Vol 1 Section 4 Bitumen Recovery Process - alberta.ca · SECTION 4.0 – BITUMEN RECOVERY PROCESS ... • reservoir pressures at which circulation is maintained. Typical steam circulation

Cenovus TL ULC Telephone Lake Project Volume 1 – Project Description December 2011

Table of Contents

SECTION 4.0 – BITUMEN RECOVERY PROCESS TABLE OF CONTENTS

PAGE

4.0 BITUMEN RECOVERY PROCESS ............................................................................... 4-1 4.1 Introduction ......................................................................................................... 4-1 4.2 SAGD Process ................................................................................................... 4-1

4.2.1 Start-up Operations ............................................................................ 4-3 4.2.2 Ramp-up ............................................................................................ 4-7 4.2.3 Conventional SAGD Operations ........................................................ 4-7 4.2.4 Blowdown Operations ........................................................................ 4-8

4.3 Dewatering Process ........................................................................................... 4-9 4.3.1 Dewatering Process Description ........................................................ 4-9 4.3.2 Field Testing History ........................................................................ 4-12 4.3.3 Dewatering Process Benefits ........................................................... 4-12

4.4 Recovery and Oil In Place ................................................................................ 4-13 4.4.1 Producible Oil in Place and SAGDable Oil in Place ......................... 4-13 4.4.2 Drilling Constraints and Bypassed Pay ............................................ 4-13 4.4.3 Drainage Pattern Layouts ................................................................ 4-14

4.5 Scheme Design and Forecast .......................................................................... 4-15 4.5.1 Reservoir Properties ........................................................................ 4-15 4.5.2 Development Sequence ................................................................... 4-16 4.5.3 Scheme Design Basis ...................................................................... 4-18 4.5.4 Well Pad Wind-Down Plans ............................................................. 4-22 4.5.5 Adding Future SAGDable Oil in Place ............................................. 4-23 4.5.6 Recovery Forecast ........................................................................... 4-23


Table of Contents

TABLE OF CONTENTS (cont)

PAGE

LIST OF TABLES

Table 4.5-1: Project Reservoir Properties .......................................................................... 4-15 Table 4.5-2: Telephone Lake PPA Development Sequence .............................................. 4-19 Table 4.5-3: Typical SAGD Well-Pair Parameters ............................................................. 4-25 Table 4.5-4: Typical SAGD Well-Pair WP1 Performance Data .......................................... 4-25 Table 4.5-5: Typical SAGD Well-Pair WP2 Performance Data .......................................... 4-29 Table 4.5-6: Typical SAGD Well-Pair WP3 Performance Data .......................................... 4-29 Table 4.5-7: Typical Telephone Lake Dewatering Pattern Performance Data ................... 4-31

LIST OF FIGURES

Figure 4.2-1: Steam Assisted Gravity Drainage Stages ........................................................ 4-2 Figure 4.3-1: Conceptual View of the Top Water Dewatering ............................................. 4-10 Figure 4.3.2: Conceptual Operation of the Dewatering Procedure ..................................... 4-11 Figure 4.5-1: The Viscosity Temperature Relationship for Dead Oil ................................... 4-17 Figure 4.5-2: Layout of Project Facilities ............................................................................. 4-20 Figure 4.5-3: Typical SAGD Well-Pair WP1 Performance Profile ....................................... 4-26 Figure 4.5-4: Typical SAGD Well-Pair WP2 Performance Profile ....................................... 4-27 Figure 4.5-5: Typical SAGD Well-Pair WP3 Performance Profile ....................................... 4-28 Figure 4.5-6: Typical Telephone Lake Dewatering Pattern Performance Profile ................ 4-30 Figure 4.5-7: Active Dewatering Pad Areas at Six Years (December 2024) ....................... 4-32 Figure 4.5-8: Active Dewatering Pad Areas at Twelve Years (December 2030) ................. 4-33 Figure 4.5-9: Annual Top Water Dewatering Production Forecast ...................................... 4-34 Figure 4.5-10: Cumulative Top Water Dewatering Production Forecast ............................... 4-35 Figure 4.5-11: Annual SAGD Injection and Production Forecast .......................................... 4-36 Figure 4.5-12: Cumulative SAGD Injection and Production Forecast ................................... 4-37 Figure 4.5-13: Annual Top Water Air Injection Forecast ....................................................... 4-38 Figure 4.5-14: Cumulative Top Water Air Injection Forecast ................................................. 4-39


Page 4-1

4.0 BITUMEN RECOVERY PROCESS

4.1 Introduction

Cenovus TL ULC (Cenovus) plans on applying the steam assisted gravity drainage (SAGD) process at the Telephone Lake Project (Project). Experience and technologies developed at the Christina Lake Thermal Project (CLTP) and Foster Creek Thermal Project (FCTP) will be incorporated into the Project. Parallel to the SAGD process, Cenovus will employ, where required, a dewatering process (Cenovus patent pending) to mitigate the impact of the (Middle McMurray Top Water Zone). As discussed further in Section 4.3, it is planned that dewatering activities are expected to start about one to two years prior to initiating SAGD.

4.2 SAGD Process

The Project will use the SAGD recovery process to produce bitumen from the McMurray Formation. At the FCTP and CLTP, SAGD has been demonstrated as a high efficiency recovery process that employs gravity drainage and takes advantage of good vertical communication within the reservoir due to high vertical permeability. The SAGD process utilizes dual horizontal well-pairs that are drilled in parallel with about 5 m of vertical separation. The lower production well is drilled horizontally and close to the bottom of the bitumen zone within the McMurray Formation. Steam is injected in the upper injection well, located 5 m above the production well. Steam injection generates a high-temperature vapour chamber which heats the surrounding bitumen, allowing it to drain by gravity into the lower production well. Historically, the earliest commercial in situ recovery process in the oil sands was cyclic steam stimulation (CSS). The presence of top water in the Middle McMurray, as well as the lack of vertical impediments to flow, gives the SAGD process an advantage over CSS. Other advantages of the SAGD process include:

• appreciably higher recovery efficiency;

• greater energy efficiency, which translates to a lower steam requirement per barrel of bitumen produced, or lower steam-oil ratio (SOR); and

• ability to operate closer to the initial reservoir pressure (and top water pressure) in a steady manner, in contrast to CSS with its higher pressure steam cycling.

Cenovus’s current commercial SAGD process involves four stages of operations, which are start-up, ramp-up, conventional SAGD and blowdown operations. An additional stage, called co-injection, occurs between the conventional SAGD and blowdown stages when a non-condensable gas such as air or methane is co-injected with the steam. This is described further in Section 4.2.4. A typical SAGD progression is illustrated in Figure 4.2-1.

Source: Cenovus.

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4.2.1 Start-up Operations The Project will employ conventional circulation start-up and enhanced start-up operations to start SAGD well-pairs. The conventional start-up stage of SAGD establishes thermal and hydraulic communication between the SAGD injection and production wells. At initial reservoir conditions, there is negligible fluid mobility due to a bitumen viscosity of over 1,000,000 centipoise [mPa-s], and a lack of water-saturated zones within the SAGD interval. Inter-well communication is established by simultaneously circulating steam through both the injector and producer wells. High-temperature steam flows through a tubing string that extends to the toe of each horizontal well. The steam condenses in the well, releasing heat and resulting in a liquid water phase which then flows up the casing-tubing annulus due to pressure gradients. Maximum bottomhole pressure for circulation start-up of a SAGD well-pair will be limited to 90% of the fracture pressure at the depth of the specific SAGD injection well. This is calculated to be 90% of the product of the depth of the SAGD injector and the Clearwater caprock fracture gradient of 21 kPa/m. Water volumes injected into and produced from the wells during circulation will be continuously monitored along with bottomhole pressures and the total net injection into the formation will be limited to 500 m3 during the steam circulation period. Conduction is the main heating mechanism during the start-up stage. There is also a differential pressure applied between the injector and producer, to promote movement of fluid, as well as heat, between the wells. Start-up steaming operations are maintained until the bitumen region between the injection well and production well becomes mobile. The time required to establish fluid communication is well-pair dependent and relates to:

• injector-to-producer well separation along the horizontal well length;

• near-wellbore reservoir quality;

• injected steam temperatures; and

• reservoir pressures at which circulation is maintained. Typical steam circulation time is 120 days. 4.2.1.1 Enhanced Start-up Operations The start-up period may be accelerated using several different methods—namely, cold water dilation, steam dilation (Cenovus patent pending), solvent soaking, and electrical heating. These are referred to as enhanced start-up operations. Cold water or steam dilation is used to create a dilation zone vertically connecting the SAGD well-pair without significant propagation elsewhere. The dilation zone is created with a short-period, small-volume and high-pressure injection targeting the area near the SAGD wells. Effectively, the inter-well region will have increased porosity, permeability and water saturation. After the inter-well communication is established, well-pairs can be transitioned to normal SAGD operations.


