovers have been necessary due to downhole failures. Poor reliability leading to high operating costs has meant that only one well is still being produced by ESP. All ESP failures have been analyzed to determine their cause. This has lead to a number of changes which have gradually improved reliability. Figure 1 shows the downhole completion used originally; Figure 2 shows the most recent installation.

Frequency and Cause of Downhole Failures

The average run time of an ESP installation over the last five years has been only 2.5 months. (Run time is defined as the time between first starting a pump and its subsequent failure; no adjustment is made to account for downtime caused by production allowables, etc.) Table 2 shows that the run time has increased from 1.5 months to about four months as a result of the changes discussed in this paper. At a run time of four monthsworkover costs to repair ESP installations run at about C$100,000 a year for each well. In addition, the downtime caused by these workovers currently amounts to one month a year per well.

Table 3 summarizes the primary causes of all the downhole failures. Eighty-one per cent of the workovers have been caused by failures of the cable, splices or electrical connectors. The pump and motor assembly has generally performed well, although Table 4 shows evidence of some potential problems including "scale" deposits in the pump and ingress of water into the seal section.

Cable

Except in the most recent installation, a conventional, lead sheathed, flat cable has been used. This type of cable is recommended for high H2S environments because while the cable insulation is permeable to H2S and other gases, the lead acts as a barrier to the H2S preventing it from reaching the copper conductor.
The Measurement Of Trace Element Emissions At Sour Gas Plant Incinerator Stacks
Authors: Oballa V. , Gnyp A.W. , Smith D.S. , Viswanathan S. , Thimm H.F.
Published: March 2010

A method for stack sampling and estimating trace element emission rates from sour gas plant incinerator stacks is described. These stacks are often of large diameter (up to 6.1 m), and the gases are usually low in particulate matter load and of high temperature (420 °C to 680 °C). Results from a survey of 29 elements at ten sour gas plants in Alberta are discussed.

Introduction

In the past, there have been sporadic reports of the presence of metals in some natural gases, and Leeper has discussed the presence of mercury as a cause of corrosion in LNG plants(1). In Alberta, the question of possible emissions of trace elements from sour gas plant incinerator stacks has arisen on several occasions.

Hsu and Hodgson(2) reported that the selenium content in stack gases from 14 Alberta plants ranges from 1.05 to 2.70 g/m3, but give no indication of the sampling method. Available consultants' reports suggested the presence of a variety of metals, but no attempts were made to sample representatively the particulate fraction of the stack gas. Furthermore, the quality of acids used to trap trace elements was not described in terms of trace element concentrations.

A search of North American governmental reference methods indicated that a code for measurement of trace element emissions, analogous to the Alberta Environment Reference Method (AERM)(3) for estimating particulate emissions, does not exist. It was, therefore, necessary to design sampling and analytical methodologies which would:collect a representative sample of stack gas,minimize sample loss in and sample contamination by sampling train components,assure quantitative recovery of the sample from the train, andensure adequate analytical results.

Sampling Requirements and Method

In a steady-state process, the gaseous phase of a stack effluent may be taken as uniform in composition. The problem of collection of a representative sample, therefore, reduces to sampling entrained particulates or liquid droplets representatively (although the latter are not likely to exist under the conditions at hand). For this purpose, the AERM is an established method, whoseessential features could be retained basic sampling train for particulate matter, consistent with the AERM is shown in Figure 1. The objective in the use of this train is to sample isokinetically, that is, to sample in such a manner that the velocity of stack effluent entering the sampling nozzle is equal to the local velocity of the stack gas stream. It is readily shown that the condition for isokineticity is:

Equation (1) Available In Full Paper

For a given survey, equation (1) reduces to:

Equation (2) Available In Full Paper

where K is constant for all local velocities in the stack. In the evaluation of K, DN is known from the choice of nozzle size, Cp and Ko are determined by calibration, and Ps, Pm, Md, Ms and Bwo are determined initially from a preliminary, usually non-isokinetic, survey. These parameters are updated after each test.
New Lz-210 Zeolites Produce Superior Fcc Performance
Authors: Letzsch Warren S. , Michaelis Dennis G. , Pollock John D.
Published: March 2010

Introduction

The most important aspect of a catalytic process is usually the catalyst. Fluid catalytic cracking is no exception to the rule. Originally. FCC catalysts were amorphous in nature and low in activity. High conversions and gasoline yields were achievedwith the use of recycle (Fig. 1).

