BAKER HUGHES INCORPORATED
`Exhibit 1014
`
`Page 1 of 127
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`Page 4 of 127
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`Page 5 of 127
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`Page 6 of 127
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`uh
`‘ ‘ .
`
`SPE CI M
`
`7th One Day Conference on HORIZONTAL WELL Technology
`November 3,1999 - Calgary, Alberta, Canada
`
`Presented by the Petroleum Society at CIM-Horizontal Well Special Interest Group
`and the Canadian Section ol the Society of Petroleum Engineers
`
`Message from the Chair
`
`Welcome to the 7th One—Day Conference on Horizontal Well Technology.
`
`On behalf of the Canadian Section of the SPE and the Petroleum Society, we are pleased to offer
`to the technical community a day of new ideas, case studies and analyses focussed on
`technology related to horizontal wells.
`
`led by General Chairman. Fiick Kry and the Technical Program Committee
`The organizers.
`Chairman, K.C. Young, have enticed a selection of presentations, divided into four technical
`sessions: “Heavy Oil", "Drilling Advances”, “FormationlStirnulation”, and “Field Cases". They
`have arranged a luncheon presentation by Dr. Alan. D. Kersey, Vice President of CiDFiA
`Corporation on fibre optic applications and potential. And to complete the program, a panel
`comprised of leaders in horizontal well applications and technoiogy and representing business
`and technical perspectives. will discuss the latest advancements in horizontal wells, what is still
`needed and what are the likely breakthroughs in the future.
`
`Thank—you to each of the authors, speakers, panel members and organizing committee and
`technical committee volunteers who have taken time from their busy schedules to contribute to
`the success of this meeting. Enjoy the day and may it be productive for you.
`
`Dr. P. H. Kry
`Imperial Oil Resources
`General Chairman
`
`7th One Day Conference
`
`Page 7 of 127
`Page 7 of 127
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`

`
`in
`
`SPE CIM
`
`7th One Day Conference on HORIZONTAL WELL Technology
`November 3,1999 - Calgary, Alberta, Canada
`
`Presented by the Petroleum Society of CIM-Horizontal Well Special Interest Group
`and the Canadian Section of the Society of Petroleum Engineers
`
`Organization and Technical Program
`
`Flick Kry
`
`Imperial Oil Resources
`
`K.C. Yeung
`
`Suncor Energy Inc.
`
`Kenny Adegbesan
`
`KADE Technologies Inc.
`
`Gil Cordell
`
`Lister Doig
`
`Con Dinu
`
`Canadian Hunter Exploration Ltd.
`
`Pancanadian Resources
`
`Husky Oil Ltd.
`
`Fabio Diaz
`
`Colulmbus Resources
`
`Brian Feity
`
`Triumph Energy
`
`Norm Gruber
`
`Sch|umberger—GeoQuest
`
`Harry R. Hooi
`
`Numac Energy inc.
`
`Fion McCosh
`
`CenAlta Well Services inc.
`
`Michael Oianson
`
`Audryx Petroleum Ltd.
`
`Bianca Paicsanu
`
`Merit Energy Ltd.
`
`Wes Scott
`
`Petroleum Society of CIM
`
`Gurk Sarioglu
`
`Elena Tzanco
`
`Petro-Canada
`
`ET Consulting
`
`Teresa Utsunomiya
`
`Pancanadian Fiesources
`
`Chi-Tak Yee
`
`GravDrain Inc.
`
`Page 8 of 127
`Page 8 of 127
`
`

`
`r‘\
`‘ ‘ .
`
`S P E Cl M
`
`7th One Day Conference on HORIZONTAL WELL Technology
`November 3,1999 — Calgary, Alberta, Canada
`
`Presented by the Petroleum Society of ClM~Horizonta| Well Special Interest Group
`and the Canadian Section oi the Society of Pelroleurn Engineers
`
`Sponsoring Organizations
`
`Platinum
`
`AGAT Laboratories
`
`CiDRA Corporation
`
`lmpon Tool Corporation Ltd
`
`JTI (Joshi Technologies International Inc)
`Outtrim Szabo Associates Ltd
`
`Petroleum Recovery institute
`
`Phoenix Technology Services Ltd
`
`Ryan Energy Technologies Inc.
