bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation Study of Acid Gas Injection Into an Aquifer
Authors: Wu R. , Heinrichs H.J.
Published: March 2010

A series of simulation runs using a compositional simulator were conducted to determine the area of influence that results from injecting acid gas (H2S) for 30 years at 330 e3m3 into a 75 m thick high permeability sandstone aquifer. In this study, the three-phase (gas-oil-water) equilibrium calculation was used. Initially, a 5 Township by 5 Range grid model was used to determine the area of influence; subsequently, a smaller grid model 1 Township by 1 Range was used.

Boundary producers were required to properly simulate an infinite aquifer. This study found that buoyancy and relative permeability, more than other parameters such as the perforation interval and the gas-water capillary pressure, affected the area of influence. A refined 75-layer model, one-metre thick, was constructed to check the gravity effect. The results of this refined layer model agree closely with a 13-layer model after 11 years of acid gas injection.

A blowdown simulation was also conducted to determine the time to significant water inflow from perforations at the bottom of the zone.

The effect of a 50 year shut-in after 30 years of injection was also simulated.

Introduction

The objective of the study was to understand the reservoir volume and the area of influence that would result from the injection of H2S into the Basal Sand aquifer of the Cambrian age Deadwood Formation. This was accomplished through the use of a compositional simulator (CMG's GEM).

The Husky Lloydminster Upgrader (HLU) produces large amounts of acid gas: mainly H2S. The existing sulphur plant removes the sulphur from the H2S. Implementation of H2S disposal into the Deadwood Formation would initially reduce the load on the existing HLU sulphur plant, and ultimately it might be shut-in. Any future expansion of the HLU would not require an additional sulphur plant if acid gas disposal was proven to be effective.

For safety reasons and regulatory requirements, it was required to know where the injected H2S would migrate to within the aquifer over time. The resulting area of influence would determine the penetrating wells and the mineral rights owners that might ultimately be affected by H2S injection.

In this study, a commercial compositional simulator (CMG's GEM) was used as the model as it can take H2S water solubility into account. In the simulation results, the area of influence is defined as the area that has an H2S concentration greater than 0.00001 mole fraction. This value is based on the numerical accuracy of the simulation.

The selected simulator was developed for oil-gas-water three-phase and multi-components usage. To simulate an H2S-water system, a small amount of methane (0.0005 gas saturation) was used as an oil phase for initialization. To distinguish the initial methane gas from H2S in the gas phase, all the gas saturation graphs used a minimum scale of 0.0005.

Deadwood Aquifer Formation and Reservoir Model

References (1) and (2) provide a detailed geological appraisal and a mineralogy study of the Cambrian Deadwood Formation Basal Sand.
Basic Investigations on Enhanced Gas Recovery by Gas-Gas Displacement
Authors: Turta A.T. , Sim S.S.K. , Singhal A.K. , Hawkins B.F.
Published: March 2010

The paper presents basic data on Enhanced Gas Recovery (EGR) by gas-gas displacement for nearly depleted natural gas reservoirs by injecting waste gases. The soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modelling and economic analyses. Paramount Resources is field testing the concept in their GRIPE Project in the Athabasca region of Alberta, to enhance production from a gas bearing stratum overlying the oil sand interval.

This paper is a part of a series of papers presenting results of EGR research conducted over a five-year period (2003 – 2007). The main targets were volumetric (closed) reservoirs in advanced phases of exploitation. Results of basic research on methane displaced from core samples by pure gases (pure CO2 or pure N2), as well as flue gases (mixtures of CO2 and N2), are presented.

A series of nine gas/gas displacement tests in 30 cm long, 4 cm diameter, Berea cores were conducted at a temperature of 70?C and a pressure of 6,200 kPa. Most of the tests were conducted in the presence of connate water, while others were conducted without connate water (dry cores) to confirm and benchmark the results by other investigators. The tests on consolidated cores showed that for pure nitrogen and pure CO2, used as the displacing medium, the recovery was comparable.

Where a mixture of CO2 and nitrogen displaced the natural gas, it was observed that there was a delay in CO2 breakthrough, associated with a period when only a mixture of methane and nitrogen was produced. This is so because solubility of CO2 in connate water is considerably higher than that of nitrogen. This leads directly to a higher gas recovery due to a longer exploitation period, given the fact that up to 20% nitrogen can be tolerated in the produced stream, as opposed to only 1% for the CO2 case. For this period of methane and nitrogen production, there are no operational problems associated with the corrosive nature of CO2.

EGR by gas-gas displacement is seen as a promising way of prolonging the productive life and economic recovery of many depleting volumetric gas reservoirs.

