bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer Analysis of Gas Field Deliverability and Development Economics
Authors: Winter C.R. , Edgington A.N. 
Published: March 2010

Abstract
Long-term forecasts of gas field deliverabi Iity are necessary for both transmission and producing companies in order to permit orderly planning of facilities and the development of reserves. A digital computer program has been developed and is described here in. It is used to predict the availability of pipeline gas over the producing life of a field or pool, to forecast the numberof wells required to deplete the reserves efficiently, and to schedule the drilling requirements. The program also computes the amount of compression asit is required.
Included in the output data are the average reservoir pressure and shut-in and flowing wellhead pressures for each year. Maximum daily per well allowable sand average well deliverabilities are calculated. These results are derived using the linear relationship between reseryoir withdrawals and P/Z forvolumetric reservoirs and using the wellhead deliverability curve. The latter function is empirical in derivation and makes use of the exponential relationship between rate of flow from a well and the difference of squares ofthe static and flowing wellhead pressures.
A special aspect of the program is the well economics subroutine. This feature enables the user to predetermine the limiting conditions that a wellmust satisfy in order to be considered economic to drill. The program will calculate the present worth of future net production revenue from each additional well at any specified discount rate and, if the result is favourable, the well will be added to the system and will yield a rate of return greater than, or equal to, that specified in the input data. Producingcompanies often require a well to yield a total net production revenue which issome multiple of the capital investment in the well. This "well payout multiple" is left as a variable in the input data to accommodate individualcompany policy and to make provision for risk, amount of capital invested, expected productive life and other factors to be considered in investment decision making. Provision is also made in the program to establish a limit to the maximum number of wells to be drilled in the reservoir.
Operations Research in Petroleum Production
Authors: Raleigh J.T. , Flock D.L. 
Published: March 2010

Abstract
The domestic petroleum producing industry in Canada and the United States is faced with serious foreign competition due to a high differential in producing costs. The crude oil transportation factor and government restrictions provide effective barriers behind which much of this country's crude is marketed. In order to become more competitive, many United States oil companies have introduced Operations Research into their domestic planning.
The purpose of this paper is to point out briefly where Operations Research has been used in the petroleum industry, with more specific application being given to producing operations. Some background thinking on the unique problems of petroleum production is presented. An example using linear programming, taken from the literature, deals with a multi-reservoir field producing operation.
It is concluded that favourable results can be obtained by using Operations Research techniques to either maximize profits or income or to minimize operating and lifting costs in petroleum production operations.

Introduction
Energy is one of the most basic building blocks of any industrialized economy. The forms of energy most commonly used in North America are crude oil, bituminous coal, natural gas and electricity. As the natural sources of theseenergies are commonly found at a considerable distance from their end use, the transportation cost will be an important factor in total energy costs.
The international character of crude oil movements and the changes in patterns that can take place from time to time are indicated by excess supply breaking through in some areas to cause price deterioration. Despite this, the basic fact remains that the United States and Canada are still largely supplied by domestic oil and that, despite very much higher production costs, the transportation factor and government restrictions provide an effective barrier behind which much of the crude is marketed.
The Medicine Hat Gas Field
Authors: Martin Ian 
Published: March 2010

Abstract
This paper discusses the development and performance of Canada's largest individual accumulation of gas. The proven initial gas in place is in excess of 2 trillion cubic feet.
The first well was drilled in the Medicine Hat sand in 1904, although gaswas known to be present in the area in the 1890's. During the first 50 years, development was very slow, as there was only a small localized market, and onlyabout 100 wells were drilled. The approval of gas export from Alberta during the 1950's provided the incentive to completely develop the pool. Subsequent approval for export from the Medicine Hat field led to the drilling of about300 wells between 1958 and 1963. The field now contains about 400 wells, and development is by no means complete.
The producing horizon is a shallow, thin, shaly sand. The determination of effective pay is complicated by the presence of extremely fine layering of the shale and sand. A correlation between logs and core analyses was developed in1959 following an intensive geological study of the cores. Further drilling andthe observation of field performance has proved this correlation to be satisfactory.
The uneven development of the pool over a period of 60 years has causedconsiderable gas migration into the older producing area. Engineering studies involving the application of fluid flow principles showed that the gas reserves of many operators who were denied access to the local market were being seriously depleted by drainage. These findings were presented to the Alberta Oil and Gas Conservation Board and may have been a factor in the subsequent granting of export permits for several operators. Methods of calculating the drainage across lease lines are described.
Recent engineering studies have shown that gas drainage is, in many instances, being curtailed. The previously penalized operators are now participating in their rightful share of gas from this field. It is now morethan ever an important asset to the economy of southeast Alberta.
Solvent Placement Improvement by Pre-Injection of Water - Lobstick Cardium Unit, Pembina Field
Authors: Kloepfer C.V. , Griffith J.D. 
Published: March 2010

