This essay has been submitted by a student. This is not an example of the work written by our professional essay writers.
Despite numerous laboratory experiments and computational studied there is not an extensive or critical review of the status of the SAGD process. A literature review was performed to fill in these gaps, by shedding light on deficiencies and limitations of the SAGD process, further development areas and new research topics.
Roger Butler, from Imperial Oil, is credited as the inventor of SAGD. In 1980 he first articulated the idea of integrating the SAGD concept with horizontal well technology, which was then in its infancy to obtain economic feasibility. In 1984 the Alberta Oil Sands technology Research Authority (AOSTRA) currently ARI, initiated the Underground Test Facility. The purpose of this facility is to validate SAGD's physical process, commercial viability and ancillary operations, e.g., drilling horizontal wells. The UTF comprises of two vertical shifts 3.3 m in diameter penetrating 140m of overburden, 20m of oil sands and 15m of limestone. Within the solid limestone formation, a horseshoe-shaped horizontal tunnel 5m wide and 4 m high was excavated. Horizontal wells were drilled upward from the tunnel walls through the limestone sequence then horizontal through the lower pay zone oil the oil sands.
The UTF operation involved multiple phases. The pilot phase in 1987, "Phase A", sought to validate only the physical process of SAGD. The success of the pilot phase led to two succeeding "Phases B and D", both of these phased proved to be successful. During these phases the technology to drill well pairs from surface using conventional drilling-rig technology did not exist. The production success and field experience from the UTF operation were crucial in understanding SAGD field performance and the challenges that would need to be overcome for commercial application. Encouraged by the promising field tests results, more than ten commercial SAGD projects have been operating in Canada, mainly in the Athabasca area in the past two decades.
2.2 The SAGD Process and Mechanics
Viscous bitumen can barely flow under reservoir conditions, therefore the bitumen viscosity must be reduced and then a sufficient drive must be applied to the mobilized bitumen for continuous well production and in-situ recovery. Thermal recovery involving injecting hot fluids such as water and steam into the reservoir has been used for several decades to reduce viscosity and enhance the mobility of the bitumen in place. The force of gravity, which exists universally, can be utilized to drive mobilized bitumen. Cardwell and Parson (1949) presented a strict gravity drainage theory early in 1949. Dykstra (1978) broadened the application of Cardwell and Parsons' previous prediction method and developed it under free-fall gravity drainage. However, Farouq-Ali (1997) considered Doscher as the first to recognize the role of gravity in the steam injection process for the California-type reservoir.
The gravity drainage mechanism had been initially used to produce conventional oil. However, because of low effective permeability, high oil viscosity, and small dip of the formation, most heavy oil and bitumen reservoirs can not apply gravity drainage alone to produce economically. Butler et al. (1981), (2001) initially proposed the concept of steam assisted gravity drainage (SAGD) in late 1978. Beginning in 1979, Butler applied this concept to in-situ thermal processes for heavy oil and bitumen recovery. He and his former colleagues carried out field tests in Imperial Oil's pioneering pilot at Cold Lake in 1980 as mentioned in Chapter 2.1. As Figure X illustrates, the steam is injected through the upper well and the fluids, including the condensed steam and the crude oil or bitumen, are produced from the lower one. The injected steam heats the bitumen and sands in the reservoir, and reduces the viscosity of the bitumen. The condensed steam and bitumen flow towards the horizontal well and are recovered at the surface by artificial lift or gas lift.
Figure 1 Schematic of SAGD Process
It is commonly agreed that a steam chamber is generated and rises upwards steadily during a SAGD operation. When it touches the top of the formation, it spreads towards both sides gradually. The steam chamber's growth is mainly measured and analyzed through the temperature changes at observation wells. The oil production is primarily from the chamber/heated oil interface therefore the steam chamber growth is responsible for oil production. A significant amount of research has been focused on the analysis of steam chamber development and the associated physical process, including counter-current flow at the top of the steam chamber and concurrent flow along the slop of the steam chamber.