Introduction

Alberta currently has 42,000 gas pools, which are in different stages of exploitation. For these gas reservoirs, the pools that should be considered first in the implementation of large-scale EGR-CO2 and CO2 storage have not yet been identified, and no screening criteria have yet been developed. Currently, only the concept of "disused gas reservoirs" has been advanced(1) for CO2 storage. This concept implies that only those reservoirs that are in an advanced stage of depletion (with very little marketable gas left), traditionally with extremely low current pressure, or which are water invaded, should be considered. In this context, they have been considered exclusively for CO2 storage and not for enhanced gas recovery (EGR). This paper brings a new concept: that of simultaneous EGR and CO2 storage.
Operational Problems in the Arctic Islands
Authors: Usher J.L.
Published: March 2010

Geological exploration on the Arctic Islands encounters many operationalproblems that are new to most Canadian geologists. Although conditions aresimilar to those of the tundra on the northern Mainland, climatic andphysiographic differences impose modifications in transportation to the field, in planned reconnaissance and detailed surface studies, and in livingconditions in the field. The relative merits of small single-winged aircraftand helicopters are discussed; the change of method of field work with changeof ice conditions from spring to fall are examined; the effect of varioustopographies and bedrock on relative ease of movement are considered.

Introduction

Recorded exploration of the Arctic Islands has been in progress for nearly450 years. It began with the search for a Northwest Passage to the Indies, asearch that was forced upon European entrepreneurswhen they realizedthat not only was the earth spheroidal but that a major continent intervenedand barred the western route between Europe and Asia. In the words of Taylor(1955, p. 8), … North America, in European eyes, was not so much a goal to beachieved as an obstacle to be surmounted." Polar exploration was furtheradvanced by whaling and sealing enterprises and by the concerted efforts of themany expeditions that attempted to reach the North Pole. These numerous voyagesestablished the basic cartography of the Islands, but yielded only a smatteringof geological knowledge from widely separated points. It was not until thepost-war years of the late 1940's that the first long-range, systematicallyplanned, geological exploration of the Islands was instrumented by the Canadian Government. Today, through the efforts of the Geological Survey of Canada, whose work has been immeasurably aided by complete photographic coverage of the Islands, regional geological reconnaissance of the Arctic Archipelago is nearlycompleted. This work was obviously basic to the opening of the Islands'territory to oil and gas exploration and to the acquisition of lands bycompanies interested in this exploration. The value of the Geological Survey'sexploration is not, however, limited to geology; their operations on the Islands have provided us with important and valuable data on methods of groundand aerial transportation, on the climate, on the terrain, and on logistics. Inshort, they have provided us with the basic knowledge of how to live and workin the area.
Combination Gas and Water Injection Project - Leduc D-3 Pool
Authors: Buckles R.S.
Published: March 2010

The oil zone in the Leduc D-3 Pool is sandwiched between an extensiveoverlying gas cap and a large underlying aquifer. It is therefore free to moveto higher or lower elevations within the reef, in response to any imbalancebetween gas cap expansion and water influx. Recent studies have shown that itwill be necessary to control the movement of both the gas-oil and oil-watercontacts relative to well completion intervals for optimum recovery andperformance. The field has been unitized and both gas and water are beinginjected to achieve this objective. The results of a detailed engineering studyare being used to control injection ratios and pool performance.

Introduction

The discovery, geology, development and performance of the Leduc D-3 Poolhave been discussed in the past. Only a brief chronological summary of poolhistory will be given here to provide a basis for this review of reservoirengineering studies. The reservoir was discovered in 1947 about 12 milessouthwest of Edmonton. Early development was spread over a period of severalyears with a total of 535 wells being drilled to 5300 feet on 40-acre spacing.At least four separate pools have been defined as shown in Figure1. Thesubject of this paper is the "Main Reservoir", which covers almost 90 per centof the developed acreage. Its properties are summarized in Table 1.

It was in 1948 that Atlantic No. 3, drilling on the eastern edge of thepool, blew wild for six months. The uncontrolled production of oil and gas-capgas during this period resulted in a sharp decline of 50 psi in reservoirpressure. An estimated 28 billion cubic feet of gas was produced withapproximately a million barrels of oil, most of which was salvaged in earthenpits.
Eastern Canadian Oil and Gas Prospects
Authors: Boggs O.D. , Lloyd G.V.
Published: March 2010

A general assessment of exploration for and development of Oil and Gas inEastern Canada, Past and Present, and the possibilities for the Future, aregiven. The assessment is subdivided for purposes of convenient discussion, intothe Southwestern Ontario, St. Lawrence Lowlands, Gaspe Peninsula and MaritimeBasins areas. The general stratigraphic and structural natures of these Basinsin relation to their Oil and Gas prospects are stressed.

Introduction

There has been an increasing realization in recent years that thesedimentary basins in Eastern Canada have not been completely evaluated as tooil and gas prospects. This has lead naturally to increased leasing and torelated exploration and exploitation activity. The resultant high success ratiohas supported this activity and it is anticipated that the trend, in somecases, will expand even further.

