SAGD Oil Recovery

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SPE-174490-MS

Design, Testing, and Field Performance of Steam-Injection Flow-ControlDevices for Use in SAGD Oil Recovery

Ryan McChesney, Frederic Felten, Scott Hobbs, Halliburton; John Edlebeck, Southwest Research Institute

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Canada Heavy Oil Technical Conference held in Calgary, Alberta, Canada, 9–11 June 2015.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents

of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect

any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written

consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may

not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

To promote efficient recovery of bitumen hydrocarbons using the steam assisted gravity drainage (SAGD)

process, it is vital that steam be used effectively because steam generation constitutes one of the largest

operational expenses during the SAGD process. To optimize this process, steam-injection flow-control

devices (FCDs) have been developed. These devices are designed to enhance the operator’s ability to

distribute steam along the wellbore and to cease steam injection at a particular injection point if necessary,

as the steam chamber matures. This paper discusses the design and capabilities of FCDs.

The project initiated with a design requirement of two core components— the axial distribution of

steam exiting the device and a device to incorporate a sliding sleeve mechanism. The basis for FCD designdecisions was developed initially by reviewing worst-case operating conditions FCDs could encounter and

then using this information as the operating envelope criteria that the design should meet. SAGD

completion tools are required to endure everything from temperature fluctuations and corrosive formation

fluids to erosive wet steam and severe wellbore trajectories. To design a tool that would survive the

erosive effects of varying steam quality, the critical velocities and erosive mechanisms were defined. API

RP 14E provides a conservative basis to determine the maximum allowable fluid velocity in a given

system, but several studies have sought to push the boundaries of acceptable fluid velocities. The most

conservative nozzle exit velocities were used to limit risks to casing. The risks caused by high velocities

in the nozzle inside/inner diameter (ID) to the injection tool were mitigated through the use of compu-

tational fluid dynamics (CFD) analyses and material selection/treatment.Because of the high temperatures under which SAGD operates, consideration of mechanical property

degradation and possible deformation had to be considered, specifically to the collet of the sliding sleeve.

To prevent diminishing performance during the operational lifetime, FCDs that use sliding sleeves with

collet mechanisms require a robust design that recognizes and addresses maximum stress loads and limits

plastic deformation at peak temperatures. The testing of the sliding sleeve was conducted throughout a

wide range of temperatures where the forces to shift the sleeve were monitored and compared to previous

finite elements analyses (FEA) for compliance.

ISO 14998 Annex D provided the basis for function testing of the FCD (i.e., cycling the sleeve and

pressure testing at temperature). All pressure and function testing was performed at or above the operating


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temperature, and pressure and results were qualified to ISO 14998 V1. Field performance is discussed in

the paper.

Introduction

The SAGD process requires the use of a horizontal well used for steam injection directly above a

secondary horizontal well used for production. After circulation and in SAGD mode, steam is injected into

the upper wellbore and heats the formation adjacent to the bore. As the steam expands through theformation a steam chamber is formed, which is made up of saturated steam (Fig. 1). Steam progresses

through the chamber and condenses near the edges yielding latent heat, which is transferred to the highly

viscous bitumen hydrocarbon. By absorbing this latent heat, the bitumen becomes less viscous and more

mobile within the reservoir. Because of gravity, the mixture of mobilized bitumen hydrocarbons and

condensate drain to the lower completion where they can be pumped to the surface.

For the in-situ recovery of bitumen hydrocarbons to be economical, the steam, which constitutes a

significant operating expense, should be effectively used. This effectiveness or efficiency is a measurable

indicator and is commonly referred to as the steam-oil-ratio (SOR), and is a key performance indicator in

terms of the overall efficiency of the well, pads, or project. Typically, short and long string injection

results in more steam chamber growth concentrated at the heel and toe of the wellbore. The dual injection

tubing configuration results in uneven steam distribution along the entire lateral bore (Gotawala and Gates

2009). By only having two points of injection, the effect of reservoir heterogeneity and thief zones can

be magnified (Ali 1997). Another cause of poor steam distribution caused by reservoir heterogeneity can

be preferred steam flow paths into the reservoir. Steam will take the path of least resistance from the

injection string to the production string, creating the potential for steam breakthrough. Steam break-

through can result in a loss of sand control on the producer caused by excessive flow rates focused on a

single slotted liner or screen section (Das 2005).