2.2.1 Steam Chamber Rise
Although a great deal of attention has been paid to the development and analysis of steam chamber growth and characteristics, the complete picture of the process of steam chamber development is not fully represented because of different processes occurring at the same time; counter-current flow, co-current flow, water imbibitions, emulsification, steam fingering and dimensional movement (lateral and vertical). These processes play a part in the fact that in SAGD lighter fluid (steam) is trying to penetrate by nature to a heavier fluid (heavy oil) above it. Analyzing field data, Iso and Ipek (2005) observed that the steam chamber grew upwards and outwards simultaneously. Recent understanding of the SAGD process, endorses the idea that the steam chamber is not connected to the producer; rather a pool of liquid exists above the production well. This pool provided the advantage of preventing the flow of injected steam into the production well, Gates et al. (2005).
2.2.2 Steam Fingering Theory
Butler (1994) observed from his sand pack laboratory experiment, separate and ragged steam fingers, rather than a flat front at the top of steam chamber during the rise of the chamber. Butler credited the occurrence of these fingers to instability caused by rising lighter steam below heavy oil. Butler (1994), in his steam fingering theory, described the rise of the steam chamber as a dome-shaped structure with steam fingers protruding from its upper surface. Steam flows into these fingers, condenses on their surface, and heats up the oil around the fingers. The heated oil drains downward around the perimeter of the fingers into the steam chamber where it meanders in counter-current flow against the steam. Sasaki et al. (2001) proved images where steam fingering can clearly be seen on their 2-D experimental model. Ito and Ipek (2005) examined the steam fingering phenomenon with the measured field data from UTF Phase A, Phase B, Hangingstone, and Surmount SAGD projects. They expanded Butler's steam fingering theory and concluded that many observations in those field projects are clearly explained by the steam fingering concept.
2.2.3 Co-current and Counter-current Displacement//
Nasr et al. (2000) studied the steam-liquid countercurrent and co-current flows for different permeability values and initial gas saturations with a non-steady state, laboratory steam-front dynamic tracking technique and a CMG STARS numerical model. They performed two-dimensional scaled gravity drainage experiments designed to represent heavy oil/bitumen reservoirs. They made visual observations of the development of the steam chamber during the experiments and compared to numerical model predictions. In their conclusion, Nasr et al. (2000) indicated that the countercurrent steam front propagation rate is not a linear function of permeability, whereas the propagation rate, for a given permeability, is a linear function of time. They also observed that for the same permeability, the countercurrent steam front propagates much slower than the co-current front. By history matching the experimental results using the numerical model, Nasr et al. (2000) determined the steam-water countercurrent and co-current relative permeability curves that show significant difference. They attributed the difference in the countercurrent and co-current relative permeability values to the results of viscous coupling between phases.
Chung and Butler (1987) stated that the production from the in-situ thermal recovery of heavy oils always consists largely of water in oil emulsion. These are much more viscous than the oil itself. They conducted a laboratory study to elucidate geometrical effect of steam injection on the water/oil emulsion of the produced fluid from a SAGD process. They performed their experiment with vertical SAGD where steam is injected at the top of formation and a pair of SAGD wells where injection well was slightly above the vertical well (bottom of formation). They concluded that "much higher water/oil emulsion content was found in the produced fluid when the steam chamber was rising in the experiment with bottom steam injection than with injection at the top". The rate of recovery was higher in the operation with top injection. This is probably due to the fact that an increase in water/oil emulsion ratio increases the fluid viscosity; hence a reduction in oil production is expected. However, they also noticed that when the steam chamber spreads sideways, a two phase stratified flow of steam and heated heavy oil occurs at which steam flows sideways to the interface, and heated heavy oil flows down, below and along the interface which dramatically reduced the water/oil emulsion ratio (Chung and Butler 1987).
They later extended their work to include other factors which may affect water/oil emulsification ratio such as initial connate water (0% and 12.5%), steam quality, and pressure variation (153 kPa - 3.55 MPa) (Chung and Butler, 1989). For initial connate water, they noticed a higher water/oil ratio emulsion when Swi = 0% than Swi = 12.5%. They commented that there are fewer tendencies for water to condense as droplets on the surface of oil when enough amount of connate water is available. As the droplets of water condense on oil, they become "buried" because of the spreading characteristics of oil. It is worth mentioning that Sasaki et al. (2002) observed this process in microscopic visualization experiment. For steam quality effect, they (Chung and Butler 1989) noticed no major difference in injecting steam wet or dry. They argued that this is because the interfacial activity at the steam front and the heating mechanism of the bitumen are the same for both cases. As for pressure variation, they observed no major difference as a result of pressure variation. This also applies to the effect of particle size in the porous matrix where no significant variation was found. Sasaki et al. (2001) visualized water/oil emulsion at the boundary of the steam chamber in a 2D laboratory scaled model. They noticed a Â±25% fluctuation in the ratio after steam breakthrough and chamber rise.