Page 4-4

Solvent soak, used before and/or after circulation start-up, will reduce the viscosity of the oil and reduce the start-up time. By placing an electrical heater along the lateral portion of a horizontal well, the inter-well region is conductively heated. This is similar to conventional circulation start-up with the exception the energy source is electrical as opposed to steam. Consequently, the well-pair can be started up before steam facilities are commissioned. These start-up techniques are in various stages of testing at both the FCTP and CLTP. Based on information from these operations, Cenovus intends to optimize the overall start-up procedure at the Project using any combination of the following:

• conventional circulation start-up;

• cold water dilation start-up;

• steam dilation start-up;

• solvent enhanced start-up (Cenovus patent pending); and

• electrical heating start-up. Benefits of improved start-up techniques are a faster ramp-up, a better use of steam capacity, and a lower cumulative steam-oil ratio (CSOR). Reducing the CSOR results in reduced emissions intensity, reduced water handling intensity, and reduced fuel gas consumption intensity (intensity referring to ‘per barrel of oil produced’).

4.2.1.2 Cold Water Dilation Enhanced Start-up Operations

The start-up stage may be reduced by dilating the inter-well region briefly. Cenovus has demonstrated that dilation start-up of a SAGD well-pair is achievable in the McMurray Formation with minimal risk of the dilated region propagating out of the McMurray Formation as demonstrated in the tests conducted at CLTP (ERCB Approval No. 8591R). To execute a cold water dilation start-up on a well-pair, Cenovus would inject water into the injection well and the production well. Estimated injection rates could be 1,000 m3/d or greater per well, as long as the maximum bottomhole pressure of 120% of the fracture pressure at the depth of the specific SAGD injector is not exceeded. Net injection volume into the formation will be limited to a maximum of 500 m3. The bottomhole pressure response and thermocouple data would be continuously monitored to observe the dilation zone and the development of communication between the wells. It is expected that the pressure in both the wells will slowly ramp up and then level off or decline slightly.


Page 4-5

At that point, water injection will continue in one of the wells, while the pressure response from the other well will be observed for communication between the wells. During this time, the pressure in the well with water injection is expected to ramp up slowly before levelling off while the other well’s pressure is expected to fall off and then increase before levelling off and track the injection well’s pressure. After the pressures in the two wells have been tracking for several days all water injection will be terminated and dilation of the inter-well region is expected to have been accomplished. Production of water from either the injection well or the production well may be used to promote and analyze the communication between the well-pairs. After a dilation zone is created between the two wells, Cenovus would then inject steam into the lower and/or upper well to heat up the inter-well region. It is likely that oil will fill the increased porosity and cool (bitumen banking effect), potentially eliminating the inter-well communication created by dilation. Steam injection into the lower well is less likely to cause this effect, as the mobilized oil has to descend through the hot formation rather than be pushed through cold formation. Tar banking remains a potential problem and it is anticipated that steam may need to be injected at high enough pressure to cause further dilation of the inter-well region in order to achieve start-up of the well-pair. In addition, production of condensed steam from either well may be used to promote more uniform dilation along the well-pair length and will limit the water volumes flowing out of the inter-well region. Thirty or more days of steam injection in the lower well is required to sufficiently heat the inter-well region so that SAGD operations can commence.

4.2.1.3 Steam Dilation Enhanced Start-up Operations

In steam dilation (Cenovus patent pending) start-up of a SAGD well-pair, Cenovus would inject steam in both the injection and production wells. The required steam rate is estimated to be from 150 m3/d to 300 m3/d (cold water equivalent (CWE)) but higher steam rates may be injected, if required, with the constraint that the bottomhole pressure cannot exceed 120% of the fracture pressure at the depth of the SAGD injection well. Net injection volume into the formation will be limited to a maximum of 500 m3 CWE. The bottomhole pressure in both wells will slowly be increased up to formation break-down pressure to help promote dilation along the well length. It would be expected that once dilation is observed the well-pairs will be in communication and the well pressures would begin tracking. Steam injection will continue during this period to heat up the inter-well region with the option to inject in both wells, or either the injection or the production well to achieve an effective well start-up. Thirty or more days of steam injection would be sufficient to heat this region so that the well-pair can be transitioned to the ramp-up stage. Production of condensed steam from either the production or the injection well may be used to promote uniform dilation along the well-pair length. Flow back rates also aid in understanding the level of communication between the well-pairs. There may be slight variations from the above procedures, as the dilation start-up techniques will be further optimized using information from the CLTP.


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4.2.1.4 Solvent Enhanced Start-up Operations

For the standard start-up operations at the Project (Section 4.2.1), steam is circulated in each well-pair until the bitumen between the injector and producer is mobilized. The duration of this start-up stage may be reduced if each wellbore is soaked with a relatively small volume of solvent prior to steaming. The solvent mixes with the formation bitumen in the near wellbore area, reducing its viscosity; therefore, lower temperatures are required to mobilize this affected bitumen. As a result, less steam will be required to initiate the ramp-up stage of SAGD operations (Section 4.2.2). Solvent enhanced start-up (Cenovus patent pending) techniques are currently being implemented with positive results at the FCTP, and are in the testing stage at the CLTP, with positive results to date. The Project’s start-up technique will be chosen after documenting key information from the CLTP and FCTP, including the following:

• how a solvent enhanced start-up compares to traditional circulation;

• how different soak times impact the start-up performance;

• what effect solvent enhanced start-up has on the ramp-up stage of the SAGD process; and

• the impact that solvent-bitumen mixtures returning to the central processing facility (CPF) will have.

This information will enable Cenovus to better formulate a comprehensive solvent enhanced start-up strategy to ultimately lower the cumulative SOR for the Telephone Lake Project. Pending results from FCTP and CLTP, it is Cenovus’s intent to inject up to 100 m3 of solvent into each of the producer and injector. The solvent will soak into the formation for a period of one week to one year before conventional steam-circulation is initiated. During the soak period, back pressure will be applied at the wellhead using a nitrogen bottle to maintain a bottomhole pressure, limited to a maximum of 90% of the fracture pressure at the depth of the SAGD injector. It is anticipated that all of the solvent will be produced back during the ramp-up stage. The solvent described above may include xylene or other light hydrocarbon fluids such as toluene, diesel, butane, pentane, hexane, diluent, condensate, or any combination thereof. 4.2.1.5 Electrical Heating Enhanced Start-up Operations Electrical Heating Enhanced Start-up consists of installing a downhole electrical heater, which will conductively heat the reservoir between the injector and producer wells to aid communication. Within the tool, electrical energy transported via a cable is converted into a magnetic field which induces conductive heating. Physically this is the same conductive heating as conventional circulation start-up. As such, the time required is similar, approximately 120 days. However, no steam facilities or infrastructure are required. In a typical SAGD project,


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the wells are drilled several months before steam injection facilities come online; electrical heaters may be used during this time frame to reduce the cumulative SOR and proceed to the SAGD ramp-up stage.

