Reservoir In Alberta Research Articles

Production Problems in the Steam-stimulated Shaley Oil Sands of the Cold Lake Reservoir: Cause and Possible Solutions

Abstract The highly viscous bitumen from the Cold Lake reservoir in Alberta isproduced by the Cyclic Steam Stimulation (CSS) process. The clean oil sands ofthe Cold Lake reservoir generally produce well, but the shaley oil sands withimbedded clasts have experienced lower bitumen production and lower steaminjectivity. This paper presents laboratory and field data that support the hypothesisthat the minerals in the clasts play a role in the production problems of theshaley oil sands. Laboratory tests reveal that clasts in the shaley oil sandshave an abundance of carbonate minerals such as siderite (iron carbonate) andaluminosilicate minerals such as kaolinite and feldspar. Laboratory studiesunder steam stimulation conditions show that the mineral reactions betweencarbonates and aluminosilicates can generate formation damaging products suchas swelling clay and carbon dioxide. Swelling clay can damage the formation byplugging the pore throats, whereas carbon dioxide can lead to near-wellborescaling. Calcium carbonate scales have been observed in downhole pumps andliners in Cold Lake wells. The field bitumen production appears to be inverselycorrelated with the carbonate content of the clasts. The field bitumenproduction is also inversely correlated with the amount of carbon dioxidegenerated in the laboratory by hydrothermal reactions of clasts. The paperdescribes the application of portable X-ray fluorescence (XRF) andnear-infrared instruments for rapid, nondestructive identification of reactiveminerals in cores, and of photoelectric absorption (Pe) logs for identifyingshaley oil sands with reactive minerals. It proposes diagnostic tests toidentify the extent and type of damage in a producing well. Finally, itdiscusses several potential methods for formation damage remediation andprevention. Introduction Cold Lake reservoir in northeastern Alberta has a vast resource base of oilsands. The bitumen in the oil sands has a viscosity of about 100,000 cp atreservoir temperature. Imperial Oil Resources Limited is using the Cyclic Steam Stimulation (CSS) process to recover the bitumen. The wells are drilleddirectionally from one surface location and there are twenty wells in one pad. In one cycle, steam is injected over a period of 30 to 40 days, and a hotbitumen and water mixture is produced over several months. Each well goesthrough several cycles of injection and production until steam injectionbecomes uneconomic.

Adsorption of Foam-forming Surfactants In Berea Sandstone

Abstract Adsorption measurements carried out with representatives of four classes of surfactant suitable for foam flooding (alpha olefin sulphonate, internal olefin sulphonate, linear xylene sulphonate, and betaine) on Berea sandstone at different conditions of temperature and salinity are described. Adsorption of (he anionic surfactants from a low salinity brine is low, but increases substantially at moderate salinities. Limited solubility of the anionic surfactant in aqueous media tends to drive these surfactants to the solid/liquid interface and can also lead to increased surfactant loss through precipitation. The betaine is highly soluble, but adsorbs very strongly on sandstone. Adsorption of this surfactant can be reduced by mixing it with an anionic surfactant. Introduction EOR production in North America is dominated heavily by gas or vapor flooding. Out of total of 371 EOR projects, 294 involve injection of steam CO2 or hydrocarbon solvent(1). Became of the low density and viscosity of the injected fluid, gas and vapor flooding processes tend to suffer from poor sweep efficiency. This problem may be alleviated through the use of mobility control foams(2,3). While the mechanism of lamella generation and collapse is crucial to foam performance and propagation, the maximum distance that a foam will travel is dictated by surfactant loses in the reservoir, caused by adsorption at the solid/liquid interface, precipitation, chemical degradation, and partitioning into an immobile oil phase. This paper deals with the last and frequently most important of these mechanisms. Surfactant classes most commonly applied in laboratory studies of EOR-foams and in field applications include alkyl aromatic sulphonates and olefin sulphonates. Since much of the EOR-foam literature deals with steam foams, surfactant selection has often been determined by the requirement of chemical stability at steam flood temperatures. The following ranking has been assigned to several surfactant classe in terms of their thermal stability(4) alkyl aryl sulphonates > olefin sulphonates > petroleum sulphonates > ethoxylated alcohols and ethoxylated sulphates. The surfactants that have been found the most thermally stable are also the most likely to precipitate in the presence of inorganic electrolyte. Surfactant solubility has been found to decrease in the following order(4); ethoxylated alcohols or sulphates > olefin sulphonates > petroleum sulphonates = alkyl aryl sulphonates. A characteristic of the surfactants most commonly described in connection with EOR-foams is thus their limited solubility in brines. The high molecular weight surfactant homologues suitable for steam-foams have very limited solubility in aqueous media and are expected to have a higher affinity for the solid/liquid interface than lower molecular weight homologues. Steam flood temperatures will favour low adsorption levels and increased solubility. During steam flooding, a surfactant encounters salinity and temperature gradients and a knowledge of the dependence of surfactant behavior on both parameters is required. Surfactants suitable for the extreme conditions of salinity and hardness encountered in many Alberta reservoirs have been identified(5). Detailed measurements of the adsorption properties of these surfactants have been previously described(6–8). By contrast, reported adsorption data for surfactant classes commonly used for steam flood applications are rather limited(9–15).