2.2.5 Residual Oil Saturation in Steam Chamber //
Butler (1994a) observed that major oil flow happened on the chamber sideways rather than through it. He explained this observation by two hypotheses; (1) residual oil saturation is too low inside the steam chamber to allow for any oil movement, (2) and due to water condensate between steam and oil, water imbibition and interfacial tension supports the oil allowing it to drain laterally. Walls et al. (2003) studied residual oil saturation in steam chamber using a numerical model. Their work consisted of two main parts; (1) sensitivity tests done on the shapes and the end points of the two phase-relative permeability curves, and (2) krog relative permeability curve adjustment to match theoretically determined residual oil saturation. They concluded that water relative permeability and oil relative permeability in the gas-oil system are the main factors that determine the magnitude and the shape of the oil saturation curve as a function of time. They also concluded that residual oil saturation increases at lower SAGD operating pressures. Many numerical simulation models reported fail to show their application of changes in relative permeability curves due to temperature change.
2.2.6 Heat Transfer and Distribution through Steam Chamber//
Understanding heat transfer through the steam chamber is crucial to analysis and modeling of steam chamber growth and consequently the prediction of oil production and process efficiency. In the original SAGD concept, Butler assumed that heat transfer to cold oil ahead of the steam chamber is by conduction only. Farouq-Ali (1997) criticized such an assumption and argued that the strong condensate flow between steam and oil along the steam chamber slope is expected to result in more dominant convection. His statement was supported by the numerical simulation results presented in Ito and Suzuki (1999)'s paper. In response to that, Edmunds (1999) analyzed the associated change in enthalpy of fluids flowing inside and along the steam chamber. He stated that the liquid water could carry and deposit 18% of the heat of condensation of the same water. Another 4% of the latent heat would be transferred by convection due to oil flow and the remaining 78% would be carried by conduction. Edmunds (1999)'s further evaluation showed that the convection role due to water streamline being almost parallel to isotherms is less than 5%. Therefore, Edmunds (1999) stated that except for the very near vicinity of the liner or anywhere live steam penetrates, heat transfer in the mobile zone is dominated by conduction, not convection.
2.3 Geology and Reservoir//
SAGD applications have been mainly on shallow, unconsolidated sandstone reservoirs with
Not many studies were presented to show the effect of porosity on SAGD performance. By reviewing the analytical models provided, however, one can observe that they all have the cumulative production and daily production proportional to porosity which means that higher porosity would "analytically" promote SAGD performance. This was observed in the analytical study by Llauno et al. (2005) where they reported that accumulation properties (thickness, porosity and oil saturation) have a greater effect on SAGD performance than flow properties (permeability, viscosity, API, and reservoir pressure).
Several studies report that increase in oil production was noticed with an increase in oil pay thickness (Sasaki et al. 2001; Chan et al. 1997; Shin and Polikar 2007; Singhal et al., 1998; Edmunds and Chhina 2001; McCormack 2001). Edmunds and Chhina (2001) stated that zones less than 15 m thick are unlikely to be economic. Most of work done to draw this conclusion is based on the fact that thin reservoirs increase thermal losses hence higher SOR. However, this conclusion is subjected to variable understanding of what is "thick" and what is "thin". Also, the steam chamber growth behaviour -due to other geological parameters- may have an effect on such conclusions. For example, a cupcake steam chamber growth (laterally and sideways) would not see much effects of reservoir thickness, while a hand fan steam chamber growth (laterally then sideways) might take much longer time for the steam chamber to grow and complicated process such as steam fingering, emulsification, and prevailing counter current flow which may result in fluctuation/decrease of oil production.