4.2.2 Ramp-up

After communication has been established between the SAGD injection and production wells, often over a limited section of the well-pair length, steam is injected into the injection well at constant pressure while mobilized oil and water are removed from the production well. During this period the zone of communication between the wells is expanded axially along the full well-pair length and the steam chamber grows vertically up to the top of the bitumen zone. In the Proposed Project Area (PPA), the bitumen zone is often overlain by a Top Water Zone which can vary in thickness from 0 to 20 m typically, with a maximum thickness of 44 m. This top water is detrimental to the efficiency of the SAGD process and would result in an increased cumulative SOR. Therefore, where the clean water sands are between 5 and 20 m thick, Cenovus plans to mitigate this negative effect by dewatering the Top Water Zone, and replacing the water with air (Section 4.3). Once the ramp-up stage starts, the steam chamber pressure will be limited to the maximum operating pressure (MOP; defined in Section 4.5.3.2) until the steam chamber reaches the top of the pay zone, at which time the pressure will be reduced and maintained at a pressure that is in balance with, or slightly above, the pressure in the dewatered Top Water Zone at that location. When the inter-well region over the entire length of the well-pair has been heated and the developed steam chamber has reached the reservoir top, the oil production rate peaks and begins to decline while the steam injection rate reaches a maximum and levels off.

4.2.3 Conventional SAGD Operations

After the ramp-up stage, the steam chamber has essentially achieved full height, although it may still be rising very slowly through or spreading around lower permeability zones in some locations. Lateral growth becomes the dominant mechanism for recovering oil. As the steam chamber widens, overburden heat losses consume an increasing portion of the heat from injected steam, leading to declining oil production rates at steady steam rates (or possibly steady oil rates with increasing steam rates). Typically, steam is injected into the injection well and controlled to maintain a target steam chamber pressure during this stage, and the production well remains submerged in draining oil and steam condensate. During this stage, the steam chamber pressure will be maintained in balance with or slightly over-balanced compared to the pressure in the overlying top water or the artificially created air zone at that location. Well pairs will produce more water than steam injected during this stage due to the water saturation in the Top Water Zone. Even after dewatering (Section 4.3), it is expected that approximately 20% additional water volume will be produced.


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The rate of fluid withdrawal from the lower production well is partly based on a target production temperature so that an appropriate fluid level generally remains above the producer. This operating strategy prohibits excessive steam from short-circuiting the SAGD process and flowing directly from the injection well to the production well, which can also damage down-hole completions. It is anticipated that conventional SAGD operations will be sustained until the optimal amount of heat has been supplied to the well-pair. When this occurs at least 50% of the producible oil in place (POIP), as defined in Section 4.4, will have been produced, and the steam injection will be ramped down to zero.

4.2.4 Blowdown Operations

Once steam injection is terminated, a non-condensable gas (expected to be air) is injected into the steam chambers to maintain pressure. This activity is subject to Energy Resources Conservation Board (ERCB) approval; thus, Cenovus expects to apply for blowdown as required at a later date. During blowdown, bitumen production continues with operations maintained under the same control scheme employed in conventional SAGD. Bitumen production rates decline over time as the growth rate of the steam front slows under gas injection. Currently the CLTP operates with an air gas cap overlying the bitumen zone, with no negative impacts to SAGD operations. The oxygen is consumed in an exothermic reaction with the residual oil, producing carbon dioxide as a byproduct. There has been no oxygen produced in the producer wells, and no observed change in oil quality once the SAGD chambers intersect the air gas cap. There is a slight change in produced gas composition as more carbon dioxide is produced. In addition to this experience, Cenovus has tested air injection directly into the steam chamber at the A4 well-pair at CLTP (ERCB Application No. 1426253 dated 21 September 2005; ERCB Approval No. 10441 dated 20 December 2005). No oxygen was produced in this pilot, and there was no change to the produced bitumen quality. In short, Cenovus expects no negative impacts from air injection into the steam chamber, and considerable benefits in steam generation fuel gas savings. Blowdown production operations are anticipated to continue until bitumen production declines to an uneconomic rate, at which time approximately 65% of the POIP is expected to have been produced. After blowdown, consideration will be given to producing and re-using the non-condensable gas for dewatering future pads. Note that Cenovus would transition from conventional operations to blowdown by injection of a non-condensable gas comingled with steam at the wellhead. Steam volumes are reduced during co-injection, subject to a minimum steam-gas injection ratio, with gas added in rates sufficient to maintain a desired chamber pressure. Cenovus would submit to the ERCB an application for co-injection in the future as required.


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4.3 Dewatering Process

Much of the bitumen zone in the PPA has an overlying non-saline Top Water Zone with a thickness varying from 0 to more than 20 m with a maximum of 44 m (Volume 1, Section 3.4.1). To improve the efficiency of SAGD in the PPA, this Top Water Zone will be dewatered where the clean water sand ranges from 5 to 20 m in thickness. The process involves a combination of water production, water reinjection, and air injection to reduce the water saturation above the SAGD area, essentially creating an air gas cap. Expected benefits of dewatering are described in Section 4.3.3.

4.3.1 Dewatering Process Description

The commercial dewatering plan involves drilling repeatable well patterns above SAGD pads to replace the top water with air. A typical well pattern will roughly match the size of a SAGD well pad’s drainage area (approximately 800 m x 800 m) and consist of:

• two or more horizontal water production wells placed near the water-bitumen contact;

• one horizontal air injection well placed near the top of the water zone; and

• up to four horizontal water reinjection wells placed near the top of the water zone and at the edge of the pattern to confine the air gas cap being created. An isolated pattern would, therefore, require four horizontal wells.

Figure 4.3-1 shows the air gas cap created by dewatering the Top Water Zone overlying SAGD operations. Figure 4.3-2 shows the conceptual operation of the dewatering process which would start one to two years prior to SAGD start-up when required. The dewatering process will be initiated by producing water from the water production wells creating a lower pressure area at the base of the Top Water Zone. Simultaneously, a non-condensable gas (air) will be injected into the clean water sand via the horizontal air injection well to replace the voidage created by the water production wells. A portion of the produced top water will be returned to the perimeter water reinjection wells. The purpose of these wells is to ensure water is injected into the top of the reservoir on the edge of the dewatering area in order to prevent air from over-riding the water. In the early stage of dewatering, it is anticipated more water will be pumped out of the Top Water Zone than is reinjected into the Top Water Zone. Excess top water produced from the reservoir will be injected into the underlying Lower McMurray water zone or handled by alternate means as described in Volume 1, Section 10.5.2. Cenovus estimates that dewatering will be required at 54 of the 90 planned SAGD well pads. The distance from the water producer to the offsetting water injection well is a function of the operating pressure of the air cap, the water thickness, the water production rate and the water injection rate. In general the required distance between these wells decreases as the water thickness decreases, the pressure in the air cap is reduced, and/or the rate of water injection and production increases.

Source: Cenovus.

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4.3.2 Field Testing History Beginning in 2007, Cenovus has executed various short-term field tests in the Middle McMurray top water and bitumen zones near the Clearwater zero-edge during the winter drilling seasons (these tests are described in letter applications dated 20 December 2007 and 17 January 2008, which comprise ERCB Application No. 1557122; the ERCB approved the application in a letter dated 23 January 2008). The objectives of these tests were to improve the understanding of the bitumen reservoir and Top Water Zone properties, and to support the design of a commercial Project recovery process. The testing programs in the past have included the following:

• nitrogen (95% N2, 5% O2) injection tests in 2007 and 2008 into the Middle McMurray Top Water Zone at various locations to determine injectivity and potential for water displacement and gas over-ride and containment, both vertically and laterally;

• minifracs in the Clearwater caprock and in the McMurray Formation to investigate fracture gradients and orientation (Volume 1, Section 3.4.2); and

• hydraulic interaction testing of the Middle McMurray, Lower McMurray, and Quaternary Lower Sand (S1) water (Volume 1, Section 3.5.3).

