Wellbore Heat Losses Research Articles

Analytical solutions to evaluate the geothermal energy generation potential from sedimentary-basin reservoirs

Sedimentary basins are attractive for geothermal development due to their ubiquitous presence, high permeability, and extensive lateral extent. Geothermal energy from sedimentary basins has mostly been used for direct heating purposes due to their relatively low temperatures, compared to conventional hydrothermal systems. However, there is an increasing interest in using sedimentary geothermal energy for electric power generation due to the advances in conversion technologies using binary cycles that allow electricity generation from reservoir temperatures as low as 80 °C. This work develops and implements analytical solutions for calculating reservoir impedance, reservoir heat depletion, and wellbore heat loss in sedimentary reservoirs that are laterally extensive, homogeneous, horizontally isotropic and have uniform thickness. Reservoir impedance and wellbore heat loss solutions are combined with a power cycle model to estimate the electricity generation potential. Results from the analytical solutions are in good agreement with numerically computed reservoir models. Our results suggest that wellbore heat loss can be neglected in many cases of electricity generation calculations, depending on the reservoir transmissivity. The reservoir heat depletion solution shows how reservoir temperature and useful lifetime behave as a function of flow rate, initial heat within the reservoir, and heat conduction from the surroundings to the reservoir. Overall, our results suggest that in an exploratory sedimentary geothermal field, these analytical solutions can provide reliable first order estimations without incurring intensive computational costs.

A Critical Review Using CO2 and N2 of Enhanced Heavy-Oil-Recovery Technologies in China

Thermal recovery technology is generally suitable for shallow lays due to the higher thermal loss for the deep heavy-oil reservoirs. Non-thermal recovery technologies, such as the non-condensate gas injection technology, are not limited by the reservoir depth and could be extensively applied for the heavy-oil reservoir. Many experimental studies and field applications of non-condensate gas injection have been conducted in heavy-oil reservoirs. The injected non-condensate gas could achieve dynamic miscibility with heavy oil through multiple contacts, which has a significant viscosity-reduction effect under the reservoir conditions. In addition, the equipment involved in the gas injection operation is simple. There are many kinds of non-condensate gases, and common types of gases include N2 and CO2 due to abundant gas sources and lower prices. Moreover, CO2 is a greenhouse gas and the injection of CO2 into the reservoir would have environmental benefits. The non-thermodynamic method is to inject N2 and CO2 separately to produce heavy oil based on the mechanism of the volume expansion of crude oil to form elastic flooding and reduce crude oil viscosity and foamy oil flow. Steam injection recovery of the thermodynamics method has the disadvantages of large wellbore heat loss and inter-well steam channeling. The addition of N2, CO2, and other non-condensate gases to the steam could greatly improve the thermophysical properties of the injected fluid, and lead to higher expansion performance. After being injected into the reservoir, the viscosity of heavy oil could be effectively reduced, the seepage characteristics of heavy oil would be improved, and the reservoir development effect could be improved. Non-condensate gas injection stimulation technology can not only effectively improve oil recovery, but also help to achieve carbon neutrality, which has a very broad application prospect in the future oil recovery, energy utilization, environmental improvement, and other aspects.

Numerical simulation of flow and heat transfer performance during supercritical water injection in vertical wellbore: A parameter sensitivity analysis