2.3.3 // Gas Saturation
Nasr et al. (2000) studied the effect of initial methane saturation on the advancement of steam front in an experimental sand packed model. They noticed that the presence of initial methane saturation resulted in a faster movement of preset temperature values ahead of the steam front at a given time as compared to the case where there was no methane present. However, as the steam front entered into the region of methane saturation, the propagation rate declined as the methane mole fraction increased in the gas phase. Canbolat et al. (2002) conducted a series of studies on a 2D visualized model. They found that initial presence of n-butane had a positive effect on the process. They explained this by the reduction of oil viscosity due gas presence. Bharatha et al. (2005) conducted a study on dissolved gas in SAGD by means of theory and simulation. They stated in their conclusion that the effect of dissolved gas on SAGD is to reduce the bitumen production rate. They also showed that operating pressure plays a greater role in reducing the effect of dissolved gas saturation presence.
2.3.4 // Permeability
McLennan et al. (2006) stated that the predicted flow performance of SAGD well pairs is sensitive to the spatial distribution of permeability. After experimental (sand packed core) and numerical model investigations, Nasr et al. (2000) noted that the effect of liquid convection ahead of the steam front can provide a better heating for the 10 Darcy permeability case than for the 5 Darcy case. They also observed that there was evidence that steam temperature inside 5 Darcy sand was lowered by about 3o C than that for 10 Darcy sand for a given steam injection temperature. They argued that this might be a result of higher capillary pressure for the 5 Darcy case. They also reported that the propagation rate of the steam front is not a linear function of permeability.
In a 2-D simulation model investigating SAGD in carbonate reservoir, Das (2007) reported no significant change in production due to matrix permeability at earlier stages and faster decline for low permeability at later stages. He referred this to the possibility of matrix production which occurs primarily by imbibition and thermal expansion. However, by looking at the examination range (10 - 50 mD) it can be seen that the range is too small to study the effect of permeability. Kisman and Yeung (1995), on the other hand, found from a simulation model that decreasing the vertical permeability resulted in a significant decrease in CDOR (calendar day oil rate) and OSR initially. But an increase in both CDOR and OSR was noticed at later stages. It was also shown by Shanqiang and Baker (2006) in a 3D simulation model that decreasing permeability reduced initial oil production but later increased dramatically.
McLennan et al. (2006) presented a permeability modeling procedure. Their methodology consists of two major steps: (1) debiasing and re-scaling the by-facies core horizontal permeability, kH vs. porosity relationships using mini-models (7 working phases), and (2) assigning permeability to the geological grid. They outlined two key features of their methodology as being (1) the integration of missing lower porosities or increased shaliness into measurements from dilated and preferentially sampled core which is also dilated, and (2) the translation of porosity-permeability relationships at the core scale to the SAGD flow simulation scale (McLennan et al. 2006).
Nasr et al. (1996) showed a decrease in OSR due to decrease in permeability through their numerical modeling study. Collins et al. (2002) stated that laboratory tests on specimens of undisturbed oil sands have conclusively proven that absolute permeability increases dramatically with dilation. They also showed that shear dilation of oil sands enhance permeability in SAGD process. Shin and Polikar (2007) found that higher permeability resulted in a higher ultimate recovery as well as lower CSOR. They also observed that fining upward sequence showed better SAGD performance due to lateral steam propagation (cupcake growth). Nasr et al. (1997) reported from 2D sand packed model that for low permeability reservoirs, the steam zone was localized around the injection well. The low permeability reduced the drainage of oil and growth of the gravity cell. Mukherjee et al. (1994) observed that the presence of low permeability zone between the injector and producer may cause water hold up between the wells where water is not well drained.
Butler (2004) studied the effects of reservoir layering. He stated that in layered reservoirs with permeability ratio less than about two, the height average permeability should be used in the Lindrain equation. He then suggested that in the situation described above, steam should be injected in the more permeable area. He also stated that if the more permeable layer is at the bottom then a steam swept zone will tend to undermine the upper layer. If the more permeable layer is at the top and the permeability ratio is greater than two, the penetration of the steam into the lower layer will be delayed and oil will move through the lower region driven by the imposed pressure gradient. Effects on oil rate are not very severe at least until the upper layer is exhausted.
2.3.5 // Viscosity and API
Das (2007) studied the effect of oil viscosity in a 2-D model investigating SAGD in carbonate reservoir. He found that recovery rate and infectivity improved with lower viscous oil. Shanqiand and Baker (2006) studied the effect of API on SAGD performance, clearly increasing API reduced oil production. Singhal et al. (1998) from a screening study outline the effects of viscosity on geometrical and operational parameters. For example, they advise that from viscosities less than 35,000 mPa.s and thickness more than 15 m, using vertical steam injectors staggered around horizontal producers was a feasible recovery strategy. Also, relaxation of subcool constrain under certain circumstances may be feasible. They also advised that, for viscosities above 65000 mPa.s, the use of horizontal injectors and subcool constrain was determined to be critical.
