Oil Drainage Rate Research Articles

Understanding the mobilised oil drainage dynamics inside laboratory-scale and field-scale reservoirs for more accurate THAI process design and operation procedures

The technical and economic validities of the toe-to-heel air injection (THAI) process for heavy oils upgrading and production are yet to be fully realised even though it has been operated at laboratory, pilot, and semi-commercial levels. The findings from Canadian Kerrobert THAI project suggested that there is no proportionality between oil production and air injection rates. However, this conclusion was reached without having to dig deeper into the dynamics of the transport processes inside the reservoir especially that efficient combustion was clearly taking place as the mol% oxygen in the produced gas was negligible. As a result, this study is conducted with aims of identifying the similarities and differences of the dynamics of the transport processes in lab-scale and field-scale reservoirs. For the first time, this study has found oil drainage dynamics inside the reservoir to be both scale-dependent and operation-dependent. For the laboratory-scale numerical model E, what is clearest is that all of the head of the oil flux vectors are either totally vertically directed or slightly inclined and pointing upward towards the heel. None of them is pointing backward towards the toe of the HP well. Thus, it is apparent that oil drainage pattern in this laboratory-scale model E is efficient as all the mobilised upgraded oil, including from the base of the combustion cell, is produced as the combustion front advances in the toe-to-heel manner. However, the combustion front has a backward-leaning shape which is an indicator that it is propagating even inside the HP well. This implies that the process is operating in an unstable, inefficient, and unsafe mode. These two opposing patterns at laboratory-scale must be resolved to ensure healthy combustion front propagation with efficient oil drainage and production rates are achieved. At the field scale (i.e. model F), this study has shown for the first time that there are actually two mobile oil zones: the one ahead of the combustion front with lower oil flux magnitude (i.e. MOZ) and the one containing large pool of mobilised partially upgraded oil at the base of the reservoir just behind the toe of the HP well. The above findings in model F show that there is conflicting dynamics about the goal of achieving large oil production rates downstream of the combustion front with the propagation of forward-tilting stable, safe, and efficient combustion front. If the combustion is to be optimally sustained, then most of the mobilised upgraded oil might be lost going in the wrong direction towards the region behind the toe of the HP well. In actual reservoir in the field, shale with very low permeability and porosity must be present behind the toe in order for the large pool of mobilised upgraded oil that is continuously draining from the vertical adjacent planes to be forced into the toe of the HP well. As a result, to balance these two conflicting dynamics of upward-tilted combustion front going longitudinally towards the heel of the HP well and the mobilised oil draining down at an angle towards the region behind the toe of the HP well, future studies are essentially required. These are proposed and also listed under the conclusion section in order to ensure thorough design and operation procedures for the THAI process are established.

Scaled physical experiments on drainage mechanisms of solvent-expanded SAGD in super-heavy oil reservoirs

In view of high oil viscosity at high temperatures, slow steam chamber expansion rate, low oil rate, and low oil/steam ratio of domestic super heavy oil blocks developed with dual-horizontal well steam assisted gravity drainage (SAGD), the solvent-aided oil viscosity reduction tests were carried out, based on which the analytical equations and similarity laws of solvent-expanded SAGD (ES-SAGD) were deduced. The large 2-D ES-SAGD scaled physical simulation experiments were conducted to compare the SAGD performances of the conventional steam and two formulas of solvent-steam system. The experimental results show that the light hydrocarbon solvents have good viscosity reduction effects to oil, and the oil reduction ratio can reach 96.5% by adding 5% N-hexane at 50 °C. Moreover, adding light hydrocarbon solvent (10% in the experiments) into the steam can bring the oil viscosity reduction effect of solvent and high temperature steam into play, speed up the lateral steam chamber expansion rate, increase the oil drainage rate and enhance the oil recovery degree. Adding 1% of xylene into the steam-solvent system can dissolve the asphalt to reduce asphalt precipitation, reduce the porous flow resistance and further enhance the oil recovery factor. The ES-SAGD recovery by reusing the solvents can realize replacement of the steam with small amount of solvents. Although currently higher in cost, the technology has the advantages of higher oil drainage rate, reduced production period, and enhanced oil recovery. The ES-SAGD theoretical model by modifying the SAGD model based on the oil viscosity reduction characteristics of solvents has been validated by the experiments and can be applied in ES-SAGD production predictions.