It may not be that the results per unit effort will, everywhere, be the samein Eastern Canada as they are for the more promising areas in Western Canada, but the higher well-head prices for oil and gas in Eastern Canada still makethis area as promising or even more so on an economic basis than many areasbeing explored in Western Canada. The strong demand and firm prices make forrapid payouts in contrast to western areas where pro-rationing and competitionhave lead, in general, to extended payout periods.

Assisted recovery methods, such as water-flooding and improved productiontechniques, including fracturing of some of the more impermeable but porousbeds, are leading the way not only to increased profitabilities but also tore-evaluations of known, but marginal, pre-existing prospects.

Another important factor is that fully modern exploratory methods have notyet been applied to a reasonable extent to the Eastern Canadian basins. Thesituation might be likened to some extent to that of old mining areas, whereimproved knowledge of mining and of metallurgy permits the extension of oreveins or the re-opening of abandoned mines and even of the slag heaps, on amore economic basis than was originally experienced.
Control and Telemetering of Gas Producing Wells
Authors: Schwartz J.H.
Published: March 2010

Pressure gas wells present unique operating problems requiring constantclose supervision. When these wells are located in inaccessible areas, or wherea saving in manpower is desirable, remote central control and data collectingare advantageous.

Vessel pressure and temperature, wellhead temperature and pressure, dehydrator dew point, and high H2S content are but a few of thepossible trouble points that should be continuously monitored for safety ofboth personnel and equipment. Regular logging of flow rates, temperatures, analog variables and other critical functions serve the dual purpose ofefficiency of operation and elimination of wellhead charts.

Central control of wellhead flow rate and shut-down provides for a safe andreadily adjustable gas gathering system. Remote units should be designed sothat alarms are "fail safe," and automatic shutdown from critical failuresshould operate independently of the central unit. In areas where a corrosiveatmosphere is present, care should be taken to protect all electrical contactsfrom contamination.

A properly designed system will operate on a minimum number ofinter-connecting channels and for this purpose some method of coding isrequired. Since equipment in the field must operate under adverse conditionseven the most sophisticated equipment must be rugged and reliable. Centralcontrol systems are economically justifiable by savings in personnel, vehicles, accounting, and by the elimination of some costly pneumatic controls.

Introduction

The technique of central control and telemetering has been successfully usedfor many years by the petroleum refiner. In recent years, oil production hasalso benefitted by the use of remote supervisory systems. With the developmentof Western Canada's vast reserves of relatively inaccessible high pressure sournatural gas, a clear need has arisen for the application of complete automationto gas production. By the use of a combination of local alarm monitors, processcontrollers, telemetering, remote data logging, and control, a safer moreefficient operation can be obtained together with lower operating costs.
Turner Valley Limestone Oilfield Past, Present, Future
Authors: Paulson M.P. , Wahl J.
Published: March 2010

A review of the history of development of the field is presented along withthe production history over a 26-year period. The performance of the reservoirindicates that the major recovery mechanism has been a gas in solution driveaided to a small extent by down dip water intrusion and gravity drainage.Waterflood performance predictions, based on detailed study of the north end ofthe Turner Valley field will be presented. Water injection on the down dip edgeof the total field is in progress. Current results are difficult to evaluatebecause of relatively short period of injection and change in operatingconditions. The injection pattern and facilities are described. Potentialresponse areas are dealt with.

History

Introduction

The Turner Valley Limestone Oilfield is located 30 miles southwest of the City of Calgary, Alberta. It extends in a north-northwest direction from Lsd.16. Section 5, Township 18, Range 2, W.5M in the south to Lsd. 8, Section 24, Township 21, Range 3, W.5M in the north. The oil reservoir is 23 miles long andvaries in width from a half to one and one half miles. Production is obtainedfrom the Madison Paleozoic limestone. There is a gas cap associated with theoil reservoir.

Development and Production

The discovery well for the crude oil zone came into production on June 16,1936, almost 26 years ago. This well, "Turner Valley Royalties No. 1", wasdrilled in the southeast quarter of Lsd. 13, Section 26, Township 18, Range 2,W.5M, which was downdip from gas production in the limestone. Initialproduction was 960 barrels in 24 hours.

The development of the field progressed at a fairly constant rate over thenext ten-year period, during which 293 wells were drilled primarily on 40-acrespacing. The maximum number of completions in any one year was 42. A total of317 oil wells have been completed in the pool to date.
Voidage Calculations for Water Flood Schemes
Authors: Agnew G.H.
Published: March 2010

The calculation of several distinct physical quantities are sometimeslumped, and not without confusion, under the term "voidage calculations." Eachtype of voidage calculation, such as withdrawals at constant pressure or gasfilled volume, has its place in evaluating the performance of water floods. Thebasis of each is the material balance. The physical significance of the variousvoidage concepts and the application of the material balance in the estimationof reservoir pressure are examined in this paper.