One way to prevent steam breakthrough is to maintain the liquid condensate level above the producer

so that there is no direct flow path for steam to escape through the producer. In order to maintain a

sufficient liquid level above the producer, the production fluid should be cooler than the steam injected

from the surface; this temperature differential is referred to as the subcool margin. The subcool margin

should be adequate to help ensure that the produced fluid will not be able reach the steam saturation

temperature at the given pressure.

The use of FCDs has been shown to help significantly improve the steam distribution along the lateral

wellbore (Medina 2013). By using FCDs on the injection string, the steam chamber growth will be more

balanced, and the risk of steam breakthrough can also be reduced. The use of a FCD with a closing sleeve

also helps provide the operator the ability to cease steam injection in a particular region of the lateral bore

Figure 1—Steam chamber formed of saturated steam.

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if there is some indication steam breakthrough might have occurred. Some experimental work has also

shown the use of inflow control devices (ICDs) or autonomous inflow control devices (AICDs) on the

producer can prevent or limit the impact of steam breakthrough (Least et al. 2014).

Tubing deployed FCDs to evenly distribute steam along the lateral bore are now very common in the

SAGD market. Multiple FCDs are used in series to control the amount of steam flow along the lateral bore

by controlling the amount of pressure decrease that occurs at each device. An FCD can be designed with

or without a closing sleeve as previously discussed based on the amount of flow control necessary and reservoir heterogeneity. The device considered in this project consists of a center nipple, top sub, bottom

sub, closing sleeve, and seals (Fig. 2).

The purpose of this project was to design, build, and test an FCD that would survive the downhole

SAGD conditions and operate reliably throughout the life of the well pair. The design process began by

identifying the most significant requirements:

● Axial steam injection to prevent direct impingement on the slotted liner,

● A design that would have the mechanical integrity to survive the most severe conditions during

running in hole (RIH).● A seal system that would allow adequate isolation of a particular steam injection zone at SAGD

temperature and pressure should the sleeve need to be closed.

With axial steam injection in mind, the next consideration was how to best use the internal flow area

to condition the steam flow so the FCD itself would not experience any negative effects from direct

internal steam impingement. To determine the best way the steam flow could be conditioned from the bore

before entering the nozzle throat, four various closing sleeves were considered. The designs each consisted

of a different geometric pattern used for fluid communication between the sleeve ID and outside/outer

diameter (OD). A fifth design did not include a sleeve to serve as a control. The bench mark to determine

how well the flow was conditioned by each design was to examine how close the peak flow stream

velocity was to the bulk velocity and the percent of total flow traveling through each nozzle (left and

right). The ratio between the two serves as a representation of how effectively the orifice cross-section is

being used. The greater the percentage of the orifice cross-section used, the lower the peak velocity

considered when determining the risk from liquid droplet impingement erosion (LDIE). A CFD analysis

was used to determine which design achieved the lowest peak to bulk velocity; the results are presented

later.

When FCDs are installed, they are forced through the dogleg between the vertical and lateral portions

of the wellbore and should be able to handle combined tensile and bending loads. The requirement of axial

steam injection lends itself to a design, which consists of greatly differing center nipple and end sub

diameters. Having two different moments of inertia can lead to bending stress concentrations at the

Figure 2—Injection FCD design.

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interface between the two parts. Special care was used to design an OD feature profile transition that

limited stress concentrations and limited the potential for crack initiation. This was done in consideration

for the metal-to-metal seals and threads on the center nipple and end sub connection components. FEA

was performed on the FCD to demonstrate that the worst-case dogleg and peak tensile loading would not

pose any risks to the FCD or completion. Results from full scale testing are presented.