`
`Schlumberger
`
`United Geo Corn Drilling
`
`Gold
`
`Halliburton Energy Services
`
`Norwest Labs Energy Resource Group
`PanCanadian Limited
`
`Poco Petroleums Ltd
`
`Precision Drilling Limited Pannership
`
`Silver
`
`Baker Hughes Canada Company
`
`Northland Energy Corporation
`Petro-Canada
`
`Q'max Solutions inc
`
`Union Pacific Resources Inc
`
`Bronze
`
`Core Laboratories Canada Ltd
`
`Directional Plus
`
`Page 9 of 127
`Page 9 of 127
`
`

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`(cid:51)(cid:68)(cid:74)(cid:72)(cid:3)(cid:20)(cid:20)
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`Page 10 of 127
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`

`
`
`
`,,.A,._..-_-.4-__..-..«_.....,...-..-_........__,.....\~).-._~.._.-._....
`
`
`
`
`
`for the WAG process is that wells produce substantially
`better after re-pressuring. The geometric arrangement of
`the study pattern was of four vertical wells at the corners
`of a square. The distance between vertical wells was 440
`m for historical reasons. For the WAG study of horizontal
`production wells, four vertical wells and a segment of
`horizontal well between them had been used. For
`
`comparison purposes a vertical infill well was also used
`in the center of
`the four original vertical wells. A
`comparison of the production from both horizontal and
`vertical wells, before and after re-pressuring by water
`injection, is shown in Figure 1. It may be observed that
`both the rates and amounts of production of either type of
`well were much improved. As was to be expected, the
`performance of the horizontal well was superior.
`
`The improvement in performance after re-pressuring
`can be shown to be primarily due to forcing gas back into
`solution in the oil rather than the increase in pressure, as
`such. One observation supporting this conclusion is, that
`re-pressuring with water beyond the pressure at which
`nearly all gas was forced into solution produced
`noticeably more water, but very little more oil. Re-
`pressuring to pressures much below the gas re-solution
`pressure markedly reduced oil production. The second
`observation was that
`if repeated re-pressurings and
`productions were done without the addition of gas,
`production declined fairly quickly with successive cycles.
`Addition of gas prior to the water re-pressuring resulted
`in a much slower decline in productivity.
`
`The conclusion drawn from the above observations
`
`is that the pressure cycling scheme works by largely
`restoring the solution gas drive mechanism of primary
`production. Primary production is a generally well
`understood process,for which information is necessarily
`available for any reservoir to which the pressure cycling
`process might be applied. The production aspect of the
`pressure cycling process should therefore be known
`about beforehand. What remains to be clarified is the
`
`details of pressuring up and the timing of phases of
`operations.
`
`Optimization of Injection Phases
`
`The optimization of gas injection amount depends
`upon what stopping criteria are used for the production
`phase of the cycles. At first sight it might be supposed
`that measures such as rate of production or watercut
`might be used. It turns out that there exists what might be
`termed a natural stopping signal for production. It was
`
`in a horizontal production well system, that if
`observed,
`production for a cycle was carried on for sufficiently long,
`four gas-oil
`ratio (GOR) peaks were observable in the
`production. An example of these GOR peaks to the top of
`the fourth peak is given in Figure 2. Examination of the
`system at the times of these peaks indicated the origins of
`the GOR peaks to be the following. The pressure exerted by
`the water during re-pressuring is not uniform over the entire
`pattern. As a consequence some gas is moved sideways,
`and ultimately two small pockets of gas are formed near the
`center part of the horizontal well, which would require quite
`high pressure to force into solution. It is counterproductive to
`do so. Not compressing this small amount of gas into
`solution does result in a brief GOR peak very early in the
`production phase. The second GOR peak occurs when the
`production well reaches minimum bottomhole pressure
`(maximum gradients). The third GOR peak is observed to be
`associated with free gas saturation occurring all the way to
`the edges of the production pattern (maximum area of
`production). The fourth GOR peak is associated with free
`gas saturation reaching the bottom of the outer part of the
`pattern (maximum volume of production).
