Thermal Heavy Oil Phase 1b Potential Vent/Efficiency Options One Page Options List

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1 Thermal Heavy Oil Phase 1b B.R. Peachey February 15, 2002 Thermal Heavy Oil Phase 1b Potential Vent/Efficiency Options One Page Options List 13. Report Summary Booklet Index Option Assessments based on Operational Objectives High Level Operation and Emission Assessment Options Overall Option Assessment Process Overall Energy Efficiency Indicators Defining Operational Objectives Moving from Overall Assessment to Options Reservoir and Production Options Reservoir Energy Distribution Control Use of Blocking Agents Gas Blanket Quenching Steam Soak Distribution Monitoring Produced Water Use Options Hot Water Flood Zonal Preheat Gas Reinjection Continuous Injection for Pressure Maintenance Pressure Cycling Steam Injection Options Static Insulation of Tubulars Dynamic Insulation of Tubulars Minimizing Vent Streams Control of Venting Multi-Phase Pumping Vent Stream Reinjection Steam Eductors Compression Multi-Phase Pumping from Satellite CO2/N2 Reinjection Facility Options Casing Vent Stream Treatment Vent Gas Cooling Dehydration Sweetening Steam Generator Design and Operation Options Use of Sour Gas as Fuel Use of Produced Heavy Oil as Fuel Enhanced Burner Controls Enriched Air Combustion Decrease Stack Losses

2 Thermal Heavy Oil Phase 1b Downhole Steam Generation on Surface Produced Water Reuse for Steam Generation Power Generation Options Reciprocating Engine Gensets Gas Turbines Co-Generation Waste Heat Power Generation Heater Treater Design and Operation Options Use of Sour Vent Gas as Fuel Stack Losses & Enhanced Burner Controls Energy Recovery Heat Exchange Diluent Assisted Treating Electrostatic Treating Product Transportation Options Trucking and Fuel Options Diluted or Emulsion Pipelines Heated Pipelines Fuel Switching Options Flares, Fugitives and Odours Area Options Use of Conventional Heavy Oil Vent Gas Use of Alternate Produced Water Sources Distributed Power Generation B.R. Peachey February 15, 2002

3 Thermal Heavy Oil Phase 1b 13.2 Option Assessments based on Operational Objectives Purpose of the Tool: Thermal Heavy Oil Phase 1b Potential Vent/Efficiency Options The charts on the following pages are intended to help users short list and prioritize options to consider based on the current operational objectives for their Thermal Heavy Oil Operations. Each option in the one page option list has been assessed to roughly indicate (X) which objectives they have potential to significantly enhance, as well as which other objective areas might be also be affected: enhanced (+) or degraded (-). Blanks indicate that there would likely be very little effect. These assessments are very subjective and it is recommended that the charts be reviewed and modified if they do not seem to fit. The reason the charts were developed is to help adjust and select options for implementation based on current corporate or operational area objectives which change over time based on commodity prices, economic environment, rate of expansion of operations and overall profitability. The Four Operational Objectives (see Option Sheet ): Reduce Off-site Energy Required (Op Costs) Reduce the off-site energy needs, which will reduce the risk of the operation becoming uneconomic if energy supply costs are high. Balancing Objectives Cash Flow Profitability Increase Oil Rate (Cash Flow) Oil rate is the indicator used by most operators to assess their performance, usually governs when heavy oil price is high and energy supply costs are low. Reduce Risk Op Costs Return on Investment Increase Oil Recovery (Return on Investment) Increased oil recovery is a longer-term measure of operating performance and is the main indicator of the efficient depletion of the oil resource. Increases the return on the capital invested in: exploration, drilling and completion of wells, and for surface facilities and pipelines. Health, Safety and Environment (Reduce Risk) Providing sustainable benefits requires that the hydrocarbon resources be depleted efficiently with the minimum of waste, while protecting workers, local residents and other organisms from any emissions that might degrade their health or well being. Corporately dominates during period of expansion and new project approvals. B.R. Peachey February 15, 2002

4 Thermal Heavy Oil Phase 1b Option Sheet Description (Tier 1 ) Reduce Op Costs Increase Cash Flow Increase Return on Investment Reduce HSE Risks Impacts Overall Option Assessment Process X X X X Overall Energy Efficiency Indicators X X X X Defining Operational Objectives X X X X Moving from Overall Assessment to Options X X X X Use of Blocking Agents (Tier 1-2) (-) (+) X Gas Blanket (Tier 2) (-) X (+) Quenching (Tier 1) (-) X Steam Soak (Tier 1) (+) (-) X Distribution Monitoring (Tier 1) (-) X Hot Water Flood (Tier 2) (+) X Zonal Preheat (Tier 2) (+) X Continuous Injection for Pressure Maintenance (Tier 1) (-) (+) X Pressure Cycling (Tier 2) (-) X (+) Static Insulation of Tubulars (Tier 1) X (+) (+) Dynamic Insulation of Tubulars (Tier 2) (-) X (+) (+) Control of Venting (Tier 1) X (+) (+) (+) Multi-Phase Pumping (Tier 1) X (+) Steam Eductors (Tier 2) X (+) Compression (Tier 1) (-) X (-) Multi-Phase Pumping from Satellite (Tier 2) X (+) CO2/N2 Reinjection (Tier 2) (-) (+) X (+) 1 Note Options are designated Tier levels based on their state of commercialization. Tier 1 Option is commercially available and has been shown to be economic in thermal heavy oil. Tier 2 Option appears to be technically viable and has been tested, but may not be widely available or accepted as being economic. Tier 3 Options showing promise but requiring further commercial development to establish technical and economic viability in Canadian Thermal Heavy Oil Operations. Assessments are subjective. B.R. Peachey February 15, 2002