An Improved Mathematical Model for Accurate Prediction of the Heavy Oil Production Rate during the SAGD Process

Steam-assisted gravity drainage (SAGD) is one of the most successful thermal enhanced oil recovery (EOR) methods for cold viscose oils. Several analytical and semi-analytical models have been theorized, yet the process needs more studies to be conducted to improve quick production rate predictions. Following the exponential geometry theory developed for finding the oil production rate, an upgraded predictive model is presented in this study. Unlike the exponential model, the current model divides the steam-oil interface into several segments, and then the heat and mass balances are applied to each of the segments. By manipulating the basic equations, the required formulas for estimating the oil drainage rate, location of interface, heat penetration depth of steam ahead of the interface, and the steam required for the operation are obtained theoretically. The output of the proposed theory, afterwards, is validated with experimental data, and then finalized with data from the real SAGD process in phase B of the underground test facility (UTF) project. According to the results, the model with a suitable heat penetration depth correlation can produce fairly accurate outputs, so the idea of using this model in field operations is convincing.

Mechanistic study of steam assisted gravity drainage in heavy oil naturally fractured reservoirs

While SAGD has been applied in tar sands extensively and its mechanism is well understood, the SAGD mechanism in heavy oil Naturally Fractured Reservoir is yet to be investigated. In this paper, the mechanism of SAGD in NFRs was studied. Results suggest that initial fracture water saturation plays a conspicuous role in production from NFRs, with no preheating requirement. This condition facilitates massive water production, leading to a considerable steam injection and consequently fast steam chamber creation. In oil-wet reservoirs, oil drainage takes place inside the steam chamber. In water-wet media, however, capillary imbibition contributes to oil recovery behind the steam chamber in hot water zone. The index Km/Lm was introduced which combines matrix permeability and size to propose a determining factor for matrix oil drainage rate. The controlling term of Kf Sfw/μo for the process initiation was proposed, so that higher values of this term imply sooner chamber creation. [Received: June 23, 2016; Accepted: July 20, 2017]

A comprehensive mathematical model for estimating oil drainage rate in SAGD process considering wellbore/formation coupling effect

The aim of this work is to present a comprehensive mathematical model for estimating oil drainage rate in Steam-assisted gravity drainage (SAGD) process, more importantly, wellbore/formation coupling effect is considered. Firstly, mass and heat transfer in vertical and horizontal wellbores are described briefly. Then, a function of steam chamber height is introduced and the expressions for oil drainage rate in rising and expanding steam chamber stages are derived in detail. Next, a calculation flowchart is provided and an example is given to introduce how to use the proposed method. Finally, after the mathematical model is validated, the effects of wellhead steam injection rate on simulated results are further analyzed. The results indicate that heat injection power per meter reduces gradually along the horizontal wellbore, which affects both steam chamber height and oil drainage rate in the SAGD process. In addition, when production time is the same, the calculated oil drainage rate from the new method is lower than that from Butler’s method. Moreover, the paper shows that when wellhead steam injection rate is low enough, the steam chamber is not formed at the horizontal well’s toe position and enhancing the wellhead steam injection rate can increase the oil drainage rate.

A semi-analytical solution to optimize single-component solvent coinjection with steam during SAGD

Coinjection of a low concentration of solvent with steam has been studied as an alternative to steam-assisted gravity drainage (SAGD). This research presents a semi-analytical method for comparing oil drainage rates of SAGD and coinjection processes using different single-component solvents for a given set of reservoir/operating conditions. The oil recovery in coinjection involves complex interaction of energy and mass balances with the effects of gravity, phase behavior, and multiphase flow. We simplify the complex interaction without loss of fundamental mechanisms, while retaining the phase behavior details near the chamber edge.The new method begins with solution for thermodynamic conditions at the chamber edge, where the phase transition occurs between two and three phases. Three components are considered; oil, solvent, and water. The chamber-edge conditions that are solved for are used to estimate distributions of solvent and temperature beyond the chamber edge. Darcy’s law and material balance are then applied to derive an analytical expression for oil-drainage ratio, the ratio of oil drainage in coinjection to that in SAGD. Since the chamber-edge temperature and composition are interdependent for this ternary phase behavior problem, oil-drainage ratio is solved for as a function of solvent concentration in the oleic (L) phase at the chamber edge (xsLedge).Case studies with the semi-analytical method show that oil-drainage ratio is higher in the higher xsLedge range than in the lower xsLedge range for a given coinjection solvent. This indicates that efficient oil recovery in coinjection requires high accumulation of solvent at the chamber edge. Oil-drainage ratios calculated for different coinjection solvents are compared in the high xsLedge range for preliminary screening of single-component coinjection solvents. This offers significant time savings in selecting a coinjection solvent by reducing the need for numerical reservoir simulation. The semi-analytical method also indicates that highly volatile solvents, which are relatively less expensive in general, tend to be more effective for less viscous reservoir oil and higher operating pressure. Less volatile solvents may offer more flexibility in operating conditions since they remain effective at lower pressures. These results are validated using fine-scale numerical reservoir simulations.

Physics‐based proxy modelling of solvent transport in VAPEX process

VAPEX (vapour extraction) is a non‐thermal process that has significant potential to provide a more environmentally friendly and energy‐efficient alternative to steam injection. While numerical modelling techniques are available for simulating mass transfer in VAPEX process, computational constraints often preclude detailed numerical solution of the flow and transport differential equations, as is often implemented in traditional flow simulators. Efficient alternatives that are based on analytical solutions could be employed to assess the transport physics. In this paper, a novel physical‐based proxy is developed to model solvent transport in VAPEX at isothermal conditions, in a way analogous to the SAGD model described by Butler (Butler, J. Can. Petrol. Technol. 1985, 24, 42). Detailed analytical formulations are derived and implemented in a calculation procedure to advance the solvent–bitumen interface and to estimate producing oil rate with time. In our approach, solvent concentration and intrinsic diffusion coefficient are introduced in the model instead of temperature and thermal diffusivity in SAGD. A new mass penetration parameter is introduced and its change with time is modelled. Growth of solvent chamber and oil drainage rate predicted from the proxy model are in good agreement with Hele‐Shaw experimental data available in the literature. Results predicted by proxy model also match well with scaled‐up flow rates for a field case described by Das and Butler (Das and Butler, J. Can. Petrol. Technol. 1994, 33, 39).

The Effect of Dispersion Processes on Block to Block Oil Gravity Drainage Recovery in Naturally Fractured Reservoirs

This article addresses mathematical modeling of oil gravity drainage with existence block-to-block and dispersion processes, which is believed to occur in naturally fractured reservoirs. Equations are written for oil drainage rates that can handle block-to-block interaction and a boundary condition of the interface between each two blocks. The boundary is written based on convective-dispersion fluxes in the interface between each two blocks with different properties. The results from the developed model show that the oil drainage rate is low during oil production from the stack, and the diffusion process has an important role on the gas dispersion and oil recovery. The gas concentration increases gradually into the stack during production time because of the existence of the block-to-block process.

Capillarity and Drainage Height Effects on the Diffusion/Dispersion Coefficient in the VAPEX Process

This study is conducted to investigate the roles of capillarity and drainage height on mass transfer phenomena during the VAPEX process in heavy oil reservoirs. A comprehensive experimental study was conducted in two 2-D slab models using Plover Lake oil from west-central Saskatchewan and n-butane as the solvent. This study revealed significant effects of drainage height and capillarity on oil drainage rates in contrast to previous studies conducted at unrealistically high permeabilities (i.e., >200 D). A new correlation was developed to predict the effective diffusion/dispersion coefficient from solvent concentration, drainage height, and total pore surface area of the porous media.

Effect of Temperature on VAPEX Performance

Summary Incorporating some heat injection along with solvent injection appears to bethe most viable option for improving the oil-drainage rate of vapour-assistedpetroleum extraction (VAPEX) in extraheavy-oil formations. This study wasintended to quantify the maximum possible increase in VAPEX drainage rate thatcan be obtained by heating the formation to a target temperature. Theexperimental phase of this study involved conducting VAPEX experiments in alarge high-pressure physical model, packed with 250-darcy sand, using propaneas the solvent. The physical model was preheated to 40, 50 and 60°C, andpropane was injected at the same test temperature but different injectionpressures to observe how injection pressure affects oil-drainage rate atelevated temperatures. In the experiments at elevated temperatures, but withoutincreasing the injection pressure, higher rate of oil production was achievedin the early stages of the process. However, a stabilized rate of oilproduction did not show pronounced improvement caused by a lower solubility ofpropane in the oil at higher temperatures. Increasing injection pressure alongwith increasing the test temperatures was successful in accelerating the oilproduction. The oil used in these experiments was found to become mobile withthe increase in temperature even without solvent dissolution. As a result, thetotal rate of oil production appeared to be controlled by two mechanisms: (1)by solvent dissolution and oil mobilization at the boundaries of the vapourchamber and (2) by pure free-fall gravity drainage beyond the vapour chamberwherever gravity head was sufficient to push the mobile oil toward theproduction well. The results of this these tests define the upper limit of oilrates achievable with heated solvent injection. They can also be used to assessthe applicability of VAPEX to warm reservoirs naturally (e.g., in Venezuela)and reservoirs with mobile oil in place.

On the Stability of the Edge of a Steam-Assisted-Gravity-Drainage Steam Chamber

Summary Steam-assisted gravity drainage (SAGD) is a successful thermal-recovery technique applied in oil-sand reservoirs in which the viscosity of the oil (bitumen) is typically in the hundreds of thousands to millions of centipoise. For the in-situ production from bitumen reservoirs, bitumen viscosity must be reduced to achieve the mobility required to flow toward the production well. Many factors influence the efficiency and rate at which bitumen is mobilized. The controlling feature of steam-based recovery processes is heat transfer from the steam chamber to the formation—the greater the heat flux, the larger the oil volume heated, and the higher the oil-drainage rate. Previous studies have demonstrated that instability at the steam-chamber edge can enhance heat transfer there by creating limited-amplitude steam fingers that enlarge the heat-transfer area, thus leading to greater thermal efficiency of the recovery process. This, in turn, increases oil production. At this point, stability studies have focused on the instability between steam and oil at the edge of the chamber—none has examined the case between steam condensate and oil. In the research documented here, the stability between steam condensate and bitumen at the edge of the chamber is explored. Here, a steam-pressure diffusion equation at the moving chamber interface is derived. The perturbations of the pressure and condensate velocity are substituted into the pressure diffusion equation and Darcy's law to realize a linear-stability equation governing the growth of disturbances at the interface. The results show that the stability is controlled by moving-interface velocity and reservoir water-phase hydraulic diffusivity.

An Experimental Investigation of the Effect of Fracture Dip Angle on Oil Recovery and Drainage Rate in Free Fall Gravity Drainage in Fractured Reservoirs Using a Glass Micromodel (A Pore Level Investigation)

Gravity drainage is the main production mechanism in the gas invaded zone in naturally fractured reservoirs. However, there are large ambiguities and complexities, resulting from the dynamic of oil depletion from matrix blocks toward the fracture network. Visualization of drained oil at pore scale using glass micromodels provides the opportunity to better understand the effects of different parameters which might affect oil recovery from fractured reservoirs. In this work a micromodel apparatus generated by laser etching is used to perform some gravity drainage tests on the network patterns. The experiments were performed on double block systems using crude oil. The block to block interactions and the formation and changes of capillary bridges between matrix blocks were visually investigated. A suitable empirical model of gravity drainage is used for the prediction and evaluation of experimental data. The empirical model will be used for sensitivity analysis of fracture dip angle which might affect oil recovery efficiency and oil drainage rate, and as seen in experiments this parameter has a direct relationship to and positive effect on oil recovery. We also found the important rule of the block to block effect on the recovery of blocks and the higher recovery of upper matrix blocks than lower ones shows this reality; also it was claimed that the threshold height of fractured reservoir blocks doesn't show the true matrix capillary pressure of matrices, because of the block to block effect that helps the gravity forces in the matrix draining procedure. By increasing the block tilting angle up to α = 90 – tan – 1(y/x) as y and x are the 2-dimensional block sides lengths, the recovery of the block will increase but its initial drainage rate will decrease. It's a result of an increase in effective block height and increasing the capillary bridges stability which increases recovery, and the decrease of rate is due to capillary bridges frequency decreasing, which decreases the area open to flow.

Impact of Noncondensable Gas on Performance of Steam-Assisted Gravity Drainage

Summary This study investigates, by means of numerical modelling, the impacts of naturally occurring and continuously coinjected and intermittently coinjected noncondensable gas (NCG) at different stages of the steam-assisted gravity-drainage (SAGD) process. The CMG Builder software was used to construct a homogeneous 2D baseline model based on generic Athabasca-type reservoir properties and well configuration. A fluid-component model was generated using the CMG WinProp package for modelling the phase behaviour and properties of reservoir fluids. This fluid-component model was modified to incorporate manually calculated K-values for the gas-water- and the gas-bitumen-phase equilibria. The modified fluid model was then incorporated into the baseline model and the CMG STARS thermal reservoir simulator. The simulation results of this study show that methane coinjection along with steam is generally not beneficial. Although it can reduce the heat loss to the overburden to some extent, the reduction in oil-drainage rate and total oil recovery negates the benefits of such heat-loss reduction. The poor performance of NCG addition to SAGD results from the tendency for the NCG to remain in the vicinity of the steam chamber and reduce the transfer of heat into the cold bitumen at the edges of the steam chamber, thereby impeding steam-chamber growth. Accurate modelling of NCG addition to steam in SAGD is highly dependent on the availability of appropriate relative permeability curves and gas-solubility data. NCG with steam may perform better compared with steam-only injection in SAGD if methane coinjection were investigated using a heterogeneous model in which SAGD is affected adversely by the presence of reservoir heterogeneities in the form of shale barriers, inclined heterolithic strata (IHS), and steam-thief zones.

Experimental and Numerical Investigations Into Oil-Drainage Rates During Vapor Extraction of Heavy Oils

Summary A set of analog vapor-extraction (VAPEX) laboratory experiments was performed to test the ability of existing analytic and numerical models to predict oil-drainage rates from this process. The selected analog fluids and porous media enabled all input parameters to the analytic model to be determined independently of the analog VAPEX experiments without history matching. The results show that the underprediction of oil rate by the standard analytic model is not because of increased levels of mixing between the solvent and oil over that expected from molecular diffusion and convective dispersion, but rather because of a deficiency in the analytic model formulation.

Role of Asphaltene Precipitation in VAPEX Process

Abstract VAPEX (vapour extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the potential for in-situ upgrading of heavy oil during the process. Oil drainage rate under VAPEX is controlled by the viscosity of solvent diluted oil and can be affected substantially by de-asphalting. In-situ de-asphalting can be advantageous because it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability. The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation would outweigh any formation damage. The effects of in-situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model, packed with 140 - 200 mesh sand, and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements. The experimental results show that the oil produced at higher injection pressures was substantially upgraded, but the viscosity reduction by asphaltene precipitation did not lead to higher production rates. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was tried but proved to be ineffective. It led to production of oil with higher asphaltene content with no improvement in the rate of oil production compared to the lower pressure operation without asphaltene precipitation. However, co-injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading obtained was encouraging.

SAGD Application In Gas Cap and Top Water Oil Reservoirs

Abstract The paper presents experimental results on the impact of top water and gas caps on SAGD performance. The effect of the top thief zone on oil drainage rates and potential oil and steam loss into the top zone were measured. The study involved the use of a large scale high-pressure/high temperature experimental facility for injecting steam into an oil sand pack and measuring oil drainage rates and development of temperature ahead of the steam chamber. Numerical modelling was conducted to predict field scale performance using the CMG's STARS simulator. An elemental experimental approach was used in the study to simulate a generic reservoir in the Athabasca region with a pay zone thickness of 50 m and an overlying thief zone thickness of 8 m. In this approach, a reservoir element was selected close to the oil/top thief zone interface. The element was located ahead of an advancing steam front. In order to set the initial conditions of the laboratory element to be similar to those in the field, field scale numerical simulation was conducted to determine the temperature distribution in the element. The field scale temperature profile was established in the laboratory elemental model to represent the element's initial temperature before the start of steam injection during the experiments. The paper discusses the results from the study and highlights the potential implications of the top thief zone on SAGD applications. In addition, differences between gas cap and top water thief zones on impacting the thermal and recovery efficiency of the SAGD process are demonstrated. Introduction There is a major concern by oil producers that the gas production from the gas cap overlying the oil sand deposit has a significant detrimental effect on oil recovery. A case in point is the Surmont oil sands lease in the Athabasca deposit in Alberta, Canada, where ConocoPhillips operates a Steam Assisted Gravity Drainage (SAGD) pilot, and plans to follow quickly by commercial development. The lease has a top gas zone and a mobile water sand zone overlying the oil sand pay zone. An observation well indicates that the gas cap pressure at the pilot site has fallen from 1,327 kPa to 858 kPa over three years due to production of the gas. It is estimated that the pressure may fall to less than 300 kPa before the gas wells are abandoned. Based on the geology and pressure measurements, there is communication between the gas cap and the oil sands. This indicates that the gas cap may be a thief zone at the pilot site. It is also believed that the mobile top water zone may extend the area of influence of the pressuredepleted gas cap. As part of the ADOE/EUB Task Force's study of this problem, numerical studies on SAGD processes in reservoirs with top water/gas cap zones were conducted by ADOE(1, 2) as well as the oil and gas producers.