2.3.6 // Wettability
Not so many studies were conducted to study this crucial reservoir property. With high heavy oil reserves in carbonates which are expected to be preferentially oil wet - this feature deserves more research. Das (2007) reported lower oil recovery with oil wet reservoirs and with no capillary pressure data set in a 2D simulation model. However, the role of wettability alteration from water-wet to oil-wet was demonstrated to have a positive impact in thermal recovery around production wellbore region (Isaacs et al. 2001; Yuan et al. 2002).
In their patent document Isaacs et al. (2001) demonstrated that oil-wet sand in the near region of the production well (by treatment with wettability alteration chemicals), when coupled with SAGD, causes an increase in recovery compared to classical SAGD. Following up on that patent, Yuan et al. (2002) conducted a study aimed to study the potential impacts of altering wettability near production well on SAGD using field scale numerical model and to learn about possible key parameters. They concluded that (1) the bigger the region around the production well being oil-wet, the better the oil production was, at least in early stages of the steam chamber, (2) more than near well effect was observed from alternating wettability in a local zone near the production well, (3) SOR was lowered which they referred to constant bottom hole pressure, and (4) it might be beneficial not to keep the oil-wet zone at its wettability status for the entire operation period to reduce the material cost for wettability-changing agent. They, however, noticed water accumulation between the water-wet and oil-wet zone, where they referred this water blockage phenomenon to oil-wet creation zone. This diagnose is very relevant since water flow through the oil wet region will be impeded due to phase lubricant absent which may also be a factor influencing SOR. This water blockage would probably have a negative impact on steam chamber growth and maintenance which may be another region why oil-wet region may be a temporary solution.
These observations lead us to raise few flags on the role of ES-SAGD in oil-wet reservoirs and how would solvent addition - with high temperature effect - would cause wettability alteration and hence affect gravity drainage performance. These observations and thought should crave researchers for further effort to understand the effect of wettability alteration on SAGD and potential performance optimization.
2.3.7 // SAGD Geomechanics
Ito and Suzuki (1996) observed a large amount of oil drains through steam chamber when geomechanical changes occur in the reservoir. They hence flagged the role of geomechanical change of formation during SAGD as very important. Chalaturnyk and Li (2004) presented an insight into the geomechanical effects on SAGD operations. They hypothesized that, in a SAGD process, the combination of pore pressure and temperature effects [resulting from steam injection] creates a complex set of interactions between geomechanics and fluid flow. In their work, they studied, using coupled reservoir simulation, major geomechanical/reservoir factors which include: (1) Initial in situ effective stress state, (2) initial pore pressure, (3) steam injection pressure and temperature, and (4) process geometry variables such as well spacing and wellpair spacing. They stated that it was difficult to be conclusive about specific geomechanical process relative to the multiphase characteristics of SAGD from a work at that stage. However, they provided some observations including enhancement of absolute permeability occurrence in significant zones of shear failure. In a discussion of Chalaturnyk and Li's paper, Ito (2004) referred some observations in SAGD processes to geomechanical effects. Mentioned observations are: (1) steam chambers stop rising or shrinking when injection pressure is reduced, (2) steam chambers resume rising when pressure is increased. Ito emphasizes that it is critical to study geomechanical properties of oil sands to understand the SAGD process.
Collins et al. (2002) modified a geomechanical/reservoir simulated to incorporate the absolute permeability increase resulting from the progressive shear dilation of oil sands. Li and Chalaturnyk (2006) emphasised on shearing process inducing improvement to absolute permeability. This causes an improvement of effective permeability to water and thereby, the water relative permeability increases due to isotropic unloading and shearing process (Li and Chalaturnyk 2006). The movement of fluid ahead of steam chamber was also reported by Birrell (2001), although he did not identify the type of fluid, such geomechanical observations (=water relative permeability increase) suggest that this fluid movement is of hot water. Singhal et al. (1998) state that the application of sand deformation concept [effect of SAGD Geomechanics] to the UTF projects, helped explain the shape and location of the steam chamber, and the strong oil rate performance at the central well AP2 which was mainly due to ceiling drainage of oil through the steam chamber, rather than gravity drainage along its sides. SAGD geomechanical effects were not studied for carbonate reservoirs.