5 Thermal Heavy Oil Phase 1b Option Sheet Description (Tier) Reduce Op Costs Increase Cash Flow Increase Return on Investment Reduce HSE Risks Impacts Vent Gas Cooling (Tier 1) X (-) (+) Dehydration (Tier 1) X (+) (-) (-) Sweetening (Tier 1-3) (+) X Use of Sour Gas as Fuel (Steam Generation) (Tier 1-2) X Use of Produced Heavy Oil as Fuel (Tier 1-3) X X X Enhanced Burner Controls (Tier 1) X X Enriched Air Combustion (Tier 2) X Decrease Stack Losses (Tier 2) X X Downhole Steam Generation on Surface (Tier 3) X X X (+) Produced Water Reuse for Steam Generation (Tier 1) X (-) (+) Reciprocating Engine Gensets (Tier 1) X (-) (+) Gas Turbines (Tier 1) X (-) (+) Co-Generation (Tier 1) X (+) X Waste Heat Power Generation (Tier 2-3) X (-) (+) Use of Sour Vent Gas as Fuel (Treaters) (Tier 1) X Stack Losses & Enhanced Burner Controls (Tier 1) X (+) Energy Recovery Heat Exchange (Tier 1) X (-) Diluent Assisted Treating (Tier 1) X (-) Electrostatic Treating (Tier 1) X (+) Trucking and Fuel Options (Tier 1-2) (+) X (-) Diluted or Emulsion Pipelines (Tier 1-2) X (+) X Heated Pipelines (Tier 1-2) X (+) (-) Fuel Switching Options (Tier 1) X (+) Flares, Fugitives and Odours (Tier 1) (-) X Use of Conventional Heavy Oil Vent Gas (Tier 1) X X X Use of Alternate Produced Water Sources (Tier 2) (+) (+) X Distributed Power Generation (Tier 1) X X (-) (+) B.R. Peachey February 15, 2002

6 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Overall Option Assessment Process In thermal heavy oil operations the basic process is very simple. Water from some source is heated, delivered to the reservoir where it can transfer energy to the oil to reduce the viscosity and increase the relative mobility of the oil. In the reservoir heating causes some gas to evolve, either by cracking of the oil or distillation, so gas, oil and water are produced back. The water and gas must find an outlet and require management while the produced oil eventually reaches a market somewhere, and arrives there at a temperature and pressure quite similar to what it was originally at in the reservoir. Along the way the process requires an input of a great deal of energy in the form of fuel and power and all this energy is dissipated or lost to the environment. Generic Thermal Process Heat Water Energy Input Deliver Water to Reservoir Transfer Heat Energy Losses To Oil Produce Oil, Water & Gas Dispose of Water & Gas Treat & Ship Oil Since the process is very energy intensive and uses more energy from outside sources than any other type of oil or gas production, the main criteria for economic and technical success in operations is based on efficient use of the energy inputs and in obtaining the energy from the lowest cost sources. The overall assessment process to be used in this study is based on identifying all locations in the entire thermal injection and production process where high quality energy is input and where it is reduced to lower quality energy, or lost from the process as low quality heat. Once these losses have been quantified options can be considered to: Maintain the stream at a higher energy level longer, to increase efficiency and allow for increased energy recovery Make use of any energy level reductions to provide some other benefit Provide a benefit from low quality energy sources that are being lost from the process. Identify ways of reducing the cost and improving the efficiency of using the energy inputs. Pro s:

7 Improving the energy efficiency of thermal operations will have a major impact on improving their economics. Thermal operations are less affected by gas, diluent, power and GHG costs if they are more energy efficient. Current projects were built based on the availability of low cost gas and power supplies, without change it will be uneconomic to produce a low quality product like heavy oil. Con s: More work is required to address the energy use on a thermal site than in other oil and gas operations that have internally generated and controlled sources of energy. Projects must be planned further into the future to ensure designs and energy supply sources are flexible enough to allow on-going operation relatively independent of the energy commodity prices. Thermal operations are the lowest net return so receive the least attention from management, shareholders and support staff.