In addition to the short-term testing described above, Cenovus applied to Alberta Environment and Water (AENV) and the ERCB in May 2011 for approval to conduct a dewatering test commencing in 2012 for a duration of 6 to 12 months (AENV Application No. 001-00292198 and ERCB Application No. 1689991). The dewatering test will be a field-scale test of the commercial dewatering process proposed herein. In November 2011, Cenovus received approvals to conduct the dewatering test from both AENV (Water Act Approval No. 00299973-00-00 dated 1 November 2011) and the ERCB (letter dated 2 November 2011). As a condition of these approvals, Cenovus will submit a final report to AENV and the ERCB summarizing the results of the dewatering test within 120 days of the conclusion of the test. The main differences between the commercial design and the 2012 test are:

• as opposed to an isolated field test, the commercial scheme will consist of repeatable dewatering well patterns, and, as such, contiguous patterns will only require reinjection wells on the outer edges of the combined area;

• surface facilities will not be temporary; • the dewatering test has a limited duration; and • the overall dewatering pad area will be larger (800 m x 800 m), compared to the 600 m x

600 m test pattern.

4.3.3 Dewatering Process Benefits

The expected benefits of dewatering are as follows:

• increase in recoverable resource. Cenovus could pursue bitumen recovery in areas of thicker top water that would otherwise be avoided;

• lower SORs. Ultimately a lower SOR reduces natural gas and water consumption, reduces greenhouse gas emissions intensity, and overall the bitumen production rate increases;


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• reduced impact on non-saline top water. The bulk of the top water that is removed during dewatering has not been in contact with the injected air, and thus remains in its natural state. It will be reinjected into the Top Water Zone away from the development areas and/or injected into the underlying Lower McMurray formation, which has comparable water quality. In a non-dewatering case, overlying top water would be produced through the SAGD chamber, thus requiring additional water treatment and disposal and resulting in higher SORs; and

• the use of the water production/water reinjection wells will also act as a hydraulic barrier between the dewatered area above the SAGD wells and the surrounding aquifer.

Several years of testing, monitoring, and discussion with the ERCB and AENV on this proposed process have culminated in the planned dewatering test that is scheduled to commence operations in 2012.

4.4 Recovery and Oil In Place

4.4.1 Producible Oil in Place and SAGDable Oil in Place

Cenovus defines POIP as the amount of resource associated with a well-pair from the production well elevation to the top of the SAGD zone, over the actual drainage length. Cenovus uses POIP as a benchmark for blowdown timing for well-pairs that have been drilled and are producing. Cenovus uses SAGD-able oil in place (SOIP) for the development planning, sequencing and field optimization of well-pairs before drilling and completing, as well as an indicator of resource volumes amenable to recovery by drilling additional wells such as bypassed pay wells.

4.4.2 Drilling Constraints and Bypassed Pay

Cenovus constrains the drilling of well-pairs for various reasons to achieve optimum well-pair performance. At times, these constraints lead to areas of bypassed pay beneath the production well. The following list details the drilling constraints Cenovus uses for all of its well-pairs:

• a depth separation of 5 m is used between the injection well and production well;

• standard SAGD well-pair is 800 m in length, but when necessary, well-pairs will be shortened and/or lengthened as required;

• lower production well profile is generally targeted about 1 m above the SAGD base. If bottom water exists (without a shale break), placement will be adjusted where there is concern over increased aquifer inflow. Currently, there is no evidence of bottom water in the PPA. The Firebag Coal Zone, where present, will provide a good datum for SAGD production well placement;

• production well profiles are typically planned with less than 5 m of relief so that no part of the production well can be at a higher elevation than any part of the injection well;

• profile directional changes in the horizontal section are typically planned at less than 6°/30 m to minimize drilling and completion difficulties such as slotted liner placement;


Page 4-14

• wellbore elevation drops during drilling can occur, especially near the toe;

• borehole-position and reservoir uncertainty will contribute to operational adjustments during drilling;

• proposed well profiles will likely be different from final drilled/surveyed trajectories;

• standard liner design consists of two blank joints at the heel, with the majority of the first one contained within the intermediate casing, and a blank joint at the toe. Within the remaining slotted interval, one out of every six joints is blanked to act as partial strain absorbers;

• in addition it is Cenovus’s practice to blank sections of the injection liner where the injector is placed too close to the production well. This ensures that a hot spot will not develop at that location. Cenovus does not expect any reduction in recovery from the well-pair in this situation; and

• in sections where there is uncertainty in the presence or extent of permeability barriers which could significantly affect well placement decisions, it is Cenovus’s practice to drill open-hole sidetracks to further evaluate the reservoir and then re-evaluate the trajectory based on this additional information while drilling.

Encountering non-reservoir rock of up to 100 m in length is not detrimental to the recovery factor for the well, as the steam chamber will develop over that area and drainage will occur into the production well on either side. If non-reservoir rock is encountered unexpectedly while drilling a production well, Cenovus would steer the well up within the drilling constraints to try and place the well above the non-reservoir facies. If a portion of non-reservoir rock greater than 100 m in length is encountered, an attempt to sidetrack the well trajectory to come up over the poor facies will be made to gain a larger percentage of effective pay along the well length. This well trajectory change is typically about 1 to 2 m. One or several of these constraints can lead to situations where there is excessive bypassed pay beneath a production well. Cenovus plans to drill future bypassed pay production wells (Section 4.5.4.2), based on the character of the bypassed pay contour map, to exploit this resource. These wells will allow Cenovus to increase the POIP of their respective well pads, and to take advantage of heat in the ground that is conducted below existing producers, leading to improvement in the CSOR, as this heat would be otherwise lost.

4.4.3 Drainage Pattern Layouts

The Project’s pattern of well pads and well-pairs was determined by jointly minimizing the SOR and maximizing the volume swept by the suite of well pads proposed. These criteria are explained in more detail below. Horizontal SAGD well trajectories are subject to constraints, such as maximum elevation change along the length of the well, as well as maximum rate of change of elevation. Cenovus’s current understanding of SAGD is that the former constraint is required for efficient bitumen


Page 4-15

recovery, whereas the latter constraint is imposed by the mechanics of drilling. In addition, Cenovus constrains well-pairs to penetrate a minimum SAGD thickness of 8 m to ensure wells meet an economic threshold, and that drainage areas do not overlap to ensure drilling cost efficiency. An estimated trajectory from the elevation of the SAGD pay base surface is calculated for every proposed well-pair. The volume drained is estimated by the distance from the producer to the top of the SAGD pay multiplied by the distance between adjacent well-pairs. Cenovus then estimates the SOR of the well-pair. Both volume and SOR are compared for a variety of different possible layouts, and then an optimal layout is selected. This approach minimizes the amount of steam needed to develop the region, and reduces emissions. After an initial layout has been chosen, a second tier of wells is planned to increase the reservoir sweep. These wells often cover the thinner SAGD pay areas. The above constraints show that the varying thickness of the SAGD pay, coupled with the topography of the base of the SAGD pay elevation surface, impose limitations on possible horizontal well-pair layouts. These limitations influence the orientation of pads, as well as the lengths of the horizontal wells. Pay that is identified as unswept on the chosen well-pair layout will be flagged for subsequent bypassed pay and use of Wedge Well™ Technology (Section 4.5.4). Final consideration is given to the location of lakes, rivers and other surface features. The expected surface pad site is determined from the heel location from any given set of horizontal wells. Depending upon the nature of the surface constraints, pads can be moved a relatively short distance and well trajectories revised, or a new layout is generated if the constraint is too large.

4.5 Scheme Design and Forecast

4.5.1 Reservoir Properties

Cenovus will target the McMurray Formation for production operations. Typical reservoir parameters for the Project are presented in Table 4.5-1.

Table 4.5-1: Project Reservoir Properties

Parameter ValueTemperature [°C] 8 Initial Reservoir Pressure [kPa] 1,200 Depth to top of bitumen reservoir [m]1 129 – 332 m TVD Oil saturation [%] 80 Porosity [%] 34 Horizontal permeability [D] 11 Ultimate recovery [% of POIP] 65 (approx.)