The sealing system designed for the closing sleeve considered an operating envelope of 520°F and no

less than 500 PSID. ISO 14998 testing was performed to stress the seals both mechanically and thermallyto simulate worst-case operating life for both the seals and collet. The testing included pressure reversals

and temperature cycling. However, the sleeve was never opened with a pressure differential because the

end of the tubing string is open for steam flow. The ISO test also served as the validation of the collet

feature at temperature. Until now, there has not been a clear set of criteria that covers the most important

design aspects and methodology to validate an FCD for use in SAGD steam injection.

Liquid Droplet Impingement Erosion

During SAGD operations, wet steam can pose problems to downhole equipment and liner. Steam flowing

at high velocity through a nozzle or orifice can thin the wall directly downstream. When steam follows

a preferential flow path to the producer, the high velocity flow with entrained sand can destroy slotted liner and screens, resulting in loss of sand control. It is important that, whenever possible, the velocity

limitations for a tool be clearly defined and the peak velocities be managed. To help ensure that erosion

is limited in SAGD operations, it is important to understand what the primary mechanisms of erosion are.

Erosion occurs when material is removed from a part or surface by physical means ( Salama and

Venkatesh 1983). Three primary mechanisms are the cause of this physical material removal—cavitation,

liquid particle impingement, and solid particle impingement. When cavitation occurs, such as the repeated

bubble collapse in a centrifugal pump impeller, the surface is repeatedly loaded and unloaded, causing

fatigue and pitting. Solid particles, such as sand entrained in steam, oil, or gas, can be carried in the fluid

and abrade tubing or other downhole tools made of ductile materials. In some cases, material loss can be

a result of repeated removal and buildup of a passive surface layer caused by erosion/corrosion (Salama

and Venkatesh 1983).API RP 14E has defined the fluid velocity limitations of oil and gas production two phase flow systems,

but some studies have shown the methodology to be overly conservative. The erosional velocity

limitations imposed by API RP 14E are particularly conservative for sand free two phase systems and

situations in which liquid droplet impingement is the primary mechanism. The velocity limitations are

defined by Eq. 1 in which Ve is the erosional velocity in ft/sec, is the fluid density in lbm/ft3, and C is

the constant between 100 and 125.

(1)

In two phase systems, which are sand free, C100 is typically used to determine the erosional velocity

limit for continuous service, and C125 is considered only for intermittent service. Based on a review of

experimental data and a comparison of the limits proposed by API RP 14E, Salama concluded that the API

equation was overly conservative. Particularly in the case of sand free systems, C300 should be an

acceptable empirical constant (Salama and Venkatesh 1983).

The Erosion/Corrosion Research Center research group at the University of Tulsa developed an

erosional model to predict velocity limitations caused by liquid droplet impingement and compared the

values to those calculated using API RP 14E. The model showed that the API equation was much more

conservative than those velocity limitations proposed by this new flow model. This work created a method

for predicting erosional velocities caused by liquid droplet impingement by considering droplet size,

impact velocity, and the type of geometry in which the fluid stream interacts. Validation of the model was

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performed by comparing experimental results from an ASTM STP 474 test on 1018 carbon steel to the

erosional velocity predicted by the correlation model. In cases where liquid droplet impingement was the

primary mechanism of erosion, the paper showed that the API equation greatly underestimated the fluid

velocity limitations (Arabnejad et al. 2014).

Navas et al. proposed a new standard of C factors to be used for estimating erosional velocity

limitations using the API equation. Erosion testing conducted was evaluated to help determine what

corresponding C factor was associated with the erosional velocity limit. A variety of geometries wereconsidered in this study to create a relevant standard to determine appropriate C factors (straight pipe,

elbow, and valve assembly). The study varied the sand particle size and concentration in addition to the

fluid in which the particles were entrained (water, wet gas, and dry gas). Results showed that, in wet gas

(1,000 psi), C factors exceeding 300 might be acceptable for determining the erosional velocity limits

in a straight pipe section. This paper demonstrates that using C factors between 100 and 200 for

production or injection tubing and downhole tools was overly conservative ( Navas et al. 2011).

CFD Simulations

To determine which closing sleeve geometry best conditioned the flow entering the steam chamber within

the FCD, two-phase CFD simulations were completed for each case. Phase-change was not considered.