8 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Overall Energy Efficiency Indicators There are a number of energy efficiency indicators that have been used in thermal heavy oil operations to allow benchmarking of the overall energy efficiency of the recovery process and/or the facility operations. Oil/Steam Ratio (OSR) or the inverse Steam/Oil Ratio (SOR) OSR or SOR are the indicators commonly used by reservoir engineers to compare various steam recovery operations. The ratios compare the volume of oil produced (m3) to the volume of steam injected, in m3 of Cold Water Equivalent (CWE). To be useful as an indicator this assumes that the steam is generated at consistent conditions of pressure, temperature and particularly steam quality (% of the CWE that is turned into water vapour). However, this indicator excludes the electrical and oil processing energy input to the process, and also does not reflect the efficiency of the rest of the process. For similar types of operation, with similar processes, this may give a Energy Inputs - Example Vent Gas 5% Re se rvoir Losse s 10% Power 15% Energy Losses Example Payzone Heating 30% Wellbore Heat Loss 15% Purchased Gas 80% G e ne ra tor Sta ck 15% Power 15% Treater Stack and Aerial Cooling 5% Vent Gas Flare 5% Produced W ater 5% reasonable indication of relative efficiency but can t be used to compare steam processes of various types, or thermal processes, which do not use steam. Energy Input/Energy Output Ratio This type of calculation will provide a more consistent and better indication of the overall energy efficiency of an operation. In this analysis, the potential energy value of all energy exports from a hydrocarbon deposit (might be power, gas or oil) is compared to all the energy inputs into the process to produce the exports including fuel gas, oil combustion, electrical power, vehicle fuel on the lease, etc. The energy balance can be developed for a given production operation, or could be a full cycle assessment right from the virgin reservoir condition to the final end-

9 user of the produced energy streams. The extent of the analysis is determined by what types of operation are compared, as well as what options are assessed. GHG Emissions per Unit of Production As most of the energy used in the upstream oil and gas industry in western Canada comes from combustion of hydrocarbons, the GHG emissions per unit of production will be relatively proportional to energy use. However, some GHG value must be assigned to the imported energy to a site to reflect GHG emissions at the energy source, and GHG associated with energy lost in transmission. Oil/Fuel Gas Ratio As most thermal heavy oil operations mainly use natural gas as fuel, the ratio of oil produced to natural gas used as fuel, can provide an overall indicator of energy efficiency of the overall process. Pro s: Energy efficiency indicators help to show improvement in the operations Assist in comparing thermal operations to operations in other sectors and reservoirs. Gives an indication of the relative risk and economics of an operation as input energy costs increase. Con s: Takes some effort to set up the indicator calculations and educate operations and management on their appropriate use. Only work over a timeframe of years, and not as a short-term indicator, as the impacts of a change in energy use or conservation may not show up in production performance for many months.

10 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Defining Operational Objectives To maximize the benefits of energy reductions in any operation, and to allow relative assessment of energy reduction options, the overall operational objectives of the business must first be defined, and redefined as changes in direction occur in a producer organization. Changes in objectives lead to selection of different alternatives but eventually all will lead to increased profitability of the operation. Reduce Off-site Energy Required (Op Costs) Unlike most energy production operations (coal power, gas, light oil or mined oil sands), thermal in-situ bitumen and heavy oil operations are unique in being heavily dependent on external energy and commodity sources. Many thermal heavy oil operations are at risk unless they can supply large amounts of their energy needs from their own corporate sources in a given province. Maximizing the use of local, corporate energy resources is one method of reducing the risk from wide fluctuations in return from thermal operations. However, a better option may be to reduce the off-site energy needs, which will reduce the risk of the Balancing Objectives Reduce Risk Return on Investment operation having to be shutdown, and free up the other corporate energy sources for external sale. Increase Oil Rate (Cash Flow) Oil rate is the indicator used by most operators to assess their performance, however, higher rates are often achieved at a high cost for small, or short-term incremental gains in oil rate. Some operators have recognized that unexpected peaks in rate can result in product being dumped into the market at a net economic loss. The incremental cost of a unit of production might be very high if it requires a reduction in the energy efficiency of the operation to achieve it. Increased production from all heavy oil sources also tends to depress prices if there is an over supply, as demand is limited by upgrader capacity and seasonal outlets such as asphalt for road paving. As with external energy supplies, producers with their own corporate upgrading capacity will be less affected by low oil prices, than those that have to compete to fill remaining capacity. Cash Flow Op Costs Profitability