Steam and Gas Push (SAGP)-3;Recent Theoretical Developments and Laboratory Results

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 48th and 49th 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(1). Most recently, the SAGD project in the Tia Juana field in Venezuela(2) 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(3). Some mechanisms and model test results were described at the 49th ATM(4) and the 7th UNITAR International Conference on Heavy Crude and Tar Sands(5).

Counter-current Aspect of the SAGD Process

Abstract The uniqueness of the steam assisted gravity drainage (SAGD) recovery process lies in the salient role of moving condensing boundaries and counter-current flows. Process effectiveness depends on the balance between rising steam and draining oil-condensate emulsions. Reservoir permeability, well completion and effective drainage-pumping of oil-condensate emulsions can affect such balance. A new, non-steady state, laboratory steam-front dynamic tracking technique was used in measuring steam-liquid counter-current and co-current flows for different permeabilities and initial gas saturations. Steam chamber ceiling propagation rates (process initialization and growth) were determined for different injection and reservoir conditions. The paper highlights critical factors that control steam-oil emulsion counter-current flow and rate of propagation of the steam chamber. In addition, the CMG STARS numerical model was used to simulate SAGD counter-current flows and determine sensitivities to different parameters. Introduction The concept of the SAGD process was developed by Butler et.al.(1) In this concept, two horizontal wells are placed near the bottom of the reservoir and separated by a distance. Figure 1a illustrates the application of the SAGD process in very viscous oil (bitumen) reservoir. The top horizontal well (an injector) is located at a distance of about 5 m above the bottom well (the producer). The process consists of two distinctive phases. An initialization phase, where in most cases, conduction heating in the space between the two wells is chosen for initialization of gravity. FIGURE 1a: Illustration of the initialization and growth phases of the SAGD process in paired horizontal wells (Available in full paper) During this phase, steam is circulated in the tubing and out of the annulus. Initial breakthrough between the wells will generally occur in a localized region. Proper initialization procedures are required to bring the entire length of a well pair into active drainage. In general, the initialization phase is slow and oil rates during this phase are low. Nasr et. al.(2) reported results on two strategies for accelerating the initialization phase of the SAGD process: first, by using inter-well channels, and second, the injection of a hydrocarbon additive (naphtha) with steam. Following the initialization phase, after the oil in the inter-well region becomes mobile enough; the second phase (the growth phase) of the process can be started. During this phase, steam is injected into the top horizontal well and production fluids are obtained from the bottom well. Pressure drop along the horizontal well bore causes a slope in the steam chamber along the well as illustrated in Figure 1a. Improvement of the process during this phase requires improving the growth rate of the steam chamber and as a result improving oil drainage rates. Figure 1b shows a cross-section perpendicular to the well bores shown in Figure 1a and illustrating fluids flow in the steam chamber. Two types of flow exist. One at the ceiling of the steam chamber (ceiling drainage) and the other along the slopes of the steam chamber (slope drainage). Along the slopes of the chamber, mobilized oil accumulates in a progressively thicker layer. However, at the ceiling, oil moves away from the front immediately after mobilization.