`
`If the production phase of the cycles is terminated too
`early, oil is produced from only the central portion of the “
`pattern, and so areal conformance is diminished.
`If
`production is carried out too long, the lower regions of the
`pattern become excessively de-gassed. This condition is
`detrimental to production in any further cycles, as re-gassing
`the lower regions of the pattern seems to be quite difficult. A
`close to optimal termination criterion is to end the cycle at
`about the minimum between the third and fourth GOR
`
`peaks. This stopping condition has the advantage of being
`one that can be quite readily operationally observed.
`
`be
`can
`it
`stopping condition
`above
`the
`With
`demonstrated that there is an amount of injection gas that is
`optimal in several senses. The average rate of oil production
`showed a maximum, and the average watercut and amount
`of injected gas required to produce a unit of oil showed
`minima. These optima were fairly broad and all occurred at
`about the same amount of injected gas. The amount of gas
`required to achieve the optimal conditions was also that
`which resulted in the system being restored to about original
`reservoir pressure, when water injection had effectively
`pressured the gas into solution. With the gas being injected
`at a maximum pressure only slightly above original reservoir
`pressure, it was found that the same amount of gas was
`needed for several successive cycles.
`it is not presently
`known if re-pressuring to about original reservoir pressure is
`a very general optimization condition.
`
`Page 11 of 127
`Page 11 of 127
`
`
`

`
`Research on pressure cycling at the Saskatchewan
`Research Council is continuing. Studies ofthicker reservoirs,
`systems with bottomwater, and a range of viscosities all
`show positive findings. Work on how to fully optimize the
`pressure cycling process is also undenivay.
`
`Effect of infill options
`
`The pressure cycling study evolved from an infill
`horizontal production well. Drilling such wells represents
`a substantial capital
`investment and so the question
`naturally arose of whether
`infill wells were really
`necessary for the pressure cycling process. The cases of
`no infill well, a vertical
`infill production well, and a
`horizontal
`infill production well were compared. The
`amounts and rates of production for the three cases are
`given in Figures 3 and 4 respectively. The results are
`reported on a per pattern basis (same production area)
`for all cases. This means, of course, that the horizontal
`well results are for just a segment of horizontal well
`contained in the square pattern. In reality a horizontal well
`would have productive end zones and would possibly be
`somewhat longer. In the no infill case there is only one
`half a production well per pattern.
`
`It may be noted that not very much is gained by using
`a vertical infill well. It is also quite clear that the horizontal
`infill well case gives much higher rates of production and
`a somewhat higher ultimate recovery than do the vertical
`production well cases. It is almost certainly necessary to
`drill horizontal wells to obtain economically attractive
`rates of production. This assumes that the heavy oil
`reservoirs exhibit normal darcian flow. In cases where a
`
`larger percentage of oil has been recovered in vertical
`well primary production, possibly due to wormholes, or in
`reservoirs with medium oil, vertical producers might
`provide acceptable rates.
`
`Comments and conclusions
`
`The research discussed above provides good reasons for
`believing the pressure cycling technique to have good
`potential as a EOR scheme in the difficult application of
`thin heavy oil reservoirs. It is, naturally, quite probable
`that application to less difficult situations would be more
`profitable. The pressure cycling scheme has the merit of
`simplicity, both in terms of what inputs are needed, and
`in terms of the process to be carried out. The inputs are
`water and produced gaswhich are reasonably available,
`require no special safety precautions, and are reasonably
`inexpensive.
`it
`is to be noted that
`the gas is not
`consumed.