11 Increase Oil Recovery (Return on Investment) Increased oil recovery is a longerterm measure of operating performance and is the main indicator of the efficient depletion of the oil resource. Maximizing recovery increases the return on the capital invested in: exploration, drilling and completion of wells, and for surface facilities and pipelines that have little, if any, salvage value once the target heavy oil deposit is no longer economically viable to operate. Health, Safety and Environment (Reduce Risk) Ultimately everything produced from the reservoir will become an emission, as most hydrocarbons produced will turn into carbon dioxide within days or months of leaving the site. Providing sustainable benefits to society would require that the hydrocarbon resources be depleted efficiently with the minimum of waste, while protecting workers, local residents and other organisms from any emissions that might degrade their health or well being. Generally, this will mean balancing reservoir fluid injection with production; and converting emissions to less noxious forms; while maximizing the benefit achieved from investment in capital and energy. While this issue is usually of paramount importance at the project approval stage, meeting the targets at existing operations will smooth approval of future projects and avoid surprises. Pro s: Provides motivation to field and design personnel working to improve operations. Ensures the immediate objectives of the corporation are being satisfied at any given time. Reduces frustration at changes in direction or lack of approval of projects which might have been expected to be approved at a different time when other objectives predominate. Con s: Requires clear and timely communication from upper management when the primary objective for an operation changes. Objectives may be different for different operations within a corporation so communications must clarify and explain the reasons for this. Makes corporate strategies more likely to become common knowledge.

12 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Moving from Overall Assessment to Options Once the information in option sheets have been assessed then work can begin on assessing which options should be considered for implementation and to determine the economics associated with the implementation. As indicated previously not all options will be attractive at the same time or with the various corporate objectives. So for any operation or proposed project the assessment, and conclusions concerning what should be undertaken when, may be different. However, to some degree provision or consideration should be given as to how all appropriate options, for all objectives, might be implemented. The key steps in moving from the overall assessment to determining which options should be studied or advanced at a given time will include the following steps: Given the Operational Objectives what primary result are we trying to achieve at this time for this operation? For example in a time of high energy cost and low product value the objective will likely be to reduce operating costs with minimal capital expenditure. Which Options can help improve the primary objective? Reducing costs might tend to focus on finding lower cost energy supplies (fuel and/or power) using surplus, low cost or leased Overall Assessment à Options Operational Objectives Options that Might Advance Objective Assessment of Energy Source vs. Demand Options with Synergies Work the Economic Cases equipment. So options considered will focus on fuel switching and power generation. What waste energy sources are available that can be used in each of those options? CHO casing vent gas from other operators in the area, thermal vent gas, low value upgrader products or other energy streams might be locally available at low cost to provide fuel and/or power from internal or lower cost external sources. What options for the primary objective will also improve the indicators or improve on other objectives? Using CHO casing or thermal vents also reduce GHG emissions. Work the economic cases for the options that fit best. A focused effort on negotiating supplies of casing vent gas from other heavy oil producers in the area might be negotiated, suggesting to a power utility that the site can be converted to internal power generation might allow discounted power costs for interruptible demand or a lowering of power rates might be negotiated.

13 Pro s: Should allow for flexible but focused assessment of options for an operation in an environment of change. Helps to prioritize focus on issues of greatest importance to the on-going viability of a particular thermal operation. Encourages clear definition of objectives for the organization. Objectives for thermal heavy oil may tend to be the opposite of those for conventional oil and gas operations. E.g. thermal operations better when gas prices and heavy/light spreads are low; conventional operations are better when those factors are high. Con s: Frustration if the objectives change before options are implemented. Staff and skills required for each objective are different and will tend to be in demand at the same time for all parts of an organization responding to the same objective.

14 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Use of Blocking Agents (Tier 1-2) Blocking agents such as foams and gels are used to control water or gas distribution in conventional oil or enhanced oil recovery projects. In thermal operations most of these agents are not able to withstand the high temperatures of the injected steam and quickly breakdown or lose their effectiveness. The high permeability of most heavy oil reservoirs can make it very easy for the steam to move around a static plug once it is placed, so dynamic blocking or periodic injection of blocking agents is likely to be more effective. Some options for thermal operations to help redirect the injected steam or block high permeability channels between wells, which may hinder the steam injection process, are: Fluid Injection Staging (Tier 1) This is any process where fluids with a range of properties are injected in various ways and orders into one or more wells to try and alter the distribution pattern of the hot injected fluids to increase steam contact, and sweep efficiency, in the reservoir. Blocking by injection staging is a dynamic process as it is based on the relative permeability and mobility of the fluids used, rather than statically blocking pore throats. Predicting the impacts, since the properties of the reservoir change with temperature and time, would be difficult and it may be just trial and error to find Inject Liquid the methods that are most likely to enhance oil Sulphur with Steam production and recovery. (120 degrees C) Sulphur (Tier 2) Some attempts 1 have been made to use molten sulphur injection to block high permeability flow channels in the reservoir, usually as a single treatment. Injection of small volumes of molten sulphur (sulphur melting point is 120 degrees C) with steam on a semi-continuous basis may act as a dynamic and static blocker and fill in high permeability channels in bottom water, as it solidifies. The molten sulphur will also Sulphur Flows Down, contribute energy to the formation and once Solidifies & Blocks Water solidified would be an excellent insulator to reduce conduction losses to underlying zones. Currently sulphur markets in Western Canada are extremely depressed so sulphur can be obtained from upgraders or sour gas plants at low cost and trucked to the injection site. Sulphur that has solidified would tend to melt and redistribute itself if steam returned to the same area of the reservoir. 1 This method was tried by Imperial Oil in Cold Lake, however, we are not aware of any published documentation on this trial. Others have suggested sulphur blocking as an area for further study.