Abstract
Stratification of petroleum reservoirs plays an important role in theperformance of fluid injection pressure maintenance recovery projects. Thesignificance of this factor in miscible recovery applications is emphasizedbecause of the generally adverse mobility ratios common to this type ofproject. The initial distribution of a miscible slug among the strata of areservoir dictates the volume of the reservoir that can be miscibly swept asthe slug is subsequently driven through the reservoir. The slug volume requiredto achieve miscibility in all strata of any given reservoir generally becomesprohibitively large. Improvement in permeability contrast prior to solventplacement will effect improved solvent utilization and enhance the efficiencyof this recovery technique.
The reservoir in the Lobstick area of the Pembina Cardium pool is severelystratified. In the area of miscible application, a conglomerate member, representing about 30 per cent of the reservoir volume, has a capacity of aboutfifty times that of the underlying sand. To improve the native capacitydistribution and to afford an evaluation tool for early injection performance,a 400,000-barrel slug of water was injected ahead of the solvent slug.Theoretically, this pre-injection of water will double the effectiveness of theinjected solvent. The calculation method for determining the improvement ofsolvent placement for Lobstick is described in detail.

Introduction
In miscible fluid displacement projects, reservoir stratification maysignificantly affect recovery because of the adverse mobility ratios common tosuch schemes. Solvent injection into a stratified reservoir will generallyresult in more permeable strata receiving a solvent volume in excess of thatrequired to effect complete miscible displacement before the less permeablezones have received the required minimum. The initial distribution of solventamong the reservoir strata governs the portion of the reservoir that can bemiscibly swept by the driving of this slug through the reservoir.
A Stable, Explicit, Computationally Efficient Method for Solving Two-Dimensional Mathematical Models of Petroleum Reservoirs
Authors: Quon D. , Dranchuk P.M. , Allada S.R. , Leung P.K. 
Published: March 2010

Abstract
There has been a growing interest in the use of two-dimensional mathematicalmodels to simulate the transient behaviour of oil and gas fields. Until very recently, the standard numerical technique used the alternating direction implicit procedure (ADIP) to integrate the basic partial differential equation describing flow through porous media. However, the computational problem, evenon high-speed computers, remained a form idable one. A new method for solving the conduction equations, first suggested by Saul'ev and later extended by Larkin, makes ingenious use of the known boundary conditions to permit an explicit point-by-point sequential evaluation of all interior grid points. A reverse sweep is used to minimize the over-all errors. The method, which may becalled an alternating direction explicit procedure (ADEP), combines thestability of the implicit methods with the computational ease of the explicit methods. By examining the structure of the computational models and noting their physical significance, it is shown that ADEP is a logical extension of ADIP and should have about the same accuracy. The new method is applied to anexample problem involving a volumetric under saturated oil reservoir, mathematically represented by several hundred grid points. The results indicatea possible order of magnitude saving in computer time for problems of this typeas compared to an ADIP solution. This suggests that three-dimensional models might now very well be practicable.

Introduction
The present paper is a preliminary report on a new numerical method, firstproposed by Saul'ev (1) and later extended by Larkin (2), for solving the basicpartial differential equation describing the flow of a slightly compressiblefluid through porous media. As it involves an alternating direction explicitprocedure, it may be referred to as ADEP.
Because of limitations of computational machinery and costs, existingmethods have been largely limited to the two-dimensional case. The mostefficient of these methods is the alternating direction implicit procedure, or ADIP, developed by Peaceman and Rachford (3). By examining the proposed methodin the mathematical context of earlier computational models, we can drawcertain, hopefully valid conclusions about its accuracy, its stability and itscalculational requirements. No attempt will be made here to give formalmathematical proofs of stability or to present a detailed error analysis -important considerations which have been examined elsewhere (4).
Application of Electrical Current for Increasing the Flow Rate of Oil and Water in a Porous Medium
Authors: Anbah Saleh A. , Chilingar George V. , Beeson Carrol M. 
Published: March 2010

Part II of their paper already published in the Journal of Canadian Petroleum Technology, Vol. 3, No. 1, pages 9–14, Spring, 1964: "Use of Direct Electrical Current for Increasing the Flow Rate of Reservoir Fluids During Petroleum Recovery."