Supercritical water injection is a promising technology for heavy oil thermal recovery. Predicting and regulating the thermophysical parameters of supercritical water at bottomhole are the prerequisite for achieving high recovery efficiency. In this paper, a novel numerical model was proposed to simulate wellbore flow and heat transfer of supercritical water injection. A modified correlation of frictional coefficient was developed to calculate water flow resistance near its critical point, where its properties change abruptly. The unsteady heat loss to the formation was calculated directly by solving two-dimensional unsteady heat conduction equations. They were respectively coupled in momentum and energy balance equations using an iterative scheme. This model was proved to be accurate by two oilfield cases in which the relative errors of wellbore fluid pressure and temperature are less than 1%. Then parameters sensitivity analysis of the injection pressure, temperature, mass flux and the apparent heat conductivity of insulating tube was conducted. The results indicated that the temperature variation of wellbore fluid depended on both enthalpy drop (or heat loss) and Joule-Thomson effect. An abnormal phenomenon that the fluid temperature increased with wellbore depth near the critical and pseudo-critical points was found because of the sudden increase in high heat capacity and Joule-Thomson coefficient of water. Raising the bottomhole fluid temperature was the key to enhanced oil recovery by supercritical water injection. Low apparent heat conductivity of insulating tube contributed richly to raise bottomhole fluid temperature by enlarging thermal resistance and reducing wellbore heat loss. There existed an optimal mass flux for maximizing bottomhole temperature, because when the mass flux increased, the shortened resident time within wellbore and the decreased fluid pressure favored temperature increase and decrease respectively. Selecting an injection pressure near the critical or pseudo-critical point and raising the injection temperature would increase the bottomhole temperature and reduce relative fluid heat loss.

Steam Cavity Expansion Model for Steam Flooding in Deep Heavy Oil Reservoirs

Steam flooding is crucial for the development of heavy oil reservoirs, and the development of the steam cavity significantly determines the efficiency of steam flooding. Previous studies have elucidated the concept of steam overburden and pseudomobility ratio; however, the thermal energy loss in deep heavy oil reservoirs during steam injection needs further investigation. Therefore, in this study, the vapour–liquid interface theory and mathematical integration were used to establish a steam cavity expansion model. The wellbore heat loss rate coefficient, steam overlay, and pseudomobility ratio were used to accurately describe the development of the steam cavity in deep heavy oil reservoirs. The proposed model was experimentally validated, and it was observed that the model could accurately reflect the actual mine conditions. In addition, the pressure gradient distribution of the steam belt and the heat dissipation areas of the top and bottom layers of the steam cavity were evaluated. The results showed that the influence of the wellbore heat loss rate coefficient on the pressure gradient of the oil layer was primarily in the range of 5–20 m away from the steam injection well. Furthermore, it was observed that the pseudomobility ratio is inversely proportional to the development of the steam cavity. As the wellbore heat loss rate coefficient increased, the wellbore heat loss increased. The larger the area ratio, the more pronounced the steam overlay phenomenon, and the large area ratio does not meet the development requirements of the steam chamber. The research closely combines theory with production, and the results of this study can help actual mines by providing theoretical support for the development of deep heavy oil reservoirs.

Overall heat transfer coefficient with considering thermal contact resistance in thermal recovery wells

Although many approaches [1–3] to calculate overall heat transfer coefficient have been presented, none has addressed the problems associated with (1) irregular and unsmooth interface between cement sheath and formation [4], (2) bad cement quality [5,6] and (3) thermal effect of cement sheath [7] during steam injection. A term “contact thermal resistance” is used to describe the extra heat transfer resistance and added to the overall wellbore heat transfer resistance. This article firstly gives a reasonable method to describe these imperfect contact interfaces. And then a mathematical model for estimating overall heat transfer coefficient and wellbore heat loss is established to analyze the effect of the thermal contact resistance at the interfaces on interface temperature drop, overall heat transfer coefficient, wellbore heat loss and casing temperature. Finally we study the effect of the thermal resistance on steam parameters distribution in the wellbore. The results indicate that the existence of thermal contact resistance produces interface temperature drop, reduces the overall heat transfer coefficient and wellbore heat loss, but leads to the casing overheated. The steam parameters distribution along the wellbore, especially steam quality, differ from the actual values. Moreover, accurate calculation of steam parameters distribution along the wellbore is a good way to save coal resources.

Study on wellbore heat loss during hot water with multiple fluids injection in offshore well

For estimating heat loss of offshore well, an analysis model of flow and heat transfer for hot water with multiple fluids injection in offshore well was established, in which multiple fluids were regarded as real gas mixture replacing the ideal gas-assumption in conventional models. Validation of the model by measured data in Bohai offshore oilfield showed that model calculation agreed with the measured data, the pressure average relative error was about 0.7%, and temperature average absolute error was about 1.4 °C. Through a simulation wellbore, the influence of some factors on heat loss of offshore well was analyzed. It was found that the heat of multiple thermal fluids lost to environment ranged from 2.3% to 9.5% under different injection parameters, and heat lost to seawater was dominant. The injection rate, injection temperature, hot water proportion and insulated tube have a great effect on heat loss of offshore well, while injection pressure, injection time and environment temperature have little effect on heat loss. An increase in injection rate, hot water proportion and depth of insulated tube, or a decrease in injection temperature and insulation thermal conductivity, leads to a decrease in heat loss, especially the heat lost to sea.

Prediction of thermophysical properties of saturated steam and wellbore heat losses in concentric dual-tubing steam injection wells

Concentric dual-tubing steam injection is important in the process of thermal recovery for heavy oils. This paper firstly presented a mathematical model to predict thermophysical properties of saturated steam (i.e. steam pressure, temperature and quality) and wellbore heat losses in CDTSIW (concentric dual-tubing steam injection wells). More importantly, a semi-analytical model for estimating pressure gradient for steam/water flow in annuli was developed. Then the mathematical model is solved using an iterative technique. Predicted results were compared with measured field data to verify the accuracy of the model. The results indicate that the direction of heat transfer between fluids in the integral joint tubing and in the annulus depends not only on wellhead injection conditions but on temperature drop in each tubing. In addition, the steam qualities in CDTSIW are significantly influenced by heat exchange between fluids in dual tubing, which can cause steam boiling or condensation. Moreover, the paper shows that to effectively reduce the wellbore heat losses and to ensure high bottomhole steam qualities in Well Xing 67 of Liaohe Oilfield, the thermal conductivity of insulation materials should be less than 0.7 W/(m K).

Study on the effect of wellbore heat capacity on steam injection well heat loss

The accurate calculation for heat loss from steam to formation in steam injection well is of great importance for enhanced oil recovery (EOR) in the thermal recovery process for heavy oil. In this study, a novel heat loss model with consideration of wellbore heat capacity was set up and the heat loss was simulated by the new model. Finally, this paper focused on the effect of wellbore heat capacity on wellbore heat loss with times, and the steam injection conditions was also regarded to study on the influence of wellbore heat capacity on heat loss. It was found that the wellbore heat capacity had an obvious influence on the wellbore heat loss, especially at early stage of steam injection. Consequently, the new heat loss model could solve the problem of low precision for heat loss calculation at early injection time caused by the conventional model due to ignoring wellbore heat capacity. Furthermore, the heat loss would decrease with the increase of wellbore heat capacity, and the effect of wellbore heat capacity on heat loss became significant with increase of steam injection pressure.

A Critical Review of Improved Oil Recovery by Electromagnetic Heating

Conventional thermal improved oil recovery (IOR) methods, such as fire flooding and steam flooding, are commercially viable when properly applied. Every conventional method has one or more limitations. If the reservoir is shallow, the reservoir pressure may be too low to maintain a steam drive. If a reservoir is too deep, wellbore heat losses become excessive. Fireflood success depends on crude composition. Each of the conventional thermal methods requires sufficient reservoir transmissibility to achieve fluid Injection. Electro magnetic heating (EMH) has the potential for overcoming some of the limitations of conventional thermal methods such as environmental, cost and depth of operation. EMH as an IOR method to heating heavy crude by increasing its transmissibility, stimulation solution in asphaltenic wells, oily pollution removal, and so on, has environmental economical and technical advantages.

Production Allocation in Multi-Layers Gas Producing Wells Using Temperature Measurements With the Application of a Genetic Algorithm

A methodology has been presented of allocating gas rate and associated water to each individual layer using temperature measurements and total surface production of gas and water. In part 1, an analytical forward model has been proposed for wellbore temperature response under two-phase production in a multilayer geometry, using a nodal representation of the well. This model accounts for the formation geothermal gradient, steady-state gas-water flow in the wellbore, friction loss, and Joule-Thomson effect in the wellbore; in contrast to the thermal and physical properties of gas and water, wellbore heat losses due to unsteady heat conduction in the earth, and the mixing of the fluid streams of contrasting temperature. The second part shows the solution technique used to allocate the gas and water rate for each layer. The practical implementation of the new developed production allocation model is examined on data from two actual gas wells with temperature measurements taken from production logging tools recorded in these wells. The results show that the model succeeded to accurately allocate the flow rates of gas and water.

Improved Predictability of In-Situ-Combustion Enhanced Oil Recovery

Summary In-situ combustion (ISC) possesses advantages over surface-generated steam injection for deep reservoirs in terms of wellbore heat losses and generation of heat above the critical point of water. ISC also has dramatically lower requirements for water and natural gas, and potentially a smaller surface footprint, in comparison with steam. In spite of its apparent advantages, prediction of the likelihood of successful ISC is unclear. Conventionally, combustion tube tests of a crude oil and rock are used to infer that ISC works at reservoir scale and estimate the oxygen requirements. Combustion tube results may lead to field-scale simulation on a coarse grid with upscaled Arrhenius reaction kinetics. As an alternative, we suggest a comprehensive workflow to predict successful combustion at the reservoir scale. The method is derived from experimental laboratory data and simulation models at all scales. In our workflow, a sample of crushed reservoir rock or an equivalent synthetic sample is mixed with water/brine and the crude-oil sample. The mixture is placed in a kinetics cell reactor and oxidized at different heating rates. An isoconversional method is used to estimate kinetic parameters vs. temperature and combustion characteristics of the sample. Results from the isoconversional interpretation provide a first screen of the likelihood that a combustion front is propagated successfully. Then, a full-physics simulation of the kinetics cell experiment is used to predict the flue gas composition. The model combines a detailed pressure/volume/temperature (PVT) analysis of the multiphase system and a multistep reaction model. A mixture identical to that tested in the kinetics cell is also burned in a combustion tube experiment. Temperature profiles along the tube, as well as the flue gas compositions, are measured during the experiment. A high-resolution simulation model of the combustion tube test is developed and validated. Finally, the high-resolution model is used as a basis for scaling up the reaction model to field dimensions. Field-scale simulations do not use Arrhenius kinetics. As a result, significant stiffness is removed from the finite-difference simulation of the governing equations. Preliminary field-scale simulation shows little sensitivity to gridblock size, and the computational work per timestep is much reduced.

Two-Phase Liquid Production Allocation in Multilayer Producing Wells Using Temperature Measurements

This work presents a methodology of allocating oil rate and associated water cut to each individual layer using temperature measurements and total surface production of oil and water. This paper consists of two parts. In part one; an analytical forward model is proposed for wellbore temperature response under two-phase production in a multilayer geometry, using a nodal representation of the well. This model accounts for the formation geothermal gradient, steady-state oil-water flow in the wellbore, friction loss and Joule-Thomson effect in the wellbore, contrast in the thermal and physical properties of oil and water, wellbore heat losses due to unsteady heat conduction in the earth, and the mixing of the fluid streams of contrasting temperature. The second part shows the application of the above solution by applying inversion techniques on temperature data coupled with forward model to allocate water and oil influx from producing layers. The inversion result is verified using a variety of commingled flow problems including a field case of a deviated well producing an oil-water mixture from two active completions. Inversion results seem to be robust within +/-15% provided the temperature contrast between the commingled layers is at least one order of magnitude greater than the resolution of the temperature measurements (e.g., 4°C contrast for 0.1°C resolution) Key words : Oil rate; Temperature measurement; Nodal representation; Inversion techniques

Estimation of geological formation thermal conductivity by using stochastic approximation method based on well-log temperature data

Thermal conductivity is a key parameter for evaluating wellbore heat losses which plays an important role in determining the efficiency of steam injection processes. In this study, an unsteady formation heat-transfer model was established and a cost-effective in situ method by using stochastic approximation method based on well-log temperature data was presented. The proposed method was able to estimate the thermal conductivity and the volumetric heat capacity of geological formation simultaneously under the in situ conditions. The feasibility of the present method was assessed by a sample test, the results of which shown that the thermal conductivity and the volumetric heat capacity could be obtained with the relative errors of −0.21% and −0.32%, respectively. In addition, three field tests were conducted based on the easily obtainable well-log temperature data from the steam injection wells. It was found that the relative errors of thermal conductivity for the three field tests were within ±0.6%, demonstrating the excellent performance of the proposed method for calculating thermal conductivity. The relative errors of volumetric heat capacity ranged from −6.1% to −14.2% for the three field tests. Sensitivity analysis indicated that this was due to the low correlation between the volumetric heat capacity and the wellbore temperature, which was used to generate the judgment criterion.

A novel analytical transient heat-conduction time function for heat transfer in steam injection wells considering the wellbore heat capacity

Steam injection technique is one of the most important methods for enhancing the heavy oil production. Evaluating the reliability of steam injection projects requires the investigation of the heat transfer in the wellbore and the surrounding formation. In this study, a new formation heat-transfer model taking into account the wellbore heat capacity was developed and a novel analytical transient heat-conduction time function was presented. Comparison of the formerly used transient heat-conduction time functions with the novel analytical transient heat-conduction time function was made. The result indicated that the wellbore heat capacity has a significant influence on the transient heat-conduction time function, especially for cases of short time injection. To investigate the effect of wellbore heat capacity on the heat transfer in steam injection wells, a comprehensive wellbore/formation model incorporating the novel analytical transient heat-conduction time function was also established. Based on this model, the wellbore/formation interface temperature and the wellbore heat losses were computed by using various transient heat-conduction time functions. The comparisons showed that the formerly used transient heat-conduction time functions would lead to inadequate estimation of the wellbore/formation interface temperature and the wellbore heat losses. High accuracy and excellent applicability of the wellbore/formation model were demonstrated when performances of the proposed model were compared with the measured field data from the steam injection well.

Super insulated wells to protect permafrost during thermal oil recovery

In cold environments, wellbore heat losses are significant and limit the applicability of thermal recovery. Our study focuses primarily on the problem of wells penetrating permafrost. The experimental component determines thermal conductivity versus temperature of nanomaterial insulators (aerogels), fibreglass, thermolastic insulation, and carbon fibres. A comparator thermal conductivity apparatus as well as direct measurements using heat flux sensors were developed. Semianalytical and numerical models were also created to design a superinsulated well. The models incorporate various composite insulations. Well failure/stability is inferred from the rate of thaw-front propagation. A key parameter is the insulation thermal conductivity versus temperature that is measured directly. Measurements of conductivity agree with literature values at ambient temperature. Aerogels (0.012–0.025 W/m K) are half as conductive as fibreglass (0.03–0.045 W/m K) and three to four times less conductive than thermolastic insulation and carbon fibres (0.04–0.067 W/m K) for temperatures between 40 and 140 °C. The wellbore heat loss and thaw front propagation model indicates that aerogels alone or aerogels in a composite with more conductive insulation may meet the requirements to avoid well failure, even for very high temperature fluids and over long time.

Prediction of wellbore temperatures in gas production wells

In this paper we present a simple and physically transparent analytical solution for the prediction of wellbore temperatures in gas production wells. It is based on the extended Bernoulli equation and the steady-state energy balance applied to the flow of a real gas in a straight flow conduit. The solution includes three dimensionless numbers representing the effect of gravity, friction and wellbore heat losses, respectively, and two newly defined thermodynamic gas properties, called psi and omega. These properties are gas specific and can be readily evaluated as a function of pressure and temperature on the basis of existing correlations for the gas deviation factor (z-factor) of natural gases. The analytical solution is very well suited to quickly estimate temperature drops in straight homogeneous wells with uniform tubing strings. It can also be used, along with the existing analytical solution for wellbore pressures of Lingen, as a basic building block in a more general and rigorous prediction method for temperatures and pressures in wellbores, accommodating variable deviation angles, variable wellbore diameters, tapered tubing strings, and layered rock formations with different heat transmission characteristics.

Recommended Practices for Slim-Hole Steam Injectors

Summary Single-string and multistring slim-hole completions have become popular in recent years as an inexpensive means of injecting steam into shallow, low-pressure sands. While slim-hole injectors appear to be simpler and cheaper to drill and complete, wellbore heat losses can be excessive at low injection rates. In addition, if a good bond is not achieved during primary cementing, thermal stresses, incurred once steam is injected, increase the likelihood of tubing failure and steam channeling behind pipe. Therefore, an appropriate tubing size and weight must be used to prevent well failures. For example, initial slim-hole steam injectors completed with 2⅜-in. and 2⅞-in. tubing are no longer advisable because of insufficient mechanical integrity. Similarly, poor cement bond in triple-string slim-hole injectors has resulted in a high percentage of well failures. Consequently, the costs associated with tubing deformation, poor steam containment, and high wellbore heat losses cannot be ignored when considering slim-hole injectors for a steamflood project. This paper discusses current drilling and completion practices and addresses the benefits and risks associated with slim-hole steam injectors. The short-term economics of initial low drilling and completion costs are compared to the long-term economics of efficient steam placement to target sands using single-string and multistring slim-hole injectors. Recommended practices and guidelines are presented for proper, cost-effective application of slim-hole injectors to improve steamflood performance.

A Cyclic Steam Injection Model for Gas Production from a Hydrate Reservoir

Thermally efficient production of natural gas from a hydrate reservoir by the use of cyclic steam injection process was modeled. The model was considered as a three-phase process: an injection phase, a soak phase, and a production phase. Using energy and mass balances, heat transfer equations, and steam properties, wellbore heat losses, heat losses to base and cap rock, and heat losses during dissociation were calculated. The radial advance of the hydrate front was tracked during each cycle. The produced gas volume and combustible energy of this gas were compared with the energy of the injected steam to compute energy efficiency of the process. To determine the best possible conditions for gas production from a hydrate reservoir by cyclic injection, the model was tested for a wide range of parameters. Overall thermal efficiency was calculated for different reservoir porosity, reservoir depth, hydrate zone thickness, heat injection rate, and steam injection temperature.