15 Gas AWACT (Tier 2) The AWACT process was developed through the Alberta Research Council (ARC) and was intended as a means of preventing water coning into heavy oil producing wells. The process requires injection of high-pressure gas into the water zone of a well, with the theory being that gas will tend to distribute itself at the oil/water interface and reduce water permeability from the bottom water zones. Nitrogen would be a preferred gas and might have synergies with a combustion air enrichment process. Pro s: Help to redirect steam into new areas of the reservoir instead of following established paths and heating depleted portions. Reduces heat and steam losses to bottom water zones and conduction out of the zone. Varying the volumes of blocking agents as injection and production proceed can help to provide some control. Most of the blocking agents suggested are readily available at relatively low cost in most heavy oil production areas. (i.e. water, nitrogen from the air, methane, or sulphur by truck). Use of blocking agents can be carried out with portable equipment so there may be no capital costs involved. Con s: Blocking is very difficult to model in heterogeneous reservoirs, so trial and error will be required, and patience to optimize for a given operation. Some blocking agents may carry through or return to producing wells and cause problems in production or dilute the production. Familiarity with handling the blocking agents, such as sulphur is needed. More Information: Various technical papers on AWACT, sulphur and injection staging stimulation techniques. ARC SRC, CIM, SPE and International Centre for Heavy Hydrocarbons

16 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet: : Gas Blanket (Tier 2) The existence or generation of a gas blanket or gas cap at the top of the reservoir is often seen as a negative factor as it will allow steam to short circuit between wells. However, it should also help reduce heat losses to the overburden and would help provide wider distribution of the steam to allow for a type of steam over-ride operation. The key would be to control steam injection and producing well Inject Steam at operations so that the steam input Lower Rates with matches the energy that can be transferred to the reservoir, rather Some Methane than a fixed rate or volume of steam. This assumes that the gas will tend to be lighter than the steam and provide an insulating effect at the top of the reservoir. Continuous gas injection would avoid steam sweeping the gas out of the reservoir and at the same time can provide dynamic insulation of the injection well. On production the gas would be produced back and can then be recycled. Gas Blanket Gas injection into oil sands reservoirs where formation fracturing is required is not attractive due to the high injection pressures (up to 15 MPa or 2000 psia). However, where steam injection is possible at lower pressures, as in the Lloydminster area, the capital costs of providing compression for gas blanketing and recycle may be attractive. Also many sites may have access to casing gas from conventional heavy oil sites which otherwise would be vented to atmosphere. Pro s: Uses methane as an insulator to reduce energy lost out of formation. Can also provide insulation in injector wellbore. Does not add a new component to production Should help steam migrate to a larger portion of the reservoir with the same volume of steam injected by acting as a carrier gas. Gas injection should be lower in energy cost than a similar volume of steam.

17 Con s: Requires capital for gas compression and distribution to injection sites. Increases the volume of gas circulating and venting from production wells. It will be difficult to predict performance by modeling so patience and experience must be gained to determine the effectiveness of this technique. More Information: Various technical papers on co-current injection techniques. ARC SRC, CIM, SPE and International Centre for Heavy Hydrocarbons

18 Thermal Heavy Oil Vent Gas and Energy Options Sheet Options Sheet : Quenching (Tier 1) Heat losses from the reservoir occur by conduction, which is driven by temperature differentials. As relatively small temperature increases can significantly decrease the viscosity of heavy oil there should be an optimum reservoir temperature that balances heat losses and other negative impacts of high temperature (in-situ upgrading, generation of H2S, and thermal coking), versus energy transferred to the oil to encourage it to flow which is the desired result. These losses would tend to increase as operations continue over time, as the steam will have to move further through the reservoir to contact new cold oil. Quenching consists of injecting steam followed by a hot/warm water chaser to push the steam s energy further into the reservoir, rather than leaving it near the injector where it will add to the conductive heat losses but not contribute to heating new oil. This result in the same net energy input to the reservoir but should reduce the energy losses to the over and underburden by reducing the average temperature of the reservoir. Inject Steam followed By hot/warm water Injection to carry heat further If the process is used in a cyclic operation the initial production will be warm/hot water, so provision must be made for managing this water by quickly injecting it into another well. This will also delay hot oil flowing to the well, as the quench water must be produced first. On a steam-flood operation injection could be rotated between injectors and the water would also help lift the oil into any flow channels that are higher in the formation, so it can flow to the producers. Pro s: Should lower the average reservoir temperature and reduce conductive losses and transfer more energy to the oil-bearing portions of the reservoir. Provides an outlet for produced water which can provide pressure maintenance and voidage replacement in the reservoir. May help oil migrate to producers by displacement.