Constant concentration and fluid properties were considered for the steam and water droplets. Modelingsoftware was used to perform CFD analyses. By conditioning the flow, the nozzle cross-section could be

more effectively used, reducing the peak velocity in the nozzle and improving FCD reliability. In addition

to verifying which design best conditioned the steam flow, the velocity of the flow exiting the diffuser

needed to be determined. The steam flow velocity should be less than 100 ft/s exiting the diffuser to help

ensure there was no LDIE risk to the slotted liner. Each case used the same center nipple, top sub, bottom

sub, and the sleeve geometry represented the variable being tested. The simulations were performed by

considering a 1/4 cut of the cross-section to reduce both mesh size and time necessary for simulation

convergence (Fig. 3). The FCD in the analysis was the top device on the injection tubing string, meaning

it would encounter the highest steam pressure and flow rate through the bore. Table 1 presents the

boundary conditions considered for each simulation.

Figure 3—1/4 cut used for simulations.

Table 1—Boundary conditions considered for each CFD simulation.

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This project considered five various cases; the first had no closing sleeve to interact with steam flow,

and the other four used various flow slot geometries in the closing sleeve to alter the steam flow.

The criteria used to determine which design performed the best consisted of three basic criteria:

● Lowest ratio between the nozzle bulk velocity and peak velocity in the flow stream.

● Closest to 50/50 balance of flow between the left and right nozzle considered.

●

No diffuser exit velocities above 100 ft/s.Based on the results from Design 1, it was determined that the recirculation that occurred in the steam

chamber had a negative impact on the velocity ratio. The flow stream tends to be restricted in the steam

chamber because most of the internal area is consumed by a large flow recirculation. Figs. 4 and 5 show

the flow stream and nozzle flow profile for Design 1. The nozzle profile shows the peak velocity

concentrated near the top half of the nozzle diameter, and the streamlines show how the recirculation

consumes the entire steam chamber.

Next, a closing sleeve was included in the simulation, which was in the open position. The fluid

communication path used in Design 2 consisted of sixteen evenly spaced radial straight slots. Results from

Figure 4—Nozzle profile (Design 1).

Figure 5—Streamlines (Design 1).

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this design were similar to those in the first iteration without the closing sleeve included. Figs. 6 and 7

show the nozzle profile and streamlines for the simulation completed for Design 2.

Design 2 had a velocity ratio higher than the control case with no closing sleeve to interact with the

flow. The radial flow slots, which span the entire length, allow for recirculation to consume the entiresteam chamber. The flow slots, which span the chamber, allow the fluid stream through the FCD bore to

interact directly with the chamber and induce recirculation. Velocity ratios and the flow balance between

the left and right nozzle are included in Table 2.

Figure 6—Nozzle profile (Design 2).

Figure 7—Streamlines (Design 2).

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Results from the first two design cases analyzed show that full chamber length flow paths in the closing

sleeve might not be the most effective means to condition the flow stream. Three more designs were

created to attempt to reduce the negative effects of recirculation on the nozzle velocity ratio. Designs 3

through 5 were created with a flow path that would diffuse the inertial energy in the flow stream that

causes circulation. The alternate designs use offset slots and varied geometry to break the flow stream

before entering the internal steam chamber. Figs. 8 through 13 show the nozzle profile and flow

streamlines that resulted from the simulations completed on the remaining three design cases.

Table 2—Design Cases 1 and 2 velocity ratios.

Case

Left Nozzle Right Nozzle

Peak Velocity

(ft/s)

Bulk Velocity

(ft/s)

Ratio of

Vmax /Vbulk

Flow Split

(%of total

flow)

Peak Velocity

(ft/s)

Bulk Velocity

(ft/s)

Ratio of

Vmax /Vbulk

Flow Split

(% of

total flow)

Design 1 222 163 1.36 7.74 222 153 1.45 7.26

Design 2 235 166 1.42 7.89 243 144 1.69 7.11

Figure 8 —Design 3 nozzle profiles.

Figure 9—Design 3 flow streamlines.

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Figure 10 —Design 4 nozzle profiles.


Figure 12—Design 5 nozzle profiles.