Significance of Foamy-oil Behaviour In Primary Production of Heavy Oils

Abstract This paper examines the effects of in situ formation of a non-aqueous foam on flow of oil-gas mixtures in porous media. A laboratory technique to investigate the role of foamy-oil behaviour in solution gas drive is described and experimental verification of the in situ formation of non-aqueous foams under solution gas drive condition is presented. The experimental results show that the in situ formation of non-aqueous foam retards the formation of a continuous gas phase and dramatically increases the apparent trapped gas saturation. This provides the natural pressure maintenance mechanism and leads to recovery of a much higher fraction of the Original oil in place under solution gas drive. Introduction Several heavy-oil reservoirs in Alberta and Saskatchewan, show "foamy-oil" behaviour in wellhead samples produced under solution gas drive. The oil is produced in the form of an oil-continuous foam which has the appearance of chocolate mousse and contains a high volume fraction of gas. This foam can be quite stale and may persist for several hours in open-vessels. The field production data from these reservoirs suggests that the production mechanisms are complex and may be quite different from those encountered in conventional solutions-gas driven reservoirs. Several of these reservoirs show anomalously high production. Both the rate of production and the total recovery under solution Gas drive are much higher than what would be expected from measured oil parameters. History matching primary production For these wells often requires unrealistic adjustment of measured parameters, such as increasing the absolute permeability by an order of magnitude. In a recent publication, Longhead and Satroklaroglu(1) have described the unusual primary production behaviour of Celtic Field reporting that the rate of production in some wells is more than ten times the calculated pseudo-steady state oil flow rate under radial flow conditions. To obtain a satisfactory history match of the primary production behaviour, they had to assume very unusual reservoir properties. These included not only an artificially high absolute permeability but also a trapped gas saturation of 35% and an unusual oil relative permeability curve. These high productivity wells produce from unconsolidated sands, and a large volume of sand is produced with the oil. Generally any attempt to stop sand production results in drastically reduced production. Another part of this puzzle is that several of these wells, which are prolific in primary production, show very poor response to steam stimulation. Several possible causes of this anomalous production behaviour have been suggested and are being investigated. These include formation of worm holes around the well which increase the effective well radius(2). Sand dilation due to removal of substantial volumes of sand with the oil, resulting in increased absolute permeability appears to be another mechanism(1). The enhancement of oil mobility by nucleation of a large number of microbubbles has been suggested as another possibility(3, 4). Another possible cause of the anomalous behaviour is the in situ formation of an oil-continuous foam. It is likely that several of these mechanisms might be involved in varying degrees in different reservoirs.

Non-Newtonian Effects On The Primary Production Of Heavy Oil Reservoirs

Abstract A number of heavy oil and oil sand reservoirs in Alberta have been successfully produced by natural depletion at rates far in excess of the predictions based on radial Darcy flow. Production rates can exceed 20 m3/d and con be maintained at such a high level for several years. What exactly causes the high primary production rates is not known, but several mechanisms on the primary production of heavy oil and bitumen have been proposed by various authors. These include solution gas drive, influx of bottomwater, sand production, wormholes, fractures and channels. Laboratory measurements which have been reported on the rheological properties of bitumen indicate that at low temperatures (e.g. 20 °Cj a mixture of bitumen or heavy oil with a small amount of sand behaves as a non-Newtonian fluid. The flow characteristics of a non Newtonian fluid in a reservoir and their effects on the primary production of heavy oil have been investigated in this study using ana/ysica/ solutions of the diffusivity equation. It was found that di/atant (shear thickening) effects can provide an explanation for low apparent viscosities at a distance from the wellbore where shear rates are low. This mechanism is consistent with the pressure buildup test results and with field production data where high production rates can be sustained over an extended period of time. Introduction A number of heavy oil and oil sand reservoirs in Alberta and Saskatchewan have been successfully produced by natural depletion. Primary recovery at the Lloydminster heavy oil deposit, which began over 40 years ago, has been significantly higher than the predictions based on radical Darcy flow. The heavy oil deposits in this area are relatively thin (3 m to 6 m) and occurring at depths from 300 m to 1000 m. The formations consist of unconsolidated sands with a relatively high porosity (29% to 35%) and high permeability (3500 mD). The oil gravity is quite low ranging from 10 to 20 degrees API with an oil viscosity of 400 mPa.s to 2000 mPa.s at initial reservoir conditions. Since 1985, Amoco have been producing significant amounts of bitumen from the Lindbergh Elk Point(1) area on primary production. The Clearwater formation at this location is 25 m to 30 m thick and consists of a moderately well sorted sand. The bitumen has a gravity of about 12 degrees API and a very high viscosity of 60 000 mPa.s at reservoir conditions (3900 kPa and 2O °C). The primary production rates average 15 m3/day 00 20 m3/day for over 3 years. These production rates are greater than can be predicted with radial Darcy flow calculations by a factor of more than 30. Potential Mechanisms It is not known what exactly causes these high primary production rates but a number of potential mechanisms have been suggested. in the literature: solution gas drive; influx of bottomwater; sand production; wormholes, fractures and channels; and rock compressibility. Smith(2) suggested that a possible production mechanism could be solution gas drive which was assisted occasionally by the influx of water.

Cost Analysis Of Current In-Situ Bitumen Production — Optimum Production Strategies And Priority R&D Needs

Abstract The survival and growth of Alberta's bitumen industry during the continuing world oil price uncertainty will, to a large extent, depend on the development of improved technologies and enhanced cost effectiveness. It is first necessary to identify key parameters that impact production costs and to determine their relative cost sensitivities. Research can be focused on these targeted areas and production strategies can be developed which could potentially provide significant cost reductions. This paper describes how energy models developed at the Alberta Research Council are used to identify key areas and to determine their cost sensitivity. Current technologies for in situ extraction of bitumen from Alberta's deposits are reviewed, and the implications of different world oil price scenarios are analyzed. The economic impact of a number of promising operating strategies and processes are presented and analyzed. Introduction Five large bitumen and heavy oil deposits with resource estimated at 400 × 109 m3 of hydrocarbon are located in Alberta(1). Defined by UNITAR(2) as a liquid hydrocarbon with a viscosity greater than 104 mPa •s and an API gravity less than 10 degrees, bitumen found in most of Alberta's reservoirs cannot be produced unless heated. There are various degrees of success of applying thermal recovery methods to Alberta's bitumen deposits — good results are reported in Cold Lake (Esso) and Peace River (Shell), while others are not that encouraging, especially in the Athabasca deposit. Even so, in the past five years, bitumen production increased six fold from less than 3400 m3/D in 1983 to about 20,000 m3/D in 1988. In the early years the production came largely from sizable piloting activity. In 1988, there were six commercial projects and 22 bitumen pilot projects operating in Alberta. Most of these projects were started during the 1983–85 era. Market opportunity, improved fiscal regimes and the high oil price prior to 1986 allowed this aggressive development. Since the precipitous price drop in 1986, the prevailing low oil price has put most new bitumen projects on hold. The bitumen production industry is at a crossroad. Its survival during the continuing world oil price uncertainty will, to a large extent, depend on the development of improved technologies and enhanced cost effectiveness. This paper analyzes the cost of bitumen production and uses a simplified Oil-Steam Ratio (OSR) model to evaluate a number of potential production strategies. A Liquid Fuel Model (ALF01), developed at the Alberta Research Council (ARC) is used to examine how, over the next 40 years, different oil price scenarios and improved technologies would impact on bitumen production. It is used to provide a basis for assessing the potential benefits of R&D in this area. Current In-Situ Commercial Technologies At normal reservoir temperature, bitumen is totally immobile. Mobilization of bitumen through the application of heat requires efficient convection and conduction of hot fluid into the formation. This involves a good distribution of heating sources and an increase of contact areas between the injected hot fluids and the reservoir.