19 Con s: Can result in increased water production. Water injected to quench should be limited to the volume required for oil voidage replacement to minimize water recirculation and increases in water handling costs. More Information: Various technical papers on quenching studies and projects. ARC SRC, CIM, SPE and International Centre for Heavy Hydrocarbons

20 Thermal Heavy Oil Vent Gas and Energy Options Sheet Options Sheet : Steam Soak (Tier 1) Steam soaking has been suggested as a process to give more time for energy to be transferred from the steam to the oil before the well is turned back to production in cyclic operations. Soaking is a trade-off between calendar day oil rate and energy efficiency. More soak time should result in more of the injected steam thermal energy being transferred to the oil to generate more production, for the same energy input, but takes longer. To increase calendar day rates short soak times use the pressure energy of the steam to rapidly move mobile oil to the well for production, so increase the average oil rate from a given well but at the cost of being more energy intensive. The optimum soak time is very difficult to assess, as it will be a function of many variables, including: Cost for the fuel and energy at the time the steam is injected which is generally higher in winter. Value of the produced oil at the time it is produced which is often higher during the summer. Area of oil zone exposed to the injected fluids that limits the rate of heat transfer, which should increase over time as the heavy oil is produced. Distance the heated oil has to flow to the producing well as the steam affected zone grows. Change in pressure gradients as the steam changes from vapour to liquid. Pay zone thickness and the size of the steam filled chamber. Volume of non-condensable gas that is in the steam zone, which is a function of gas evolution from the oil, gas already present and gas injected. Pro s: Steam soak should be more energy efficient to reduce the energy intensity of the oil production.

21 May be more useful in early cycles when heat transfer area to the oil is small and in later cycles when the oil is further away from the cyclic well. Can be used to allow steam to be injected when fuel costs are lower and produce the oil when prices or spreads are better. Con s: Requires more wells for the same production, as daily rate per well will be lower. May result in larger energy losses to over and under-burden as the average reservoir temperature during the soak period will be higher, although some of the energy may be recovered later in the cycle. Requires development of dynamic reservoir management tools to optimize steam injection and production timing. More Information: Various technical papers on steam soak. ARC SRC, CIM, SPE and International Centre for Heavy Hydrocarbons

22 Thermal Heavy Oil Vent Gas and Energy Options Sheet Options Sheet : Distribution Monitoring (Tier 1) New technologies have now been demonstrated that can help to determine which parts of the reservoir have been affected by steam. This provides the key information required to develop and monitor new injection strategies to improve performance and preferentially direct heat energy to untouched areas of the reservoir. Without this type of monitoring it will be difficult to troubleshoot problems with reservoir performance and it will also be extremely difficult to predict potential impacts of changes in the operating strategies discussed in other option sheets. The two main methods are: Comparative Seismic This method has been utilized by Imperial Oil at Cold Lake, where the oil sands deposits are very large, and homogeneous, over large areas. The technique compares seismic results from steamed and un-steamed areas of the reservoir to determine where steam has penetrated. This is most useful in these large deposits and for areas where seismic of the virgin reservoir is not available. Virgin Reservoir w Gas Cap 4D Seismic A series of seismic surveys taken with consistent methods and along the same survey lines can be used to determine where steam has accessed the deposit over time and, similar to comparative seismic, After X Years of Steaming help direct future steam operations. This method is better for new projects so that a baseline survey can be conducted. Other potential sources of data are from temperature observation wells and from coring infill wells. The main information provided by these methods will be in assessing the impacts of changes in geologic structure on the vertical steam distribution in the reservoir, but the value is more limited and generally these options are higher cost than seismic. Pro s: Is one of the few methods of determining what is happening in the reservoir Relatively inexpensive if it is planned for in advance of operations.

23 Should allow for much greater control of the operation and allow some potential to avoid problems such as steam breakthrough between wells. Should increase recovery by ensuring that most areas of the reservoir will receive some heating from the steam and avoid premature abandonment of steaming. Con s: Requires pre-planning of seismic work. Requires that seismic be repeated on an area every few years to allow timely adjustment of operational strategies. More complex analysis techniques than is required for most conventional operations. More Information: Seismic services contractors Reference materials from CIM, SPE and others.