1 See Volume 1, Section 3.4.1.


Page 4-16

4.5.1.1 Oil and Gas Properties

The McMurray Formation within the PPA contains bitumen with American Petroleum Institute gravity ranging from 6 to 8. Dead oil viscosity, at initial reservoir conditions, is over 1,000,000 cP. The reservoir is believed to be gas saturated at initial pressure such that the virgin bitumen contains the maximum dissolved gas at those reservoir conditions. Although difficult to measure accurately due to the gravity of the bitumen, Cenovus expects the gas-to-oil ratio to be 2 to 6 m3/m3. At steam zone conditions, there is not expected to be any significant effect of the gas on the oil viscosity (Figure 4.5-1).

4.5.2 Development Sequence

The initial pads to be developed will be in sections 7, 8, 17 and 18-094-03W4M. These pads were chosen for the following reasons:

• relatively thin top water, thus minimizing initial dewatering requirements;

• close proximity to the CPF in section 21-094-03W4M;

• presence of the full Clearwater caprock thickness; and

• a thick bitumen pay zone. The first five pads in the development sequence do not require dewatering. The first pad requiring dewatering is TL05 at sequence #6 with a steam start date of September 2019, and a likely dewatering start date in 2018. Knowledge gained from the dewatering test will be incorporated in the dewatering design for this pad and subsequent dewatering pads and facilities. Development will progress to the east into sections 2, 3, 9 and 10-094-03W4M, with a sequence largely dictated by the same parameters. The final areas to be developed will be the southernmost pads in sections 20 and 27-093-03W4M, followed by pads in the northeast quarter of Township 094-03W4M. Cenovus is adopting a staged approach to development near the Clearwater zero edge in the Northeast corner of the PPA. In the proposed development plan, a significant offset from the Clearwater zero-edge is planned, as the nearest SAGD development will be a minimum of:

• 2.5 km away up to April 2038 (up to pad TL73 at sequence #57, as shown in Table 4.5-2);

• 1.0 km away up to March 2041 (up to pad TL97 at sequence #64);

• 600 m away up to July 2046 (up to pad TLS14 at sequence #80); and

• pads from sequence #81 to 90 are a minimum 200 m away from the Clearwater zero-edge and are currently not scheduled to be developed until August 2046.

Source: Cenovus.

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Figure4.5-1

ANALYST:

PROJECT:

CE0339901

December 2011



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Page 4-18

The geology in the Northeast portion of the PPA as described in Volume 1, Sections 3.4.1 and 3.4.2 outlines how the Clearwater formation has been eroded, reducing its thickness from 70 to 0 m at the Clearwater zero edge. Adjacent to the Clearwater zero edge is the presence of the Quaternary Lower Sand (S1) unit, which is overlain by the Quaternary Upper Till (T2), which in turn is overlain by the Quaternary Upper Sand (S2) unit. Hydraulic testing, groundwater level monitoring, and groundwater sampling have demonstrated that groundwater in the S1 sand is hydraulically connected and is generally of similar quality to the Middle McMurray Top Water Zone. Moreover the Upper Quaternary Sand Unit groundwater is not hydraulically connected to the Lower Quaternary Sand Unit or to the Middle McMurray Top Water Zone due to the presence of the thick and low permeability Quaternary Upper Till (T2) unit (Volume 1, Section 3.5). However, development in this region will not proceed until additional testing is done to further demonstrate that the Quaternary Upper Sand (S2) will not be impacted by SAGD or dewatering operations near the Clearwater zero edge. Additional data will be provided through hydraulic tests, groundwater monitoring, results from the dewatering test and the initial dewatering pads. Table 4.5-2 outlines the pad development sequence, and pad locations are outlined in Figure 4.5-2.

4.5.3 Scheme Design Basis

As described in Sections 4.2 and 4.3, the current commercial recovery scheme incorporates, where required, a dewatering process and the four stages of SAGD operations—start-up, ramp-up, conventional SAGD, and blowdown.

4.5.3.1 Well Length and Spacing

Cenovus is expecting to use an inter-pair spacing of approximately 67 m for the initial implementation of the Project. This spacing is within the optimum range to balance the reserves developed by a single well-pair and the scheme CSOR. As the spacing is increased, oil recovered from a single well-pair increases; however, as depletion time increases, additional heat loss occurs and the CSOR increases. The sum of the well and steam costs typically reaches a minimum over a broad range of 50 to 200 m for many different reservoir assumptions. For a given reservoir quality, the optimum is a function of the commodity prices and is, therefore, impossible to determine with precision over the life of the Project. In view of these considerations, 67 m will be used initially, but future well-pairs may be drilled at distances from 50 up to 200 m. The dewatering pattern is expected to cover the drainage area of a SAGD well pad – typically 800 m x 800 m. In event of larger or smaller pads, the dewatering pattern size will vary accordingly.


Page 4-19

Table 4.5-2: Telephone Lake PPA Development Sequence

Pad Pad Sequence

Dewater or No Dewater

Steam Start

(mmm-yy) Pad Pad

Sequence Dewater or No Dewater

Steam Start

(mmm-yy) TL29 1 No Dewater Apr-18 TL12 46 Dewater Feb-35 TL08 2 No Dewater Apr-18 TL81 47 Dewater Apr-35 TL64 3 No Dewater Apr-18 TL55 48 Dewater Nov-35 TL65 4 No Dewater Sep-19 TLS17 49 Dewater Mar-36 TL23 5 No Dewater Sep-19 TL13 50 No Dewater May-36 TL05 6 Dewater Sep-19 TL06 51 No Dewater Sep-36 TL78 7 Dewater Mar-21 TL84 52 Dewater Oct-36 TL14 8 No Dewater May-21 TL61 53 Dewater Apr-37 TL04 9 Dewater Jun-22 TLS23 54 No Dewater Jul-37 TL79 10 Dewater Sep-22 TL18 55 Dewater Oct-37 TL59 11 Dewater Oct-22 TL99 56 No Dewater Jan-38 TL26 12 Dewater Dec-22 TL73 57 No Dewater Apr-38 TLS20 13 Dewater Mar-24 TL16 58 No Dewater Sep-38 TL63 14 Dewater May-24 TL40 59 No Dewater Mar-39 TL56 15 Dewater Jun-24 TL34 60 Dewater Oct-39 TL89 16 Dewater Sep-24 TL31 61 No Dewater May-40 TL74 17 Dewater Jun-25 TL25 62 Dewater Aug-40 TLS15 18 No Dewater Aug-25 TL02 63 No Dewater Dec-40 TL85 19 Dewater Sep-25 TL97 64 Dewater Mar-41 TL67 20 Dewater Nov-25 TL24 65 No Dewater Oct-41 TL88 21 Dewater Mar-26 TL91 66 Dewater Jan-42 TLS10 22 Dewater Mar-27 TL50 67 No Dewater Mar-42 TL46 23 Dewater May-27 TL75 68 Dewater Mar-43 TL48 24 Dewater Aug-27 TLS11 69 No Dewater Jun-43 TL103 25 Dewater Oct-27 TL53 70 No Dewater Sep-43 TL51 26 Dewater Jun-28 TLS12 71 No Dewater Jan-44 TL07 27 Dewater Sep-28 TLS01 72 Dewater Jul-44 TLS16 28 Dewater Nov-28 TLS08 73 No Dewater Oct-44 TLS04 29 Dewater Mar-29 TLS31 74 No Dewater Jan-45 TLS09 30 Dewater Feb-30 TL105 75 No Dewater Mar-45 TLS19 31 Dewater Jun-30 TLS28 76 No Dewater Apr-45 TL41 32 No Dewater Aug-30 TL70 77 Dewater Jan-46 TL83 33 Dewater Nov-30 TLS25 78 Dewater Apr-46 TL20 34 Dewater May-31 TLS33 79 No Dewater Jun-46 TL77 35 Dewater Sep-31 TLS14 80 Dewater Jul-46 TLS02 36 Dewater Nov-31 TL32 81 No Dewater Aug-46 TL101 37 No Dewater Jan-32 TL106 82 Dewater Oct-46 TL87 38 No Dewater Dec-32 TL44 83 Dewater Nov-46 TL21 39 Dewater Apr-33 TL93 84 No Dewater Jun-47 TLS22 40 No Dewater Jul-33 TL28 85 No Dewater Oct-47 TL72 41 Dewater Sep-33 TL17 86 Dewater Dec-47 TL19 42 No Dewater Apr-34 TL39 87 Dewater Mar-48 TL95 43 Dewater Jul-34 TL49 88 Dewater Aug-48 TL90 44 Dewater Oct-34 TL96 89 No Dewater Apr-49 TL47 45 Dewater Dec-34 TL01 90 No Dewater May-49

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TL74TL04

TL21TL59

TL47

TL16TL32

TL50 TL49

TL78

TL106

TL105

TL101

TL103

TLS11

TLS33

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TLS12

TLS25

TLS08

TLS16TLS09

TLS14

TLS17TLS22

TLS23

TLS20TLS15

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LegendProposed Project Area

Open Water

Watercourse

Project LayoutBorrow Pit

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Camp

Dewatering

Disposal

Laydown

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Project ROW

SAGD Only

SAGD/Dewatering

±

Source: Cenovus, Spatial Data Warehouse Ltd.

