on the evaluation of fast-sagd process in naturally fractured heavy oil reservoir

$: On the evaluation of Fast-SAGD process in naturally fractured heavy oil reservoir$
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Fuel xxx (2014) xxx–xxx

JFUE 8627 No. of Pages 10, Model 5G

5 November 2014

Contents lists available at ScienceDirect

Fuel

journal homepage: www.elsevier .com/locate / fuel

On evaluation of the FAST-SAGD process in naturally fractured heavyoil reservoir

http://dx.doi.org/10.1016/j.fuel.2014.10.0650016-2361/� 2014 Published by Elsevier Ltd.

⇑ Corresponding author at: Institut de Recherche en Génie Chimique et Pétrolier(IRGCP), Paris Cedex, France. Tel.: +33 1 64 69 49 70; fax: +33 1 64 69 49 68.

E-mail address: [email protected](A.H. Mohammadi).

Please cite this article in press as: Kamari A et al. On evaluation of the FAST-SAGD process in naturally fractured heavy oil reservoir. Fuel (2014),dx.doi.org/10.1016/j.fuel.2014.10.065

Arash Kamari a, Abdolhossein Hemmati-Sarapardeh b,c, Hani Hashemi-Kiasari c, Erfan Mohagheghian c,Amir H. Mohammadi d,e,⇑a Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iranb Department of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, Iranc Department of Petroleum Engineering, Amirkabir University of Technology, Tehran, Irand Thermodynamics Research Unit, School of Chemical Engineering, University of KwaZulu-Natal, Howard College Campus, King George V Avenue, Durban 4041, South Africae Institut de Recherche en Génie Chimique et Pétrolier (IRGCP), Paris Cedex, France

h i g h l i g h t s

� Fast-SAGD is compared with traditional SAGD in a naturally fractured heavy oil reservoir with oil wet rock.� The CMG-STARS thermal simulator is used for this purpose.� The effect of operational parameters on Fast-SAGD performance is investigated.� Novel economical model is established in which all economical parameters are evaluated.� Cash flow particularly CAPEX and OPEX is studied.

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a r t i c l e i n f o

Article history:Received 19 March 2013Received in revised form 22 October 2014Accepted 22 October 2014Available online xxxx

Keywords:Fast-SAGDNaturally fractured reservoirOperational parametersEconomical modelPetroleumOil

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a b s t r a c t

Very recently, Fast-SAGD as a modification of SAGD has been much attended due to lower cumulativesteam oil ratio as well as higher cumulative oil production. However, there are still many suspicionsabout the successful application of this method in naturally fractured reservoirs (NFR) in which faults,fissures, vugs, micro-fractures, poorly interconnected matrix pore structure as well as undesirable wet-tability are combined with high-viscosity oil. In this communication, initially, Fast-SAGD is comparedwith traditional SAGD in an Iranian naturally fractured heavy oil reservoir with oil wet rock usingCMG-STARS thermal simulator. Moreover, the effects of operational parameters on Fast-SAGD methodhave been investigated. In addition, a novel economical model has been establish in which all economicalparameters including input cash flow such as the rate of oil production and oil price, and the output cashflow costs such as capital expenditures (CAPEX), operating expenditures (OPEX), injection material andpipe line tariffs, have been considered. During the optimization of the operational parameters, it wasobserved that by increasing steam injection rate into both offset and SAGD wells in Fast-SAGD system,ultimate RF increased, but ultimate (net present value) NPV increased up to an optimal point which couldbe due to the increased SOR value. By increasing steam injection pressure into offset well, both the ulti-mate RF and NPV increased up to an optimal point. To optimally select parameters such as the number ofCSS cycles, elevation of CSS well and well spacing of SAGD well pair, sensitivity analysis should be per-formed to achieve the best case economically and technically due to the lack of a decrease or increasetrend. In contrast to conventional reservoirs, the start-up time performance at offset well during Fast-SAGD process in fractured reservoirs indicates that earlier start-up time of steam injection leads to highRF and NPV.

� 2014 Published by Elsevier Ltd.

