bluuebunny/crossref_metadata_2025_split huggingface dataset:
Detection Of Gas Migration Behind Casing Using Ultrasonic Imaging Methods
Authors: Forbes D. , Uswak G. 
Published: March 2010

Abstract
Failure of the cement, providing zonal hydraulic isolation on the outside of the production casing, occurs in some wells and can result in upward migration of gas behind the casing. Such a cement failure might result in a gas flow from the surface vent connected to the production by surface casing annulus. Or, if the vent is closed, the gas might build sufficient pressure at surface to break down the formation strength at the casing shoe and thereby migrate up around the wellhead itself.
Prior to attempting repairs, both the location of the gas source and the potential to displace the annular space with cement must be evaluated. These may be determined from an ultrasonic image obtained from the Cement Evaluation Tool (CET*).
Temperature and audio logs attempt to detect the actual movement of the gas flow which may be very small and difficult to detect. In such cases the CET image has shown a significant presence of gas filled channels from the source zone up to the surface. Log examples pinpoint probable gas sources and identify annular materials enabling successful remedial cementing strategies to be developed.

Introduction
The Problem of Surface Gas Migration
There are a significant number of wells today leaking gas to surface. In Alberta, Energy Resources Conservation Board statistics indicate that, in 1988,4.7% of wells in Alberta had surface casing vent flows compared to 2.6% in 1931(1). Potential environmental effects include ground water contamination and release of hydrocarbon vapours to the atmosphere.
How much gas is a serious problem? What is the cause of the leak? Can it be repaired? How? When should it be repaired? immediately or if not serious, at time of abandonment? Many of these questions are being evaluated by regulatory agencies as well as energy companies. As we enter the 1990s, the onus will be on energy companies to reduce the number of wells that have surface gas leaks.
Data is needed to evaluate these problem wells and develop remedial action plans. Part of the data required can be obtained through wireline logging techniques. These measurement techniques have had a measure of success detecting movement near the completed interval in a well. Figure 1 illustrates subsurface gas migration resulting in a surface flow at the casing vent valve.
The Gas Migration Advisor (GMA) is a new wireline logging technique that employs ultrasonic imaging to identify the contents of the casing annulus as gas liquid or solid.
Quantifying and Measuring the Problem
Historically, gas leak detection has been accomplished with varying degrees of success by logging with noise and temperature tools(2). The noise tool responds to audio signals. Detectable signals are caused by fluid or gas moving turbulently through a sufficient pressure differential. By examining the tool response at different locations in the well, significant movement behind casing can be detected leading to an identification of the source of the gas (Fig, 2).
The temperature tool measures the temperature in the wellbore.
Carbon Dioxide Flooding As An Enhanced Oil Recovery Process
Authors: Mungan N. 
Published: March 2010

Synopsis
In earlier work(1–5), the fundamental and the field applications of carbon dioxide flooding were described. The presentation(5) at the Western Regional Meeting of SPE in 1991 focussed on a comparison of CO2 flooding for light and heavy oils, with examples from the field showing that CO2 flooding has recovered significant amounts of incremental oil under miscible as well as immiscible conditions. Carbon dioxide flooding for the enhanced recovery of heavy oils is important for Canada since it provides an alternative to thermal recovery. In this article the author will attempt to illustrate the state-of-the-art on CO2 flooding in general and how CO2 flooding relates to the recovery of heavy oils in particular.

Introduction
There is a great deal of industry interest in CO2 flooding as evidenced by the large number of field applications which have been initiated in the past decade(6). Additional field tests are certain to be carried out when CO2 supplies of acceptable purity and volumes are found. All major petroleum research centres, institutes, universities and government research institutions have projects relating to CO2 flooding. With two exceptions, the process normally involves the injection of CO2 initially, followed by a period in which CO2 is alternated, as small slugs, with another fluid, and terminates, with the injection of the principal driving or chase fluid which would be either water or gas. The two exceptions are the carbon dioxide stimulation process which is carried out in producing wells and is a stimulation technique very similar to a ""huff-and-puff' scheme. The other exception occurs in reservoirs which have such low pressure that they must initially be pressurized prior to the injection of CO2. Normally, such pressurization is by injection of water.
Carbon dioxide flooding may be carried out either as a miscible or as an immiscible oil recovery process and has been studied in the laboratory or practiced in the field in the following modes:carbon dioxide stimulation;continuous CO2 injection;simultaneous injection of CO2 and water;alternating slugs of CO2 and water;injection of CO2 with H2S;injection of CH4 and CO2;CO2 and N2 mixtures;the CO2, SO2, combination;CO2 and LPG mixtures; andLPG followed by CO2.
The most common way that CO2 flooding is being applied in approximately 60 depleted light oil reservoirs in the United States has been to initially repressurize the reservoir to the minimum miscibility pressure by injecting water. In a few cases, repressurization was accomplished by injecting CO2 from the start. Of course, this can be costly. For a reservoir depth of, say. 2500 m, one can expect the minimum miscibility pressure to be about 16 MPa and the reservoir temperature to be 90 °C. At these conditions, 350 m3 of CO2 would approximately equal 1 m3 in reservoir volume. Depending on the size of the reservoir and the cumulative past production the CO2 requirements can prove to be prohibitive.
Revitalization Of The Pembina
Authors: Krasey Rusell , Jackson Marc 
Published: March 2010