24 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet: : Hot Water Flood (Tier 2) Produced water can often represent a significant loss of energy from thermal or other heavy oil process. Water requires twice the energy to heat up than oil or bitumen does, and, if there are no convenient heat sinks for the energy, it is often disposed of to an injection zone. This energy could be utilized to heat or pre-heat the reservoir by the use of a hot water flood rather than sending the water to a disposal zone where the energy will be lost, and has no chance of contributing to production. Hot produced water from thermal operations in Lloydminster type formations could be used in adjacent field areas for hot water flooding. Non-producing areas, no longer used for thermal operations, or cold flow producing areas near the thermal operations could benefit from injection of hot produced water to generate incremental production. In cold flow areas surplus vent gas could be used to further heat the produced water. As the viscosity of heavy oil decreases logarithmically with increasing temperature, even a small temperature increase should enhance production. Traditionally, there would be a concern that water would finger, which would reduce the ability of the water to push oil to producing wells, however, cold heavy oil cannot be pushed until it is heated and fingering will improve heat transfer to the oil. A recent paper on a geothermal hot water flood in Indonesia 1 shows the type of study needed to determine the impact of water temperature on the performance of a flood with temperature sensitive oil. As in the case of a geothermal hot water source, a hot water flood in conjunction with a thermal heavy oil operation takes advantage of the availability of a low cost hot water source, so no additional energy needs to be input. If CHO casing gas is available additional water heating might be desirable but is not a necessary component. Warm/Hot Water Tier 2 1 mmbtu/hr = 1000 m3/d 70% eff Can heat 100 m3/d of water by 100 deg C How many m3 oil would this add to production? T= C P= kpa Watered out Well Line Heater Casing Vent Gas T=65-80C Surface PCP Lease Produced Water Storage Avoids Produced Water Disposal Equipment costs are minimal, as the water is already hot and being pumped into a disposal zone. All that is required is an insulated line to a waterflood injector or recompletion of the disposal well into the producing formation or target zone for heating. 1 SPE 68724, Geothermal Hot-Water Flood Balam South Telisa Sand, Sumatra, Indonesia by John M. Pederson, and Jayadi H. Sitorus of PT Caltex Pacific Indonesia.

25 Potentially produced water could be also be used as a heat transfer fluid for recovering energy from the steam generation and treater stacks. To avoid the acidic conditions that cause corrosion in the stack gases as they are condensed, the produced water might be used to dilute the acid by spraying it into the waste heat recovery units. The produced water will pick up energy from the stack gases as it cools them, it should also absorb some of the SO2, CO2 and NOx emissions which will go into solution. The heated produced water stream could then be injected into the reservoir as a hot water flood or used as a heat source for an Organic Rankin Cycle power generation system., before going to injection or disposal. Pro s: Hot produced water likely contains 5-10% of the energy input by the steam generators and is wasted in a disposal zone. Increased oil production possible at very low cost. Water will also maintain reservoir pressure through voidage replacement Equipment to change where the water is injected should be minimal and limited to insulated lines or recompletion work If CHO casing gas is available or waste heat from generators then water can be pressurized and heated to degrees C with no need for softening. Con s: More water will be circulating so WOR s will likely increase. Water injection locations will likely have to be changed over time. Effects of relative mobility are more difficult to model. More Information: Papers and reservoir engineering texts cover many aspects of water flooding which is a mature technology. Use of low cost waste energy sources and hot water flooding in shallow, low temperature formations is newer. Reference materials from CIM, SPE and others.

26 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet: : Zonal Preheat (Tier 2) Zonal preheating would also make some use of the energy that has already been invested in producing hot water. In this case the hot water would be used to try and reduce heat losses from the steam injection. It would also tend to allow steam to become more evenly distributed in the producing reservoir by making it easier for the steam to penetrate the upper and lower parts of the oilbearing formation across the entire reservoir. Hot Water Injection Hot produced water could be injected into bottom water zones or any water zone above or below the oil producing formation that are preferably only separated by thin shale barriers, so that flow in the zones is segregated, but thermal energy transfer is supported from the hot water to the cold oil bearing reservoir. The heating would reduce the temperature gradient out of the producing reservoir and provide some heating to all of the area where the two zones are superimposed. This provides some thermal benefit without the problem of the water having to be produced again on surface and re-circulated. Pro s: Produced water is not re-circulated but more energy is input or stays in the target producing zone. Provides some potential to effectively utilize the 5-10% of the waste energy in the produced water disposal stream. May just require re-completion of existing disposal wells. Distribution of the heat in the water bearing formation(s) will tend to be aerially more uniform than heat injected into an oil rich zone. May be very little change in operation.

27 Con s: Greater risk of communication or creating communication channels between zones. Will need to work with regulators as this may or may not be a problem. Highly dependent on the location and local stratigraphy in the reservoir. Zones may not be entirely segregated or isolated from each other. Complicates thermal modeling as fluid properties in one zone might be affected by heat flow in another zone. More Information: Some studies have been done on thermal energy transfer between producing and non-producing zones. Reference materials from CIM, SPE and others.

28 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet: : Continuous Injection for Pressure Maintenance (Tier 1) Gas injection for EOR is distinguished from vent gas injection in that the gas used may not be from the vent stream, may be focused on a smaller number of injection wells and would be a more controlled process rather than the opportunistic vent gas reinjection. Generally gas injection for EOR is not thought to be particularly effective in cold heavy oil or bitumen wells but may be useful in thermal operations. This type of injection would be similar to standard practices in conventional light oil reservoirs. The gas would be injected into a high feature in the reservoir structure, such as a gas cap. The gas pressure would help to force heated oil to the producing wells, would serve as a barrier to heat transfer out of the reservoir and help ensure that the injected steam Methane Reinjection (Tier 1) 1000 m3/d gas à 900 m3/d gas injection Assume 10% of gas needed for fuel Vent Gas T= o C P= kpa Methane does not just fill a large volume where there may be no potential for incremental oil recovery. Pressure Injection Compressors required would likely be quite low Watered out (Vent Gas for Fuel) Water Reduction and would be a function of how Well producing wells near the gas injectors are operated. Pro s: Gas injection would only be into a limited number of injection wells rather than every producer. CHO casing vent gas may be readily available for injection and as fuel for compressors. Lloydminster type operations generally do not require high injection pressures. Con s: Heavy oil must be heated before it can be moved to any great extent by gas pressure. Once gas breaks through to a producer it will be difficult to retain the gas in the reservoir as many producing wells are completed over the entire oil bearing

29 zone and isolating flow in the zone with well recompletions is not likely to be successful. More Information: Compressor suppliers. Reference materials from CIM, SPE and others.