Abstract
The possible use of direct electrical current for increasing the flow rate of reservoir fluids during petroleum recovery was recently investigated by Ambah et al. [1964] (29). As pointed out by the writers, however, thestudy of the application of electrokinetic phenomena in oil production was notcomplete, and many other problems remain to be solved.
The possibility of using electric current for enhancing the injectivity ofwater in waterflood systems or simply increasing the rate of production intight formations was further investigated in the present study. In all cases, the volumetric rate of flow increased on increasing the electrical potential imposed. Additional theoretical analysis is also presented here.

Theoretical Analysis
Reuss [1808] (2) was the first to notice that if two electrodes were placedin a liquid on opposite sides of a porous diaphragm, on application of an electromotive force the liquid would flow from one compartment to the other. An equilibrium will be reached when the hydraulic head, due to the difference influid level, is balanced by the driving force caused by the imposed e.m.f.
Wiedemann's [1852] (3) first and second laws stated that:
When an electrical field is applied to a liquid in capillaries, the flowis proportional to the electric current or the applied potential. If, instead, this flow is prevented, the electroosmotic pressure is likewise proportional tothe current.
Quincke [1860] (4) recognized electroosmosis and streaming potential as inverse phenomena and explained them by assuming the existence ofan electric double layer at the boundary surface between the liquid and thesolid wall. It can be assumed that the solid surface is negatively charged andthe positively charged part of the double layer is present in the liquid phase.Thus, upon the application of an external electrical field, the positivelycharged liquid layer will move toward the cathode, drawing with it watermolecules in the free liquid stream because of the viscous drag. Conversely, ifa liquid is forced through capillaries, a streaming potential or a streamingcurrent, depending on which is measured, is produced which is proportional tothe pressure differential applied.
Gas Cycling in the Lookout Butte Rundle Pool
Authors: Hnatiuk J. 
Published: March 2010

Abstract
The Lookout Butte condensate-bearing gas accumulation is contained in afractured thrust block of Rundle strata at a depth of 12,200 feet. Themoderately sour gas initially contained 106 barrels of pentanes plus permillion cubic feet of well effluent. As studies indicated that only 27.5 percent of the original pentanes plus in place were recoverable by normal pressuredepletion, a gas cycling scheme was initiated in 1963 to increase condensate recovery. Gas is produced from four wells, condensate is removed and stabilized, and sour, relatively dry gas is injected into a single well at the north end of the pool. It is anticipated that 33.7 per cent of the originalpentanes plus in place will be ultimately recovered if the pool is cycled at 40MMcf/D prior to pressure depletion. The prediction methods and performance todate are discussed. The effect of fractures on cycling performance isimportant. Performance in Lookout Butte during 18 months generally confirms assumptions regarding the effectiveness of the fractures. The elongated shapeof the reservoir is expected to result in a favourable areal sweep. This configuration also permits flexibility in the event that a second injection well is required in the future.

Introduction
The Lookout Butte Rundle gas pool is located in the extreme southwestern corner of Alberta between the Pincher Creek Rundle gas pool and the International Boundary, as shown on Figure 1. The pool was discovered in1959 by the drilling of B.A. Lookout Butte 11–31, in Lsd. 11-31-1-28 W/4, which encountered gas-bearing Rundle at approximately 12,000 feet. Seven wells were subsequently drilled, which resulted in four producing gas wells, two marginal gas wells and one abandonment. The Lookout Butte Rundle Unit No.1 became effective in August, 1963, at which time gas cycling commenced.

Reservoir Characteristics

I. Geology
The Lookout Butte reservoir is a thrust block of Rundle strata, strikingnorth-northwest, dipping west and plunging gradually northward. Maximum elevation of the thrust block above the regional elevation of the Rundle is approximately 1,500 feet.
The Chemical Treatment of Water Used in Steam Injection Systems
Authors: Walker Charles L. 
Published: March 2010

Abstract
The chemical treatment of waters used in steam injection involves the control of the following problems:the removal of oxygen from the process waters;the prevention of mineral deposition due to hardness leakage by the ionexchangers;the control of corrosion in the steam injection lines; andthe prevention of biological growths in the source water.
This paper deals with the fundamentals of water chemistry involved insolving the above-mentioned problems and the chemicals necessary to bring aboutthe control. The author will also discuss the divergence of opinions on thenecessity to treat waters used for steam injection systems. The treatment problems involved in the production of steam-treated crudes will also be considered.