Abstract
Over the past eight years, 1981 to mid-989, Canadian Occidental has invested $16,300,000 in the revitalization of the company's Pembina properties. A total of$3,800,000 was invested in 83 fracture stimulations yielding an average payout period of just over one year and incremental reserves per job of 2130 m3. The stimulated wells are currently producing 45 m3/day of incremental oil yielding $1,650,000/year of additional revenue/or the Pembina operation. A total of $12,500,000 was invested in 33 infill wells and their associated facilities. The infill wells have an average payout period of 2.5 years and the estimated incremental reserves per well of 10 930 m3. The infill wells are currently producing 80 m3/day of incremental oil yielding $2,000,000/year of additional revenue. Canadian Occidental's program has increased the current annual revenue to $5,550,000 from an estimated $1,900,000 if none of the work had been Carried out. The increase is significant considering the majority of the work has achieved payout. The work carried out by Canadian Occidental ensures continued profitability and life from the field in the future.

Introduction
The main purpose of this paper is to prove to the industry that the Pembina Oilfield can be a source of significant reserves and revenue in the future. Huge gains in productivity cannot be expected but sustained economic development can take advantage of the already existing infrastructure with excellent returns in both production and profit.
Cities-Service/Canadian Occidental has been active in the Pembina Oilfield since 1956 and was instrumental in setting up many of the units in the field. The company's first waterfloods were initiated in 1961. The company also experimented with gas/LPG injection in both Bear Lake and Keystone. By 1965, most of the Pembina Cardium had been unitized and the majority was under waterflood.
Canadian Occidental currently operates 412 wells in the field with 15 batteries and 76 satellites and one gas plant located in Keystone, Of the 412 wells, 282 are producing, 65 are injectors and 65 wells are shut-in. Production from the field, on a Lease Gross Basis, currently averages 420 m3/day of oil, 112 103/m3day of gas, and 1850 m3/day of water as of November 30, 1989. Production on a per producing well basis averages of 1.5 m3/day of oil, 0.4 l03m3/day of gas, and 6.6 m3/day of water.
The average producing well operating cost, including battery, shut-in well and injector costs, currently averages $28,800/year. Using a price of $120/m3, the break-even production rate for a Pembina well is 0.7 m3, /day. Over-all, the field is still profitable, but every means had to be taken to increase production. Because the operating cost is not directly proportional to production rates, a 50% increase in production may only equate to a 10% increase in operating costs. Canadian Occidental's Engineering staff in Drayton Valley used the following criteria when choosing fracture stimulation candidates. Explanations into what was looked for in each criteria is also included.
Reservoir Simulation Integrated with Geomechanics
Authors: Tortike W.S. , Ali S.M. Farouq 
Published: March 2010

Abstract
Petroleum reservoir simulation has reached a point where it is desirable, and often necessary, to couple fluid and heat flow with the geomechanics of thereservoir and the surrounding rocks. The first step in this direction was Geertsma's hypothesis concerning pore compressibility in an elastic porousmedium, and its local relationship to fluid pressures. The evolution of thiscoupling of the solid matrix response to the changes in fluid pressure isdiscussed for materials with more complex behaviour than linear elasticity, andfor when temperature changes add new loads to the structure. A general coupledreservoir geomechanics model for thermal reservoir modelling is presented. Theresults of an implementation of this model are presented for coupled anduncoupled analyses of the stress and fluid pressure responses to cyclic steaminjection in a tar sand, a material with elastoplastic behaviour. The materialand fluid response to coupling was moderately different to that withoutcoupling, with principal stress rotations occurring at later times. The model, however, was also providing the complete distribution of stresses throughoutthe simulated domain, and the changes in porosity appropriate to a sandundergoing shear failure. These changes were noticeably different from thevariations in porosity obtained when only considering linear elastic porecompressibility.
MTBE: A Carrier For Heavy Oil Transportation And Viscosity Mixing Rule Applicability
Authors: Anhorn J.L. , Badakhshan A. 
Published: March 2010