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Design Cases 3 and 4 still exhibited some localized recirculation, while it was less pronounced in the

steam chamber. Even though both design cases used offset slot patterns or varied slot sizes, particularly

near the nozzles, multiple instances of recirculation were present in the flow stream. It appears that using

a slot, even in the case of a slot that does not run the full length of the steam chamber, allows the main

flow stream through the bore to influence the streamline behavior in the steam chamber. However, Design

5, which incorporated progressively smaller holes in place of slots as the fluid communication, showed much less recirculation in the steam chamber flow streamlines. It is counterintuitive to consider progres-

sively smaller rather than progressively larger diameter pathways. In most cases, the primary mechanism

that governs fluid flow is fluid pressure rather than the fluids inertia. By limiting the amount of continuous

cross sectional area exposed to the main flow stream the amount of recirculation that occurs can be

minimized. Table 3 displays velocity ratios for each of the remaining designs were obtained from the

simulation.

The simulations showed that the casing would not encounter a steam flow velocity100 ft/s, meaning

that liquid droplet erosion would not be a concern. Results also demonstrated that, even without a closing

sleeve to condition the flow steam, a near 50/50 balance between left and right nozzles could be achieved.

By reducing the velocity ratio between the peak and bulk velocities, more of the nozzle cross-section was

effectively used. Reducing the velocity ratio also helps ensure that no portion of the FCDs internal

components will be exposed to a steam flow velocity that exceeds the recommended erosional velocity

limit. Design 5 represents the optimal design case because of its near 50/50 flow balance, minimal velocity

ratio, and lack of significant recirculation present in the steam chamber flow streamlines.

Mechanical Testing

Full scale mechanical testing was performed to help ensure the design, which has a widely varied OD,

would not have excessive stress concentrated at the interface between two ODs. The test was conducted

in a horizontal load frame rated for one million pounds with the capability for applying tensile and bending


Table 3—Design case 3 to 5 velocity ratio.

Case

Left Nozzle Right Nozzle

Peak Velocity

(ft/s)

Bulk Velocity

(ft/s)

Ratio of

Vmax

/Vbulk

Flow Split(%of total

flow)

Peak Velocity

(ft/s)

Bulk Velocity

(ft/s)

Ratio of

Vmax

/Vbulk

Flow Split(% of

total flow)

Design 3 213 165 1.29 7.87 195 162 1.20 7.13

Design 4 199 155 1.28 7.35 207 176 1.18 7.65

Design 5 201 158 1.27 7.41 201 168 1.20 7.59

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loads simultaneously. Before being installed into the load frame, the ends subs were installed with 1200

ft-lb of make-up torque. Following assembly, eight uniaxial strain gages were mounted onto the top and

bottom end subs (four on each). Gages were placed at 0, 90, 180 and 270°. The strain gages were mounted

on sections with the same ID, OD, and wall thickness to help ensure that bending on any axis would be

detected. Additionally, four tri-axial strain gages were positioned at critical locations along the FCD to

calculate the bending moment and strain. Load testing consisted of applying a 126,000 lbf tensile load

then a 4,200 ft-lb bending moment through the assembly, which equates to 17°/100 ft well deviation. The

load was held for five minutes, during which the axial displacement was measured with a displacement

transducer to help ensure the center nipple and end sub connections were not yielding. The bending

moment through the assembly was also monitored through the assembly to help ensure the expected

deformation was occurring and the strain values were not changing over time. Strain values that varied

significantly over the hold period would indicate some yielding in the FCD. No deformation or yield was

observed during the load hold. The assembly was visually inspected after the mechanical test with no

damage or crack initiation detected. Fig. 14 shows the test setup and Fig. 15 shows the results from the

test as recorded by the strain gage.

Figure 14 —Combined bending and tensile test setup.

