bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design Considerations For Dome's David Alkali/Polymer Flood
Authors: Manji K.H. , Stasiuk B.W. 
Published: March 2010

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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%.