Abstract
The pipeline transportation of bitumens is made difficult by the excessive viscosities of the heavy oil. The current solution to this problem has been the addition of C4+ paraffinic liquid hydrocarbons. There are a number of drawbacks, however, to the use of this diluent. To overcome these difficulties the alternate use of MTBE (methyl tert-butyl ether), a gasoline additive, as a liquid solvent has been investigated. With the potential for Alberta to become a substantial exporter of both bitumen and MTBE, the prospect of transporting the two constituents simultaneously is promising.
A liquid viscosity model has been utilized to calculate the component viscosities as a function of temperature, and then use a mixing rule to determine blend viscosity as a function of composition. It was found that the addition of 25–30% MTBE (mass basis) was sufficient to reduce the viscosity of the Cold Lake bitumen to meet pipeline specifications. The viscosity model was found to be accurate over the entire range of compositions and temperatures examined. A simple distillation was performed on a 35% MTBE (mass basis) blend to study the ease of separation of the liquid diluent from the heavy oil phase at atmospheric conditions.

Introduction
The most detrimental factor in the production and transportation of bitumen is its excessive viscosity. A typical Cold Lake heavy oil will have a viscosity greater than 500,000 mPa-s at 4 °C, while the viscosity of a typical conventional oil may be 3–4 orders of magnitude lower(1). An increase in temperature of the bitumen has been shown to greatly reduce its viscosity(2). This temperature-viscosity relationship is used in many enhanced oil recovery (EOR) techniques to produce heavy oil and bitumen at economical Rates(2). However, to adequately heat an entire pipeline for the length of the transportation is clearly unrealistic. The current solution to this problem has been the addition of liquid diluents to the bitumen to reduce its viscosity.
The most common diluent used in this manner is a C4+ paraffinic liquid hydrocarbon (or condensate) obtained from natural gas processing. This solvent generally achieves the needed viscosity reduction, but also has some inherent drawbacks. The availability of this liquid hydrocarbon is sometimes in question, and there may not be sufficient buyers to purchase the solvent at the end of the transportation. In fact, many suppliers of the bitumen consider the diluent to be a lost expense, and do not expect to be reimbursed. Also, the solubility of the solvent in the bitumen may pose some difficulties. The bitumen can be diluted with the condensate up to a critical dilution ratio, after which asphaltene deposition occurs(3,4). Therefore it can be seen that the ideal solvent choice is one which would achieve the required viscosity reduction, not cause the asphaltene fraction to precipitate, and also possess a substantial consumer market.
"Is There a Future For the Canadian Oil And Gas Industry?"
Authors: Cleland N. 
Published: March 2010

Abstract
My answer to the question, "Is there a future for the Canadian oil and gas industry?" is a plain, straight-forward and absolutely positive "YES!" Now, before you accept my confident answer on the future of this industry, you'd no doubt like to know why I am so optimistic. There are a number of very good reasons why my answer to the query. "Would you recommend a career in the oil business?" is an unequivocal "yes. "

Industry Maturity
Everybody recognizes that the industry is different now than it was during the first 40 years after the Leduc discovery in 1947. Remaining reserves of oil have been declining since the early 70's, while remaining gas reserves have been on the way down since the mid-80's. The combination of these two events has caused the industry to move from the "development stage" of its evolution to the "depletion stage" of its existence. This new stage reflects the maturing of the development of the Western Canada Sedimentary Basin. It results from the increasing difficulty in finding new reserves.
The mistake a lot of people make is to assume that the change from development to depletion heralds the end of industry activity. This is not the case. The industry will have the cash flow to continue its exploration and development at a high level for the next half century. The sunset years are still a long way away. With time, the Basin will change from being weighted towards oil production to being weighted towards gas production. This merely reflects the earlier development of the oil reserves in the Basin.

Remaining Reserves
How much all and gas do we, currently have left to produce and what can we expect to add in the future? It's important to note that more than 70 per cent of the remaining gas reserves forecast in 20 years' time have not yet been discovered. The situation for oil is less dramatic, but new oil discoveries will still be very significant in the future.
If crude oil is considered to include Light, medium and heavy crude, bitumen, synthetic crude and pentanes plus, there were 7.5 billion barrels left to produce at the end of 1992 from the 25 billion barrels discovered to that date. We've produced 70 per cent of the oil discovered so far. There were 68 Tcf of natural gas remaining to be produced at the end of 1992 from the 145 Tcf of gas discovered to that time. Cumulative production of gas is only 55 per cent of discoveries to date.
In addition to these discovered reserves, it is forecast that 75 Tcf of gas reserves will be added in the next 20 years. New oil reserves to be discovered in the next 20 years are expected to amount to 4 billion barrels. The amount of exploration and development required to add 75 Tcf of gas and 4 billion barrels of oil will keep the industry very busy during the next 20 years.
Analysing Pressure Buildup After a Multiple-rate Drillstem Test In a Well Near a Fault
Authors: Exall D.I. 
Published: March 2010