QA/QC:

KW

December 2011

CE0339901

PROJECT:

ANALYST:

Figure4.5-2

KW

Fig04.05-02 Project Layout

11-12-14

DATE:

LR EH AMEC

FINAL MAPPING BY:PROVIDED BY:

AMEC

PROJECTION/DATUM:

UTM Zone 12 NAD83Layout of Project Facilities

1 0 1 20.5

Kilometres1:110,000

Cenovus TL ULCTelephone Lake Project


Page 4-21

The maximum length of SAGD well-pairs is constrained primarily by hydraulic considerations. Both flow rates and the distance travelled scale up with the pairs’ length, so that, for a given size of tubular, eventually too large a pressure gradient will arise in the liners or tubulars. The practical length depends upon the quality of the reservoir, (i.e., the expected flow rates per unit length), the operating pressure and the liner diameter. Based on a liner diameter of 178 mm, Cenovus is planning 800 m well-pair lengths for the initial Project development but may use up to 1,200 m well-pair lengths in certain cases to allow for optimization of net pay area coverage. As discussed in Section 4.4.3, the drainage pattern layout has been optimized to jointly maximize the value of each well-pair as well as maximizing the volume swept by the suite of well pads.

4.5.3.2 Operating Pressures

Clearwater caprock thickness over the SAGD pad development areas in the PPA varies from 16 to 78 m (Volume 1, Section 3.4.1). The depth to the base of the Clearwater caprock (or the Top of the McMurray Formation), over the PPA, ranges from 99 to 310 m (Volume 1, Section 3.4). As discussed in Volume 1, Section 3.4.2, Clearwater minifrac tests resulted in a consistent fracture gradient of 21 kPa/m. Cenovus is planning to operate the steam chambers over a range of bottomhole pressures; however, there are essentially three pressure conditions: initial high pressure during the start-up stage, followed by a ramp-up stage limited to the MOP, followed by a low pressure during the conventional SAGD stage and blowdown stages. This is similar to the operating strategy employed at the CLTP. A description of the SAGD stages is provided in Section 4.2. Operating pressures for the start-up stage will be determined on a per pad basis, as discussed in Sections 4.2.1 and 4.2.2. After the start-up stage, there will be no significant steam chamber development; thus, the pressure will drop quickly. The pressure will fall off significantly while shut down for the electric submersible pump (ESP) installation, and will continue to decline as production is initiated. Thus, in advance of starting steam injection for the ramp-up stage, the pressure will decline to the MOP. For the ramp-up and conventional SAGD stages, the MOP will be 1,660 kPa. This is based on the shallowest depth (99 m) to the base of Clearwater caprock in the PPA, a fracture gradient of 21 kPa/m, and 80% factor of safety. Similarly, the MOP in the Top Water Zone due to dewatering activities will be 1,660 kPa. The Top Water Zone is highly mobile and is at a reservoir pressure of approximately 1,200 kPa. Cenovus expects this pressure to be reduced with the application of the dewatering process. Therefore, the higher steam injection pressures during start-up will not reach the caprock. If the steam chamber intersects the Top Water Zone at a higher pressure, it will simply lose pressure and steam to the dewatered Top Water Zone. Furthermore, this situation is not expected to arise, as high steam injection pressures will only be used for start-up steam circulation, which will be completed with approximately 90 days of steaming, and total net steam injection will be limited to 500 m3 CWE during this period. Starting at the beginning of the ramp-up stage, steam chamber pressures will be maintained below 1,660 kPa.


Page 4-22

During the lower pressure stage after the steam chamber reaches the top of the oil pay, steam chamber pressures will equalize with the top-water pressure in the range of 800 to 1,400 kPa, with an absolute maximum of 1,660 kPa. This pressure range will apply during the conventional SAGD period and the blowdown period. To monitor the impacts of dewatering and SAGD, Cenovus will be installing heave monitors on the surface at selected well pads. In summary, Cenovus is requesting two operating pressures: a high pressure based on specific well parameters during the start-up stage, and a lower limit based on field-wide MOP during ramp up, conventional SAGD operations and blowdown.

4.5.3.3 Artificial Lift

After start-up operations, ESP systems will be used for artificial lift. This choice relates to the relatively shallow and low pressure formation. In addition, ESPs provide greater operational flexibility during turnarounds and unexpected shutdowns.

4.5.4 Well Pad Wind-Down Plans

Cenovus plans to prepare a wind-down strategy for each well pad after allowing for sufficient time to evaluate the well pad’s SAGD performance. This strategy will optimize well pad recovery and thermal efficiency. The optimization will include expected timing and corresponding oil production volume at which Cenovus plans (after receiving necessary approvals from the ERCB) to:

• drill any additional wells on each well pad, including bypassed pay producers and Wedge Well™ Technology as necessary;

• proceed to well pad-wide non-condensable gas co-injection; and

• proceed to well pad-wide full blowdown. It is anticipated that these strategies will be reviewed periodically with the ERCB in advance of all application submissions to ensure that there is agreement on the appropriate balance between oil recovery and thermal efficiency.

4.5.4.1 Wedge Well™ Technology

Cenovus does not plan on using its patented Wedge Well™ Technology everywhere in the Project due to the well-pair spacing of 67 m. However, there may be specific cases where Wedge Well™ Technology is required due to poor well placement, poor recovery factors, or if economics justify the additional capital costs.


Page 4-23

4.5.4.2 Bypassed Pay Producers

As described in Section 4.4.2, Cenovus intends to evaluate future bypassed pay producer opportunities to increase the POIP of a well pad.

4.5.4.3 Co-Injection as a Transition to Blowdown

In association with well pad wind down plans, all the original well-pairs on a pad would transition from SAGD to full blowdown. Cenovus plans to implement co-injection (Sections 4.2.4) to perform this transition, and will apply for co-injection as required.

4.5.5 Adding Future SAGDable Oil in Place

Cenovus will pursue developing future opportunities in the PPA, including previously unidentified resource, secondary pay zones adjacent to the resource being developed, areas of thicker top water, and resources stranded areally between developed SAGD well pads and/or along the edges of the defined resource base. Cenovus could drill vertical production wells, horizontal production wells, or horizontal well-pairs, as dictated by factors such as location and geology. Cenovus will continue to evaluate the economics of such opportunities based on pay quality, proximity to infrastructure, and proximity to existing heated zones (steam chambers). If deemed economic, using this ‘unrecovered’ heat to access the resource would enable Cenovus to increase the ultimate recovery of the Project. Note that infill producers/well-pairs, whether accessing a secondary pay zone or resource stranded between adjacent pads, would be assessed their own POIP and SOIP, and would be subject to well pad wind-down plans of their own.