A Steam Assisted Gravity Drainage Model For Tar Sands: Radial Geometry

Abstract This paper presents a new model for oil production during steam assisted gravity drainage (SAGD) in tar sands in radial geometry e.g., around vertical wells. The model assumes that the steam zone is an inverted cone, the temperature profile in the oil declines exponentially with distance away from me steam/oil interface, and the viscosity depends on the temperature through a power law. An energy balance is used to determine the latent heat injection fate for steam to expand the steam zone and balance eat losses. The energy balance and oil production fate equations are combined to estimate the steam-oil ratio for this process. Results obtained with this model suggest that SAGD in radial geometry is a promising recovery process. Additional studies of the process are recommended. Introduction One of the few successful oil recovery methods for tar sands is steam injection. The high temperature of the steam lowers the itumen viscosity allowing it to flow toward production wells. During steam injection, the density difference between the injected steam vapor and the oil induces gravity segregation of the phases in the reservoir. The steam vapor rises to the top of the formation, while the heated oil drains to the lower parts of the reservoir. Steam Assisted Gravity Drainage (SAGD) in linear geometry along horizontal wells has received considerable attention and a number of models for this process have been developed(1–5). SAGD in radial geometry around a single, vertical well has not received as much study, but may also become an important recovery process. During this process, steam is injected into the reservoir through a vertical well and fluids are produced from the bottom of the formation. Experimental studies of the SAGD process in radial geometry have shown that the steam zone shape around the injection well is roughly an inverted cone with the vertex at the bottom of the well. In this paper, a conic steam zone shape will be used in developing a model for the SAGO process in radial geometry. A conic steam zone shape has also been used in modeling team injection in lower-viscosity, heavy-oil reservoirs(6–7). One proposed application of the SAGD process in radial geometry is the Single-Well Injection/Production Steamflood (SWIPS) or vertical HASDrive process(8–9). SAGD in radial geometry is also expected to be important around a vertical injection, while in the horizontal well HASDrive process(10), In the SWIPS process the vertical well can be dually completed as an injector at the top and a producer at the bottom, while in the horizontal well HASDrive process, the fluids are pushed from the vertical injection well along a heated horizontal well at the bottom of the formation to a separate production well. Model Derivation The oil flow rate in the bitumen along the steam zone interface from gravity drainage can be found using Darcy's Law. If qo is the oil drainage rate at a given height, the oil flow rate can be expressed as Equation (1) Available In Full Paper where is the hydrostatic potential difference between the steam and oil along the steam zone interface,

Scaling Criteria And Model Experiments For Horizontal Wells

Abstract Horizontal wells are gaining increased prominence in primary recovery and steam injection, yet experimental and theoretical modelling of horizontal wells is still inadequate. This paper explores these two areas. Equations were developed for three-phase and non-isothermal flow in the vicinity of a horizontal well, as well as flow inside the well. These were used to obtain scaling criteria for designing laboratory experiments. The question of skin factor due to perforated casing is also considered. An interesting idea offered is the use of variable diameter horizontal wells. A series of steam injection experiments was carried out in a model, with a concentric well. Temperature distributions were determined and used to interpret oil recoveries and pressure behaviour. Oil recovery performance for different experiments was evaluated to determine the effectiveness of different types of horizontal wells, and the impact of perforated casing. Introduction It has been reported extensively(1,2) that horizontal wells offer prospects of improved performance over conventional vertical wells, primarily due to the larger contact area between the formation and the horizontal well. This is especially true for thin oil formations where the reservoir contact area for a horizontal well can be hundreds of times that for a fully-penetrating vertical well, Furthermore, horizontal wells, when strategically placed, can reduce water/gas coning and result in improved cumulative recovery in view of the small draw downs(3). Horizontal wells are also believed to have a much better chance than vertical wells of intersecting systems of vertical and horizontal fractures in an oil-bearing formation, and thus lead to higher production rates(4). In steam injection recovery of heavy oils and oil sands horizontal wells especially when combined with steam-assisted gravity drainage could lead to high production rates, more uniform distribution of steam front leading to improved sweep efficiency and cumulative oil recovery(5,6). One aspect that has so far received little attention in discussions of horizontal well performance concerns the flow in the vicinity of, and inside a horizontal well. Often, it has been assumed that a horizontal well has infinite conductivity and that the flow in the well is predominantly laminar - meaning the pressure drop across [he well is not significant. Dikken(7) showed that this assumption is not necessarily true for most practical situations, and that pressure drops across horizontal wells can significantly affect the performance. This paper attempts to contribute to an understanding of this aspect of horizontal wells by presenting mathematical models of flow in the vicinity of, and inside a horizontal wellbore. These models were used to obtain scaling criteria for a series of scaled model steam injection experiments. Data, including well pressure drop and fluid production rates in the presence of a perforated casing are also reported. Literature Review Butler, McNab, and Lo(5) presented the first theoretical and experimental study of steam-assisted gravity drainage and horizontal wells to recover bitumen from oil sands. Equations were derived to calculate oil drainage rate and lateral position of steam-oil interface as functions of time and height. A subsequent study by Butler and co-workers(H) introduced improvements to the original model.