Crystalline molecule sieves or the zeolite promoted catalysts were introduced in fluid cracking units in 1963–1964 with spectacular results. Nearly all of these early products contained the Type X sieve, though ultra-stable or US-Y sieves were briefly used. The latter were found to be more suitable for hydrocracking applications. Type X zeolites, patented by Union Carbide, belong to the faujasite family and have a silica/alumina ratio of 2–3 to 1. These early products allowed refiners to cut recycle and increase fresh feed rates without losing conversion. Laboratory data and commercial results indicated the molecular sieves had an activity that was at least an order of magnitude greater than the amorphous catalysts they replaced. Figure 2 shows the benefits of high catalyst activity.

With the activity problem essentially solved for gas oil cracking operations, the focus shifted toward stability and selectivity. Here, the answer proved to be the Type Y zeolite, also developed by Union Carbide. It has the same proven faujasite structure as the Type X sieve, but has a silica/alumina ratio of 3–6 to 1. Figure 3 illustrates the faujasite structure with the chemical formulas for each sieve type.

The Type Y zeolite has been the workhorse in FCC processing for the last 17 years but the composition of the Y sieves has evolved considerably over that time. Early silica/alumina ratios were about 3.8 to 1, just barely in the Y range. By 1975 this ratio was up to the typical values found today (about 5 to 1). Most of the Y zeolites originally used were fully rare-earth-exchanged; i.e. the rare earths replaced the sodium associated with the crystalline structure.

Maximum rare earth was used because it gave the highest zeolite stability. Catalyst manufacturers could use less sieve in their formulations to achieve a desired activity level and variations in starting Na-Y quality were overshadowed by the presence of rare earth. In refiner's terms, rare earths were the tetraethyl lead of the catalyst business. Fully-exchanged FCC catalysts were the predominate choice right up to the 1980s.

The high price of crude oil in the late 70s and early 80s made it attractive to process resid. This put a premium on coke selectivity. Catalyst manufacturers responded by removing some of the rare earth from the zeolite. Figure 4 shows how the coke selectivity improves as rare earth in the zeolite declines. n the past few years, the need for higher FCC gasoline octanes due to the removal of lead from the gasoline pool, has led catalyst suppliers to products with higher starting silica/ alumina ratios. The off-the-shelf technology in this area was the ultra-stable Y or US-Y zeolites discovered some 20 years earlier.
Astrakhan, The World's Largest Sour Gas Development
Authors: Leipert G.F.
Published: March 2010

The Astrakhan Sour Gas Field located near the northern tip of the Caspian Sea in the U.S.S.R. is considered to be the largest of its type in the world. The difficulties associated with transporting an extremely deadly and corrosive fluid in an area characterized by extreme environmental conditions make the development of this field extremely challenging. This paper outlines how Lavalin addressed these challenges in the development of the second phase of the project.

Introduction

At approximately 9:00 p.m. on New Year's Eve, 1986, Lavalin signed a contract with Machinoimport for the development of the 2nd Phase of the Astrakhan Sour Gas Field in The U.S.S.R. While this was not the first contract ever undertaken by Lavalin in Russia, it was the first contract for a project under the urisdiction of the Ministry of Gas and followed more than ten years of proposal and business development activity and an expenditure of more than $3 million. At this time, the engineering is basically complete, all of the equipment is either in fabrication or has already been delivered, and construction at the site is now well under way.

The project undertaken by Lavalin was for the complete development of the 2nd Phase of the Astrakhan Sour Gas Field. The Sour Gas Field is approximately a one-and-a-half hour drive away from the city of Astrakhan located near the northern tip of the Caspian Sea in the U.S.S.R. (Figs. 1 and 2). The project involved the collection of sour gas and condensate from a total of 83 wells and delivering to the Gas Processing Plant (later referred to as OPP) a volume of 6 billion m3 per year of sour gas.