4.5.6 Recovery Forecast

4.5.6.1 Analytical Model Performance Forecasting

A proprietary analytical model has been developed (and is periodically updated) to calculate the expected performance of the well-pairs. The model is derived from historical field performance at the CLTP and can be applied over a range of reservoir parameters such as well length and spacing, formation thickness, top water thickness, dewatering, reservoir quality and operating pressures. The SAGD performance is predicted using these analytical models based on reservoir quality and anticipated operating pressure for specific well-pair locations. The performance predictions are then used to plan the number of well-pairs required at any stage of the development to maintain full steam capacity usage and replace older well-pairs as they move into blowdown. Typical well-pair parameters and estimated performance are presented in Section 4.5.6.3.


Page 4-24

4.5.6.2 SAGD Description Model

Peak Oil Rate

The peak oil rate (Qo) is calculated via a correlation developed from Butler’s equation and sensitivity studies performed using numerical simulation:

Qo = [(H/Hi)a × (K/Ki)b × (∆So/∆Soi)c × (Ø/Øi)d × (L/Li)e × (μ/μi)f] × Qoi where: H = SAGD pay thickness [m]; K = formation permeability [D]; ∆So = mobile oil saturation; Ø = formation porosity; L = drainage length [m]; μ = bitumen viscosity [mPa-s] at steam chamber saturation temperature; a,b,c,d,e,f = sensitivity-derived exponents; and i = subscript denoting standard, base case, parameters to which specific parameters

are normalized.

Cumulative Steam-Oil Ratio

The CSOR at the end of the steaming period is determined from an empirical correlation:

where: dT = steam chamber temperature – initial reservoir temperature [°C] Hlv = latent heat of vapourization at steam chamber pressure [kJ/kg] Φ = formation porosity dSo = initial oil saturation – steam chamber oil saturation H = SAGD pay thickness [m] Cvr = 2,150 (constant) Ce = 22,000 (constant) t = time to end of steaming period in years K = constant For a particular pattern geometry, the parameter “t” encompasses start-up circulation (120 days), the chamber rise stage (H/0.08 m/d), and the steaming stage to 55% recovery. By knowing calculated peak oil at the end of the ramp-up stage, CSOR at 55% recovery, and assuming an oil decline rate, a full performance profile can be calculated from the above assumptions and correlations. For the cases where top water is present, the SAGD steam and water calculations use a modified SAGD height that includes the top water thickness in combination with an oil rate that is calculated based on only the oil pay thickness, resulting in increased SOR and WOR. The constant K is modified for cases where less than 5 m of top water is present and dewatering is not planned, which impacts the steam and produced water forecasts.

⎥⎦⎤

⎢⎣⎡ ⋅+⋅

⋅⋅⋅⋅

≈ tHCeCvr

dSo)1000(HlvdTK CSORφ


Page 4-25

4.5.6.3 Typical SAGD Well-Pair Performance

Typical well parameters used for the Project are provided in Table 4.5-3. Typical Well-Pair WP1 has no top water. Typical Well-Pair WP2 has 15 m of top water that is dewatered. Typical Well-Pair WP3 has 15 m of top water that is not dewatered.

Table 4.5-3: Typical SAGD Well-Pair Parameters

Parameter Units Well-Pair WP1 Well-Pair WP2 Well-Pair WP3Well-Pair Length m 800 800 800 Well-Pair Spacing m 67 67 67 SAGD Pay Thickness m 20 20 20 Top Water Thickness m 0 15 15 Dewatering Yes/No No Yes No Oil Saturation % 80 80 80 Porosity % 34 34 34 Permeability D 11 11 11 SAGD Operating Pressure1 kPa 1,300 1,300 1,300 SAGDable Oil In Place (SOIP) m3 301,594 301,594 301,594 Producible Oil In Place (POIP)2 m3 282,933 282,933 282,933 1 Operating pressure is expected to be between 1,000 kPa and 1,660 kPa. 2 Assumes producer is 1 m offset from the base of SAGD.

The example data sets for typical SAGD well-pairs (Table 4.5-3) result in estimated SAGD well-pair performance profiles shown in Figures 4.5-3 to 4.5-5 and Tables 4.5-4 to 4.5-6.

Table 4.5-4: Typical SAGD Well-Pair WP1 Performance Data

Year Average Rates (m3/d) Cumulative Volumes (m3) Recovery

Factor (%)

CSOR (m3/m3) Oil Water Steam Oil Water Steam

1 87 234 234 31,830 85,261 85,261 11 2.68 2 155 260 260 88,320 180,014 180,014 29 2.04 3 154 243 243 144,502 268,845 268,845 48 1.86 4 112 107 32 185,215 307,894 280,690 61 1.52 5 41 35 0 200,289 320,815 280,690 66 1.40 6 20 17 0 207,575 326,865 280,690 69 1.35 7 12 10 0 211,870 330,377 280,690 70 1.32 8 8 6 0 214,701 332,671 280,690 71 1.31 9 4 3 0 216,263 333,931 280,690 72 1.30

Source: Cenovus.

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Figure4.5-3

ANALYST:

PROJECT:

CE0339901

December 2011



Well Pair WP1 Performance

0

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SAGD Pay Thickness: 20 m

Top Water Thickness: 0 m

Dew ater ing: No

Source: Cenovus.

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Bitum

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Pro

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4\F

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AG

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PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-4

ANALYST:

PROJECT:

CE0339901

December 2011



Well Pair WP2 Forecast

0

50

100

150

200

250

300

350

400

450

500

0 12 24 36 48 60 72 84 96 108

Time (Months)

Rate

s(m

3 /d)

0

1

2

3

4

5

CS

OR

(m3 /m

3 )

Oil

Water

Steam

CSOR


Top Water Thick ness: 15 m

Dewatering: Yes

Source: Cenovus.

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4 -

Bitum

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Pro

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ig04.0

5-0

5\F

ig04.0

5-0

5 S

AG

D.c

dr


PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-5

ANALYST:

PROJECT:

CE0339901

December 2011



W ell Pair WP3 Performance

0

100

200

300

400

500

600

700

800

900

0 12 24 36 48 60 72 84 96 108

Time (Months)

Ra

tes

(m3

/d)

0

1

2

3

4

5

CS

OR

(m3/m

3)

Oil

Water

Steam

CSOR


Top Water Thick ness: 15 m

Dewatering: No


Page 4-29



Factor (%)


1 86 277 262 31,385 100,983 95,585 10 3.05 2 153 430 378 87,085 257,868 233,562 29 2.68 3 153 431 379 142,785 415,246 371,971 47 2.61 4 113 211 142 183,999 492,369 423,690 61 2.30 5 39 49 0 198,202 510,311 423,690 66 2.14 6 19 23 0 205,103 518,538 423,690 68 2.07 7 11 13 0 209,181 523,264 423,690 69 2.03 8 7 8 0 211,874 526,334 423,690 70 2.00 9 4 5 0 213,214 528,012 423,690 71 1.99



Factor (%)


1 85 386 338 30,934 140,801 123,441 10 3.99 2 150 777 598 85,832 424,275 341,576 28 3.98 3 150 780 600 140,730 709,005 560,678 47 3.98 4 107 280 172 179,768 811,114 623,495 60 3.47 5 37 59 0 193,138 832,501 623,495 64 3.23 6 18 28 0 199,667 842,575 623,495 66 3.12 7 11 16 0 203,536 848,441 623,495 67 3.06 8 7 11 0 206,095 852,282 623,495 68 3.03 9 3 4 0 207,075 853,744 623,495 69 3.01

4.5.6.4 Dewatering Pattern Performance

The dewatering performance is based on a proprietary analytical model. The dewatering system performance is estimated based on a configuration of wells that would include a single air injector, two water producers and two to four water reinjectors that would dewater an area approximately 64 ha (one quarter section) above a single SAGD well pad. This would represent the typical volume requirements for dewatering a single pad of SAGD wells. The individual configuration of wells for the dewatering system, however, will depend on the local top water thickness and the local structural geology. Areas where the clean water sand thickness is less than 5 m or greater than 20 m are not planned to be dewatered in the current development plan. A typical dewatering performance profile for a top water thickness of 10 m over 64 ha, or approximately one SAGD pad, is shown in Figure 4.5-6 and tabulated in Table 4.5-7.