2.3.8 //Effect of Reservoir Heterogeneity
Due to the nature of reservoir geology, heterogeneity always exists in a formation, sometime with significant variations even within the same field. As illustrated in Chapter 1, the limited steam chamber growth observed using 4D and crosswell seismic images at the Christina Lake SAGD project (Zhang et al., 2007) gives a good example demonstrating the importance of reservoir heterogeneity effect on SAGD performance. Another example is UTF Phase A where the observed steam chamber in UTF Phase A was oblate and expanded sideways rather than vertically to the top of the formation. Farouq-Ali (1997) attributed this to small differences in formation characteristics.
Over the past decades, the role of reservoir heterogeneities in the steam chamber development for a SAGD process has been investigated numerically and experimentally. Joshi and Threlkeld (1985) studied reservoirs with shale barriers and compared the effects of various well configuration schemes as well as vertical fractures experimentally. They indicated that vertical fractures perpendicular to a horizontal injector improved oil recovery rate as compared with a horizontal injector/horizontal producer.
Yang and Butler (1992) conducted SAGD experiments with reservoirs of two different types: reservoirs with horizontal layers of different permeabilities and reservoirs with thin shale layers. They observed faster production when a higher permeability layer located above a lower permeability layer than a lower permeability layer located above a higher permeability layer. For the effect of shale, they compared the experimental runs with horizontal barriers of different lengths placed in their two dimensional scaled reservoir model. They found that a short horizontal barrier does not significantly affect the general performance of the SAGD process. The presence of a long barrier decreases the production, but, in some configurations, not as seriously as expected.
Kamath et al. (1993) presented a numerical investigation of SAGD performance in a layered reservoir. They found that the placement of horizontal producer in a high permeability zone significantly improves the rate of recovery at early times. They also compared cases with 5 ft thick continuous shale barriers located above the injector and producer, and their results indicated that the presence of shale significantly lowers the oil recovery and increases SOR. Kisman and Yeung (1995) conducted a sensitivity test on flow barriers (discontinuous carbonate lenses) in their numerical studies of the SAGD process in the Burnt Lake Oil sands lease and reported results consistent with that presented earlier by Yang and Butler (1992) based on laboratory experiments.
Bagci (2004) reported experimental studies of the effect of fractures and well configurations on the SAGD processes. He used a 30 cm Ã- 30 cm Ã- 10 cm rectangularshaped box model equipped with 25 thermocouples and obtained temperature profiles along time that visualize the effect of fractures on the steam chamber growth. His experimental results indicated that vertical fractures improved SAGD. He also observed higher SORs during the early stage in the fractured model than those in the uniform permeability reservoir. Therefore, he stated that the vertical fracture could be used to improve the initial oil production rate. In a later paper, Bagci (2006) reported numerical simulation of his previous experiments. A reasonable agreement was found between the history-matched numerical simulation and the experiment in terms of oil production, steam chamber and temperature profiles.
2.4 Well Construction (horizontal well technology)
Directional-drilling technology evolution has been a key enabling factor in the commercial implementation of SAGD. Two parallel horizontal wells are drilled to vertical depths between 90 and 600 m, with 4 to 7 m of vertical offset and up to 1000 m of horizontal displacement. Due to their shallow vertical depths, some of these wells require slant drilling from the surface. Typically, the production well is drilled first and placed as close as possible to the bottom of the reservoir.
In 1993, the technology to drill parallel horizontal wells was developed. The first SAGD well pair was drilled using magnetic-ranging/- guidance technology, which refers to the measurement of the relative position of one well with respect to another. It determines the distance and orientation from the well being drilled (injector) to the reference well (producer). The determination is based on measuring the magnetic signature from the target/reference well, which may be induced and measured by several methods (Grills 2002).
SAGD wells must be designed to withstand the harsh environment of this process. Integrity and reliability must be balanced with the requirement to minimize capital expenditure. Typical SAGD well designs are shown in X. The intermediate casing is the main barrier for isolating the bottomhole SAGD environment from the surface, while the integrity of the production liner is crucial to avoid sand production. Therefore, the selection of adequate cement for thermal conditions and proper thermal casing design (steel and connection selection) are critical (IRP 3, Enform 2002; Kaiser 2009; and Nowinka and Dall'Acqua 2009).