`It
`is returned as the oil
`is produced. The
`production side of the process, being primary production,
`is readily understood, and the production limitations of
`needing to produce to the edge of the pattern but without
`de-gassing the oil are easily grasped.
`
`Page 12 of 127
`Page 12 of 127
`
`

`
`20000
`
`16000
`
`12000
`
`8000
`
`4000
`
`CUMULATIVEOILPRODUCTION,m3
`
`Horizontal lnfili after Waterflood
`
` Horizontal Infill after Primary
`
`
`
`Pnmary
`
`10
`
`°/oIOIP
`
`10
`
`TIME, Years
`
`14
`
`16
`
`18
`
`Figure 1. The Effect of Restoring Solution Gas Drive
`
`
`
`500
`
`400
`
`300
`
`200
`
`100
`
`GOR
`
`50
`
`40
`
`Eg
`
`E u
`
`a“
`‘E 30
`n:
`C
`.2
`‘5 20
`
`31
`
`:oL
`
`.
`n.
`= 10
`O
`
`0
`5200
`
`4
`5300
`
`5400
`
`J
`5500
`
`5600
`
`5700
`
`O
`5800
`
`Figure 2. The Characteristic GOR Peaks
`
`Time, days
`
`4
`
`Page 13 of 127
`Page 13 of 127
`
`

`
`n 24000
`
`28000
`
`[OOOOO
`
`16000
`
`8000
`
`4000
`
`
`
`CumulativeOilProductionm3
`
`12000
`
`%IOIP
`
`Vertical Infill Well
` jay:
`Horizontal Infill Well
`
`
`
`
`
`o
`
`4ooo
`
`sooo
`
`Time, days
`
`Figure 3. Comparison of Infill Option Productions
`
`5
`
`-3-‘-
`
`
`
`ProductionRate,m3lday
`
`0
`
`0
`
`1
`
`No lnlill Well
`
`Zg:
`Vertical lnlill Well
`
`,.
`Horizontal Infill Well
`
`\\
`
`x
`
`7
`
`2
`
`3
`
`4
`
`5
`
`6
`
`7
`
`8
`
`Cycle Number
`
`Figure 4. Comparison of Infill Option Production Rates
`
`5
`
`Page 14 of 127
`Page 14 of 127
`
`

`
`Numerical Simulation of an Innovative
`
`Recovery Process
`
`(VAPEX)
`
`R. Engelman — GeoOuest Reservoir Technologies
`
`UNAVAILABLE AT TIME OF PRINTING
`
`Page 15 of 127
`Page 15 of 127
`
`

`
`Drilling Engineering Challenges
`in Commercial SAGD Well Design in Alberta
`
`R. Knoll — H-Tech Petroleum Consulting Inc.
`K.C.Yeung — Suncor Energy Inc.
`
`THIS PAPER IS TO BE PRESENTED AT THE SEVENTH ONE DAY CONFERENCE ON HORIZONTAL WELL
`TECHNOLOGY, CALGARY, ALBERTA, CANADA, NOVEMBER 3, 1999.
`
`ABSTRACT
`
`Recently, the field pilots in Canada using SAGD (Steam
`Assisted Gravity Drainage) technology have generated
`sufficient positive response to encourage commercial
`scale development in the Alberta Oil Sands Deposits.
`This will be a very interesting time for drilling engineers,
`since SAGD well pairs present some unique design and
`operational challenges.
`
`This paper will attempt to review some of the drilling
`engineering challenges of generic SAGD well design in
`the Alberta setting, specifically, the need to cool the
`drilling mud to maintain hole stability, and the selection of
`slant or vertical intermediate hole section geometry.
`
`INTRODUCTION
`
`The Alberta Oil Sands deposits, located in the areas of
`Athabasca, Cold Lake and Peace River, are widely
`recognized for their tremendous resources (Figure 1).
`The Alberta Energy and Utilities Board (AEUB) has
`estimated that the potential ultimate volume of crude
`bitumen in place in Alberta to be some 400 billion cubic
`metres (2.5 trillion barrels).
