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Collaborating Authors
Butler, R.M.
Abstract The development of the SAGD process has been facilitated by the ability to predict performance from theory. Analytical and numerical methods have given results similar to those obtained in the field and in laboratory-scaled models. It was realized before any field projects were undertaken that horizontal wells would be required and that production rates of hundreds, or even a thousand or more, barrels per day of bitumen production were possible. There was also success in predicting the quantities of steam required. In early analyses, the permeability of the reservoir was assumed constant and non-condensible gas was ignored. The effects of reservoir layering are discussed and it is proposed that, in layered reservoirs, with permeability ratios less than about 2, the height average permeability should be used in the Lindrain equation. Several authors have pointed out that when dissolved gas is included in their numerical simulation models, it tends to accumulate in the steam chamber, particularly towards the top, and inhibit the process by lowering the dew point of the steam. In some cases, this appears to choke the process and severely limit production and recovery. On the other hand, it has been appreciated that the accumulation of gas, and even its intentional addition to the steam, can be desirable because the lowering of the temperature of the steam chamber at the top reduces the heat, and hence the steam, requirement. The SOR is improved. The role of gas is discussed and it is shown that gas can move relatively easily, in small fingers, through the reservoir beyond the steam chamber. This allows the purging of gas from the chamber and also the pressure support of the chamber by gas flowing from the exterior. The intrusion of gas into the region above a rising chamber raises the pressure and tends to push oil downwards"the "Steam and Gas Push." Varying the steam injection rate can control pressure and allow the optimization of the gas content of the chamber. Results from a new computer program, "HOTSTEAM," are discussed. Unlike its predecessor, "HOTWELL," the new program allows the injection rate of the steam to be scheduled and it also provides for the support of the chamber pressure by gas"either from the reservoir or from injection. The program includes a continuing analysis of the production ell hydraulics and predicts the WHP as a function of time for natural lift. Introduction The Steam Assisted Gravity Drainage Process (SAGD) is finding increasing application for the in situ recovery of Canada's tar sand and bitumen deposits. This paper describes new concepts and ideas for the optimization of the process. The SAGD Process In the SAGD process, steam is injected, usually from a horizontal well, into a growing steam chamber. Oil drains, driven by gravity, from the heated region around the chamber to a horizontal production well placed low in the reservoir.
Abstract The development of the SAGD process has been facilitated by the ability to predict performance from theory. Analytical and numerical methods have given results similar to those obtained in the field and in laboratory scaled models. It was realized before any field projects were undertaken that horizontal wells would be required and that production rates of hundreds or even a thousand or more barrels per day of bitumen production were possible. There was also success in predicting the quantities of steam required. In the early analyses non-condensible gas was ignored. Since then several authors have pointed out that when dissolved gas is included in their numerical simulation models it tends to accumulate in the steam chamber, particularly towards the top, and to inhibit the process by lowering the dew point of the steam. In some cases this appears to choke the process and severely limit production and recovery. On the other hand it has been appreciated that the accumulation of gas, and even its intentional addition to the steam, can be desirable because the lowering of the temperature of the steam chamber at the top reduces the heat, and hence the steam, requirement. The SOR is improved. In this paper the role of gas is discussed and it is shown that gas can move relatively easily, in small fingers, through the reservoir beyond the steam chamber. This allows the purging of gas from the chamber and also the pressure support of the chamber by gas flowing from the exterior. The intrusion of gas into the region above a rising chamber raises the pressure and tends to push oil downwards-the "Steam and Gas Push". Varying the steam injection rate can control pressure and allow the optimization of the gas content of the chamber. Results from a new computer program, " HOTSTEAM" will be shown. Unlike its predecessor, " HOTWELL" the new program allows the injection rate of the steam to be scheduled and it also provides for the support of the chamber pressure by gas - either from the reservoir or from injection. The program includes a continuing analysis of the production well hydraulics and predicts the WHP as a function of time for natural lift. Introduction The Steam Assisted Gravity Drainage Process (SAGD) is finding increasing application for the in situ recovery of Canada's tar sand and bitumen deposits. This paper describes new concepts and ideas for the optimization of the process. The SAGD Process In the SAGD process steam is injected, usually from a horizontal well, into a growing steam chamber. Oil drains, driven by gravity, from the heated region around the chamber to a horizontal production well placed low in the reservoir. The main mechanism is darcy flow for the oil drainage and conductive heating of the reservoir surrounding the chamber that reduces the viscosity of the oil and allows flow at practical rates. Production rates from horizontal SAGD well pairs are typically about 100m/d and have been reported as high as 380m/d, Rates of this order are predicted both by analytical equations and also by numerical simulation.