On the Difficult Birth of SAGD

Introduction This contribution attempts to address some questions suggested by the series(1,2,3) to date. The answers are not all technical in nature: "Problems aren't solved by technology alone; we also need a thorough understanding of social dynamics."(4) After some select technical observations, this contribution is indeed an essay on social dynamics, as they relate to R&D in general, and SAGD development in particular. Is There any Evidence SAGD is Better Than Conventional Methods? The best evidence of this is that the more successful SAGD projects have demonstrated comparable oil/steam ratios (OSRs) to those of vertical/thermal implementations, even though the SAGD projects were conducted in reservoirs of significantly lower quality. This is illustrated in Figure 1, which compares the realized or projected OSRs of four actual projects plus a projected "prime Athabasca" case. Reservoir quality is characterized by permeability times thickness. It can be seen that approximately twice the kh is needed to achieve the same OSR using vertical technology, as can be obtained with twin-well SAGD. Pikes Peak and Cold Lake were each conducted in essentially the best reservoirs ever found in their respective formations; whereas the pay zone at Senlac, at only about 40 feet thick, would have failed most screening criteria that have been proposed for vertical CSS or steam flood. The low value of kh assigned to the UTF B Pattern is actually on the generous side. A low-energy estuary resulted in good quality sand units (5 Darcys) but with frequent silty laminations (25 – 250 mD), which prevented easy passage of steam around them. The reservoir was too heterogenous to estimate an effective bulk permeability, but geostatistical simulations and the observed project performance suggest an overall effective SAGD permeability of about 1.0 ± 0.3 Darcy. The projected Prime McMurray case is based on 40 m of 5 D sand, representing perhaps a top-decile Athabasca reservoir. Such reservoir quality is not ubiquitous over the deposit, but is known in commercial quantity at a number of widely-separated places.(5) Finally, OSR is by far the most important economic indicator for steam recovery, but the high productivity of SAGD pairs also promises lower unit costs for drilling, workovers, wellbore heat losses, and field operating labour. Why Do All SAGD Wells Seem to Produce at 100 m3/d? The UTF B pattern performance has widely come to be viewed as representative of the better Athabasca reservoirs. Nothing could be further from the truth; at least 1/3 of the total Athabasca resource is better than the B pattern, and the top 10% is enormously better. The author hypothesises that this situation has resulted in a syndrome of significant under-design in many projects, exploiting much better reservoirs. In order to reconcile predictions for such reservoirs with UTF results (while assuming sand quality is comparable), unrealistically low values for kh, kroi' and/or kv/ kh must be employed. Acceptable OSRs are nevertheless predicted, and the project proceeds. The resulting field design may be too conservative by a factor of two or three, in terms of unit-length well performance.

The Nature And Control Of Geyser Phenomena In Thermal Production Risers

Abstract Efficient application of Steam-assisted Gravity Drainage (SAGD) for bitumen or heavy oil recovery requires production of large fluid volumes, close to the boiling point of water. Flowing or gas/steam lifting such wells is an attractive alternative to rod pumping, but evidence is given that the flow can be unstable, due to the large energy release of flashing water. The instabilities are the same phenomena that drive cyclic eruptions in geothermal geysers. A unique finite difference simulator is used to model and study the transient thermohydraulics of superheated water in an idealized wellbore. It is shown that some form of dynamic wellhead choking system is probably required for satisfactory control of a surface access SAGD well. The advent of horizontal wells for thermal recovery and especially for SAGD has led to the need to produce very large fluid volumes from individual wells, at high temperatures. For optimum SAGD, the temperature in the production liner should be kept close to the steam point at bottomhole pressure (steam trap production control)(l), so as to maintain the steam chamber as deep as possible. Sustained fluid production rates of 300 m3/D or more(2) are anticipated from single producers; at this rate, wellbore heat losses will have a limited cooling effect. In most SAGD applications, then, produced water will flash as pressure declines on the way to the surface. UTF Production Lifting Experience At the AOSTRA Underground Test Facility (UTF)(3), SAGD testing is carried out using horizontal wells that are drilled from a tunnel located below the oil sand reservoir. Steam generation and production treating facilities are on the surface, and standard piping carries fluids to and from the well chambers. The wellheads and production control valves are about 20 m lower in elevation than the production liners. This arrangement takes advantage of gravity to avoid flashing in the wellbore and the tunnel facilities, but production is still subject to flash conditions in the riser, during the 185 m climb to the surface. This was recognized during the design of the Phase A facilities, and it was hoped to exploit the resulting steam lift effect. The underground pump was de-rated and a steam sparge system was installed at the base of the riser to enable the lifting of cold fluids. A summary of experience with this system is shown in Figure 1. This is a scatter plot showing the average riser pressure gradients for about 700 days of Phase A operation, as a function of riser bottomhole temperature. This temperature is expressed in terms of subcooling below the steam point, to account for varying pressure. Most days fall into one of three groups indicated, corresponding to the (I) no flashing, (II) slight flashing, and (III) high enthalpy (est. 15 – 30% quality) conditions. The large gap between regions II and III represents conditions that were avoided due to extreme and persistent instability. In this region, flow consisted of geyser-like eruptions occurring at periods from one-half to several hours.