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ISO 14998 Testing

Laboratory testing was performed at Southwest Research Institute (SwRI) in San Antonio, Texas. The

testing plan for the two seal designs was based on Annex D of ISO 14998: Petroleum and natural gas

industries-downhole equipment-completion accessories. ISO 14998 requires that the test article be opened

and closed the maximum rated number of cycles at the maximum rated temperature. It requires that, after

cycling, a 15 minute pressure hold at the maximum rated pressure be performed on the bore, followed by

one pressure reversal at the maximum rated pressure from the bore to the annulus. A pressure reversal

involves a pressure hold on the bore, a pressure hold on the annulus, followed by another pressure hold

on the bore. Leakage is measured during each pressure hold, and pressure holds should last at least 15

minutes. For Grade V0 and Grade V1 of Annex D, at least one temperature cycle is necessary in which

the temperature of the test article is cooled down by at least the maximum rated temperature cycle range.

Pressure holds are necessary at the low end of the temperature cycle range and after heating back up to

the maximum rated temperature. Grade V2 of Annex D requires no temperature cycle. The acceptance

criterion for Grade V0 are zero bubbles of gas accumulated in a graduated cylinder over a hold period,

and the acceptance criterion for Grade V1 and Grade V2 are no more than 20 cc of gas accumulated in

a graduated cylinder over the hold period.

A custom test fixture for shifting the test article shifting tool was designed and fabricated at SwRI. Fig.

16 shows a three dimensional (3D) computer model of the test fixture and Fig. 17 shows the fabricated

test fixture. The test article shifting tool was coupled to a 3 1/4-in. bore hydraulic cylinder with a 1-in.

diameter shaft and a 12-in. stroke length. The connection between the test article and the hydraulic

cylinder included a tension and compression load cell for measuring the force necessary to shift the tool.

The assembly was mounted to a 12-ft section of wide flange with gussets welded in place to react the

shifting force. The fixture was designed to accommodate a shifting force of up to 10,000 lbf.

Figure 15—Plot of bending moment through the assembly and tensile load at each strain gage.

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Fig. 18 illustrates a diagram of the test setup. A port in one of the test article end caps was used to

supply pressurized nitrogen to the bore of the test article, and to measure any leakage from the bore when

the test article was pressurized from the annulus. Similarly, one of the ports in the annulus of the test

article was used to supply pressurized nitrogen to the annulus of the test article, and to measure any

leakage from the annulus when the bore of the test article was pressurized. A dynamic gland seal was

incorporated into the test article end cap facing the hydraulic cylinder to accommodate the reciprocation

of the closing sleeve while pressurized with nitrogen, An arrangement of automated isolation valves wasused to direct pressurized nitrogen to the test article or direct leakage from the test article to an aquarium

tank containing an inverted graduated cylinder submerged in water for quantifying leakage. A heat

exchanger was necessary to cool the nitrogen leaving the test article before coming in contact with the

automated isolation valves, which were rated at a temperature lower than the temperature at which the test

article was heated for testing. The pressures of the bore and annulus were measured with pressure

transmitters.

Figure 16—Solid model of the test fixture used for shifting the test article shifting tool.

Figure 17—Test fixture used for shifting the test article shifting tool.

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The test article was wrapped in heater bands to raise the fixture’s temperature to the maximum rated

temperature of 520°F. A proportional integral derivative (PID) temperature controller was used to control

the power to the heater bands based on feedback from thermocouples. Three thermocouples, two of which

were used as inputs to the PID controller and one of which was used for data collection, were secured to

the outside of the test article.

A hydraulic pump and a manifold of automated isolation valves were used to control the hydraulic

cylinder. The pressure supplied to the cylinder by the pump was measured to quantify the force necessaryto shift the tool in addition to the measurement made by the tension and compression load cell.

Two seal package designs were tested within the same test article. For this test, intermediate pressure

holds were performed before reaching the maximum rated number of cycles. The maximum rated number

of cycles for the test article inside of which the seals to be tested were installed was 10 cycles. For Seal

Design 1, pressure holds on the bore were performed every two cycles, and two pressure reversals and a

temperature cycle were performed after ten cycles. For Seal Design 2, pressure holds on the bore were

performed after two cycles, six cycles, and ten cycles. If the seal design had not already failed because

of more than 20 cc of leakage during a pressure hold, one pressure reversal and a temperature cycle were

Figure 18—Diagram of the test setup.

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performed after ten cycles. Tests were conducted at the maximum rated temperature for the test article of

520°F. For temperature cycling, the temperature of the test article was reduced to below 400°F.