Introduction
Everyone knows that the chemical symbol for water is H2O; butwhat few people realize is that, unlike other symbols for chemicals, the(H2O) symbol tells us very little about what water is. Water is only H2O at the first instant of its formation. From the time water fallsthrough the atmosphere until it reaches its final resting place, waterdissolves the various gases and minerals with which it comes into contact. Therefore, water as we know it is actually a solution of minerals and gases. Itis, therefore, this aqueous solution of minerals and gases that we deal with inthe everyday use of water; and the types of these components in water governthe use to which it can be put. In no place is this fact more strikingly revealed than in the examination of waters used for the generation of steam.The presence of certain minerals and dissolved gases is directly related to many of the operational problems involved in the production of oil by steam injection.
Advances in Estimating Gas Well Deliverability
Authors: Winestock A.G. , Colpitts G.P. 
Published: March 2010

Abstract
In the past, drawdown tests to estimate well deliverability and diagnose wellbore damage, although simple in themselves, have been of limited value, often because it is inconvenient or costly to obtain the constant flow rate required to analyze them reliably. This paper presents a new drawdown analysis technique developed with the aid of a digital gas-well simulator. The new method does not require a constant rate, is as simple to analyze as the conventional method and is considerably more accurate. It can thus heused in gas wells to analyze the early time data from a back-pressure test when the rate has not yet "stabilized" to a constant value. The new technique takes into account turbulent flow in gas-well systems - a prerequisite to calculatinga gas well's current and potential deliverability. These calculations areeasier if at least two drawdown tests, and preferably, more, can be conducted on the gas well. Fortunately, the practice of running a multiplicity of drawdown tests is already embodied in the four-point isochronal AOF test, where each flow test is separated from the others by a sufficiently long period of shut-in. This type of test lends itself to reliable drawdown analysis. However, in the four-point flow-after flow test, where the flows at each rate are consecutive, the deliverability estimates often are not reliable. The new drawdown technique is not limited to use in gas wells. It can also be used toestimate well productivity and diagnose wellbore damage in oil or water systems.

Introduction
Gas flow in a porous medium is different from oil or water flow in that itdoes not obey the Darcy Law. In the gas-reservoir-engineering literature (1), this difference is now commonly called "turbulence." Turbulence occurs becausethe low viscosity of gas (compared to that of oil or water) results incorrespondingly higher gas velocities under a given pressure gradient. At these higher velocities, the gas suffers inertial energy losses as well as the usualviscous energy (Darcy) loss.
Understanding Surface Casing Waiting-on-Cement Time
Authors: Maier L.F. 
Published: March 2010

Abstract
The waiting-on-cement time in low-temperature surface casing cementing canvery often be reduced to less than what is common practice today through abetter understanding of cementing conditions. Two major factors in the earlydevelopment of the compressive strength of cement are the water-cement ratioand the curing temperature. The latter is partially dependent upon theformer.
The strengths of cements required for drill-out are discussed, and the curing times required to achieve the necessary strengths are presentedgraphically. API Class A, B and C cements are considered, and the advantages of using the densified systems are illustrated.
Data from field studies concluded over the past several years, including temperature measurements on well fluids and temperature surveys followingcement jobs, illustrate the curing temperature behaviours of typical western Canadian surface casing cement jobs. The effects caused by heat of hydrationand by cement mixing water and displacement fluids which are warmer than formation temperatures, can be rather significant, producing average curing temperatures which are higher than the surrounding formation temperatures by asmuch as 5°F to 30°F or more.
A laboratory study was made to determine the comparative effects of the heatof hydration of cement slurries under different conditions. The heat evolved isincreased when (1) the slurry is placed at a higher starting temperature, (2)the volume of slurry is increased and (3) the slurry is mixed at a higherdensity.
Cementing practices are discussed and recommendations made. With a more thorough knowledge of the basic factors involved, it should be possible in manycases, to more accurately correlate the required waiting-on-cement time withthe conditions as they exist rather than adopt a policy of fixed time which satisfies all probable conditions of cementing materials, temperatures and techniques.

Introduction
The phrase "waiting-on-cement," or "WOC," has long been a misnomer in mostinstances. The nonproductive and expensive time spent waiting has usually notbeen necessary, because, in fact, the cement was firmly set and was actuallywaiting on us. Increasing concern is being expressed by the industry over thiscostly waste, and continual attempts are being made to reduce WOC time to asafe minimum. The area of greatest interest appears to be that of surfacecasing cementing; this is due to the difficulties caused by the lowertemperature curing conditions.