`Of
`these,
`the ultimate
`potential amount of crude bitumen recoverable from '
`Cretaceous sediments by in situ recovery methods is
`estimated to be 33 billion cubic metres (200 billion
`barrels).
`
`About 80% of the bitumen in Alberta are contained in the
`Athabasca Oil Sands Deposits, where the in situ viscosity
`
`is over 1 million centipoise. The oil industry and Alberta
`government have been searching for in situ techniques to
`recover the bitumen economically. Significant amount of
`research and development and piloting effort have been
`spent on in-situ combustion, cyclic steam stimulation and
`steamflooding with limited success.
`Finally, with the
`advance in horizontal well technology, the Steam Assisted
`Gravity Drainage (SAGD) process was pioneered at the
`Underground Test Facilities (UTF) near Fort McMurray
`and has become the technology of choice for many new
`in-situ projects in Alberta. Some 39 SAGD well pairs have
`been drilled in Alberta to date.
`In the last two years, there
`are four announced new commercial in-situ development
`in the Athabasca Oil Sands, whereby SAGD is
`the
`selected recovery process. These projects are AEC
`Foster Creek,
`JACOS Hangingstone, Pan Canadian
`Christina Lake and Petro Canada Mackay River.
`
`These commercial scale projects will utilize parallel pairs
`of horizontal wells which are key to the SAGD process.
`The lower horizontal well
`is the producer and the upper
`horizontal well, which is placed several metres directly
`above the producer, is the steam injector
`(Figure 2). As
`steam is
`injected into the reservoir along the upper
`horizontal well, the steam rises in the reservoir and heats
`the bitumen. As the steam cools,
`the force of gravity
`enables the heated bitumen and condensate (water) to
`flow to the lower production well.
`
`The amount of steam injected and fluid produced depend
`on reservoir qualities such as permeability, porosity, water
`saturation; on operating constraints such as operating
`pressure and steam trap control temperature; and on the
`
`Page 16 of 127
`Page 16 of 127
`
`

`
`SAGD reservoir is low. The “Cold Lake” type d%posits will
`have reservoir
`temperature around 12-16 C.
`The
`deposits of
`the more tar-like bitumen in
`the Fort
`McMurray region to the north tend to occur at a shallower
`depth and will have in-situ temperatures in the 7-10 °C
`range. While drilling, the fluid gains temperature due to
`the pumping action. The relatively hot drilling fluid will
`warm the near wellbore radius.
`The bitumen being
`heated along the well will thin, and this would lead to a
`reduction in the cohesive nature of the tar sand material.
`
`This may lead to a higher risk of hole instability, wellbore
`collapse and a host of other potential aggravations to the
`drilling operations. One can argue that mud chilling is an
`appropriate preventative maintenance step to reduce
`these hole trouble risks.
`
`However, a few experienced SAGD pilot operators claim
`mud cooling is expensive and inefficient, and question the
`“value added” of this undertaking. In the publicly available
`documentation of SAGD field pilot operations there exist
`very little detailed data on either the effectiveness of mud
`cooling, or any definitive field observations of improved
`hole conditions being the direct result of mud chilling.
`During extensive interviews with SAGD pilot operators, it
`became clear that the issue is driven by personal opinion
`and common sense, as opposed to any detailed field
`data, which either strongly supports or challenges the
`benefit argument.
`
`The authors conducted a review of the field data available
`
`from a pilot drilled in the Cold Lake area in the winter
`season.
`During extended bitumen drilling intervals
`(horizontal hole exposure time averaged 7.3 days per
`well),
`the drilling fluid temperature increased to a
`maximum of approximately 35 °C. Mud chilling was
`attempted by adding dry ice to the mud tanks. The field
`data was too sparse to define the chilling efficiency of this
`method, although it was expensive. The limited hole
`condition monitoring of torque and drag values (T&D)
`conducted on these wells precluded any ability to validate
`a value added, or risk avoided by mud chilling. The fact
`that all well pairs (for the most part) were successfully
`completed is not definitive proof of a mud chilling benefit.
`This “rather indefinite” scenario is common.
`
`Heat Generation and Dissemination
`
`is
`There are unknowns in regard to how much heat
`gained by the drilling fluid via handling and pumping.
`There exists a complex set of unknowns in terms of
`where and how fast the heat is disseminated throughout
`the hole and surface system, as well as how deep and
`how fast
`the heat is transferred from circulating fluid to
`the wellbore wall along the horizontal section in the
`reservoir.
`
`Page 17 of 127
`Page 17 of 127
`
`V.
`
`
`
`we length of the well. Some of the factors_ that determine the
`;length of a well include geology and the_pressure drop
`
`between the heel and the toe in the horizontal section.
`The pressure drop in an injector is a function of steam
`volume, pressure and pipe size. Using a larger casing
`will reduce this pressure drop. The selection of the size
`of the liner and the intermediate casing is also influenced
`by the size of tubing and other instrumentation strings
`inside the casings. All the injection/production process,
`monitoring and manipulation demands have to be defined
`and addressed prior
`to considering the more typical
`drilling engineering issues. Thus, the optimization in the
`drilling design of SAGD wells requires dramatically more
`multi-disciplined team synergy than do vertical wells.
`
`(ERD)
`drilling
`reach
`extended
`are
`SAGD wells
`applications, where total length will be 3 to 8 times the
`true vertical depth (TVDV). The well pairs require uniquely
`precise 3-D trajectory control, since the accuracy of well
`separation is a critical parameter in the SAGD process.
`Typically the reservoir will be a very shallow depth (150 to
`600 m TVD). Hole stability is a concern in drilling in the
`unconsolidated oil sands. Tight streaks and shale plugs
`in the reservoir and the erratic overlain glacial till deposits
`can complicate directional drilling capability.
`All these,
`and other aspects, present
`significant design and
`operational challenges to the well construction team.
`
`In the field pilots conducted to date, these challenges
`have been overcome with numerous
`technical and
`
`Pilot curves and magnetic
`innovations.
`operational
`vectoring for trajectory control, fibre optics for downhole
`instrumentation, expansion joints
`for
`tubular
`thermal
`distortion are examples. As the industry progresses from
`process validation
`(i.e.,
`pilot)
`to commercial
`scale
`development, much more emphasis must be placed on
`the capital and operating costs of these wells. The well
`construction costs represent a significant portion of total
`project capital expenditures. The economic success of
`any commercial SAGD development will depend on how
`cost effectively the multi-disciplined team can address
`and overcome the design'and operational challenges of
`optimized well pairs.
`
`This paper will focus on two specific drilling engineering
`issues: the requirement for mud cooling and the choice of
`vertical vs. slant intermediate hole section geometry.
`
`MUD COOLING
`
`An extensive series of informal interviews with SAGD pilot
`operators revealed a spectrum of opinion in respect to the
`value added of mud cooling during drilling operations.
`The
`argument promoting mud cooling is
`relatively
`straightfonivard. The in-situ temperature of the typical
`
`

`
`to quantify the heat generation and
`In an attempt
`dissemination in a generic SAGD well design,
`the
`following assumptions were made:
`
`1. A 1-km horizontal section is drilled with water. The
`total hole volume (total measured length is 1,500
`metres) is 110 ms, the surface tank volume is 250 m3,
`and the total system volume is 360 m3.
`
`2.
`
`_A 1,200 HP pumping system is employed and
`operates 18 hours
`in a 24-hour period at 95%
`mechanical
`efficiency.
`The
`initial
`reservoir
`temperature is 10 °C, and the ambient temperature is
`10 °C and constant.
`
`per
`2,545 BTUs/hour
`of
`generation
`3. A heat
`horsepower of pump is assumed for
`the heat
`generated by pumping.
`in one day of drilling
`operations (18 hours pump activity), this would predict
`the
`total
`system volume would
`experience
`a
`temperature increase of approximately 18 °C, thus,
`the system temperature would be 28 °C after the first
`day with zero heat loss.
`
`The monitored heat gain values in the reviewed pilots
`were far less than this figure. Perhaps 5-7 °C gain per
`day is more in line with reported field observation. This
`would suggest that the majority of the heat is lost by the
`drilling fluid as it is circulated. How much of this heat is
`taken up by the bitumen wellbore wall
`is difficult
`to
`quantify.
`
`The effectiveness of introducing dry ice, liquid nitrogen, or
`other agents to the system is not well documented in the
`public domain. One operator employed liquid nitrogen to
`“boil” the active drilling fluid in a Fort McMurray area pilot
`during the winter season. This appeared to help, since
`the mud temperature was controlled at low levels. The
`two pilot pairs were constructed without any major hole
`stability problems. However,
`the incremental well cost
`was quoted in the $70,000 to $100,000 range. For a 50-
`well commercial project,
`this would relate to a 3 to 5
`million-dollar
`trouble
`avoidance
`expenditure.
`in
`a
`commercial scale development, perhaps a more" capital
`intensive (consumable free) commercial
`chilling unit
`would be more cost effective.
`
`Recently an operator employed a commercial chilling unit
`in a SAGD project. The first well pairs were drilled in the
`winter season without major hole trouble observed related
`to mud temperature. The second phase pilot drilling was
`to be conducted in the summer. The operator employed
`a commercial chiller for the summer drilling operations to
`restrict the drilling fluid temperature to that experienced
`during winter drilling. This chilling unit is similar in scale
`
`to the refrigeration system required in a typical community
`ice rink.
`
`A series of tubes were installed in a conventional mud
`
`tank to act as a heat exchanger. A coolant was circulated
`to lower the drilling fluid temperature in the tank. This
`arrangement can be used to either pre-chill the mix water
`or
`to actively chill
`the drilling fluid. Other than the
`purchase cost or rental of the chiller itself, the only daily
`expense was fuel to operate the chiller compressors and
`transfer pumps. The operator reported that this system
`was relatively inexpensive and trouble free to employ
`during the drilling operations. The quoted capability of the
`chiller was 480,000 BTUs per hour. At 90% efficiency,
`this chiller would remove approximately 10.4 million BTUs
`from the drilling fluid in a 24-hour period.
`For our
`example well scenario, the 360 m3 water system could be
`chilled approximately 7 °C in 24 hours, or about equal to
`the field observation of the heat retained in the drilling
`fluid from the pumping activity.
`
`A review of the field data from this pilot suggests that in
`general, this degree of cooling was achieved. The well
`pairs were successfully completed, the fluid temperature
`was lowered to winter condition levels, and thus the
`operator is inclined to assign a benefit to the mud cooling
`efforts.
`
`The critical unknowns are the effectiveness of heat
`transfer from the fluid to the wellbore wall, and the
`threshold bitumen temperature at which hole trouble is
`experienced. Recently one operator conducted lab tests
`on
`site-specific
`cores
`to
`identify
`this
`threshold
`temperature at which thinning of
`the bitumen would
`generate hole instability. The tests did identify a target
`“trouble” temperature, although it must be stressed that it
`is extremely difficult to mimic all downhole physical and
`chemical dynamics. There are many inter-related factors
`other than mud temperature at play. Annular velocities
`and flow regime, solids distribution, reservoir character,
`fluid chemistry and rheology, pipe movement, hole
`exposure time, etc., all may have significant impact on
`hole integrity.
`The operator did suggest
`that
`for a
`commercial
`scale SAGD development,
`conventional
`chiller mud-cooling
`expense will
`probably average
`$10,000 per well. They concluded that this may represent
`a reasonable “trouble avoidance’ expense.
`
`To Cool or Not to Cool?
`
`Most drilling engineers will quickly accept the fact that hot
`drilling fluid could help aspirate poor hole conditions in a
`SAGD well setting.
`It also appears that chillers can be
`employed to counteract some of the heat gain generated
`by the drilling activity. Does this mean that mud cooling is
`a must for commercial SAGD operations?
`
`Page 18 of 127
`Page 18 of 127
`
`

`
`Figure 3 presents the temperature/viscosity relationship of
`some sample bitumen. As seen, there is a variance of
`character. The bitumen in the more northern Athabasca
`and Fort McMurray regions have higher in-situ viscosity
`than do the Cold Lake type deposits. This more viscous
`bitumen tends to be at a shallower depth, and their in-situ
`temperatures are therefore lower than the deeper, less
`viscous varieties.
`
`Let us assume that a SAGD well was drilled in an
`
`of 4,000,000
`viscosity
`(in-situ
`Athabasca Bitumen
`centipoise at 10 °C); and the drilling fluid was allowed to
`heat to 30 °C.
`If the hot mud was 100% effective in
`
`heating the wellbore wall to a similar temperature of 30
`°C, the altered material would still be significantly (i.e., 10
`times) thicker than the Cold Lake material in its unheated
`native state. Given the observation that relatively hot fluid
`was employed at a Cold Lake area pilot, and the holes
`had very extensive exposure times without any major hole
`collapse problem, leads one to conclude that mud chilling
`will be
`less
`critical
`in a colder,
`thicker, bitumen
`application. The thicker and cooler the target bitumen,
`the less it will be susceptible to hole trouble related to
`heat transfer from the drilling fluid.
`
`SLANT OR VERTICAL INTERMEDIATE SECTION
`DESIGN
`
`the well will be
`The optimal 3-dimensional profile of
`defined by numerous issues. A pilot program may involve
`a few well pairs having relatively simple 2-D curve shapes
`from a small surface pad. On a commercial scale, SAGD
`development strongly promotes utilization of multi-well
`pads. The primary benefits of this surface geometry
`being minimized land disturbance, optimized drilling
`operations, heat
`conservation and surface facilities
`consolidation. Assuming the reservoir areal distribution
`allows for symmetrical exploitation with parallel well pairs,
`the vast majority of well pairs will
`require a 3-D
`intermediate hole section design.
`
`Figure 4 provides one possible plan view example for a
`twin, 8-10 pair pad geometry. As seen, most of the wells
`must have 3-D shape in their intermediate hole section to
`generate symmetrical, parallel steam chambers. This
`example design employs 200-metre
`inter-well
`pair
`spacing with horizontal productive intervals of 1-km
`length. The total area exploited by this layout would be
`approximately 4.75 km2 (1.75 miles ). This geometry puts
`the gathering system in the ground and exploits almost 2
`sections of resource from one central plant facility.
`
`One issue is whether or not to employ a slant design in
`the upper hole section vs. a more conventional vertical
`
`The slant design would
`surface hole arrangement.
`reduce the dogleg severity (DLS) in the curve. The DLS
`is a critical design issue since it constrains ability to drill
`the wells and install completion tubulars.
`It also will
`significantly impact well
`intervention capabilities, and
`affects the stress on the thermal casing around the curve.
`Figure 5 illustrates the performance envelope for thermal
`grade casing as a function of DLS. As seen, the more
`gentle the bend, the greater the performance capability of
`the tube. Connector performance is also dramatically
`affected by the bend rate.
`In general terms, the greater
`the bend rate, the more the stress on the connector, thus,
`the higher
`the risk of
`failure.
`Limiting the DLS is
`attractive, and thus employing a slant intermediate hole
`design appears advantageous.
`
`Torgue and Drag
`
`A comparison of predicted surface torque and drag
`values was conducted on the generic far corner well,
`illustrated in Figure 4, with progressively shallower
`settings. For this analysis, the ability to run 1 km of 178
`mm slotted liner was investigated in the well where the
`only c