Well-completion designs can vary between operators and even within projects. The industry is still in an evaluation phase, and different completion configurations are being implemented. However, the general trend is to allow for steam injection or bitumen production at two or more points along the horizontal wellbore. As illustrated in Fig. 2, the typical completion designs are dual parallel, or concentric, strings with tubing and annulus flow paths.
The unconsolidated nature of the sandstones in which most SAGD projects are carried out has led to the requirement of sand control in both wells. Slotted liners are the most widely used sand-control method, with standalone screens a distant second. This preference probably reflects the lower cost of slotted liners, along with research efforts (Bennion et al. 2009; and Kaiser et al. 2002) that have improved their design and performance. However, as more challenging reservoirs are targeted and more operational issues arise, the industry continues to seek other competitive sand-control options.
2.5 Production Operation and Control
The SAGD process takes place in three distinct phases: startup, or circulation; normal SAGD operation; and wind down. The startup is aimed at mobilizing the bitumen close to and between the injector and producer to establish "communication" between the wells. The most widely used method for startup is circulating steam in both wells for as long as 90 days. Normal operation involves injecting steam and producing bitumen to form the steam chamber above the well pairs. This provides access to the maximum amount of resources within the drainage area. This phase lasts as many years as necessary, so that the maximum amount of oil is recovered from the drainage volume. Finally, the wind down consists of a series of operations aimed at reducing the amount of steam injected and using auxiliary operating patterns to maximize recovery.
SAGD operations require monitoring strategies aimed at controlling the downhole process, to avoid operational issues and maximize efficiency and recovery. Producer wells are fitted with multiple temperature-measuring devices along the horizontal wellbore. Thermocouples are the preferred choice because of their reliability and lower cost; however, fiber-optic technology has been field tested widely and implemented as well. Pressure monitoring is also employed in producer wells through bubble tubes, open annulus gauges, or, more recently, fiber optic gauges. Typically, the injector wells have less instrumentation. The main objective of temperature monitoring in the producer well is steam-trap control.
2.5.1 // Steam Trap Control
2.5.2 // Steam Quality
2.5.3 // Length, Spacing and Placement of Horizontal Wells
2.5.4 // HP (high pressure) vs. LP (low pressure) SAGD
2.5.5 // Steam Chamber Monitor and Volume Size Estimation
2.6 Performance and Challenges
Most companies have their own evaluation methods for SAGD performance. However, steam-to oil ratio (SOR) is commonly used as the key performance indicator to benchmark project efficiency. SOR indicates the volume of steam required to produce a certain amount of oil. Although it does not truly reflect energy-use efficiency, it remains a widely used industry metric. The aim is to minimize SOR, where values in the 2.0 to 3.5 range are considered good performance. Currently, the best performing SAGD projects by this criterion are: Devon's Jackfish, Cenovus' Foster Creek and Christina Lake, and Suncor's Firebag projects.
Other performance indicators are bitumen production rates and recovery factors. The industry average bitumen production per well pair is between 400 and 1,000 B/D with ultimate recovery factors higher than 50% (Handfield et al. 2008). The current trend for most commercial projects is to increase the thermal efficiency and bitumen recovery of the process through enhanced techniques or SAGD variations, such as nonparallel-well geometrical configurations, additional wells, solvent injection, steam-distribution optimization, and inflow control. Despite the successful commercial implementation of SAGD technology, the industry still has two major challenges to overcome: dependence on natural gas and environmental impact. Most SAGD projects still rely on natural gas as the energy source for producing steam.
The volatility of natural-gas prices, especially in North America, and the long-term supply uncertainty directly impact the economic performance and overall feasibility of SAGD projects. Finally, SAGD's carbon footprint and water requirements are quite substantial, mainly due to the steam generation process. Cogeneration, brackish-water use, water recycling, and other enhancements are being implemented or considered to minimize the environmental impact of SAGD. However, additional efforts are required because more stringent regulatory requirements are likely forthcoming. Furthermore, SAGD's negative perception by a portion of the general public remains an important driving force to clean up the image of SAGD and guarantee the sustainable development of the technology.