Abstract Most of Canada's trillion barrels of petroleum consists of bitumen, and to a lesser extent, heavy oil. This total may be compared with the total Canadian production of light-medium crude oil to date, which is only 12 billion barrels. Mining is effective for the production of bitumen, but is limited to the minor fraction of the resource that is shallow; also mining involves significant environmental difficulties. The challenges of efficient in situ production are like those for other petroleum production activities:to find and define suitable reservoirs, to create conditions for oil to flow at economic rates, and to drain the reservoir systematically to obtain high recoveries. This paper discusses the following in terms of production rate, recovery, energy requirements and economic factors. Each topic is a step, sometimes a sideways step, in the search for a means to achieve high rates and recovery within the bounds of economic constraints.Cold production using vertical wells and horizontal wells. Stimulation by wellbore heating. Cyclic steaming using conventional wells. Steam Assisted Gravity Drainage (SAGD). Steam and Gas Push (SAGP). Cyclic Steaming with horizontal wells. Vapour Extraction (Vapex). Processes resulting in the displacement of oil by gas to a lower horizontal well show the most promise. The viscosity in the region around the horizontal well should be reduced to allow economic rates without gas coning. In SAGD, injected steam heats the oil and fills the reservoir as it drains, and rates of 79 โ 159 m/d (500 โ 1,000 B/d) can be achieved with bitumen recoveries greater than 50%. Heat savings can be achieved by building a substantial gas concentration within the depleted region (SAGP). In Vapex, viscosity reduction is obtained by dilution with a olatile solvent; this is a promising approach for lower viscosity heavy oils. Another promising approach is cyclic steaming with horizontal wells, combined with gas addition to the steam to maintain drive. Introduction As conventional oil reserves become depleted, interest continues to grow in the improved recovery and utilization of Canadian tar sands and heavy oil. The resources are enormous in magnitude, and there have been great strides in technology. One approach, the mining and upgrading of shallow Athabasca deposits has, with the success of the Suncor and Syncrude projects, already become a major source of Canadian oil. Major expansions to both of these projects, as well as other new tar sand mining projects are underway. While mining overcomes the problem of moving the oil to the surface and of obtaining high recoveries, it requires the handling and disposal of vast amounts of solids and sludge, and it is only economic for the shallowest of deposits. The major part of the Canadian oil sand resource is too deeply buried for mining to be practical. This paper is concerned with the recovery of bitumen and heavy oils by in situ methods, i.e., by means of wells drilled from the surface.
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Celtic Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Primrose Field > Clearwater Formation (0.99)
- (2 more...)
Abstract This paper is a continuation of earlier papers on the development of the SAGP process presented at Annual Technical Meetings of the Petroleum Society. SAGP improves the thermal efficiency of SAGD by adding non-condensible gas to the steam. Significant steam savings are achieved by lowering the average temperature in the reservoir and by reducing heat loss to the overburden. Rising gas fingers increase the pressure towards the top of the reservoir and displace oil downwards even though the temperature is below that of saturated steam. The gas hold-up in the reservoir equals the volume of the produced oil, with allowance for the effects of pressure, temperature, and partial pressure of the steam. The gas in the chamber comes from the combination of added gas, solution gas, and gas generated by chemical reactions, minus gas produced with the oil and the net gas driven to or coming from outside the depleted region by pressure difference. The gas hold-up and gas dissolved were estimated and it was found that, in general, more gas is required for higher pressures. Effects of layered sands on SAGD and SAGP performance are studied experimentally using a physical model. In SAGD, steam spreads below the low-permeability layers and oil cannot drain from above until the steam vapour can penetrate to replace it. In SAGP, gas fingers rise into the low-permeability layers and displace the oil downwards below steam temperature. Mechanisms for the enhancement of oil drainage from the low-permeability layers by gas fingers are discussed together with the experimental results. SAGP continues to show promising results and it is thought that results in the field will be better than in our experiments. Introduction Several papers have been presented on the theoretical and laboratory studies of the Steam and Gas Push (SAGP) process since it was described first in 1997 at the 48th Annual Technical Meeting of the Petroleum Society. The process improves the thermal efficiency for SAGD by adding a small amount of noncondensible gas to the injected steam. Steam condenses and leaves concentrated gas in the upper portion of the vapour chamber. As a result, only the region near the injector and producer, where the gas concentration is low, is heated to the temperature of saturated steam. The upper part of the reservoir remains at a relatively low temperature and the heat loss is low; significant steam is saved. The gas required to achieve the SAGP effect is obtained from gas dissolved in the oil, gas generated by chemical reaction, net reservoir gas flowing into the recovery region, and gas supplied from injection. In heavy oil and bitumen reservoirs, such as those in Athabasca and Cold Lake, the operating pressure for SAGD is usually higher than the initial reservoir pressure and gas injection is required. The required gas hold-up in the vapour chamber is related to the volume of oil produced, with allowances for operating pressures and temperature. To make the injected gas more effective in the chamber, the production of gas should be minimum.