Seismic Velocities In Carbonate Rocks

Abstract Seismic velocities were measured in the laboratory vs pressure, temperature, and saturation on over 80 cores from various carbonate reservoirs in Alberta, using an ultrasonic pulse transmission method. Porosity, permeability, electrical properties, and capillary pressure were also measured in order to characterize the pore systems. All the measured data and other information are compiled into a database. The results show that both permeabilities and seismic velocities are related to the porosities of the cores, although the data are scattered. Liquid saturation (e.g. oil and water) increases the compressional velocity but has only nominal effect on the shear velocity. The magnitude of the increase in compressional velocities with liquid saturation is dependent upon the pore geometry of the rocks, reservoir pressure, as well as the distribution and properties of the saturating fluids. The velocity data are also fit to the time-average equation and the Gassmann equation. The results are usually unsatisfactory, which mean that the time-average equation used in sonic log interpretation is inadequate. For log interpretation, it might be desirable to establish a porosity-velocity relationship specific to carbonate reservoirs, instead of using the time-average equation. Furthermore, the Gassmann equation does not adequately explain the laboratory results. In most of the cores measured, the compressional velocities increase by more than 5% with oil saturation, with a subsequent decrease by over 5% when flooded with a hydrocarbon solvent. This suggests that seismic monitoring of injected gases and hydrocarbon solvent in carbonate reservoirs should be possible. Introduction Seismic properties or rocks are very important to petroleum exploration and production. In seismic exploration, velocity and density contrast between two rock layers causes reflection of seismic waves at the interface. The reflected seismic waves bring out information on the structure of the earth's crust, so that the seismic interpreter can look for potential hydrocarbon traps from the seismic profile. In the process of seismic exploration, a thorough understanding of seismic velocities in rocks plays a vital role in the success of seismic methods. In recent years, seismic methods have found other applications with success in petroleum production assessment, reservoir characterization, and enhanced oil recovery (EOR) and production monitoring. In seismic monitoring applications, the velocity contrast caused by various EOR and production processes is the physical basis of the method. Laboratory results have shown that large velocity decreases are found in heavy oil sands as temperature increases(1–5), in oil-saturated rocks when flooded with carbon dioxide (CO2(6,7) and in oil-saturated rocks when flooded with gas and hydrocarbon solvent(8,9). Furthermore, laboratory result also show large differences between the compressional velocities in gas and liquid (e.g. water or oil) saturated rocks(10). These results open the door for using seismic methods to monitor EOR and production processes. In the literature, most of the seismic velocity data were measured in sandstones and sand. Little has been published on seismic properties of carbonate rocks. Rafavich er al.(11) measured 93 Mission Canyon formation carbonate cores from four wells in the Williston basin field, North Dakota, which appears to be the only systematic study of seismic velocities in carbonates.

Effect of net confining pressure on formation damage in unconsolidated heavy oil reservoirs

It has long been recognized that authigenic clay minerals of various kinds are present within the pore system of most hydrocarbon reservoirs. These clay minerals and other fines may be mobilized during field operations causing permeability reduction. In secondary and tertiary recovery, if the injectivity and productivity of wells are impaired as a result of permeability damage, sweep efficiencies and recovery factors will be adversely affected. The repair of formation damage is usually expensive and difficult; hence, the basic approach should be to prevent damage. To achieve this goal, how formation damage is affected by various system parameters should be known. One of the factors which effects fines migration is the overburden pressure. This is particularly true in the case of unconsolidated formations. However, the authors found no reported investigation of the effect of net confining pressure on fines migration in the literature. This paper presents the results of fines migration experiments carried out in unconsolidated cores from various heavy oil reservoirs in Alberta. The results show that the net confining pressure has a significant effect on fines migration. In particular, it has been found that the critical velocity, at which fines start to be dispersed and permeability starts to decline, decreases with increasing net confining pressure. The reasons behind this phenomenon together with implications for oil field operations are discussed and recommendations are made to prevent this type of damage.

Waterflooding Oil Reservoirs With Bottom Water

Abstract This research addresses the problem of waterflooding a medium gravity oil-bearing formation with a water leg, and offers recommendations/ or process selection. Many oil reservoirs in Alberta and Saskatchewan have some type of a high water saturation zone below the oil layer. The presence of a bottom-water zone results in very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil recovery technique for reservoirs with a bottom-water zone. The performance in such reservoirs can be improved greatly if an effective method of partially plugging the bottom-water zone can be developed. A possible means of accomplishing this would be to precede the waterflood with a slug of a mobility control agent. Recently(1) this possibility was investigated using a large flow model, for a series of mobility control agents, such as polymer, emulsion, air, biopolymer, and foam. The present study complements that investigation for a wider range of mobility control agent slug sizes, oil-to-water zone permeability and thickness ratios, etc. Also presented is a qualitative comparison of various mobility control agents to show their relative merits. The flow stability and displacement pattern are discussed jar each mobility control agent. It is shown that the choice of one agent over others depends on variables such as permeability contrast, relative oil-water layer thickness, etc. Introduction The problem of controlling mobility of water or gas has received attention for more than two decades(2–9). However, very few studies report a systematic comparative evaluation of various mobility control agents. In fact, some of these techniques have not been specifically tested for bottom-water cases. Only recently, slam and Farouq Ali(1) reported a systematic study of various mobility control agents available for improving oil recovery from a reservoir with a bottom-water zone. The present study complements the authors' previous study and gives new interpretation to various mechanisms involved in the process. Experimental Set-up and Procedure The experimental apparatus for the displacement tests consisted of a pump and an especially designed rectangular core holder. A constant rate, computer-controlled, positive displacement syringe pump was used along with floating pistons. The rectangular core holder had one inlet and one outlet at the inlet/outlet faces. Figure 1 shows a schematic of the experimental set-up. The core holder had a cover plate along the bottom side. This enabled one to pack several layers along the length. The chemicals used for different runs are listed in Table 1. Further details f the experimental procedure are available in References 1 and 10. Experimental Results and Discussion Displacement tests were carried out with water and different mobility control agents, viz. polymer, emulsion, air, foam, glycerine, etc. A total of 21 different runs were conducted to test the effectiveness of each of the mobility control agents with permeability, relative thickness and slug size as variables. These runs will be discussed under different sections according to the mobility control agent used. Table 2 lists major characteristics of different runs. FIGURE 1. Schematic of the experimental set-up. FIGURE 1. Available In Full Paper TABLE 1. Properties of chemicals used. Table 1 Available In Full Paper.

Verification Of Scaling Approaches For Steam Injection Experiments

Abstract Three sets of new scaling criteria for high-pressure steam injection experiments were derived and tested in a unique series of experiments. Unlike previous scaling criteria for steam injection, which require the use of porous media and pressure conditions different from the field, the present criteria permit the use of reservoir rock, fluids, and pressure conditions. Two of the new approaches relax some of the geometric scaling groups in order to satisfy other scaling requirements. To examine the suitability of these three new scaling approaches as well as a widely used approach from the literature. Results from a large model were compared with those of smaller models scaled by the appropriate scaling approach. The scaled models, representing one-eighth of a jive-spot pattern, were designed to simulate steam flooding of a prototype reservoir in Alberta. This series of experiments examined the scaling of the mechanisms for heat transfer and steam zone development by injecting steam into a completely water-saturated reservoir. Verygood predictions of energy distribution, temperature distribution, production rate, steam zone volume, produced steam quality, nd steam breakthrough were achieved for two of the scaling approaches. The ability of each approach to scale from one physical size to another is illustrated and the relative merits and potential applications of the approaches are discussed, leading to useful guidelines for the design of steam injection experiments. Introduction Steamflooding is a proven method of enhanced oil recovery. Many laboratory studies have been conducted in an effort to improve this process. Some of the experiments study the various mechanisms of a process and extend the results to make field predictions by using numerical simulators. Other experiments, referred to as scaled experiments, permit direct interpretationof the results to predict field performance. Scaled model experiments can be used to predict the effect of various parameters On the production response of a reservoir undergoing steam injection. The parameters include injection rate, production pressure, slug size, completion interval, bottom water, reservoir heterogeneities, and steam quality. Scaled models are also used to calibrate numerical models as the relative influence of many of the mechanisms is similar to that expected in the field. It is difficult to satisfy all of the criteria required to design scaled experiments of stearn flooding processes. Consequently, some of the scaling requirements must be relaxed. The choice of which requirements to relax will depend on the particular process being modelled. Scaling of the phenomena considered to be least important to a particular process might be relaxed without significantly affecting the major features of the process. The objectives of this work were to develop and verify suitable scaling techniques for steam injection experiments and identify the conditions under which a particular scaling approach is most suitable to a particular recovery process (e.g. steam additives, thin reservoirs, gas caps, bottom water, etc.). Scaling Approaches A number of scaling approaches have been used in the past for steam injection experiments. Stegemeier, Volek, and Laumbach(1) developed an approach which operates at sub-atmospheric pressures and uses fluids which are different from those found in the field.

Enhanced Oil Recovery In Canada: Success In Progress

Abstract The oil industry in Canada has been in the forefront applying enhanced oil recovery technology. Fifty-one commercial projects were operating in 1987 in reservoirs producing light and medium** crude oil in Alberta. Several pilot projects are operating in Alberta. Saskatchewan and Ontario. This paper discusses enhanced oil recovery (EOR) in general and reviews the history of EOR application in Canadian reservoirs. The performance of several projects and the economic factors affecting EOR implementation are reviewed. Introduction Primary and secondary methods leave a substantial portion of oil unrecovered in the reservoir. Tertiary recovery, more often called enhanced oil recovery (EOR), can recover some of the oil left behind by secondary recovery methods. Field application of enhanced recovery in Canada dates from the North Pembina Cardium Unit hydrocarbon miscible pilot project in 1957–58. Fifty-one commercial projects are now operating, all of them hydrocarbon miscible floods in the Province of Alberta. Other EOR techniques are being or have been used in pilot tests, so far with limited or uncertain results. Is EOR successful? The performance and proliferation of projects affirms that additional oil is being recovered and that this additional oil recovery is economic. Oil Recovery Factors Affecting Oil Recovery Large volumes of oil will remain unrecovered after primary recovery, which uses the natural energy of the reservoir, fluid and rock expansion and water influx, to produce the oil. Recovery factors for primary recovery range from 0% to 50% of the oil originally in-place in the reservoir, averaging about 19%(1) for Alberta reservoirs. In some reservoirs, a portion of the oil not recoverable using primary recovery can be produced with secondary recovery methods, which involve adding energy to the reservoir to maintain the pressure by injecting a fluid, usually water or gas. Water injection is the most common secondary recovery method used to enhance oil recovery. Waterflood recovery factors range from 25% to 45% of the original oil-in-place (OOIP). For the waterfloods in Alberta, the average ultimate recovery factor is 32%(1). Approximately 20% of the total Alberta light and medium reserves will be recovered because of waterflooding. Water injection leaves oil in the reservoir as a residual saturation, trapped by capillary forces where the water has swept the reservoir, and at higher saturations where the injected water did not contact the oil. Waterflood displacement efficiency, or the portion of the original oil saturation that can be recovered from rock that is flooded by injected water, ranges from 40% to 70%. However, not all of the reservoir will be contacted by injected water. The water may be more mobile (less viscous) than the displaced oil, causing early water breakthrough and poor areal sweep. The water may be more dense than the oil and may tend to move to the bottom of the reservoir, reducing the vertical sweep. The combination of areal and vertical sweep efficiency is the volumetric sweep efficiency, which is the portion of the total reservoir volume that is contacted by injected water and which ranges from 20% to 90%.

Mobility Control In Waterflooding Oil Reservoirs With A Bottom-Water Zone

Abstract Many oil reservoirs in Alberta and Saskatchewan have a bottom-water zone which leads to very poor areal and vertical sweeps under a water flood. Performance in such reservoirs could be improved greatly if an effective method of partially plugging the bottom-water zone can be implemented. A possible means of accomplishing this would be to precede the water flood with a slug of a mobility control agent. This possibility was investigated in this study using a laboratory flow model, for a series of mobility control agents. In an effort to screen a variety of techniques to water flood an oil reservoir with bottom water, polymer, emulsion, biopolymer, and foam were used as mobility control agents in various slug sizes. Core flood experiments were conducted to study the effect of permeability contrast, relative oil-water layer thickness, oil viscosity, injection rate, slug size and the use of an artificial barrier. Oil of viscosities ranging from 1 to 200 mPa •s were used in 42 displacement tests. A qualitative comparison is made to show the relative merits of different mobility control agents. It is shown that when all the mobility control agents used have a favorable impact on tile water-flood performance, the choice of one over another would depend largely on variables such as permeability contrast, relative layer thickness, oil viscosity, injection interval, etc. Moreover, it is noted that only in certain situations it is better to inject the mobility control agent directly into the bottom-water zone. With polymer, emulsion and foam as mobility control agents, the worse the conventional water flood performance is, the more effective the mobility control agents are. For instance, when the bottom-water zone was as thick and permeable as the oil zone, only about 5% of the oil-in-place was recovered by a water-flood, whereas with polymer, emulsion or foam as mobility control agent, more than 60% of the oil-in-place may be recovered. The effect of slug size is investigated for all mobility control agents, and an optimum slug size is discussed. Introduction Many reservoirs in Alberta and Saskatchewan contain some type of high water saturation zone underlying the oil reservoir. Such reservoirs show rather poor performance under a conventional Water-flood. However, the medium to light gravity of the reservoir oil and the plant facilities dictate that water-flooding is the best suitable technique for these reservoirs. Therefore, there is a need to develop a technique that would improve the performance of a water-flood in such reservoirs. This problem has received attention for more than two decades and several techniques have been proposed in the literature(1–7) to control the mobility of water or gas. However, none of the previous studies reports a systematic study of all these mobility control agents applied to a reservoir with a bottom-water zone. Besides, some of these techniques have not been tested specifically for bottom water. This paper reports a systematic study of all the mobility control agents available in improving oil recovery from a reservoir with a bottom-water zone and discusses the relative merit of each of these under various reservoir characteristics and operating conditions.

Discussion Of Analytical Miscible Relative Permeability Curves And Their Usage With Compositional And Pseudo-Miscible Simulators

Abstract M. S. Jankovic (July-August 1986, JCPT, pages 55–65) is to be complimented for providing us with simple, analytical expressions for the solvent and oil miscible relative permeabilities and the relative permeability ratio. It should be emphasized that these equations are applicable to two-phase miscible flow only. There are times and situations when even in a miscible flood this condition may not prevail and hence these equations may not apply well. Consider the multiple contact miscible, enriched gas injection process: Around injection wells, miscibility often does not exist for a certain distance because there has not yet been sufficient contact and mass transfer between the injected solvent and the reservoir oil to have developed the miscibility. Within some distance around production wells on the other hand, miscibility may be lost depending on the pressure drawdown. The relative permeabilities of these immiscible, multiphase flow regions often control such things as injectivity, gas / oil and solvent / oil production rates, albeit the flood may be miscible in the bulk of the reservoir. I note that the solvent-oil relative permeability ratios given in Figure 8 by the author to describe the multiple contact rich gas drive process of Metcalfe et al.(1) are slightly different from those given in the original paper. There are differences between the two sets around a solvent saturation of 10 per cent for cases 2 and 3. Were the data from the original curves inadvertently truncated or purposely dropped because they did not fit the straight line MRPR relationship proposed by the author? I rather think the latter is the case since in very low solvent saturation zones miscibility may not have existed. Finally, the author states that in Equation (5) the oil saturation So can be replaced by the liquid saturation SL. This is correct if and only if other fluids present, be it gas or liquid, are immobile. In a number of Alberta reservoirs the solvent flood will be allowed to displace previously water flooded zones where water mobility, along with that of the oil and solvent, will occur. Also, in the alternating water / gas process, simultaneous gas/water/solvent mobility may exist. In such situations the use of MRPR may not be all that rigorous.

Recovery of Retrograde Condensate from Naturally Fractured Gas-Condensate Reservoirs

Abstract This paper considers the flow behavior of retrograde condensate in naturally fractured gas-condensate reservoirs and the possibility of recovering part of the condensate by gravity drainage. The analysis is applied to calculate the potential for retrograde condensate recovery in the Waterton reservoir in Alberta. The calculated results are in agreement with field observations: for fracture density, matrix permeability, and reservoir-layer thickness typical of the Waterton reservoir, a small part of the retrograde liquid will accumulate within a practical time span. Condensate accumulation and recovery will significantly increase if the reservoir pressure is restored—e.g., by lean gas or nitrogen injection.

Role of Cementation in Diagenetic History of Devonian Reefs, Western Canada: ABSTRACT

Devonian (Givetian and Frasnian) reef reservoirs in Alberta and British Columbia contain 60% of the conventional recoverable oil and 20% of the recoverable gas in the Western Canada sedimentary basin. Although the depositional history of these reefs is well understood, it is the diagenetic overprint that is often responsible for their reservoir quality. Frasnian (Woodbend and Beaverhill Lake Group) reefs are characterized by stromatoporoid and coral knoll reef belts deposited near moderately sloping bank edges. Bank margin sediments are composed of skeletal lime grainstones, packstones, rudstones, and rare framestones. In contrast, bank interiors are often extensive (e.g., Redwater, Swan Hills) and characterized by cyclic deposition of lagoonal and tidal flat sediments. Certain Givetian reefs found in evaporate basins (e.g., Rainbow or Zama) usually occur as reefs with steep (> 20°) margins and only minor bank interior development. Frasnian reef complexes range in size from 1 km2 (0.4 mi2) to greater than 600 km2 (230 mi2) with thicknesses from 100 to 400 m (330 to 1,300 t). Givetian pinnacle reefs are commonly as much as 300 m (984 ft) thick, but with areal extents of less than 1 km2 (0.4 mi2). Regardless of differences in size, depositional history, and age, most reefs have been subjected to diagenesis in essentially three environments: (1) submarine (marine to hypersaline pore waters), (2) subaerial (fresh to brackish pore waters), and (3) subsurface (below phreatic aquifers, saline to brackish pore waters). Fibrous calcite cements, syndepositional fracturing, displacive calcite cements, micrite cements, and bored hardgrounds are typical submarine diagenetic fabrics, particularly at bank margins in Rainbow reefs and certain Leduc reefs (e.g., Golden Spike, Ricinus). Subaerial disconformities are numerous in most reefs, and associated vadose diagenesis produces localized paleosols, microstalactitic and meniscus cements, and abundant solution porosity. Phreatic or shallow bu ial cements usually include clear, equant calcite or dolomite that vary in Fe++ and Mn++ concentrations. Subsurface cementation produces nonferroan calcites and dolomites which are often related to stylolite formation (e.g., Kaybob, West Pembina D-2, Strachan, Ricinus). Other diagenesis occurring during burial includes dolomite and anhydrite replacement, sulfide mineralization (e.g., Pine Point, Presqu'ile barrier reef), and bitumen formation (e.g., Clarke Lake, Rainbow). Primary porosity and permeability are altered by the overlapping processes of cementation and solution (vadose and/or phreatic) that occur early in the diagenetic history. In reef interiors these subaerial processes produce stratified reservoirs with impermeable barriers (cemented beds) to vertical flow (e.g., Golden Spike, Swan Hills, Judy Creek). Submarine cementation is rare in most reefs but can be locally pervasive resulting in occlusion End_Page 565------------------------------ of bank margin and fore-reef porosity. Absence of significant subsurface cementation in many reefs (e.g., Redwater, Golden Spike) aids in preservation of the reservoirs formed during earlier diagenesis. In summary, it is the early diagenetic history in many Devonian reefs in the Western Canada basin that is responsible for reservoir distribution and quality. Likewise, the knowledge that reef margins and interiors often have different cementation histories is important in both reef exploration and reservoir management. End_of_Article - Last_Page 566------------

Physical Model Study of Inverted Seven-spot Steamfloods In a Pool Containing Conventional Heavy Oil

Abstract A triangular model was fabricated, containing an injection and a production well and representing one twelfth of an inverted seven-spotflood pattern, and several parameters significant to oil recovery by steam-flooding were scaled in the model size. The model was designed to simulate steam-flooding of a prototype reservoir in Alberta in which conventional heavy oil is underlain by bottom water at several places. In this physical model study, the roles of different operating variables and production strategies are examined/or regions without bottom water. The operation of the physical model provided certain insights into the, mechanism of the steam displacement process which might not otherwise have been possible. It was seen that although the temperature profiles for the steam zone grow more or less radially, the hot condensate zone ahead of the steam zone exhibits severe fingering and channelling, which results in early water breakthrough. The steam zone does not exhibit fingering. The water-oil ratio thus rises steeply in the early periods of the steamflood and then stabilizes and grows very gradually. The steam displacement is characterized by severe gravity override and under running of hot condensate fluid. The additional recovery of oil by steam flooding over water flooding is largely due to a better sweep. Of various production strategies examined with the physical model, pressure cycling' gave maximum advantage in the recovery of heavy oils. Finally, water flooding following the termination of steam injection was found to recover as much as 5 per cent additional oil from the model. Introduction Recovery of Lloydminster-type heavy oils of Alberta has been suggested as a short-range solution for meeting the growing demand for crude oil in Canada. Steam drive is one of the promising methods of achieving this objective. For this study, an oil pool in the eastern part of Alberta was chosen as the prototype. The pool has conventional heavy oil underlain by bottom water at several places. This work deals with the role of different operating variables and strategies in oil recovery from the regions in the prototype where the bottom water is absent. The objectives of this model study were to obtain insights into the manner of steam propagation, and to examine the role of flooding and steam quality. Based on a variety of considerations it was decided to use a physical model to fulfill the above objectives. The considerations leading to the choice of the particular physical model system are described below. Modelling Models (both numerical and physical) are aids to improved conceptual understanding of one or more physical processes. If various phenomena associated with a given process are adequately understood, so much so that one could write equations and assign numerical values to individual parameters, it would be prudent to work with numerical models alone, as they are much faster. One could then apply the results directly to the field. However, if certain phenomena of importance are not properly understood, physical models may help to improve the understanding of relevant facets of the process.

Use of Pressure, Pressure-Squared Or Pseudo-Pressure In the Analysis of Transient Pressure Drawdown Data From Gas Wells

Abstract In the analysis of transient pressure drawdown data, it is possible to Plot the data in terms of pressure, pressure-squared or pseudo-pressure. Equation Available In Full Paper In this paper, we compare these three approaches and provide some guidelines for the use of each. The use of pseudo-pressure is found to be the only reliable method when large drawdowns exist. We find that any of the three approaches is adequate when drawdowns are small. However, the pressure-squared approach is found to be better than the pressure approach in most wells where these two are different. Our conclusions are based on the comparison of analytical solutions with numerical solutions for several typical gas reservoirs in Alberta. Introduction In the reservoir engineering literature, the flow of gas is variously analyzed by using one of three variables - namely, the pressure, the pressure-squared or the pseudo-pressure. There is no clear evidence concerning the conditions of flow under which the use of some of these variables is admissible. Rawlins and Shellhardt (1935) found empirically that stabilized gas flow could be described in terms of pressure-squared by the well-known deliverability equation Equation (1) Available In Full Paper. Aronofsky and Jenkins (1954) showed that Darcy flow of an ideal gas in the reservoir could be represented by the diffusivity equation expressed in terms of pressure-squared (instead of pressure, as in the case of oil flow), Matthews and Russell (1967), in their discussion of pressure buildup and analysis, suggested that using the pressure-squared was unnecessary and that satisfactory results were being obtained by simply using the pressure as the variable in the diffusivity equation. AI-Hussainy and Ramey (1966) proposed yet a third variable, originally termed the "real gas potential", but later referred to as the "real gas pseudo-pressure." We refer to this simply as the "pseudo-pressure." There are then three well-known approaches for the plotting and analysis of well data: pressure, pressure-squared and pseudo-pressure. To complicate matters, some pressure data may be analyzed by using any one of these three variables, and give the same answer. Other data will give a different answer for each of the variables. Moreover, deliverability tests on gas wells are usually analyzed using the pressure-squared, whereas drill-stem tests or buildup tests are often analyzed using the pressure. This gives rise to the question of consistency of results. Further complication and confusion results because some of the parameters that must be constant for the application of the analytical solution are actually dependent on pressure. What pressure should these variable parameters be evaluated at? A clear answer to this question is also not available in the literature. The purpose of this publication is to clarify the relationship between the three systems of analysis, and to indicate clearly when they are consistent with each other and when they are not. We will also consider the question: At what constant (or average) conditions should the variable parameters be evaluated? This study is restricted to constant-rate production from infinite-acting reservoirs.

Prediction of Molecular Diffusion At Reservoir Conditions. Part 1- Measurement And Prediction of Binary Dense Gas Diffusion Coefficients

Abstract Diffusion coefficients in binary dense, fluid systems are measured and used along with data available in the literature to obtain a generalised correlation for predicting binary molecular diffusion coefficients in dense gases over a broad range of conditions. Introduction Attempts to quantify mixing phenomena in porous media are often encountered in design studies of processes related to petroleum recovery. Dispersion, an important part of mixing phenomena, can be related to the distribution in travel times that results when a fluid passes through a porous media(1). On a microscopic scale, the two most important mechanisms contributing to dispersion are variations in velocity between fluid elements flowing in neighbouring pores or groups of pores (often referred to as convective mixing) and molecular diffusion(1, 2, 3). Although there is some controversy over the magnitude of convective effects, it has been thought that in vertical gravity stabilized miscible floods, such as those carried out in the carbonate pinnacle reefs of Alberta, molecular diffusion played an important role in the mixing of the solvent bank with drive gas and oil(3, 4, 5). In other processes, such as gas, solvent or CO2 horizontal miscible floods, the effects of molecular diffusion are difficult to quantify, but are thought to be important in the recovery of non-flowing oil by mass transfer(6, 7, 8). The estimation of molecular diffusion coefficients in low-pressure gases using the Chapman Enskog Theory(11) is adequate for a wide variety of single component and binary gases(10, 12), In liquids, the success of theoretical models has been more limited, perhaps because of the complex nature of molecular interactions in the liquid state, Nevertheless, except in the critical region, liquid diffusion coefficients can at present be predicted by empirical correlations with sufficient accuracy for many engineering purposes(9, 13, 14). In the critical or dense fluid state, there are few experimental studies of diffusion coefficients in binary mixtures. This has made it difficult to assess predictive techniques, which have so far been tested largely on the basis of self-diffusion data and are generally considered unreliable(9, 10). The present two-part paper describes Petroleum Recovery Institute work that was directed toward developing improved predictive methods for molecular diffusion coefficients in the high-pressure dense gas state which is commonly encountered under reservoir conditions. The first part presents previously unobtained data on binary diffusion coefficients for fluids in the dense gas state, and a general correlation for binary molecular diffusion coefficients at conditions ranging from ambient to those likely to exist in Alberta reservoirs. The second part presents a method for using the binary con-elation to estimate diffusion in multicomponent systems and shows how the effects of convection and diffusion can be combined to calculate concentration profiles for fluid mixtures flowing in porous media.

Quantitative Geologic Aspects of Cretaceous and Jurassic Oil and Gas Pools in Alberta

ABSTRACT Statistical analyses of size, orientation, and pressure measurements on Cretaceous and Jurassic oil and gas pools in Albeta reveal general predictable trends and some significant anomalies. The total oil and gas in place, and the plan areas of pools, appear to be lognormally distributed although this cannot be proved statistically. For major reservoirs showing a well-defined lognormal size-frequency distribution, the probability of future economic exploration success in that unit can be evaluated from the general trend. Notable deviations from the lognormal distribution pattern occur for Viking oil pools and Wabiskaw (Glauconitic) gas pools. The presence of two populations of pools (one of large pools and one of small pools) can explain the anomalous size-frequency distribution. The large, and therefore more profitable, oil pools in the Viking Formation occur in the Main Viking sand in areas of favourable hydrodynamics. For the gas pools in the Wabiskaw, a factor analysis indicates a relationship between the size of the pool and a combination of porosity and elevation of the reservoir. A map of factor loadings defines an area on the southwestern edge of the basin in which the large Wabiskaw pools are more likely to be found. For oil occurrences in Viking, Cardium, and Belly River reservoirs, the size of the pool can be predicted reliably from its plan area. Consequently, for these reservoirs the reserves potential of an exploration target can be estimated from the untested area. Gas reserves are generally less predictable from plan area. Diagrams showing the orientation of oil and gas accumulations in major reservoirs have both analytical and predictive applications. The orientations are caused by the original depositional conditions, and by later structural and hydrodynamic effects, and are used to identify the controlling features. A quantitative knowledge of the orientation directions of oil or gas pools in a particular reservoir will influence the extension of a new oil or gas discovery in that reservoir. Plots of pressure against depth for oil and gas pools reveal that the interconnected reservoir systems such as Gething Formation and Ellerslie (Basal Quartz) Member have well-defined pressure gradients close to hydrostatic. Groupings of pools on the Ellerslie Member plots, when mapped, define a western limit for the occurrence of oil in the Ellerslie. Maps showing the areal occurrence of oil and gas in Cretaceous and Jurassic reservoirs in Alberta delineate hydrocarbon-rich belts trending NW-SE. Some well-explored areas of the province have very small quantities of oil and gas discovered, apparently for lack of suitable reservoir units.

A Laboratory Investigation of the Enriched Gas Displacement Process In Vertical Models

Abstract The object of this study was to understand the enriched gas displacement process that is being applied in several kigh-relief carbonate reservoirs in Alberta. There is not yet sufficient field production history to determine the mechanisms affecting their performance. Therefore it is necessary to use laboratory data to show how the process works and the manner in which the various mixing zones develop and grow. Two programs were developed to study this phenomenon. The first was to define the behaviour of a simple three-component fluid system. The other was to use a multicomponent system in actual reservoir carbonate rocks performing the displacements at field pressure, temperature and rates. These experiments indicate that the solvent is not directly miscible with the oil but rather acts to change the composition of the oil. This change iscaused by the solvent contacting the oil and coming into thermodynamic equilibrium with it, forming two phases (liquid and gas). The velocity of the gas phase is greater than the liquid phase; hence, it moves ahead contacting new oil and coming into equilibrium with it. This exchange takes place until the gas at the front is in equilibrium with the original oil. These experiments showed that three zones develop. First there will be a zone having the composition of the original reservoir oil. The secondwill be a two-phase zone. This will be followed by a zone in which only a gaseous phase is flowing. The utility of these experiments is only to explain the displacement mechanism. The sizing of the solvent bank and recovery prediction must be made by numerical simulation. INTRODUCTION MISCIBLE FLOODING of a petroleum reservoir is defined as a displacement process which- has zero interfacial tension between the displaced and displacing fluids. There are two types of miscibility.Direct miscibility, where the two fluids form a single phase on first contact with each other.Conditional miscibility, where the fluids are not miscible on first contact but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchange of components, the system becomesmiscible. In summary, there are three general types of miscible displacements in active field use: LPG solvent, which is directly miscible with the reservoir oil; high-pressure gas, which is conditionally miscible with the reservoir oil; and enriched gas, which is conditionally miscible with the reservoir oil. Figure 1 is a constant pressure temperature pseudo-ternary diagram which is not thermodynamically rigorous but can be used to represent these three processes. The ternary representation is composed of four regions. The size and shape of these areas are determined by the dewpoint and bubble-point curves of the particular fluids being studied. Region A is a single-phase gas area, B contains two phases, C is a single-phase liquid area and region D is a single-phase fluid area.

Lateral Water Encroachment In the Pincher Creek Field

Abstract Unusual water production performance has occurred in a portion of the Pincher Creek Gas Field. This fingering or ‘lateral water encroachment’ from the downdip aquifer has been insufficient to significantly affect pressure performance, but has severely restricted the productivity of some wells and will reduce the recovery of gas in place. Water encroached into one structurally high drilling spacing unit even before the well was drilled and placed on production. The mechanics of this water movement have been confirmed during two reconditioning operations and by the production performance of wells. It has been found that a watered-out well can be made to produce water-free gas by recompleting LOWER in the same continuously porous interval. Relief from water production after reconditioning may be short-lived. The various factors to which water fingering could be attributed have been examined and are discussed. Lithofacies studies indicate two ‘shoals’ which form one continuous gas reservoir. Premature water encroachment at individual wells could be related to interfingering of rock types and lack of vertical permeability. This water encroachment phenomenon could be effective to varying degrees in other deep, fractured reservoirs in Alberta. INTRODUCTION The Pincher Creek Rundle Gas Pool, located in the extreme southwestern corner of Alberta, as shown on Fig.1, was discovered at a depth of 11,700 feet by the drilling of Pincher Creek No.1 in 1947. Subsequent drilling resulted in twenty-four gas wells and three dry holes. Figure 2 is a structure map which shows the locations of the wells. Commencing early in 1957, the pool was cycled at a raw gas rate of 60 MMcf/D for two years to recover sulphur and condensate. In late 1958, gas sales to Trans-Canada commenced. Water production problems have adversely affected the deliverabilities of wells in the northern half of the field, some occurring very early in the blowdown operation. The primary purpose of this paper is to discuss the unusual water production performance and remedial measures. RESERVOIR CHARACTERISTICS Geology The Pincher Creek sour gas – condensate reservoir consists of a fractured thrust block of Rundle strata striking N3 °W and dipping 4 to 8 degrees to the southwest. The areal extent of the pool is determined by the down-dip aquifer on the west and by faults that bound the eastern edge of the structure, as shown schematically on Figure 4. Two wells appear to have encountered separate fault blocks which are in pressure communication with the main reservoir. The productive portion of the Rundle can be subdivided into five zones, the Upper Dense, Upper Porous. Middle Hard, Crystalline and Lower Porous, each differing in lithology, thickness, porosity and permeability. The five zones form a continuously porous reservoir which is normally 550 feet thick when the entire section is above water and not faulted. In general, the lithology of the pay section is one of dolomite above the Crystalline Zone and of variable amounts of limestone and dolomite through the remainder.