It is shown that the common method of determining withdrawals, based on thesimple concept of a two-phase volume factor, while useful for demonstratingwhether or not reservoir pressure is being maintained, has limited value indetermining the overall status of a water flood. A new equation for determiningthe gas filled volume in a reservoir is presented. From it, a simple definitionof cumulative voidage is proposed. Suggestions are made regarding the use ofconventional reservoir fluid analyses. The estimation of reservoir pressure andcalculation of voidage are illustrated by examples.

Introduction

The word "voidage" or the phrase "voidage calculation" are rather looselydefined terms frequently used by engineers in connection with water-floodperformance. In one commonly used context, "voidage" is the volume that theproduced fluid occupies at reservoir conditions. An almost equally commonconcept of "voidage" is the amount of void or gas-filled space in a reservoir.In fact, these concepts are so intimately associated that it is sometimesincorrectly assumed that the production of one reservoir barrel of fluid, be itoil, gas or water, will result in a like increase in the void space in areservoir. Similar confusion can result from the misinterpretation of the term"net fill-up" which is in effect the opposite of "voidage."

The purpose of this paper is to examine the various concepts of voidage andto describe their application to the evaluation of flood performance. Emphasisis laid on material balance principles for development of the equations. A newequation for the calculation of the gas-filled volume in a reservoir ispresented and a voidage concept based on this equation is proposed.
A Method For Transporting Wet Natural Gas Utilizing Hot Water Tracing
Authors: Noyes H.D. , Towie N.R.
Published: March 2010

To transport wet natural gas through gathering or transmission systemsrequires either the removal of the free water phase, the use of hydrateinhibitors or alternatively the maintenance of the temperature throughout thesystem above the hydrate equilibrium temperature.

This paper describes an unique method of preventing hydrate formation usinghot water tracing of buried gas pipelines. The decision to utilize such asystem was made in consideration of circumstances peculiar to a particular gastransmission problem. The gathering system was to be installed in which theultimate design capacity would be one hundred million cubic feet per day of wetsour gas and yet, in the first one to two years of operation, the throughputwould be at forty percent of capacity. The use of heat rather than dehydrationappeared to be an economical method of preventing hydrate blockage, however theuse of conventional line heaters posed certain problems in a non-unitizedfield. The principal problem was that there were to be four wells connected toa thirteen mile trunk line and the competitive operation of the wells would notpermit cascaded operation. Consequently a situation existed where heat transferareas would be large and that mass transfer rates would be low. Preliminarydesign calculations indicated that as many as twenty-five conventional lineheaters would be required in a thirteen mile system in order to offset thisproblem.

A hot water tracing system was installed in the Wildcat Hills gas fieldduring the last three months of 1961. The system was placed into operation andat the time of preparation of this paper, it has been operated four months.While the initial performance of the system was exceedingly satisfactory, it isnot yet possible to compare design calculations with field observations for allranges of weather and soil moisture conditions. It is generally accepted thatany system using heat for hydrate prevention faces its crucial test during the Spring break-up period.
Some Practical Aspects of Interference Attenuation in Routine Seismic Exploration
Authors: Evans H.
Published: March 2010

An economic and a rather simplified scientific approach to the solution ofmore proper spacing of pattern holes and geophone arrays in the field isdiscussed. A method of recording and calculating the surface or apparent wavelength of interference waves is outlined. Several examples of actual fieldseismograms are included to illustrate the degree of interference attenuationthat can be obtained with a minimum amount of recording experimentation.

This paper is designed primarily to point out an economic and rathersimplified scientific approach to the solution of more proper spacing ofpattern holes and multiple geophone arrays in the field. The proceduresoutlined are not proposed as a "cure-all," but merely are intended to depict alogical sequence of steps which, in many instances, will yield at least apartial solution to the enhancement of the quality of seismic reflectionsignals.

Initially a few of the fundamental concepts of wave propagation should bereviewed. The word interference is defined as any unwanted signal generated atthe shot hole whereas noise is defined as any unwanted signal generated by someextraneous source such as wind, power lines, well pump, etc.

There are numerous types of interference such as Rayleigh waves, Love waves, ground roll, reflected refractions. Both the primary and the harmonic form ofthese various waves are frequently detected on or are suspected to be on thefield seismogram. This paper is primarily concerned with the attenuation of thetype of interference wave that travels from the shot through the weathered andsub-weathered near surface materials at velocities of 1000 to 8000/second andpossesses frequencies from 10 cps to 40 cps. The primary or fundamental lowfrequency wave can usually be cancelled by electrical filtering or, as in thecase of a strong low velocity surface wave, the employment of an in-line offsetspread removed sufficiently in distance to allow all reflection data to berecorded before the interference wave is recorded. However, in areas where thenear surface material possesses exceptional acoustic transmission properties(i.e. the ability to readily transmit most types of sound waves), the first, and even second harmonics of the low frequency interference waves aretransmitted through the near surface and are sufficiently strong in amplitudeto mask, or at least in part distort, the desired reflection signals.
Digital Computer Solution and Automatic Plotting of Acoustic Log Interpretations
Authors: Taylor W.H. , Kernahan G.M.
Published: March 2010

Defining the problem of reconciling or adjusting sonic derived velocities tothose velocities derived from seismic methods and programming the problem foran electronic digital computer is described. Prior to programming the sonic, preliminary planning to program and print-out the geophone survey results wascarried out. The use of stored computed geophone data, to assist in makingsonic computations manipulated by the sonic program, is explained.

An attempt has been made to illustrate the large quantity of data andcomputations handled while maintaining high quality of results andpresentation. The paper intends to be a guide to approaching problems ofsimilar complexity and traces out the stops and the solution of this particularproblem. It is not intended to explain in any way how the computer operates, except in very general terms, since this is a special field of study initself.

Since original presentation, the paper has been up-dated to present newtechniques now available through utilization of the Calcomp Incremental Digital Plotter.

Introduction

The handling of thousands of calculations involved in making severalinterpretations which may be derived from the acoustic log in conjunction witha geophone survey may be handled economic• ally and presented graphicallyutilizing the electronic digital computer and the incremental digital plotterrespectively. The calculations and interpretations may now be presented in anycombination of the following:

The presentations as outlined above in the seven separate processes may nowbe presented in a single continuous computer-plotter operation.
Coal vs. Natural Gas at Wabamun
Authors: Thompson G.H.
Published: March 2010

A brief history is given of Calgary Power Limited since the company startedsupplying power and energy in 1911 from its Horseshoe Falls Hydro Electric Plant. This paper deals primarily with the company's thermal plant on Lake Wabamun, which was designed to burn coal as fuel. However, while the Wabamun Steam Plant was still in the planning stage, the company was offered gasdelivery at 10½ c per million BTU's and in sufficient quantity to satisfygrowing requirements,.This gas supply was exhausted in 1961. The plant's thirdunit of 150,000 KW capacity will use coal for fuel. Comparative costs of usinggas and coal are outlined.

This paper deals with the use of natural gas and coal at the Wabamun Steam Plant of Calgary Power Ltd. The plant is located some 45 miles west of Edmontonon the Canadian National Railway main line.

First the manner in which the Company has been providing its power andenergy requirements over the years should be reviewed, since this has animportant bearing on the whole subject. The term "power" is used to denote therate of generation or use of electricity and is expressed in kilowatts (KW).The term "energy" is used to denote the quantity of electricity generated orused in any given period of time and is expressed in kilowatt hours (KWH)."Load factor" (L.F.) is an important term and is defined as the ratio of the KWH actually generated in a certain period of time to the KWH that could havebeen generated in the same period, had the units been operating continuously atfull load. Thus a 10,000 KW generator operating at full load, that is at 100%load factor, for one hour, will generate 10,000 KWH, but at 50% L.F. willgenerate only 5,000 KWH.
Imperial's Steelman Unit Ia and II Waterflood System
Authors: Stevenson D.W.
Published: March 2010

In January, 1962, full-scale water flooding began in the Steelman field ofsoutheastern Saskatchewan. The field has been developed on 80-acre spacing andthe injection pattern is an inverted nine-spot. The main requirements of theflood are a high quality water and flexibility in injection rates andpressures. To accomplish these ends water from the high capacity Blairmore sandis distributed to the injection plants, where it is filtered andinhibitor-treated, before injection into high pressure lines radiating to theinjection wells. The pressure and rate of injection to each well is controlledat the injection plant. Plant operation is semi-automatic and source wellpumps, filters, engines and injection pumps are protected by safety controls.Corrosion throughout the injection system is controlled through coatings andinhibitor and bacteriacide injection.

The design of the injection system was influenced by the results of a pilotoperation which commenced in 1958. The use of dry gas engines and diatomaceousearth filters are some of the design improvements derived from pilotexperience. This presentation discusses the design of surface facilities forthe water floods in Steelman Units IA and II, which were installed by ImperialOil Limited in 1961.

Introduction

The Steelman field is on the northern rim of the Williston Basin insoutheast Saskatchewan, approximately 15 miles north of the InternationalBoundary (Figure 1).The reservoir, at an average depth of 4,700 ft., isa stratigraphic trap of Mississippian limestone known locally as the MidaleBeds. The zone is thin and heterogeneous with low permeability. To date, 760wells have been drilled on 80-acre spacing. Recovery has been estimated at 16per cent under natural depletion and 35 per cent under water flooding.
The Demand for Canadian Crude and Natural Gas Liquids, 1962-1967
Authors: Lounsbury J.P.
Published: March 2010

Since 1956 a high degree of correlation has been evident between thecyclical growth of the Canadian economy and the total demand for petroleumproducts in Canada. The author develops assumptions as to the rates of growthwhich can be expected for the Canadian economy over the next five years and, onthe basis of these assumptions, forecasts a demand for petroleum products in Canada for 1967 of about 1,175 Mb/d (thousand barrels per day). Thiscorresponds to a rate of growth in product demand of about 4.5 percentcompounded annually. Since some three-fifths of this product market fallswithin that area west of the Ottawa Valley which has been reserved to Canadiancrude and natural gas liquids under the terms of the National Oil Policy, Canadian producers can expect to market nearly 675 Mb/d in Canada by 1967. Theexport market, now beginning to be influenced by slower growth rates in thePacific Northwest and by informal quotas in U.S. markets east of the Rockies, should nevertheless provide outlets for about 325 Mb/d in 1967. Thus totalCanadian production of crude oil and natural gas liquids five years henceshould reach close to 1,000 Mb/d, a gain of 35 per cent over estimated outputin 1962. Alberta's production, influenced in the short run by developments inBritish Columbia should by 1967 still account for about two-thirds of totalCanadian output. If Alberta's production is to grow at rates faster than thosedetermined by the now relatively mature Canadian energy market, it must do soas a result of greatly enlarged export markets. Even if export markets developat no faster rates than those forecast by the author, larger new additions toreserves will have to be developed over the next five years than have beendeveloped over the last five.
The Windfall Field Cycling Project
Authors: Wichert E.
Published: March 2010

Gas and condensate are produced from the Windfall reservoir and delivered tothe Windfall Gas Plant. The gas, containing 14% hydrogen sulphide and 5% carbondioxide, is sweetened and sold to the Alberta and Southern Gas Company, withthe hydrogen sulphide being converted to elemental sulphur. The condensate isstabilized and delivered into the Peace River Pipeline Company pipeline goingfrom Fox Creek to Edmonton. Gas is also produced from the Pine

Creek field, dehydrated and delivered through a 14-inch transmission line tothe Windfall Gas Plant. Here the Pine Creek gas is compressed and injectedthrough four wells into the Windfall reservoir to maintain the reservoirpressure. The Pine Creek gas contains 26% hydrogen sulphide and 6% carbondioxide. By means of this pressure maintenance cycling scheme, maximum liquidhydrocarbon recovery will be achieved and the processing of the Pine Creek gaswith its larger hydrogen sulphide content will be delayed by several years.

Introduction

The Windfall field is located approximately 20 miles west of Whitecourt, Alberta, which is approximately 110 miles northwest of Edmonton. The field isin part of a large number of lease blocks owned by Hudson's Bay Oil and GasCompany, Pan American Petroleum Corporation and Canadian Fina Oil. Also locatedwithin these lease blocks are two more gas fields approximately 23 miles to thesouthwest of the Windfall field, namely the Pine Creek and Beaver Creek fields.The exploitation program of these fields is called the West Whitecourt Projectby the owners and each of the owners is an operator of a certain phase of theproject: Hudson's Bay Oil and Gas Company operates the Pine Creek and BeaverCreek fields and a transmission line from Pine Creek to Windfall; Pan AmericanPetroleum Corporation operates the Windfall Gas Processing Plant and CanadianFina Oil operates the production and injection facilities in the Windfallfield.
Economics of Marketing Small Gas Reserves
Authors: Wickens L.I.
Published: March 2010

One of the most difficult and frustrating situations that exists today inthe exploration for oil and gas is the marketing of small gas reserves. Inrecent years, operators in Alberta and British Columbia exploited the exportfield to market the larger established reserves. Most of the subsequentdevelopment was conducted in close proximity to these reserves leaving manyprospects undeveloped. The problem of marketing the smaller reserves must andwill remain the major deterrent to development. This will no doubt be solvedbut only if operators diligently weigh the economics of each situation andendeavour to improve their position.

During the extensive search for oil and natural gas in Western Canada, manyof the wells discovered were classified as potential gas wells. Some of thesewells have been completed and tested and others were abandoned. Theinterpretation of the information collected from these wells must be used todetermine future development. The prevailing marketing conditions will controlthe future development of each prospect and, as circumstances alter in themarket situation, the economics of the proposed development must be reviewedand adjusted.

There are several factors which contribute to the classification of a well apotential gas producer. Since each company, engineer, or geologist evaluateslogging, testing and geological information differently, the evaluation of agiven well may vary widely. The interpretation of the well data willdetermine the value of the prospect. This information must be weighed in itsproper perspective and should be supported by as much supplementary data aspossible. Frequently, the operator found it impossible to get additionalinformation as the forseeable markets make further testing uneconomical. Thismay have been the case at the time of discovery and undoubtedly would determinethe type of completion used.
Measurement Problems in Gas Plant Operations
Authors: Cullen G.R.
Published: March 2010

Introduction

In September, 1962, the gas processing plant owned by Edmonton Liquid Gas, located on the southern outskirts of the City of Edmonton, started processinggas delivered to it by Northwestern Utilities for the removal of hydrocarbonliquids. The plant was originally designed to handle 50 MMcf/D of gas coming toEdmonton from the Pembina field and another 20 MMcf/D from the Texaco plant atBonnie Glen. These gas streams were to remain segregated, so two separateabsorption towers were required for processing. The Pembina unit was to operateat 650 psig and the Bonnie Glen at 450 psig. The residue gas was to be returnedto the Northwestern Utilities transmission line system. The reduction in gasvolume through the extraction of approximately 48,000 gal/D of liquid productswas estimated at 3.6% of the inlet gas volume. Payment was to be made for thisreduction on a therm basis.

Normally, gas plants of this nature are either subsidiaries of production ortransmission companies or part of an integrated system. As such, anydiscrepancies in a plant balance between the gas shrinkage and the extractedproducts are of no great consequence and can be taken care of in the accountingprocedures. However, in this case with separate ownership of the two companies, metering becomes a major problem to determine an accurate value of the productsextracted or used. The measurement in the reduction of gas volume cannot beused because the inherent inaccuracies in gas orifice metering are too greatfor this purpose. Measurement of the liquid products with positive displacementmeters would be the basis for billing. Gas measurement would be done only forthe purpose of obtaining plant balances.

Prior to the selection and installation of the gas measurement equipment, asurvey was made of gas plants operating under similar circumstances in bothCanada and U.S.to determine their experiences and practices.
Pembina Unit Institutes Line-Drive Type Waterflood; Off-Creek Reservoir Provides Water Supply
Authors: Harris R.L. , Horney D.M.
Published: March 2010

Operators select line-drive waterflood over other pattern type injectionsystems for the Lindale area. Greater oil recovery is predicted at asubstantially lower capital investment. Problems of primary water source areovercome by off-stream reservoir. Treatment and injection facilities arecombined to reduce operation and maintenance costs. Under the line-drive typewaterflood scheme the operators expect to recover the equivalent of the primaryoil in eight years compared to a normal twenty-five years. It is anticipatedthat the ultimate oil recovery will be more than double the primary reserves.Utilization of specialized engineering services can result in substantial costsavings on projects of this nature.

Introduction

A portion of the Pembina field in the Keystone-Berrymoor area was thought tobe a good prospect for a secondary oil recovery scheme. Unitization was aprerequisite to carrying out any full-scale project because of the large numberof ownership interests.

A feasibility study by a reservoir engineering consultant outlined an areawithin Twp. 49, Rge. 5, W5M which might be successfully water-flooded. Theconsultant considered several methods and recommended a line-drive typewaterflood. Implementation of this scheme is expected to increase presentincome, more than double the oil recovery, cost considerably less than apattern type flood, and be more economical in operation. The study indicated awater requirement of 3,500 B/D.This requirement and the generalconfiguration of the area and pattern governed the design of thefacilities.

Outline of Study Area and Brief History

Immediately to the east of the recently formed Berrymoor Cardium Unit and inthe western portion of the main Keystone-Pembina area a part of the sprawlingPembina oil field was subjected to examination for waterflood. The study areawas contained mainly in Twp. 49, Rge. 5, W5M, and was designated the Lindalearea. Some additional areas to the east and south were considered unsuitablefor waterflood because of the poorer Cardium sand characteristics. A separatepilot flood was recommended for this marginal area.
The Engineering Design of Well Stimulation Treatments
Authors: Flickinger D.H. , Fast C.R.
Published: March 2010

Correlation of the pump rate, fluid additives, tubular goods, andperforating programme can result in appreciable cost reduction in a wellstimulation treatment. The use of a specially designed cross-over valve topermit stimulation treatments to be conducted through manifolded tubing andcasing annulus, after initial formation breakdown through the tubing can resultin greatly increased treatment efficiency and reduced costs. A technique isoutlined for analyzing treatment variables and field examples are used todemonstrate the savings that can be realized by engineering the design of wellstimulation treatments.

Introduction

The hydraulic fracturing process has been the most successful and widelyused technique to stimulate oil and gas wells. It is estimated that 400,000treatments have been conducted during the 15 years the process has beenavailable and approximately 2,400 jobs per month are now being completed in thefree world's oil and gas producing areas.

The unusually high (80%) success ratio achieved using the process isprobably the major reason that many operators devote little thought andplanning to the hydraulic and mechanical factors involved in a successfultreatment. It is the object of this paper to demonstrate the economicincentives for optimum treatment design with emphasis on correlating thetubular goods arrangement, perforating programme, pump rate and the additivesused. It will be shown that substantial cost reductions are feasible byengineering the design of well stimulation treatments while increasing theefficiency and success probability of the treatment.