- South America > Venezuela (0.28)
- North America > Canada > Alberta (0.16)
Abstract SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48 and 49 Annual Technical Meetings of the Petroleum Society. Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils. In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments. The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption. Introduction The successful applications of the Steam-Assisted Gravity Drainage (SAGD) process in the fields have provided tremendous opportunities for the development of heavy oil and bitumen resources. SAGD field projects are continuing to be constructed following the successful testing of the process at AOSTRA's Underground Test Facility (UTF) (now Northstar's Dover project). In addition to Canadian projects, this process has also been field tested in other countries. Most recently, the SAGD project in the Tia Juana field in Venezuela is reported to produce average oil rates of 700 bpd per well pair from the first year's operation. Although SAGD is effective in producing bitumen and heavy oils, it requires a large quantity of heat to heat the whole chamber to saturated steam temperature and the heat loss to the overburden is high. The process may become uneconomic in some reservoirs such as those with thin sands, low porosity, low oil saturation, and bottom water zones. To extend the range of reservoirs that can be produced economically with SAGD technology, a new process was developed to reduce the heat loss to the overburden while maintaining high oil drainage rates. The Steam and Gas Push (SAGP) process involves the addition of a small amount of non-condensible gas, such as nitrogen or methane, to the steam. The accumulation of gas in the upper part of the chamber reduces the average temperature in the chamber and the heat loss to the overburden. As a result, the steam requirement is reduced and oil/steam ratio is improved. Both theoretical and physical model studies have been carried out at the University of Calgary with support from participants from industry, since the process was first described. Some mechanisms and model test results were described at the 49 ATM and the 7 UNITAR International Conference on Heavy Crude and Tar Sands.
- South America > Venezuela (0.68)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.26)
Abstract This paper is a continuation of earlier papers on the development of the SAGP process presented at Annual Technical Meetings of the Petroleum Society. SAGP improves the thermal efficiency of SAGD by adding non-condensible gas to the steam. Significant steam savings are achieved by lowering the average temperature in the reservoir and by reducing heat loss to the overburden. Rising gas fingers increase the pressure towards the top of the reservoir and displace oildownwards even though the temperature is below that of saturated steam. The gas hold-up in the reservoir equals the volume of the produced oil, with allowance for the effects of pressure, temperature and partial pressure of the steam. The gas in the chamber comes from the combination ofadded gas, solution gas and gas generated by chemical reactions, minus gas produced with the oil and the net gas driven to or coming from outside the depleted region by pressure difference. The gas hold-up and gas dissolved are estimated and it is found that, in general, more gas is required for higher pressures. Effects of layered sands on SAGD and SAGP performance are studied experimentally using a physical model. In SAGD, steam spreads below low-permeability layers and oil can not drain from the above until the steam vapour can penetrate to replace it. In SAGP, gas fingers rise into low-permeability layers and displace the oil downwards below steam temperature. Mechanisms for the enhancement of oil drainage from the lowpermeability layers by gas fingers are discussed together with the experimental results. SAGP continues to show promising results and it is thought that results in the field will be better than in our experiments. Introduction Several papers have been presented on the theoretical and laboratory studies of the Steam and Gas Push (SAGP) process since it was described first in 1997 at the 48 Annual Technical Meeting of the Petroleum Society of CIM. The process improves the thermal efficiency for SAGD by adding a small amount of noncondensible gas to the injected steam. Steam condenses and leaves concentrated gas in the upper portion of the vapour chamber. As a result, only the region near the injector and producer, where the gas concentration is low, is heated to the temperature of saturated steam. The upper part of the reservoir remains at relatively low temperature and the heat loss is low; significant steam is saved. The gas required to achieve the SAGP effect is obtained from gas dissolved in the oil, gas generated by chemical reaction, net reservoir gas flowing into the recovery region and gas supplied from injection. In heavy oil and bitumen reservoirs such as those in Athabasca and Cold Lake the operating pressure for SAGD is usually higher than the initial reservoir pressure and gas injection is required. The required gas hold-up in the vapor chamber is related to the volume of oil produced, with allowance for operating pressures and temperature. To make the injected gas more effective in the chamber, the production of gas should be minimum.