Source: Cenovus.

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Pro

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6\F

ig04.0

5-0

6 D

ew

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ring.c

dr

Typical Telephone LakeDewatering Pattern Performance Profile NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-6

ANALYST:

PROJECT:

CE0339901

December 2011



Typical Telephone Lake Dewatering Pattern Performance

0

1000

2000

3000

4000

5000

6000

7000

8000

0 200 400 600 800 1000 1200

Time (Da ys)

Wa

ter

Ra

te(m

3/d

)

0

10

20

30

40

50

60

70

80

90

100

Ga

sR

ate

(e3

m3

/d)

Produced Water Re-injected Water Air Injection


Page 4-31

Table 4.5-7: Typical Telephone Lake Dewatering Pattern Performance Data

Year Dewatering Pattern Cumulative Net Water

Production (m3)

Water Production Rate (m3/d)

Water Reinjection Rate(m3/d)

Air Injection Rate(Se3m3/d)

1 2,964 882 27 760,200 2 1,154 799 5 889,600 3 921 796 2 935,200

Note: Water to be reinjected into the Top Water Zone. 4.5.6.5 Field Scale Development The commercial scheme will include the following aspects:

• the SAGD well pads that will require dewatering are indicated on Figure 4.5-2 (which shows the overall Project footprint) and in Table 4.5-2; 54 of the 90 proposed SAGD well pads are currently anticipated to require dewatering prior to the initiation of SAGD in the bitumen zone. As described in the previous sections, only areas with greater than 5 m, and less than 20 m, of clean water sands in the Top Water Zone are planned for dewatering;

• dewatering drainage patterns will typically overlay the SAGD pad drainage areas that are generally 800 m x 800 m in size. However, some perimeter water reinjection wells will have their own surface locations; and

• the typical SAGD well pad with dewatering requirements will have the following horizontal wells: an air injector, up to three water producers and up to four water reinjectors.

The first SAGD pads to be dewatered will be isolated patterns. Each pad will have the required air injectors and water producers, and be surrounded with perimeter water reinjectors to confine the air to the dewatered zone. As adjacent SAGD pads are started-up, the corresponding Top Water Zone must be dewatered. In this case, new perimeter wells are drilled around the expansion pads, and the existing wells are retained, shut-off or converted to water producers or air injectors. Hence, the dewatered zone will expand outwards, encompassing new contiguous SAGD pads as they are added. Figure 4.5-7 and Figure 4.5-8 show the areal extent of the predicted active dewatering area after approximately six and twelve years of dewatering, respectively. In these figures, the dewatered area is outlined in blue. Figure 4.5-9 and Figure 4.5-10 show the estimated annual and cumulative top water dewatering production forecast over the life of the Project. In these figures, the “Produced Water” is the total water removed from the Top Water Zone by the water production wells, the “Re-injected Water” is the water re-injected back into the Top Water Zone to confine the injected air, and the “Net Water” is the difference between the “Produced Water” and the “Re-injected Water”, and this surplus top water will be sent to the CPF for processing and disposal (Sections 4.3.1 and Volume 1, Section 10.5.2). Figure 4.5-11 and Figure 4.5-12 show the estimated annual and cumulative SAGD injection and production forecast over the life of the Project. Figure 4.5-13 and Figure 4.5-14 show the estimated annual and cumulative top water air injection forecast over the life of the Project.

Source: Cenovus.

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Active Dewatering PadAreas at Six Years (December 2024) NA

PROJECTION/DATUM:


AMECEHEH


11-12-13

KW

Figure4.5-7

ANALYST:

PROJECT:

CE0339901

December 2011



Source: Cenovus.

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4 -

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ecovery

Pro

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5-0

8\F

ig04.0

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8 D

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dr

Active Dewatering PadAreas at Twelve Years (December 2030) NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-8

ANALYST:

PROJECT:

CE0339901

December 2011



Source: Cenovus.

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s\V

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1 S

ection 0

4 -

Bitum

en R

ecovery

Pro

cess\F

ig04.0

5-0

9\F

ig04.0

5-0

9 D

ew

ate

ring.c

dr

Annual Top Water DewateringProduction Forecast NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-9

ANALYST:

PROJECT:

CE0339901

December 2011



Telephone Lake Dewatering Rates

(Phases A&B)

0

5,000

10,000

15,000

20,000

25,000

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

2056

Year

Rate

(m3/

d)

Produced Water Re-injected Water Net Water

Source: Cenovus.

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4 -

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ecovery

Pro

cess\F

ig04.0

5-1

0\F

ig04.0

5-1

0 D

ew

ate

ring.c

dr

Cumulative Top Water DewateringProduction Forecast NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-10

ANALYST:

PROJECT:

CE0339901

December 2011



Telephone Lake Dewatering Cumulative Production

(Phases A&B)

147

98

48

0

20

40

60

80

100

120

140

160

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

2056

Year

Cum

ula

tive

Volu

me

(MM

m3)

Produced Water Re-injected Water Net Water

Source: Cenovus.

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4 -

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ecovery

Pro

cess\F

ig04.0

5-1

1\F

ig04.0

5-1

1 S

AG

D.c

dr

Annual SAGDInjection and Production Forecast NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-11

ANALYST:

PROJECT:

CE0339901

December 2011



Telephone Lake Production Rates(Phases A&B)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2018

2021

2024

2027

2030

2033

2036

2039

2042

2045

2048

2051

2054

2057

2060

Year

Oil,S

tea

m,

Wate

rR

ate

(m3

/d)

0

20

40

60

80

100

120

140

Gas

Rate

(e3

m3

/d)

Produced Oil Steam Produced Water Produced Gas

Source: Cenovus.

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1 S

ection 0

4 -

Bitum

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ecovery

Pro

cess\F

ig04.0

5-1

2\F

ig04.0

5-1

2 S

AG

D.c

dr

Cumulative SAGDInjection and Production Forecast NA

PROJECTION/DATUM:


AMECEHEH


11-12-14

KW

Figure4.5-12

ANALYST:

PROJECT:

CE0339901

December 2011



Te lephone Lake Cumulativ e Volumes

(Phases A&B)

0

100

200

300

400

500

600

700

800

900

1,000

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

2056

2058

2060

Year

Oil,

Wate

r,S

team

,Gas

Cu

mu

lati

ve

Volu

me

(MM

m3)

Cumulative Water Cumulative Steam Cumulative Oil Cumulative Gas

Source: Cenovus.

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s\V

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1 S

ection 0

4 -

Bitum

en R

ecovery

Pro

cess\F

ig04.0

5-1

3\F

ig04.0

5-1

3Top W

ate

r.cdr

Annual Top WaterAir Injection Forecast NA

PROJECTION/DATUM:


AMECEHEH

DATE: Fig04.05-13 Top Water

11-12-14

KW

Figure4.5-13

ANALYST:

PROJECT:

CE0339901

December 2011



Telephone Lake Dewatering Air Injection Rate (Standard Conditions)

(Phases A&B)

0

20

40

60

80

100

120

140

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

2056

Year

Rate

(e3

m3/d

)

Air Injec tion

Source: Cenovus.

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s\V

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1 S

ection 0

4 -

Bitum

en R

ecovery

Pro

cess\F

ig04.0

5-1

4\F

ig04.0

5-1

4Top W

ate

r.cdr

Cumulative Top WaterAir Injection Forecast NA

PROJECTION/DATUM:


AMECEHEH

DATE: Fig04.05-14 Top Water

11-12-14

KW

Figure4.5-14

ANALYST:

PROJECT:

CE0339901

December 2011



Telephone Lake Dewatering Cumulative Air Injection (Standard Conditions)

(Phases A&B)

629

0

100

200

300

400

500

600

700

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

2056

Year

Cu

mu

lati

ve

Vo

lum

e(e

6m

3)

Air Injection

Documents

Vol 1 Section 4 Bitumen Recovery Process - alberta.ca · SECTION 4.0 – BITUMEN RECOVERY PROCESS ... • reservoir pressures at which circulation is maintained. Typical steam circulation