Development of Sour Gas Fields

Developing sour gas fields is not a new concept and certainly one that people in Alberta are very familiar with. This project, however, was made increasingly more difficult by a number of factors. The first of these was that the gas is extremely sour, being consisted of approximately 24% H2S and 14% CO2 resulting in an acid gas component of approximately 40% of the total gas produced. In addition, produced with the gas are significant quantities of sour condensate and produced water. The produced water has a very high chloride concentration resulting in one of the most corrosive fluids you are likely to encounter in sour systems. Add to this the fact that the production comes from a very high-pressure reservoir with shut-in wellhead pressure of approximately 400 bars (near 6000 psi) and that the particular gas combination has a hydrate temperature above 30 °C and you will understand why this fluid is very difficult to handle.

The problems, however, did not end with the fluid itself. In addition, there were extreme environmental conditions that must be considered in the design of the facilities. The field is located in a desert where the terrain is really nothing more than rolling sand dunes which change their shape and position dayby day as the winds blow.
Project Cash Flow Analysis - How To Avoid The Fast Track To Red Ink
Authors: Martin V.N. , Smith B.J.
Published: March 2010

The purpose of this paper is to provide a better understanding of the impact of cash flows on project costing and control. This is essential to effective proposal development and efficient project management. To this end, the authors will provide analyses of typical receipts and disbursements relating to international contracts and show how financial costs/benefits can affect project profitability. Additionally, they will provide a structured approach to project cash flow analysis which should be useful in costing and managing future international projects.

Introduction

The recent dramatic decrease in world crude prices and the consequent decrease in the availability of funds for capital investment has had a devastating effect upon the petroleum-related construction industry. The excess of supply over demand has narrowed profit margins to a point at which extremely rigorous financial planning and control of projects is necessary for a firm's survival. One area of financial planning and control which typically is not subject to adequate scrutiny is cash flow.

Cash flow is the receipt and disbursement of cash over a given period of time which, for our purposes, is the life of a project. The normal use of a cash flow statement is to provide information elative to a firm's investing and financing requirements, whereas, the income statement (or P&L) focusses on the economic results of an entity's operating activities.

Generally speaking, cash flow analysis provides vital information in two significant areas:cash requirements over the life of the project; andfinancial costs/benefits derived from cash balances over the life of the project.

These costs and benefits affect the planning stage of a contract through their impact on costing (and pricing) and the execution stage of the project where cash flow management becomes a significant task.

It should be noted here that the final cash balance figure derived from a project cash flow analysis can normally be equated to the final "net profit" figure which might be derived from a Pro Forma income statement for a project. This anomalous relationship (between accrual and cash accounting) occurs because a project is a discrete economic event that requires "liquidation" of all accounts at the termination of the project and the consequent reduction of all relevant revenues and expenses to cash. Although the concept of cash flow is quite simple, forecasting the cash flows of a project can become a complex activity involving the delineation (timing and amount) of all relevant cash receipts and disbursements.

The stream of disbursements and receipts unique to any project comprise a project's total "sales transaction". A sales transaction is termed as the exchange of assets such as cash or the promise of future payment for goods or services. The real complexity of international projects stems from the nature of their sales transactions.
South Jenner Horizontal Wells A Water Coning Case Study
Authors: Freeborn W. Randy , Russell Boyd , MacDonald Alaistair J.
Published: March 2010

AEC has been a Canadian pioneer in the use of horizontal well technology to combat the adverse affects of water coning(1,2), A medium radius well of 420 m horizontal displacement was drilled in July 1987 and has been produced at controlled rates since that time. A follow up long radius well with a horizontal displacement of 1042 m was drilled in December 1988. These experimental wells are targeted to recover oil from bottom water reservoirs where the net pay is too thin to justify vertical wells. This paper will describe AECs experience in planning and designing its first two horizontal wells, and share insights which have been gained in the drilling, completion, operation and reservoir evaluation of these wells.

Background

The Suffield Upper Mannville J pool, commonly known as the South Jenner pool, is located in the northwest comer of the Suffield military range in southern Alberta. Discovered in 1976 by West-coast Petroleum Ltd, the pool was first developed on 16 ha spacing for primary production of 14" API heavy oil. With an active aquifer under the oil, water breakthrough was rapid and recovery was in the range of 1% to 2%.

In 1981, a five well in situ combustion pilot was initiated as the only EOR technology practical for the reservoir configuration and depth. This pilot operated until 1986. AEC is also presently conducting a hot waterflood and testing cyclic gas/chemical injection to enhance recovery from the developed portion of the pool.

In 1985, AEC decided to improve recovery by matching well spacing to drainage area. Using a reservoir simulator, it was determined that wells could be as close together as 100m without reducing the ultimate production from each well. As a result of this information, 132 infill wells were drilled in a seven spot orientation on one hectare spacing. This approach has increased recovery to 25% of the developed oil in place for vertical wells.

Horizontal wells are now being used to produce oil from portions of the reservoir which cannot be economically developed with vertical wells. A short radius well, AEC WC 51 Suffield EX 6-34-19-8 W4M (51-34) and a long radius well, AEC WP 11M Suffield EX 6-3-20-8 W4M (1IM-34) were drilled in July 1987 and December 1988, respectively, to test this technology.

Geology and Geophysics

The South Jenner oil pool is an Upper Mannville Glauconitic sand stone which was deposited in an estaurine environment. The sand is consolidated, but friable, and exhibits an upward coarsening typical of an estuarine bar sequence. Subsequent to the sand deposition, the estuary was filled with a silty sandstone which lacks productive capacity. This silt section is thin or absent at the apex of the bar; however, it thickens toward the reservoir flank. Tidal channels, which cross the bar, segment the reservoir into smaller development regions.

The reservoir is connected to a large regional aquifer which reaches a thickness of 20 m in the reservoir area.
New Correlation for Estimating the Viscosity of Undersaturated Crude Oils
Authors: Abdul-Majeed Ghassan H. , Kattan Riadh R. , Salman Naeema H.
Published: March 2010

A new general correlation for estimating the viscosity of undersaturated crude oils has been developed using 253 experimentally obtained oil viscosities on 41 different oil samples collected from two different unpublished sources.

The developed correlation is derived from plotting (P-Pb) vs. (µoa - µob) on log-log paper. The plot reveals a series of straight lines of a constant slope equal to 1.11. It is found that the intercepts of the resulting lines can be accurately represented as a function of API gravity and solution gas-oil ratio at bubble point pressure.

The present correlation shows excellent results and clearly outperforms the existing correlations, when tested against the present data bank (253 points) and against available data from the literature (137 points).

Introduction

Viscosity in general can be defined as the internal resistance of fluid to flow. Like other physical properties of liquids, the viscosity is sensitive to changes in pressure and temperature. Increasing temperature always causes a decrease in viscosity. Increasing pressure always increases viscosity above the bubble point. However, below the bubble point, an increase in pressure causes an increase in solution gas which in turn decreases viscosity. Crude oil viscosity is essential for both petroleum reservoir engineering and production design operations.

The present work deals with the correlations of viscosity of undersaturated crude oils (above bubble point pressure). The common empirical correlations available for predicting this property are those of Beal and Vasquez.

In 1946, Beal presented a graphical method derived as the rate of change of the undersaturated oil viscosity per unit pressure increase above the bubble point pressure and the bubble point crude oil viscosity. The disadvantages of Beal's correlation are:it is based on only 26 data points covering limited ranges of flow conditions, andno analytical expression is given for the correlation.

Using only 11 data points, obtained from Figure 11 of Beal's work, Standing found that Beal's correlation can be approximated by the following equation, which fit the 11 points with average error = 1% and standard deviation = 4.64%.
A Correlation Of Viscosity And Molecular Weight
Authors: Closmann P.J. , Seba R.D.
Published: March 2010

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

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

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

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.
Laboratory Evaluation Of Formation Damage Caused By Drilling Fluids And Cement Slurry
Authors: Rahman S.S. , Marx C.
Published: March 2010

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.