Discussion

Effect of TubularGoods on Treatment Costs

The total hydraulic horsepower required to pump water into a typical 7,000ft. well with various arrangements of tubular goods is shown graphically onFigure1. It will be noted that the total hydraulic horsepower consistsof two components:the horsepower necessary to inject fluids into aformation, andthe additional horsepower to overcome friction for thevarious combinations of tubular goods.
Understanding the Muskat Method of Analysing Pressure Build-up Curves
Authors: Larson V.C.
Published: March 2010

The somewhat neglected Muskat method is an excellent way to obtain staticpressure from build-up curves. A re-examination of the technique, accountingmore rigorously for fluid compressibility, shows why the early part of theMuskat pressure plot actually curves upward, so that it sometimes seems to giveunsatisfactory results. A straight line, indicating a correct static - pressureguess, should be expected only for later data; however, the time at which theline stops curving can be estimated simply. The study also revealed thatreservoir transmissibility and expansibility can be obtained from the plot.Three other methods of estimating static pressure from build-up curves arecompared to the Muskat method. They are less precise because they either do notaccount adequately for compressibility or they need more accurate reservoirinformation than is usually available.

Introduction

The Muskat method of analysing build-up curves seems to have been neglectedin favour of other methods. This paper should renew confidence in the Muskatmethod in that it provides a new theoretical basis for its use, adds to itsscope, shows why and when it will sometimes fail and compares it with someother techniques.

Applied to wells in a uniform, bounded system, the Muskat method is shown togive static pressure with very good resolution and without the need for priorknowledge of any reservoir parameters; however, the plot behaves as a straightline only for the later build-up data. A modification to the method permitsdetermining drainage-area transmissibility and expansibility from the plot.

The Basic Muskat Method

In 1937 Muskat published a method for finding static pressure from abuild-up curve.
Chemical Cleaning as a Maintenance Tool
Authors: Mullin G. , Quinn H.
Published: March 2010

This paper will attempt to outline how chemical cleaning provides apractical method of removing fouling products which interfere with heattransfer or with flow rates.

It will discuss how the selection of the proper solvent and technique for asuccessful and economic cleaning application depends on a number of factors, such as the nature of the deposit, the metals in the equipment to be cleaned, the solvents available, temperatures and safe operating practices.

The relationship of time and frequency of cleaning to cost will be outlined, as well as the factors which should be considered in the total cost whenevaluating chemical cleaning as a maintenance tool.

The author will also discuss recent developments in new solvents andtechniques, such as EDTA formulations, foam cleaning, organic solvents, vapourcleaning and one-stage copper solvents.

Chemical cleaning provides a practical method of removing fouling productswhich interfere with heat transfer or with flow rates. In the case of newpiping or other new equipment, the chemical removal of mill scale and oils andpreservatives is frequently necessary. This is especially true in the case oflubricating oil systems, oxygen systems and high-pressure boilers.

The successful and economic application of solvent cleaning depends upon anumber of factors; namely, the deposits, the metals in the equipment to becleaned, the solvents available and safe operating practices. The removal ofany type of deposit with solvents is dependent upon the nature of thatdeposit.

In solvent cleaning, the deposits, for purposes of identification, aredivided into one of three broad classes - namely, inorganic deposits, organic deposits,or mixtures of inorganic and organic deposits.

The inorganic deposits (Table I) consist of a comparatively small number ofspecific chemical compounds (Table II). They may be designated by chemical ormineral name, and by chemical formulae.
Physiographic Controls on Development in the Queen Elizabeth Islands
Authors: Sim V.W.
Published: March 2010

Introduction

Dean Hare of McGill University has recently pointed out that Canada is toocold and too big. His precise reasons for this belief do not concern us here, but I suggest that it is also an apt description of the Queen ElizabethIslands. To put it another way, climate and terrain in the Queen ElizabethIslands are seriously restrictive physical factors determining the directionand rate of economic expansion. These factors are discussed in some detail inthis paper.

Climate

In all activities in the Arctic, man's comfort is of primary importance. AsHarwood (1961, p. 1106) suggests "… in the end it is his heat loss whichdetermines whether he is cold and inefficient or warm and efficient." The firstaspect of the climate of the Queen Elizabeth Islands which needs emphasis isthe severity of the temperature and the duration of the period of extreme cold.Temperatures normally associated with winter in southern Canada occur during 10months of the year (Figure1), At Resolute, on Cornwallis Island, sub-freezing temperatures are usual between mid-October and mid-April. Onlyduring July and August can temperatures be expected to remain above freezing, and even during this period occasional sub-freezing days may occur. Most areasof the Islands share with interior Keewatin District the distinction of beingthe coldest areas in Canada in January, when the mean monthly temperature dipsbelow -30°F. Thomas points out, however, that even under these extremeconditions, daily temperature variations may range as high as 10° to15°F. (Thomas, 1961, p. 945).

Summer, as we know it in southern Canada, is not experienced in the QueenElizabeth Islands. In July, the mean monthly temperature is approximately40°F., or roughly the same as winter temperatures in Vancouver or April andOctober temperatures in Edmonton.