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1. Introduction

Conforming to the depletion of conventional oil reservoirs, oilindustry has started turning its consideration to unconventionalreservoirs such as naturally fractured reservoirs (NFR) and

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Nomenclature

EOR enhanced oil recoveryRF recovery factorSOR steam oil ratioCSOR cumulative steam oil ratioNFR naturally fractured reservoirSTBD stock-tank barrel per dayBHP bottom-hole pressurePVT pressure–volume–temperatureKro oil relative permeability

Krw water relative permeabilitySAGD Steam Assisted Gravity DrainageCSS Cyclic Steam StimulationISC In-Situ CombustionCSI Continuous Steam InjectionNPV Net Present ValueOPEX operating expendituresCAPEX capital expenditures

2 A. Kamari et al. / Fuel xxx (2014) xxx–xxx


5 November 2014

reservoirs of bitumen, ultra-heavy and heavy oil. Heavy oil existedin naturally fractured carbonate reservoirs is a striking resourcewhich has been estimated to be 1600E+9 STB in place [1]. Undesir-ably, in such reservoirs, rock complexity at different scales isencountered, i.e. faults, fissures, vugs, micro-fractures, poorlyinterconnected matrix pore structure as well as undesirable wetta-bility are combined with high-viscosity oil [2]. Consequently, oilrecovery from these reservoirs becomes a real challenge and classicthermal application theories are failed to define the process.

There are different thermal methods which have been intro-duced for heavy oil recovery in fractured carbonate reservoirs.These methods include Cyclic Steam Stimulation (CSS) [3–6], Con-tinuous Steam Injection (CSI) [7–10] and In-Situ Combustion (ISC)[11–13] as well as Steam Assisted Gravity Drainage (SAGD) [14–22]. However, to date only limited experience has been obtainedin the application of thermal recovery methods to this class ofreservoirs.

During the last decades, SAGD and its modifications are tech-nologies which have been much attended as they are more effi-cient and profitable in the recovery of heavy oil and bituminoussands [23]. This method consists of a horizontal well pair in whichthe top well serves as the steam injector and the bottom well as theproducer. These wells are placed near to the bottom of the pay andat a short distance from each other. In this process steam isinjected ceaselessly through the upper wellbore. Subsequently, asteam chamber is constructed by rising steam in the reservoirand forming a steam-saturated zone. The heat from steam is trans-ferred into the surrounded reservoir by thermal conduction andsubsequently oil viscosity reduces greatly and becomes mobile[24]. In fact, viscosity reduction plays a key role in thermalenhanced oil recovery (EOR) processes [25].

Fast-SAGD, a modification of the SAGD method, in addition toSAGD well pair uses offset wells operating with cyclic steam stim-ulation in order to accelerate the steam chamber growth sideways[26]. Actually, the Fast-SAGD recovery process is combined fromSAGD and CSS processes and consequently benefit from advantagesof both of them. It should be noted here that one of the mostimportant advantages of Fast-SAGD process over the traditionalSAGD method is that Fast-SAGD solves drilling difficulties anddecreases costs in a SAGD operation requiring parallel paired wellsone above the other.

In Fast-SAGD process, the offset wells are located at the sameelevation as the SAGD producers and can be 50–80 m away fromthe SAGD well pairs. It is suggested that operate the SAGD wellsuntil the steam chamber reaches the top of the formation and thenstart a CSS operation at the offset wells at a remarkably higherpressure than the SAGD wells. The aim injecting steam into the off-set CSS well is to hasten growth and propagation of the steamchamber laterally. Once the inter-well area between the SAGD wellpairs is heated enough, ideally when the two steam chamberscome into contact, the offset well is converted into a producerand the SAGD operation continues [27].

Please cite this article in press as: Kamari A et al. On evaluation of the FAST-Sdx.doi.org/10.1016/j.fuel.2014.10.065

Economic evaluation serves as the policeman of the petroleumindustry and determines whether or not a project should be under-taken. To date, several papers have appeared within oil industry lit-erature in regard to economic evaluation methods [28–38].However, few papers have been published encompassing economicevaluation methods for Fast-SAGD process [39–41].

Initially, in this study, influences of CSS well elevation, numberof CSS cycles, CSS well injection pressure and rate, CSS well startingtime, spacing of SAGD wells and SAGD wells injection rate on theultimate oil recovery factor and steam oil ratio are investigated.After that, in order to select the optimum operational parameterseconomically, unlike the reported results of previous researchers[39–41], a comprehensive study to quantify the effects of increaseor decrease in the operational parameters on Net Present Value(NPV) is done.

2. Literature review

Application of Fast-SAGD in NFR reservoirs is not well under-stood. As a matter of fact, some studies have been conducted tostudy Fast-SAGD processes in sandstone reservoirs [26,27,39–46].Polikar et al. [26] carried out a numerical simulation to evaluatean enhancement of the SAGD process, namely Fast-SAGD, for theCold Lake deposit. They observed a raise in ultimate recovery andits rate and also a reduction of the Cumulative Steam Oil Ratio(CSOR) through this new process.

Shin and Polikar [42] studied reservoir parameters as well asoperating conditions to optimize the SAGD and Fast-SAGD pro-cesses and compared the efficiency of these methods. Their studyshowed an improvement of 24% in energy efficiency and 35% inproductivity for Fast-SAGD compared to conventional SAGD. Inthe other work, Shin and Polikar [41] carried out a sensitivity anal-ysis for Fast-SAGD operating conditions in conventional reservoirssuch as offset well distance and CSS start-up time at the offset well.To pursue their objective, in addition, Shin and Polikar [43] oper-ated physical model experiments under high temperature and highpressure conditions. The results of preliminary experiments illus-trated larger cumulative oil production in the Fast-SAGD case,although end-point CSOR was lower in the SAGD case.

To more realistically investigate the performance of Fast-SAGDprocess, Coskuner [27] used a 3D model in contrast to the previousstudies based on 2D homogeneous models. It was found that Fast-SAGD produces more oil in a shorter time but with a higheramount of SOR compared with conventional SAGD. In the nextresearch, a comparative evaluation between conventional SAGDand Fast-SAGD in three typical formations of Alberta oil sandwas presented [45]. The results showed that significantly recover-able bitumen was originally produced from offset well in Fast-SAGD model which subsequently led to higher recovery factor,but there was a slight increase in cumulative oil recovery whenthe two processes were conducted in the same pattern with iden-tical number of production wells. Beside, Holcomb et al. [28]

AGD process in naturally fractured heavy oil reservoir. Fuel (2014), http://



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Table 1Reservoir rock-fluid data of under-survey reservoir.

Parameter Unit Value

Matrix porosity % 19.5Fracture porosity % 0.006Matrix permeability mD 50Fracture permeability mD 2000Matrix oil saturation % 85Fracture oil saturation % 100Irreducible water saturation % 15Residual oil saturation % 40Viscosity Cp 2000Formation thermal conductivity Btu/Day .ft. �F 24Oil thermal conductivity Btu/Day .ft. �F 2Rock heat capacity Btu/ft3. �F 30Reservoir pressure Psi 1200Reservoir temperature �F 140

Fig. 1. Oil–water relative permeability curves.

A. Kamari et al. / Fuel xxx (2014) xxx–xxx 3


5 November 2014

introduced a computer program of a simplified model that dealsonly with the economic evaluation of steam injection projects.Moreover, Petit et al. [37] compared the injection strategiesapplied to different vertical and horizontal well patterns from aneconomic point of view, which considered the recoveries and fieldcosts for the processes. The economic interest of using horizontalwells for deep heavy-oil reservoirs where steam injection with ver-tical wells would be economically unprofitable was shown. Unlikethe present study, they only examined profitability of the verticalor horizontal well parameters.

As previously mentioned, Shin and Polikar [41] optimized Fast-SAGD process through numerical reservoir simulations for threetypical oil sand areas in Alberta: Athabasca, Cold Lake and PeaceRiver reservoirs. Economic analysis was then used to optimizethe Fast-SAGD operating conditions. The simulation results indi-cated that project economics in most cases were enhanced com-pared to the SAGD process. In order to compare the processes,they used the parameters of offset well location, CSS start-up timeat the offset well, steam injection pressure at the offset well andreservoir thickness. However, they did not include effects ofparameters related to SAGD well pair.

Rios et al. [31] conducted a numerical study of SAGD process infield scale. The methodology used involved an investigation ofmain parameters influencing the application of the method and asensitivity analysis in order to determine the best time to startgas injection in pursuit of maximizing Net Present Value (NPV).Like previous researchers, Rios et al. did not perform a comprehen-sive optimization; they only investigated three parameters ofinjection pressure, production pressure and injection rate.

Nguyen et al. [40] investigated different cases designed to opti-mize operating conditions of SAGD and Fast-SAGD processes. How-ever, the drawback was that they did not use the main andimportant parameters of Fast-SAGD process in order to select thebest case economically and technically. They have reported thatcumulative oil for Fast-SAGD process does not significantlyincrease and even NPV is the lowest in comparison with othermentioned SAGD cases.

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Table 2Used operational parameters to build the base model.

Parameter Unit Value

Steam injection rate at offset well STB/day 1400Steam injection rate at SAGD well pair STB/day 1000Steam injection pressure at offset well Psi 2250Steam injection pressure at SAGD well pair Psi 1220Steam injection temperature at offset well �F 600Steam injection temperature at SAGD well pair �F 600Producer BHP at offset well Psi 1190Producer BHP at SAGD well pair Psi 1190Steam injection quality at offset well – 0.9Steam injection quality at SAGD well pair – 0.9

3. Model development

3.1. Technical model description and base case analysis

The under-surveyed reservoir is an Iranian oil-wet carbonatereservoir. It is a massive, highly fractured and heavy-oil reservoirlocated on the coast of Persian Gulf in the south of Iran, containinga huge amount of original oil in place (several billion barrels).However, development of the reservoir has not begun yet; there-fore, it is a good candidate for study of enhanced oil recovery meth-ods. In order to evaluate the effects of various technical parameterson the RF, CSOR and cash flow values of the Fast-SAGD, a sector ofthis reservoir was selected as follows. To build this sector,42 � 1 � 12 cells in i, j and k coordinates were chosen, respectivelyas the base case grid number. In fact, a rectangular cubic reservoirwith dimensions of 378 � 1400 � 96 ft was defined. PVT propertiesof the fluid have been obtained using CMG-Winprop software andCMG-STARS have been employed as the simulator. To simulateNFR, dual porosity model has been applied in this study. The frac-tures with the permeability of 2000 mD and 10 ft distances in alldirections made a network with porosity of 0.006 fully saturatedby oil. The matrix and fracture propertied are demonstrated inTable 1. The crude oil consists of three pseudo-components classi-fied as CO2-C1 (gaseous phase), C2-C6 (oil phase) and C7+ (oilphase). Peng–Robinson Equation of State [47] was used to modelfluid properties. The oil–water relative permeability (Kro and

Please cite this article in press as: Kamari A et al. On evaluation of the FAST-SAdx.doi.org/10.1016/j.fuel.2014.10.065

Krw) and rock-fluid data are illustrated in Fig. 1 and Table 1,respectively [48].

Two horizontal SAGD well pairs have been located at the twosides of the reservoir and one offset well between them. The CSSat offset well includes two cycles in which the first cycle consistsof three phases: 10 months of injection, two weeks of soak, and4 months of production, while the second cycle operates with8 months of injection, two weeks of soak and production for theremainder time. It should be noted that the injection scenario forSAGD well pairs is based on constant injection rate of 1000 STB/day for 8 years. In the base case of Fast-SAGD, start-up time ofthe first offset well cycle was set at the beginning of the processwhich has shown the best performance of Fast-SAGD process inthis model.

The Bottom Hole Pressures (BHP) for either of the offset andSAGD production wells is 1190 psi and maximum injection

GD process in naturally fractured heavy oil reservoir. Fuel (2014), http://



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5 November 2014

pressure for offset and SAGD injection wells are 2250 and 1220 psi,respectively. The injection steam temperature in all scenarios is setto 600 �F. Moreover, the quality of steam and steam injection ratefor offset and SAGD wells are set at 0.9, 1400 and 1000 STB/day,respectively. Beside, the operating constraints at the productionwells dictate a maximum temperature between the temperaturein the well bore and saturation temperature corresponding to thepressure of fluids equal to 5 �F. All of used operational parametersto build and analyze the base case are summarized in Table 2 [48].

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3.2. Economic model description

To economically select the optimum technical parameters dur-ing Fast-SAGD process, an economical model has been established.To develop such a model, the input cash flow of the model isobtained from the rate of oil production and oil price and the out-put cash flow is lost by costs and pipe line tariffs, both of which areexpressed as dollars per year from the time of project start. Thecosts consist of capital expenditures (CAPEX), operating expendi-tures (OPEX), injection material costs and other costs. In this study,a series of financial assumptions are used as follows:

1. During the calculation, assumed prices and costs are unchangedfor predicting future years although update is needed for futureuse.

2. In this model, for the calculation of gross revenue, oil price is setover 105 $ US and pipe line tariff is set over 7 $ US.

3. Operating expenditures include fixed and variable costs. FixedOPEX and variable OPEX are assumed (8 $ US) � (STB of oil pro-duction) and 3 million $ US per year, respectively.

4. Capital expenditures consist of drilling and completion of wells,costs of rework of existing wells and costs related to injectionoperations. Drilling and completion costs of each individualinjection and production well are 2 million $ US per12,600 ft2. Costs of rework of existing wells is assumed 0.4 mil-lion $ US.

5. The tax rate is 0%, royalty and inflation rates are 0%.6. The cost of steam is 7 $ US/STB of cold water equivalent. This

cost includes all the operating expenses related to steamgeneration.

Fig. 2. Layout view of the developed


There are several important calculation and procedures thatmust be taken into consideration during the development of aneconomic model. Fig. 2 is a structure indicating the economic-development strategies proposed and implemented in this study.

3.3. Comparison between SAGD and Fast-SAGD processes

Initially, to compare the ultimate RF, CSOR and cumulative oilproduction between SAGD and Fast-SAGD methods, two base mod-els were developed. All operational parameters of SAGD processare the same as Fast-SAGD except that SAGD does not have an off-set well. The results showed that ultimate RF and CSOR for SAGDmethod are 36.25 and 5.28, and those of Fast-SAGD processes are63.81 and 3.59, respectively. Fig. 3 evidently represents differencein cumulative oil production for SAGD and Fast-SAGD processes.

Steam chamber, during the SAGD process, in conventionalheavy oil reservoirs expands in both vertical and horizontal direc-tions simultaneously (an umbrella shape) from the beginning ofSAGD process, whereas in NFR steam chamber rises just verticallytill it reaches the top of the reservoir and then starts a lateralexpansion due to the existence of fractures and the low-resistancepass provided by them. Fig. 4 illustrated how steam chambergrows and expands in Fast-SAGD process in the under-survey nat-urally fractured reservoir. As it is clearly seen, it is essential to usean offset well to propagate the steam which subsequently leads tohigher RF and lower SOR. This reveals the importance of Fast-SAGDin naturally fractured reservoirs.

As previously mentioned, the Fast-SAGD process in this studycontains one additional CSS well and a couple of CSS cycles. Theadvantages of using offset wells are that CCS cycles make the steamchambers in Fast-SAGD model reach each other sooner and thissubsequently yields better performance in comparison with tradi-tional SAGD model.

The economic analysis exhibited that SAGD process was noteconomically promising because it was not producing sufficientoil to compensate all costs. Albeit the fact that SAGD process hasthe benefit of one fewer well, it has more CSOR and lower cumula-tive oil production compared to Fast-SAGD process. As a result,economic policy dictates that Fast-SAGD process has to be selectedin order to enhance oil recovery in this NFR.

economical model in this study.




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Fig. 4. IK 2-D view of steam chamber growth during Fast-SAGD process in NFR.

Fig. 3. CumulativeQ5 oil rate for SAGD and Fast-SAGD processes.



5 November 2014

4. Results and discussion

Various sensitivities produced different results for the Fast-SAGD process which were compared. Firstly, the ultimate RF, CSORand ultimate NPV were used to compare the most important oper-ational parameters. Then, the most economical case was selected.In order to calculate the ultimate NPV, costs were deducted fromthe gross profit.

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4.1. Elevation of CSS well

To select the optimal offset well elevation between the twoSAGD well pairs at Fast-SAGD system, the simulations were con-ducted with a maximum offset well pressure of 2250 psi, a maxi-mum steam injection rate of 1400 STBD at the offset well and1000 STBD into the SAGD injectors. Also, in order to select the opti-mal elevation, four cases with elevations of 4 (base case), 12, 20


and 28 ft were considered. During the optimization, it wasobserved that cumulative SOR trend reduced by increasing eleva-tion in all of the investigated cases. The ultimate recovery factorin the elevation of 12 ft was the optimum case.

The offset well placement between the SAGD well pair has dif-ferent effects on oil production. Oil production plays the key role asthe most important input parameter of the economic model. Dur-ing optimization, the offset well elevation of 12 ft yielded the high-est amount of oil production which caused an increase in grossprofit. On the other hand, this elevation had the highest amountof CSOR compared with other mentioned cases. Excessive increasein CSOR can lead to CAPEX increase and as the result it affects totalexpenditures and lowers the cash flow. Therefore, the economicsmeasured by our developed economic model were best in the ele-vation of 28 ft (Fig. 5). Nevertheless, the results of this researchconcerning the offset well elevation shows that injecting moresteam to enhance recovery increases oil production and net profitas well. The above results confirm the main and significant role ofoil production amount compared with other economicalparameters.

4.2. Injection start up time of CSS

The appropriate CSS start-up time at the offset well plays a fun-damental role in the economic evaluation of Fast-SAGD process forapplying in oil reservoirs. In this study, to observe the effects ofstart-up time at offset well on Fast-SAGD performance, seven sce-narios have been selected consists of steam injection starting up atCSS well 0 (base case), 6, 12, 18, 24, 30, 36 and 40 months aftersteam injection in two SAGD well pairs. The results revealed thatRF was highest in the case of 6 months with 64.16% and CSORincreased due to the delay in injection start-up time of CSS well.

While performing enhanced recovery methods (EORs), oil pro-duction should not be the only considered parameter as thesemethods are so expensive and sometimes the expenses of perform-ing them are much higher than the revenue, hence the significanceof economical analysis is understood. In this study, the case withthe start-up time of 6 months at the offset well had the highestoil production, hence the highest recovery. However, as previouslymentioned, it is the final cash flow which matters, not the higheramount of production. Nevertheless, the case of 6 months had alsothe highest CSOR and steam consumption to sweep oil, which hascaused the expenditures to increase excessively compared withproduction revenue. It means that the amount of oil productionhas not been to an extent which can compensate for the amountof injected steam. Instead, although the base case had a lesser pro-duction compared with the case of 6 months, its productionamount has compensated for the expenses. Therefore, the signifi-cance of economical analysis and precise calculation of theexpenses in EOR process and in particular, Fast-SAGD, are recog-nized. The results of this case confirm that the main goal shouldnot be set only as the highest amount of oil production, but theexact investigation of the expenses is of special significancebesides it.

Economical start-up time case is the simultaneous steam injec-tion in two SAGD well pairs and CSS well due to its higher NPV(Fig. 6). The reported NPV for the base case and the case of6 months are 2.84E+07 and 2.75E+07 dollars, respectively. This dif-ference in NPV is due to more CSOR for the case of 6 months. Theresults of previous researches [41] about the effect of CSS start-up time at the offset well on RF and NPV in sandstone reservoirsare inconsistent compared with the current study which has beendone in a fractured reservoir. In a sandstone reservoir, highest NPVwas reported at the start-up time of 1.5 years, whereas highestNPV in a fractured reservoir is obtained by simultaneous injectionin the offset system.




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Fig. 5. Ultimate RF, CSOR and NPV for various investigated cases of elevation at offset well.



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4.3. Number of CSS cycles

Cyclic steam injection process is composed of three parts: injec-tion, soaking and production. Among these three, time manage-ment of the soaking part is of special importance compared withthe other two since if the soaking time is so little, the reservoiroil will not have sufficient time to distribute and absorb steam heatthrough heat transfer from hotter areas of the reservoir to colderpoints; therefore, change in influencing parameters such as reser-voir temperature increase, oil viscosity reduction, pressure devel-opment due to solution gas compressibility, etc. will not occurefficiently. In contrast, if the soaking time is excessively high, theinjected steam will lose its temperature and will not have mucheffect on viscosity reduction and oil production.

The offset well at the base case comprises two cycles. The firstcycle including three phases: 10 months of injection, two weeksof soak and 4 months of production. The second cycle is operatingwith 8 months of injection, two weeks of soak and production forthe remainder time. In order to investigate the number of CSScycles effects on Fast-SAGD performance and cash flow, two casesof 1 and 3 cycles have been defined in addition to the base case.The second case with one cycle including: 1.5 year for injectionperiod, two weeks for soaking period and the remainder time forproduction period. In the third case with three cycles, the first cycle

Fig. 6. Ultimate RF, CSOR and NPV for various inv


is made up of seven months of injection, two weeks of soaking andfour months of production. The second cycle is composed of6 months for injection period, two weeks for soaking period andfour months for production period. The third cycle consists of threeperiods: 5 months of injection, two weeks of soaking and produc-tion for the remainder time.

The investigation of the three above cases in this study con-firmed the aforementioned materials. The case with 1 cycle hassurely had a lesser soaking period than cases with 2 and 3 cycles;hence it has not been able to cover the mentioned factors. Besides,the case with 3 cycles has a longer soaking period and this hascaused the temperature and steam efficiency to decrease andresulted in lesser amount of oil production. In case with 2 cycles,the soaking time has been managed well, the oil production hasincreased and compensated for steam injection expenses and thus,it is selected as the best case. The optimization results showed thatRF and NPV were the highest and also CSOR was the lowest in thecase with two cycles (base case). Fig. 7 shows the obtained resultsduring the optimization of the number of CSS cycles.

4.4. Injection pressure of CSS

To select the best pressure conditions for steam injection intothe offset well in Fast-SAGD system, three cases were defined in

estigated cases of startup time at offset well.




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Fig. 7. Ultimate RF, CSOR and NPV for various investigated cases of cycle number at offset well.



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addition to the base case pressure of 2250 psi. Therefore, we usedthree different steam injection pressures of 2100, 2500 and 2750psi in order to investigate the effects of steam injection pressureon Fast-SAGD performance. During the steam injection process,steam can penetrate more quickly through the reservoir byincreasing of injection pressure and therefore, higher injectionpressure causes the reservoir to be drained immediately; however,due to the low thickness of the reservoir, steam reaches the top ofthe reservoir quickly and then oil production rate reduces (Fig. 8).

As previously mentioned, by increasing the injection pressure inoffset well, the production rate and ultimate recovery factor willalso increase. Also, higher injection pressure causes cumulativeSOR to increase dramatically at the initial stages of production.In other words, by increasing injection pressure, more steam canbe injected into reservoir and therefore, CSOR increases. For thisreason, excessive increase in pressure might not be technicallyand economically appropriate.

Fig. 8 shows clearly above issue since the case with the pressureof 2500 psi has a higher recovery compared with the pressure of2750 psi, which has caused the former to have a higher net valuethan the latter. In other words, the economical analysis showedthat the case with the pressure of 2750 psi is less economical thanwhen the injection pressure equals to 2500 psi due to higher CSOR

Fig. 8. Ultimate RF, CSOR and NPV for various invest


and CAPEX which will be ranked as the second priority. Thus, ulti-mate NPV for the case of 2500 psi with 3.6E+07 $ has been selectedas the optimal case.

4.5. Injection rate of CSS

Our economic model provides conditions to achieve a correctand proper choice. In other words, economic analysis makes spe-cial criteria with an optimal oil recovery in order to achieve thehighest net profit. The amount of injected steam has a significantimpact on CAPEX value. Like injection pressure, injection rate hasmuch influence on oil production. However, high amount of oilproduction does not always mean higher net profit since higheramount of steam should be injected to yield more oil, which resultsin increases in steam generation expenses and CAPEX. Besides,high production rate causes the OPEX to increase.

To investigate the effects of steam injection rate into the offsetwell in Fast-SAGD method and also to select the best case econom-ically, five cases of 1200, 1400 (base case), 1600, 1750 and 1830STBD were simulated.

In this case study, the highest oil production and recoverybelongs to the case with the highest amount of injected steam.The results showed that by increasing steam injection rate,

igated cases of injection pressure at offset well.




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Fig. 9. Ultimate RF, CSOR and NPV for various investigated cases of steam injection rate at offset well.



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ultimate RF increased up to an optimal point which could be due tothe increased CSOR value. Fig. 9 indicates that due to the aboveitems, the case with steam injection rate of 1830 STBD has thehighest ultimate RF; instead, the case with steam injection rateof 1600 STBD has the highest cash flow. This can be justified asthe amounts of OPEX and CAPEX of this case are lower than caseswith rates of 1750 and 1830 STBD and thus, the gross profit of thiscase has compensated for the expenses to a good extent. Also,these economic results showed that the steam cost plays a mainrole to determine the optimal steam injection case.

4.6. Injection rate of SAGD

To study the effects of steam injection rate into SAGD well pairon Fast-SAGD performance and also to select the best case eco-nomically, seven cases of 800, 1000 (base case), 1200, 1500,2000, 2300 and 2500 STBD were defined. By increasing steaminjection rate, the cumulative oil production and RF increases.Although increase in injection rate improves oil production, CSORtends to increase because increasing oil production cannot com-pensate the undesirable effect of increase in injected steam. How-ever, water production increases by increasing steam injection rate

Fig. 10. Ultimate RF, CSOR and NPV for various investiga


and thus, restricts dealing with water–oil emulsion. Totally, theoptimized steam injection rate can be selected based on the oiland steam generation prices. The case of 2500 STBD produces moreoil and is selected as the optimum case technically with 81.64% RF.However, selecting the suitable case depends on economic issuesas well as oil production. The case with 2500 STBD of steam injec-tion rate has the highest RF, but its NPV is 2.43E+07 $. The ultimateRF and NPV for the case of 1500 STBD are reported 75.94% and3.54E+07 $, respectively. These obtained results confirm the evi-dent effect of cumulative SOR on the increase in CAPEX and thereduction in the ultimate NPV. Mindful of this interpretation, theoptimum case with 1500 STBD was selected due to its higher ulti-mate NPV. Fig. 10 indicates the obtained results in optimization ofsteam injection rate into SAGD well pair during Fast-SAGD processin the naturally fractured reservoir.

4.7. Vertical well spacing of SAGD

To investigate the effects of vertical well spacing of SAGD wellpairs on Fast-SAGD performance and NPV, our cases with 16, 24(base case), 32 and 40 ft spacing were conducted. During the opti-mization process, it was observed that by increasing well spacing,

ted cases of steam injection rate at SAGD well pair.




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Fig. 11. Ultimate RF, CSOR and NPV for various investigated cases of well spacing at SAGD well pair.



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the initial oil rate increased due to the presence of more fracturesin near well region, then the recovery of the next two cases grad-ually reduced. From this performance, it can be concluded that wellspacing effects can not be the same in all of the oil reservoirs. Byincreasing vertical well spacing, cumulative SOR reduced at earlierstages of production, but in the cases of 24 and 32 ft increased(Fig. 11). It is not believed that increasing the distance of two wellsincreases oil production and recovery linearly as the distances of24, 32, 40 and 16 are ranked from the highest to lowest recoveryfactor.

The case with the distance of 24 ft has produced such amount ofoil which has covered all the expenses and resulted in the highestnet profit. Fig. 11 shows the advantage of economical analysis asthe case with the distance of 32 ft had a higher recovery than thecase with the distance of 40 ft, but the former had higher CAPEXdue to more CSOR, which resulted in a decrease in net profit. Thus,the case with well spacing of 24 ft was selected as the best caseeconomically and technically. The ultimate RF, CSOR and NPV ofthe optimum case (base case) were reported to be 63.81%, 3.59and 2.84E+07 $, respectively.

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5. Conclusions

The Fast-SAGD operating conditions have been optimizedthrough numerical simulation by using CMG-STARS software. Theoptimizing procedure uses ultimate NPV without considering thetax rate based on project performance characteristics. Comparedto the conventional SAGD process, the Fast-SAGD process indicatedan improvement in energy efficiency and productivity. Therefore,the project economics was enhanced compared to the SAGD pro-cess. During the optimization of the operational parameters, itwas observed that by increasing steam injection rate into bothCSS and SAGD wells in Fast-SAGD system, ultimate RF increased,but ultimate NPV increased up to an optimal point which couldbe due to the increased SOR value. By increasing steam injectionpressure into offset well, both the ultimate RF and NPV increasedup to an optimal point. To optimally select parameters such asthe number of CSS cycles, elevation of CSS well and well spacingof SAGD well pair, sensitivity analysis should be performed toachieve the best case economically and technically due to the lackof a decrease or increase trend. The start-up time performance atoffset well during Fast-SAGD process in fractured reservoirs indi-cates that earlier start-up time of steam injection leads to high


RF and NPV. Finally, this research confirms the role of economicanalysis to achieve a successful project and save costs in additionto technical analysis.

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