Abstract
The analysis of pressure buildup data in a well following a multiple-rate flow test is made more difficult if the well is near a fault. Although both these cases have been treated independently in the literature, the combination leads to a more complicated expression for the predicted pressure behaviour after shut-in.
The theoretical expressions for the post shut-in pressure and the skin on the well are derived from first principles. The predicted pressure response is compared with the measured pressure buildup data from a well in the Apiay field in Colombia, and values are obtained for the permeability of 615 mD and distance to a fault of 160 m that provide a good fit to the observed, data. The distance to the fault obtained from the model matched exactly the distance to the main Apiay fault determined from :independent seismic data. Data is also presented in the form of the response surface on which the objective function minimization takes place.

Introduction
In most instances, drillstem testing (DST) of a well to determine productivity and reservoir properties in the vicinity of the well is completed before a thorough analysis can be made of the results. Where there are reservoir heterogeneities in the area, such as a sealing fault this often leads to a change in the slope of the usual Homer-type plot near the end of the test and it is not clear whether this increase in slope is due to the effect of the fault or is an artifact of the measurement.
As several instances of this late-time increase in slope had been found in analysing drillstem test data from the Kl and K2 formations of the Apiay field in Colombia, the theoretical behaviour of a well near a fault has been analysed in order to compare this with the observed pressure behaviour in the final buildup period of a multi-rate DST The Apiay reservoir is particularly suitable for testing this type of theoretical response as it is a very clean and uniform sand of fairly high permeability with some well-defined faults and possible minor faults in the area.

Theoretical Pressure Response
We consider initially a DST carried out in an infinite-acting reservoir for times where wellbore storage effects have become negligible.
The usual methods for treating the pressure buildup in a DST with multiple rates before shut-in are described in Earlougher(1), Matthews and Russell(2) and Lee(3). The first method, used for rates that do not vary substantially, is to calculate a production time defined by(1): Equation. (Available In Full Paper) where Vp is the total volume produced since the last pressure equalization and q is the constant flowrate just before shut-in. This is used in a Homer-type plot of PW5 as a function of Equation. (Available In Full Paper) where δt is the time since the shut-in of the well. When the flowrates before shut-in vary considerably, it is necessary to use a more elaborate multiple-rate analysis.
Countdown To 97
Authors: Kerr A. 
Published: March 2010

Abstract
As I stood there that cold winter afternoon 49 years ago, little did I realize, let alone understand, the significance of those hundreds of barrels of crude (light gravity 38 degrees, lube stock, I'll have you know) going up in smoke. This was to herald the new knowledge of millions of barrels which we would soon start finding in astonishing amounts.
As a junior geologist, to paraphrase Gibby Gibson, "we did not speak unless we were spoken to." I was totally ignorant of the machinations of Imperial Oil's Geophysical Department and had to wait until 1977 when I saw the October 1946 super secret plat. Ray Walters, the Wizard, had selected the well site from this plat (though even he did not know what the anomaly meant).
Hundreds of farmers showed up with horse blankets spread over their 1929 Essexs, possibly with the idea that they were going to share in the mineral wealth. But this privilege had been granted to relatively few homesteaders, none of whom realized their good fortune prior to September 1946 (when Imperial started trying to sign them up).
Now, with nearly 50 years behind us, several major disturbing conclusions must be drawn:The main Devonian Reefs were found within 7 years of Leduc and within a 50 mile radius of Edmonton. They comprise 20% of the known crude reserves of the Province. These giant accumulations are all but depleted.Alberta, the home of the Devonian Reef, has been unable, over the past 30 years, to discover any accumulations on the scale of Leduc or Redwater.So-called ‘statistical experts’ may be allowing Rome to bum as the crude pipeline capacity to the east is increased. These additions are no longer required because of conventional reserve additions, but rather from such arcane items as horizontal drilling and sliptivity chemicals to counteract the viscosities of the heavier crudes which are replacing conventional.
In broad historical perspective, the 50th anniversary of the discovery of Leduc should be observed next February (1997), as less of an achievement than a "blip" on the reserve curve, the direction of which will continue to climb due only to tar sands and heavy oil.
And what of 2047, the 100th anniversary of Leduc? All the conventional crude will have long since been exhausted, and the Leduc "blip" on the reserve curve will have lost its significance.
Instead of airy promises of undiscovered conventional crude, all eyes should be focussed on the growing importance of the tar sands. They were there 250 years ago when the first explorers tramped through northeast Alberta. They are now required to assure Canada's future liquid hydrocarbon self-sufficiency.