30 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet: : Pressure Cycling (Tier 2) Some have proposed pressure cycling for non-thermal heavy oil to allow the oil to be recharged with gas to support continued cold flow production. This type of process may also help in thermal operations, although the benefit may be a result of providing drive energy to move oil to the producing wells rather than inducing gas back into solution. It would also be necessary to have a relatively isolated area or inject the gas with the steam (Option ) into the reservoir. The pressures would have to be able built up and care must be taken that the injected gas is not just being vented from adjacent producing wells. The mechanism may be more like a pneumatic pumping system or blowcase to assist oil flow and increase calendar day oil rates, rather than affecting the properties of the oil. M o n t h s Pro s: Gas could be cycled with only the amount used as fuel actually consumed. Process may increase calendar day oil rates at a lower input energy cost than injecting more steam and avoiding soak time to do the same thing. Gas used would not have to be treated any more than is necessary to allow it to be compressed and injected. Low cost if another waste energy source (letdown of high repressure steam or eductor systems) can be used to compress the gas for injection. Can provided dynamic insulation if it is injected with the steam. Con s: More gas will be cycled through the process. May be difficult to predict performance in this type of operation Gas Injection Cycle Number Production

31 Performance will likely be a strong function of the reservoir characteristics and may be less effective in thick pay zones. More Information: SRC has been investigating pressure cycling in conventional heavy oil wells. Reference materials from CIM, SPE and others.

32 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Static Insulation of Tubulars (Tier 1) The use of insulated tubulars or an insulating medium in the annulus between the tubing and casing has potential to reduce heat losses on production and injection. Farouq Ali and Meldau, developed a comparison of heat losses on injection based on various types of insulation in the annulus as follows: Conditions: Depth 2000 ft (615 m), Pressure 1000 psig (7 MPa), Rate 500 bbls steam/day (14 m3/d), Time 30 days, Tubing 2-7/8, Casing 7 Insulation Provided Heat Losses (%) Casing Temp ( o C) No Insulation 24% 290 Gas Pack 20% 230 Vented Annulus 17% 200 Crude Oil Gel 10% 140 Solid Insulation 6% 90 The above table is based on an isolated annular space so that the injected steam is not allowed to enter the well annular space between the tubing and casing. Without an isolated annulus the heat losses may not be reduced, as steam will tend to enter the annulus and condense on the casing, resulting in little or no change in casing temperature and therefore conductive heat loss. Static Insulation of Tubulars Model for Static Losses Casing Temp Varies with Insulation Actual with Open Annulus Casing Temp = Steam Temp Pro s: Work well in a steam flood with dedicated injector wells Provide higher insulation and less heat lost than other options. Insulation effect can be calculated. 1 As reported by Aurel Carcoana in Applied Enhanced Oil Recovery, Prentice Hall 1991, page 33.

33 Con s: Requires a packer that allows for tubing expansion on heating and contraction on cooling. Insulated strings are more expensive. Insulation used must be able to withstand high temperatures ( degrees C) More Information: Insulated tubing suppliers. Reference materials from CIM, SPE and others.

34 Thermal Heavy Oil Vent Gas and Energy Options Sheet Option Sheet : Dynamic Insulation of Tubulars (Tier 2) One potential method of insulating the annulus during steaming and early production stages would be to inject the steam down the well tubing and co-currently inject natural gas down the well annulus. The gas injection rate could be quite low, enough to ensure steam is kept out of the annulus, and the gas would be injected with the steam into the reservoir and should be recovered during the production cycle. Since the gas is flowing downward any energy it acquires from the tubing will be transferred to the reservoir and the well casing can be cooled to reduce heat losses. On the production cycle gas injection could continue down the annulus if the well is able to flowback or flump (flowing but with the pump going to assist the flow) of if a multi-phase pumping system can be used. Hot Water Methane Steam Methane It is assumed that the effect of dynamic insulation would be similar to something intermediate to a gas pack or vented annulus calculations in option This might reduce heat losses by 15-20% compared to an open annulus without dynamic insulation. Pro s: No change in downhole equipment Can be easily used on cyclic steam stimulation wells in steaming and early production phases. Gas addition may also help reduce heat losses in the reservoir and provide other benefits. See options , and Con s: Requires surface compression and gas lines to all wells. Pressure required for insulating gas is set by steam injection pressure. More Information: