decreased dramatically over the years,resulting in fields that—while still hav-ing ample reserves—are not consideredto be viably economic to produce orhave not been economically viable,given heavy oil-production costs.Specifically in California, approxi-mately half of the state’s crude oilreserves consist of heavy oil. How-ever, using current or dated technol-ogy, fewer than 9 billion barrels ofheavy oil have been produced from anoriginal total resource of 77 billionbarrels [3].
This article explores the utilizationof electric heat tracing (EHT) as a viabletechnology solution to bridge the gapbetween economic and uneconomicwhen considering heavy oil wells in theCalifornia region, wherein production has dropped to anunacceptable level or production is not economically desir-able. Historically, specific EHT technologies have provento be viable solutions—technically and economically—when considering the maximization of well output againstthe capital costs of new equipment required at the well.Recently other EHT technologies, such as mineral-insu-lated (MI) heating cables or skin-effect tracing systems,have entered the arena of down-hole heating (DHH) orbottom-hole heating considerations, providing a much-needed solution for the development of more difficultreservoir conditions. With this mindset, this article willlook at the specific application needs (i.e., heavy oil reser-voirs throughout the California region), the availabletechnology solutions with specific emphasis on EHT, andthe expected and realized results through the use of theseavailable technology solutions. Further, this article willhighlight the system requirements for this solution andthe associated cost, with specific emphasis on return oninvestment when considering capital cost and operatingcost expenditures.
Crude OilUnconventional oil has many definitions within the oilindustry and often includes the broad term heavy oil.In simplest terms, crude oil is a mixture of hydrocarbonssuch as paraffin, aromatics, napthenes, resins, and asphal-tenes. The heavier crude has proven to be problematic inpast years due to the highly viscous nature of heavy oiland the inherent difficulties of producing these reservoirsat a production rate that is economical. Oil is consideredheavy if it has 10–20� API gravity or a viscosity from 100to 10,000 cP at original reservoir temperature. Heavy oilin California is approximately 13 API gravity or close to5,000 cP [3]. One of the largest fields of heavy oil in theUnited States is located in Kern County, California,approximately 160 km north of Los Angeles.
The Kern County reservoirs are estimated to be a 40-bil-lion barrel resource, primarily of heavy crude located in shal-low reservoirs. Production of these heavy oil reservoirs wasslow until the introduction of steam in the 1960s to reducethe viscosity. Through the cyclic steam process and steamfloods, producers were able to reach a peak production in the
mid-1980s of 250 million barrels/year.Environmental concerns contributedto increasing cost of production. Sincethen, with as much as 65% of theoriginal oil believed to be still inplace, production has dropped offconsiderably [3].
Today, with more than 70% of theproduction in Kern County beingconducted by independents and theeconomics and environmental con-cerns taking on a heightened presencein production, alternative methods ofoil recovery are being considered.Hence, EHT is a viable solutionfor the enhanced oil recovery ofshallow low-flow wells in the KernCounty region.
For the purpose of this article,the application being presented involves an onshorewell currently in development outside of Bakersfield,California, in the Kern County region. The specific fieldbeing developed has a reservoir temperature of 120 �F(49 �C) and the reservoir depth is approximately1,400 ft (427 m) with an expected total production rateof 10–20 barrels per day. The combination of theseand other factors posed several challenges relative totechnology selection and physical deployment, all ofwhich are presented in this article.
Traditional Methods of Enhanced Oil Recoveryof Shallow Low-Flow WellsCrude oil development and production in the UnitedStates has three distinct phases: primary, secondary, andtertiary recovery. Primary recovery involves the naturalpressure of the reservoir along with artificial lift methodsto move oil reserves to the surface. Under primary recov-ery, depending on the nature of the reservoir and oilcharacteristics, normally, only 10–25% of the oil isrecovered economically. Secondary recovery involvesinjecting either gas into a gas cap or water into the waterleg of a reservoir to regain pressure and energy to allowoil to flow to the wellbores. This process normallyproduces 20–40% of the original oil in place. Tertiaryprocesses have been developed, and several methods havebeen used in an attempt to prevent or at least mitigate
CRUDE OIL IS AMIXTURE OF
HYDROCARBONSSUCH ASPARAFFIN,
AROMATICS,NAPTHENES,RESINS, ANDASPHALTENES.
TABLE 1. EHT TECHNOLOGIES.
Constant-Wattage(PolymerInsulated)
MineralInsulated
Maintaintemperature
Up to 122 �F(50 �C)
Up to 1,022 �F(550 �C)
Maximumheat output
12.5 W/ft(41 W/m)
82 W/ft(269 W/m)
Maximumheater length
Up to 3,608 ft(1,100 m)
Up to 5,740 ft(1,750 m) 19
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the impact of the viscous nature of theseheavy oils. These include methods suchas thermal recovery process, which con-sists of cyclic steaming, steam flooding,and in situ combustion; chemicalflooding, which includes polymer andsurfactant flooding; more recently,CO2 flooding is beginning to takeprecedence due to new environmentallaws and carbon sequestration. Theseprocesses have been developed be-cause, in many reservoirs, the oilviscosity is so high that primaryrecovery is not sufficient to ade-quately produce the oil in place.A brief look at these methods high-lights some of the drawbacks inherentin each.
Kern County has more thermal recovery projects thananywhere else in the United States. Fields like Kern River,Belridge, and Midway Sunset are a few of the large fields
where steam flooding and cyclic steam-ing processes are taking place. Thecompanies responsible for developingthese heavy oil reserves have investedgreatly in the infrastructure requiredto steam high-viscosity oil reserves.Steam generators, cogeneration facili-ties, dense well spacing, high volumesof natural gas, and fresh water arerequired to make these projects viable.The principal concern is that theseprojects are highly capital-cost inten-sive and would be uneconomic on asmaller scale. That is where the down-hole heaters come into play. The down-hole heaters can be economicallydeployed in a well-by-well case where
large infrastructure and capital projects cannot be econom-ically justified.
Along with steam processes, such as in situ combus-tion, polymer and surfactant flooding have beendeployed in heavy oil fields. In situ combustion is aprocess where air/oxygen is injected into the reservoir.At pressure, oil around the injection well ignites andproduces heat. The heat reduces the viscosity of the oil,allowing it to flow and hence produced in the surround-ing wells. This is a destructive process due to well fail-ures, where oil reserves are lost. This technique hasbeen tried but has almost always been an economicfailure. Surfactant flooding involves injecting a surfac-tant with injected water. This is similar to a waterflood, where the chemical injected reduces the oilviscosity and allows reserves to flow. Due to the highcost of chemicals, economic success is limited. Polymerflooding is a similar approach to surfactant flooding,where, instead of reducing the viscosity of the oil, itincreased the viscosity of the water so that viscous fin-gering does not occur. This method also has minimalresults. These three methods have not been proven to beeconomically viable in any large-scale heavy oil recov-ery projects.
Control Panel
Transformer
ProductionTube
Cold Lead
Thermocouple
Heater
1A typical system.
TABLE 2. BASIC CHARACTERISTICSOF THE SUBJECT WELL.
Characteristic Value
Reservoir depth 1,499 ft (457 m)
Reservoir temperature 120 �F (49 �C)
Casing diameter 7 in
Total liquids production rate 6 BLPD
Production tube size 2–7/8 in
Viscosity, API gravity 14.3 at 60 �F
Viscosity (cSt) 365.8 at 120 �F
Viscosity (cSt) 92.3 at 160 �F
Viscosity (cSt) 33.6 at 200 �F
CRUDE OILDEVELOPMENT
ANDPRODUCTION INTHE UNITED STATES
HAS THREEDISTINCT PHASES.
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With federal and state legislationrequiring oil companies to be moreenvironmentally friendly, CO2 flood-ing and sequestering have gained thespotlight since 1972. This processinvolves capturing CO2 emissions froman industrial facility or CO2 gas fieldand injecting the waste gas into aheavy oil reservoir. CO2 mixes withheavy oil and reduces its viscosity.The produced oil is then stripped ofCO2 and sold. The produced CO2
is then reinjected. This process is capi-tal-cost intensive due to the specializedcorrosion-resistant facilities requiredto collect, inject, and remediate the
recycled gas. The main reason thatthis has been economically successfulin places like Texas is due to federaland state subsidies.
Utilization of EHTEHT has been used in the past—for atleast 20 years—as a viable solution forfreeze protection, process temperaturemaintenance, and heat up of specificprocesses. For DHH services, one ofthe early successful application usedself-regulating (SR) EHT technol-ogy, which eventually transitionedto the use of polymer-insulatedconstant wattage (CW) EHT
2
Current Wellbore Diagram
TDEDGLKB
1499′Tubing Record Formation TopsSize Length 1390′
1400′
Cement/Drill Bit RecordSX or
CFTrue or CTOC
CMT Depth
Bit SizeShoeTOLLengthGradeLB/FTSize
14′′7′′ 23
15.5J-55J-55 131′ 1340′ 1449′ 13′′
1380′ 9-7/8′′58cf377cf
Gravel
Description
TOL @ 1340′
Casing: 7′′, 23#, J-55, from Sur. to 1380′ Cement Return to Surface
Liner: 5-1/2′′, 15.5#, J-55, 1340-1449′
Gravel: 58cf of 8 × 12 Gravel
ED @ 1449′
Zone Top
Zone Bottom
at 1390′
at 1400′
TD @ 1449′
(107% in Place)
131′ Long. Slotted 0.050′′, 48R
Surface53′′ Surface
5-1/2′′
Casing/Liner Record
1499′861′13′
Current wellbore diagram.
KERN COUNTYHASMORETHERMALRECOVERY
PROJECTS THANANYWHEREELSE IN THE
UNITED STATES.
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technology. This technology providedan effective solution for wells withheavy crude as well as low-temperaturewax, paraffin, and hydrate issues, butthis was eventually limited by theamount of thermal power density theCW EHT cable was able to produce.Within the past few years, the viabilityof MI-EHT, another type of CW cable,as an effective DHH solution has beenexplored and implemented. Table 1shows the basic technical specificationsof each of the two principal EHT tech-nologies discussed earlier. Each of thetechnologies was considered for the application discussedin this article, and each is explored in detail so as to presenta more comprehensive case for the importance of technol-ogy selection relative to this application.
A typical system is depicted in Figure 1. In this system,as a minimum, the scope would include the electric heater, athermocouple for down-hole temperature indication, ameans to affix the heater to the production tube, a well-headpenetration for the heater to be brought to the topside, and a
control/power panel and transformer. Inthis case, the heater is applied to theoutside of the production tube.
Body
The ChallengeThe targeted well for this considera-tion was located in Kern County, Cali-fornia. The reservoir contained heavyoil with a 14.3 API viscosity at 60 �F(15.6 �C). The primary specifics andschematic of this well are shown inTable 2 and Figure 2.
To achieve an increased production rate on this well, aspecific amount of heat would need to be introduced to thewellbore in the reservoir area. By adding heat to this sectionof the production tube, it was expected that the increasedtemperature would expand into the reservoir. By expandingthe heat out away from the production tube and into thereservoir, we would be heating the heavy oil above its reser-voir temperature decreasing its viscosity, thereby allowingfor better flow upto and into the production tube itself.
There were several challengesinherent with this solution. Toincrease the production flow, a rela-tive amount of heat would need to beinput into the immediate area of thereservoir; so, in effect, the heat itselfwould need to be concentratedtoward a relatively small area of thetotal production tube length. This isthe payzone area of the reservoir.Similarly, since this is a relativelysmall-diameter production tube, theheat tracing itself would need toeither be able to input a largeamount of heat through minimumpasses or be of a small-enough diam-eter so that multiple passes could beinstalled. Finally, the technologywould need to be rugged enough towithstand the tubing and long-termwellbore conditions. All of these fac-tors, and many more, played into the
Galvanized ArmorFluoropolymer Outer Jacket
Tin-Plated Copper Braid
Tin-Plated Copper Conductors
SpacerFluoropolymer Jackets
GalGGGG vanizeii d ArmorFluoropolymer Outer Jacke
Tin-Plated Copper Braid
Tin Plated Copper Conductors
SpacerFluoropolymer Jackets
4Polymer-insulated CW cable.
3A typical application.
Alloy 825 Sheath
Heating ConductorsInsulation (Magnesium Oxide)
5The MI cable.
POLYMERFLOODING IS A
SIMILARAPPROACH TOSURFACTANTFLOODING.
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overall technology selection as solutions were sought forthis application (Figure 3).
Possible EHT SolutionsEHT, as an industrial technology, is governed by IEEEStandard 515 [1]. The most common form of electricalheating is the production of heat in an electrically conduc-tive or semiconductive material occasioned by passing anelectric current through the material.
EHT has been considered an effective solution for flowassurance, wax, paraffin, and hydrate concerns for manydecades, with the primary technical solution being an arm-ored polymer-insulated CW technology. Historically, theprevious CW heating cable technology used consisted ofthree insulated conductors running parallel to each other.The conductors are insulated and have a metal braid, poly-mer-jacket, and an overall armor. A voltage is appliedacross the conductors, causing the current to flow, generat-ing heat. The three-phase CW heating cable, as shown inFigure 4, is an industry-proven solution with literally hun-dreds of down-hole heater installations worldwide. For thisapplication, though, the CW technology would not be ableto produce the amount of heat output required for thisunconventional reservoir, given the number of passes thatwould be required. Further, space limitations were also a
7Configuration of control and monitoring.
TABLE 3. CHARACTERISTICS OF THE MICABLE TECHNOLOGY.
Characteristic Value
Cold lead length 1,400 ft (427 m)
Heating cable length 536 ft (163 m)
Heated section passes 6
Heated cable diameter 0.184 in
Total power output 25.7 kW
Power output per footof wellbore
286 W
Voltage 600 V
Phase 1
Inrush current (at 20 �C) 69 A
Heated Length Cold Lead Length
Hot/Cold SpliceCold–Cold Splice
(If Required)Temporary Seal or
Factory Termination
6The MI cable configuration.
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consideration, as the CW cablewould require multiple passes toproduce the amount of heat neces-sary for this application, and thecable itself, when applied to thesmall production tube, would havemade the application difficult if notcompletely impractical.
MI-EHT, as shown in Figure 5,was considered next. This cable con-sists of one or two conductorsembedded in a magnesium oxideinsulation enclosed in a metalsheath. The series-type MI heatingcable has been utilized successfullyfor conventional applications—top-side pipe and equipment—for deca-des, but it has only recently beenused in the oil-production industryas a viable solution for down-holeheater applications, specifically forlow-flow, shallow, aging wells, mon-itoring application for cyclic steamstimulation applications and specificflow assurance (i.e., wax/paraffinissues) applications. For this application, the MI technol-ogy proved to be an ideal solution, given its rugged con-struction, high heat output capability, and relatively smalldiameter when compared with the CW cable.
For this specific application, it was decided to use asingle-circuit MI cable with characteristics as describedin Table 3. In total, the design accounted for six passes ofsingle-circuit MI cable with a heat output of 25.7 kWover the 90 ft reservoir area. Revisiting each of the
aforementioned concerns, the cableitself was designed to produce up to 48W/ft (157 W/m); was fabricated to asmaller heater diameter of 0.184 in;and, as is typical for this technology, wasalso fabricated with a rugged Alloy 825sheath for additional protection duringinstallation and operation. The specificsof this heat trace cable are providedin Table 3.
The above heater was designed andfabricated with a continuous heatedsection and no hot-to-hot splices. The1,400 ft (427m) length of cold leadrequired four cold-to-cold splices.The only other splices required forthis application were at the hot-to-cold connections. Ensuring that therewere no hot-to-hot splices as spacelimitations were of enormous concern,providing as much space as possiblefor actual heater was important for thedesired results. A sketch of this typeof cable is shown in Figure 6.
Control and Monitoring SolutionA diagram is presented in Figure 7 that illustrates thecontrol and monitoring configuration used for this solu-tion. The control concept for this system was simplicity.A temperature indicator was incorporated into the panelwith a direct connection to a Type-K thermocouple, andthe thermocouple sensor was installed in the well justabove the payzone so that the most accurate readingscould be taken. Other than the temperature indicator,readings such as current, voltage, and ground fault sen-sors were incorporated. The system is intended to beeither on for production or off for shut in. The amount ofheat being put into the reservoir will be constantthroughout, providing maximum reduction of the oilviscosity in the near wellbore reservoir area.
System Performance and ResultsThe results from this application solution to a bottom-hole heating surpassed the original expectations from a
PRIMARYRECOVERY
INVOLVES THENATURAL
PRESSURE OF THERESERVOIR
ALONGWITHARTIFICIAL LIFTMETHODS TOMOVEOIL
RESERVES TOTHE SURFACE.
TABLE 4. SYSTEM PERFORMANCE AND RESULTS.
Before After
Bottom-holetemperature
120 �F(49 �C)
240 �F(116 �C)
Production flow rate 6 18
8Picture of an installation.
TABLE 5. ECONOMIC ANALYSIS CRITERIA.
Criteria Cost Basis
Electricity cost US$0.09/kWh
Heater output 25.7 kW
Price of barrel of oil (New YorkMercantile Exchange)
US$40.00
Heavy oil discount factor 85%
Heater/system cost US$60,000
Installation cost US$20,000
Site electrical cost US$10,00024
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technical and economic perspective.With the incorporation of the abovetechnology, the production of this wellincreased substantially. Table 4 pro-vides a comparison of the well’sproduction rates before and after instal-lation of the heater (Figure 8). Notethat the production flow rate beforeimplementation of the bottom-holeheating system was dependent uponambient conditions. In other words, oncold days, the well would be left idle,as the derived benefits from productiondid not outweigh the operation costs,and on hot days, the well wouldproduce up to six barrels of liquid perday (BLPD).
As the results indicate, the produc-tion flow rate literally tripled, and thebottom-hole temperature—critical forincreased production—increased dra-matically. From an economic perspec-tive, the following data, shown in Table 5, was used toarrive at a total cost of ownership. This data is based onearly 2009 information, as it is recognized that cost data ofthis nature is, especially as of late, in constant flux. At thetime the system was actually installed, the price per barrelof oil was in the US$90 range, so the return on investmentwould have been a considerably shorter duration of time.
From the economic criteria above, an overall paybackperiod calculation was developed. First, we looked at theoverall revenue increase from the technology application:
18 BLPD� 6 BLPDð Þ3US$40=B3 0:85
¼ US$408:00=day:
To arrive at an investment payback number, the operat-ing cost increase to produce the additional 12 BLPD is cal-culated as
25:7 kW3US$0:09=kW� h 3 24 h ¼ US$55:51=day:
So, from these two values, we are able to calculate thenet daily revenue increase
US$408:00� US$55:51 ¼ US$352:49:
The simple payback period is then calculated as totalcost of installation divided by the revenue increase
US$90, 000=US$352:49 ¼ 255 days 8:5monthsð Þ:
This is an impressive result by most business standardseven at a moderate oil price.
ConclusionTo effectively develop resources from unconventionalreservoirs, specifically where low-flow conditions existdue to heavy oil characteristics, unconventional
solutions should be sought. Whilepolymer-insulated CW EHT hasbeen used successfully in the past as aDHH solution, its widespread usehas been limited due to lower heatoutput.
With the recent success of the MI-EHT technology applied towardDHH, the solution potential for thesedifficult-to-produce reserves not onlybecomes viable but also attractive froman economic standpoint.
With MI-manufacturing capabil-ities continuing to produce morerobust cables, resulting in higherquality and longer heat trace cables/systems with high heat output, thespectrum for solution-oriented optionsincreases. Following this, throughthe use of this EHT technology, adegree of control could be achievedthat is not available with typical con-
ventional solutions such as steam or chemical injection.As can be seen from the results of applying this technol-
ogy to the low-flow shallow well applications, there nowexists a viable enhanced oil recovery solution to these local-ized wells, many of which have been dormant for decades.Through the use of unique EHT technologies and, morespecifically, the MI technology, previously unattainableproduction can be achieved with minimum capital invest-ment with a desirable return on investment for operators.
AcknowledgmentsThe authors thank the following people for their assistanceduring the writing of this article: Jim Summers for hisinsight into the low-flow shallow-well landscape and hisassistance in mining for data that was relevant and key indeveloping this article and Julie Ahner for her valuableassistance in proofreading various revisions of this articleand for supplying key points of data to help substantiatethe overall findings.
References[1] IEEE Standard for the Testing, Design, Installation, and Maintenance of
Electrical Resistance Heat Tracing for Industrial Applications, IEEE 515-1997.
[2] C. J. Erickson, Handbook of Electrical Heating for Industry. New York:IEEE Press, 1995.
[3] M. Collison. California Heavy: Sharing Alberta’s Unconventional Oil Knowledgewith the Golden State. [Online]. Available: Oilsandsreview.com
Greg McQueen ([email protected]) and David Par-man are with Tyco Thermal Controls in Houston, Texas. HeathWilliams is with E&B Natural Resources in Bakersfield, Cal-ifornia. Parman is a Member of the IEEE. This article firstappeared as “Enhanced Oil Recovery of Shallow Wells withHeavy Oil: A Case Study in Electro Thermal Heating of Cali-fornia Oil Wells” at the 2010 Petroleum and Chemical Indus-try Conference.