- North America > Canada (0.30)
- South America > Venezuela (0.28)
Abstract Adequate lifting of produced fluids is an important issue for SAGD producers. It is often necessary to evaluate the natural lift capability of the SAGD process for given producer well designs and modify the design if self-flowing capability of the well is a requirement. This paper describes the methodology for calculating pressure, temperature, and fractional vaporization of water profiles along SAGD producers, leading to the development of a computer program RISEWELL to perform such calculations. Sample calculations using the program and a discussion of control methods for self-flowing SAGD production wells are included. Introduction The analysis of fluid flow in producing wells of the Steam-Assisted Gravity Drainage (SAGD) process is necessary for evaluating the natural lift capability of the process and for well design. The lifting of produced fluids at an adequate rate is of prime importance for the successful operation of the SAGD process. In many SAGD projects, the early performance of the process has been severely limited by inadequate lifting. When this occurs the produced oil tends to be replaced by water rather than gas and steam, and a steam chamber either does not form or is confined to only the upper part of the reservoir. If the steam chamber pressure is sufficiently high in relation to the depth of the reservoir, it may be possible to achieve natural lifting of produced fluids in a SAGD project without the use of a pump. While this mode of operation is very convenient, it is less attractive for very deep reservoirs-the high operating pressure required to produce natural lift would then result in poor oil-steam limiting the viability of SAGD for such reservoirs. Even for more shallower reservoirs, the production well has to be designed so that it is self-flowing. Therefore it is necessary to perform pressure drop calculations to aid in the well design. This paper describes the development of a computer program RISEWELL for the analysis of flow in SAGD producers. In this program, pressures, temperatures, and fractional water vaporization profiles along the well are calculated using momentum and energy balance principles combined with heat transfer equations and experimental correlations for pressure drop in multi-phase pipe flow. Sample calculations are presented to illustrate the use of the program for the design of producers in SAGD projects. Balance of Momentum and Energy The calculations are based on the fundamental principles of balance of momentum and energy for pipe flow. Consider the multi-phase flow of water, oil, and gas through a deviated producer well of constant cross-sectional area (not necessarily circular) as shown in Figure 1. Let's denote the arc length measured along the centre line of the well, increasing along the fluid flow direction. Although the fluid flow in SAGD wells is not strictly steady, owing to slow changes in the temperatures, pressures, and flow rates with time, the assumption of steady flow (particularly, constant mass flow rate in every cross-section at a given time) will be made to simplify the equations.
Abstract The Steam-Assisted Gravity Drainage (SAGD) process, which usually employs horizontal injection and production wells, has been applied successfully in producing heavy oil reservoirs. It allows high recoveries to be obtained, at high rates without significant bypass of steam. However, SAGD process, due to the heat loss to the overburden and adjacent formations, can only be used for thick reservoirs with relatively high porosities and oil saturations if there is to be an economic oil/steam ratio. The Vapex process, which uses light hydrocarbon vapors to extract heavy oil from the reservoir, is studied experimentally in the work described in this paper using a new, longer, scaled, packed model. In the process that evolved from the work, liquid solvent (propane, butane, or mixtures) is injected with a small amount of non-condensible gas through a horizontal well at the top of the reservoir to contact and mobilize oil by dilution. The diluted oil is produced by a horizontal well, laterally separated from the injector, and located at the bottom of the reservoir. With this configuration, practical production rates can be achieved without appreciable gas bypass. Solvent is separated easily from the produced liquid by distillation and recycled and this results in relatively low net solvent requirements. Gas fills the vacated pores. The objective of the experiments was to develop process conditions to give high oil production rates with economic solvent requirements. To achieve this, major parameters affecting the Vapex performance were investigated: temperature, pressure, solvent injection rates, types of solvent, mixed solvents, well spacing and configurations etc. The major finding has been that wider lateral well spacing allow higher production rates and make the process more economic. Experimental results indicate that, under suitable conditions, the net solvent injection is about 0.2 B per B of produced oil and that high recoveries and practical rates are achievable. For example, a field prediction based on the experimental data indicates an average oil production rate of 450 B/D per horizontal well pair, 1,000 m long, drilled in a pressure-depleted, heavy-oil reservoir that is 10 m thick, to give a recovery of over 50% OOIP for a 70 acre