Table 5 presents a summary of the test results. Seal Package Designs 1 and 2 met the acceptance

criterion for Grade V1. Note that Seal Package Design 2 was tested at a maximum rated pressure of 750

psi opposed to Seal Package Design 1, which was tested at a maximum rated pressure of 500 psi. Table

5 also shows the ranges measured for the force necessary to open and close the test article with the load

cell throughout cycling for each test.

Completion Design/Performance

Several studies have demonstrated the benefits of using FCDs as part of the injection tubing string in

SAGD wells. A validated model developed by Max Medina (2013) provides a methodology for designing

injection tubing strings for SAGD upper completions that incorporate FCDs. This steady state model of

the injection string determines the ideal locations and pressure drop through each device. The model was

validated by comparing simulation results to field performance data collected from wells both with and

without FCDs. The injection pressure vs. steam flow rate was compared for both completions types to

understand how the steam flow capacity of each differed. A new method was also proposed to measure

the dynamic pressure gradient of the lateral wellbore. The method consists of using temperature data

obtained along the bore to extrapolate the steam pressure based on the known properties of saturated

steam. This paper demonstrated that upper completions with FCDs can be successfully designed to injectsteam more evenly along the lateral bore and also deliver more steam to the formation at a given injection

pressure (Medina 2013).

Another study also used numerical analysis to determine what benefits FCDs might have on steam

distribution and limiting steam breakthrough caused by reservoir heterogeneities and overall performance

of SAGD. The study considered both a base case (dual injection sting method) and several designs, which

incorporated FCDs. Based on the simulation results, it was concluded that FCDs on both the injector and

producer can provide a solution to combat reservoir heterogeneity. Also shown is that, even with the

higher capital expenses necessary to deploy FCDs, the payback period was still shorter when FCDs were

used. The cost recovery period was shorter with the inclusion of FCDs primarily because of the SOR being

12% lower compared to the standard long and short string completion geometry. Overall, FCDs were

demonstrated to be the preferred method compared to the standard dual tubing completion because of amore even steam distribution, minimizing breakthrough, and improved economics (Ajumogobia-Bestman

et al. 2014).

Conclusions

● Under typical SAGD well conditions and flow rates, it is possible to develop an FCD design that

can provide steam axially in both directions that prevent steam from impinging on the slotted liner.

It was also shown that the threshold velocity for liquid droplet impingement erosion is much higher

than the velocity of any flow the casing will interact with.

Table 5—Summary of test results.

Seal

Design

Testing

Pressure

(psi)

Testing

Temperature

(°F)

Maximum Leakage

(path)

Opening

Force

Range (lbf)

Closing Force

Range (lbf) Summary

1 500 520 11 cc (bore to

annulus)

1019–1289 950–1163 Met t he acc ept ance crit erion

for Grade V1

2 750 520 2 cc (bore to

annulus)

1321–1550 1012–1386 Met t he acc ept anc e c ri terion

for Grade V1

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● Using the geometry of the fluid communication flow paths in the closing sleeve, it is possible to

condition the flow such that the bulk velocity and peak velocity are very similar, thereby limiting

internal nozzle velocities to those below the LDIE threshold velocity.

● The FCD design presented should not encounter any issues downhole because it was tested well

beyond the tensile and bending values it should normally encounter.

● The seal package and collet design performed well under SAGD conditions and can help provide

reliable functionality throughout the life of well.● A set of design criteria and benchmarks for validating future designs was presented that will serve

as a starting point for future developments of FCDs intended for use in SAGD injection.

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Control Devices in SAGD Applications in the Surmont Area Through Numerical Analysis.

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Ali, S.M. 1997. Is There Life After SAGD? J Can Pet Technol 36(6). PETSOC-97-06-DAS.

http://dx.doi.org/10.2118/97-06-DAS.

ANSYS® CFX, Release 15.0, ANSYS, Inc.Arabnejad, K.H., Shirazi, S.A., McLaury, B.S. et alet al. 2014. A Guideline to Calculate Erosional

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16 SPE-174490-MS

Documents

SAGD Oil Recovery