pattern. Introduction The concept of Vapex evolves from the Steam-Assisted Gravity Drainage (SAGD) process in which two closely spaced horizontal wells are employed with steam injected from an upper horizontal injector to form a steam chamber in the formation and heated oil drains downwards, driven by gravity, to a horizontal producer located near the base of reservoir. Another form of the process involves the use of multiple vertical injection wells instead of the horizontal injector. In the Vapex process, light hydrocarbon vapors or their mixtures with non-condensible gases are employed instead of steam to extract heavy oil or bitumen from the formation. Compared to thermal processes, the Vapex process can be operated at reservoir temperature with almost no heat loss. Vapex can be used as an alternative to recover the heavy oil and bitumen from reservoirs which are not suitable for thermal processes such as reservoirs with bottom water and/or high water saturation, vertical fractures, low porosity and low thermal conductivity.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48 and 49 Annual Technical meetings of the Petroleum Society. Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils. In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments. The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption. Introduction The successful applications of the Steam-Assisted Gravity Drainage (SAGD) process in the fields have provided tremendous opportunities for the development of heavy oil and bitumen resources. SAGD field projects are continuing to be constructed following the successful testing of the process at the AOSTRA's Underground Test Facility (UTF) (now Northstar's Dover project). In addition to Canadian projects, this process has also been field tested in other countries. Most recently, the SAGD project in the Tia Juana field in Venezuela is reported to produce average oil rates of 700 bpd per well pair from first year's operation. Although SAGD is effective in producing bitumen and heavy oils, it requires large quantity of heat to heat the whole chamber to saturated steam temperature and the heat loss to the overburden is high. The process may become uneconomic in some reservoirs such as those with thin sands, low porosity, low oil saturation and bottom water zones. To extend the range of reservoirs that can be produced economically with SAGD technology, a new process was developed to reduce the heat loss to the overburden while maintaining high oil drainage rates. The Steam and Gas Push (SAGP) process involves the addition of a small amount of non-condensible gas to the steam. The accumulation of gas in the upper part of the chamber reduces the average temperature in the chamber and the heat loss to the overburden. As a result, the steam requirement is reduced and oil/steam ratio is improved. Both theoretical and physical model studies have been carried out at the University of Calgary with support from participants from industry, since the process was described firstly by one of us at the 48 Annual Technical Meeting of the Petroleum Society in 1997.
- South America > Venezuela (0.68)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
Abstract If the problem of fluid flow in a reservoir toward a well cannot beapproximated as a two-dimensional one, the analytical treatment becomes verydifficult. This is especially true when horizontal wells are involved and theend-effect cannot be neglected. There are, in the literature, mathematical expressions to calculateproductivity of horizontal wells for various geometric configurations and manyof these include the effect of flow convergence. Some of them appear to besignificantly in error. The paper describes experiments with an electrolytic model. This approachuses the analogy between the flow of fluid particles, driven by fluidpotential, in a porous medium and movement of ions, driven by electricalpotential, in an electrolyte. A simple and low-cost experimental setup permitsthe testing of various theoretical equations and the results are presented. Introduction In many cases the flow of fluids in a homogeneous reservoir toward a well, vertical or horizontal, can be analyzed simply when the problem istwo-dimensional. In some situations this approach may be sufficient; but when, because of more complicated geometry, the effect of convergence toward the tipof a well (as, for example, in the case of a vertical well partiallypenetrating a liquid- bearing porous matrix layer) has to be taken intoaccount, the difficulties of establishing the flow pattern and, consequently, calculations of the well productivity, may be significant. A common simplification is the assumption of the uniform flux along theactive well length. But this approach, as pointed out by Muskat(l), does notgive the correct results, even for the relatively simple case of a partiallypenetrating vertical well and steady-state flow. The situation becomes more difficult for horizontal wells of finite lengthdraining bounded volumes. There is usually a problem of convergent flow towarda well in a plane perpendicular to the well's axis, but on top of this there isa three-dimensional convergence toward the tips of the well. Probably in somesituations when, for example, the well is very long and draining a thin layerand narrow pattern, this additional convergence can be neglected.
- North America > Canada > Alberta (0.31)
- North America > United States > Texas (0.28)