SPE-185037-MS

EOR in Tight Reservoirs, Technical and Economical Feasibility

K. Joslin, S. G. Ghedan, A. M. Abraham, and V. Pathak, Computer Modelling Group

Copyright 2017, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Unconventional Resources Conference held in Calgary, Alberta, Canada, 15-16 February 2017.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractField experience indicates that primary depletion of tight oil formations, using multistage fracturedhorizontal wells, commonly recovers only 5 to 10% of OOIP. The impact of various EOR techniqueson recovering additional oil from these formations is still not fully understood. This paper investigatesthe applicability of feasible EOR methods and determines their technical and economic success over thenatural depletion process under different well and fracture designs. Additionally, the study investigates theminimum reservoir permeability required for success.

To achieve the objectives, both black oil and compositional simulation models were generated for aWestern Canadian tight reservoir containing volatile oil. In addition to primary, the EOR recovery processesthat were considered include waterflooding, immiscible-N2 and miscible-CO2 gas flooding. Combinationsof these techniques, coupled with the effects of various well and fracture design parameters were technicallyexplored, and economically ranked using a comprehensive economic analysis. Furthermore, the optimalcase of each process was subjected to sensitivity on matrix permeability to determine the minimumpermeability at which these methods can be applicable.

In the EOR scenarios evaluated, the highest cumulative oil produced was associated with the closestwell and fracture spacing, and longest fracture half length. With a larger well spacing (in the order of 400m), the wells were found to be too far apart to offer any benefit from any EOR technique. Additionally,the capital expenditure of tight-oil projects is high and therefore greatly influences the economic success.Several scenarios yielded similar NPV values, however, the IRR performances and CAPEX requirementshelped further evaluate and rank the scenarios.

For the reservoir model used, waterflood was found to be uneconomical at the initial permeability levelsinvestigated (around 0.3 md) and required a minimum permeability threshold (1 mD) to become profitable.The primary recovery mechanisms in waterflooding are pressure maintenance and areal sweep, which weremore pronounced in the N 2flood. This was the best recovery technique based on NPV. However, the bestrecovery technique based on oil recovery was the miscible-CO2 flood. It offered an increase in oil recoveryfactor from 11% to 23% over the best natural depletion case, which was a result of increased oil mobilityby dissolution of CO2. At lower permeability values (down to 0.03 mD) immiscible-N2 flood became themost effective method via pressure maintenance within the drainage area. For even tighter reservoirs (under0.03mD), natural depletion remained the best option for this reservoir.

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This paper provides an elaborate workflow for evaluating and optimizing EOR techniques in tightoil formations through an integrated modeling approach. It helps to identify the most technically andeconomically proficient techniques under different levels of permeability, well spacing and fractureparameters.

IntroductionTight oil reservoirs are considered as reservoirs with an average permeability below 1 mD. These are notnecessarily nano-Darcy shale oil reservoirs, but micro-Darcy tight clastics or carbonates. In this study, thefocus has been kept on tight sandstone type of formations, typical of Western Canadian and northern USAformations like Bakken, Torquay/Three Forks, Cardium and Lower Shaunavon. Over the past decade or so,drilling of horizontal, multi-staged hydraulically fractured wells has been established as the suitable wayof recovering oil from such reservoirs. However, due to low mobility of the oil and rather quick pressureinterference between the fractures, the depletion of the reservoir is almost confined to the near fracturespace and the initial high production rates will rapidly decrease with time (Ghaderi et. al.,2012). Therefore,primary recovery remains low; typically confined to 5-15% of original oil in place (OOIP). (Yu et. al., 2014;Song et. al., 2013; Hoffman, 2012; Christensen et. al., 2001; Cherian et. al., 2012)

At the end of the primary production stage, the remaining oil saturation could be significant, henceproviding a highly potential prospect for enhanced oil recovery (EOR) (Yu et. al., 2014; Ghaderi et. al.,2012). While the primary recovery process is well studied and documented, not much analysis has beendone in terms of secondary or tertiary recoveries, both in terms of technical success (more oil production)as well as in terms of economic success (more NPV, IRR, etc.).

In the last few years, there has been some work done on experimenting and simulating various secondaryand tertiary recovery processes in tight oil reservoirs. Injecting surfactant with water has been shown toimprove waterflood performance in the lab (Kathel et. al., 2013), but the field applicability of this conceptis not well known. There are only a few examples of field tests of secondary and tertiary recovery methodsin tight oil reservoirs. A water injection project was done in a Lower Shaunavon Pilot area, but it didn'tresult in greater sweep efficiency (Thomas et. al., 2015).

In contrast, gas injection is recognized to be more suitable than water flooding for enhanced oil recoverydue to its lower viscosity and higher injectivity (Yu et. al., 2014). For example, the viscosity of CO2 isabout 10-25% of that of water at pressures higher than 1070 psi and temperatures higher than 31°C (Chenet. al, 2013).

The most commonly used gases for injection include Carbon Dioxide (CO2), Nitrogen (N2), Naturalgas or a mixture of them (Yu et. al., 2014). A methane injection pilot project in the Mississippian Bakkenformation in the Williston Basin has been shown to be promising in terms of oil production (Schmidt andSekar, 2014). EOR fluid availability was the main reason behind choosing methane (solution gas) as thefluid in this project, and an injection/production well ratio of 1/9 was found to be the most economical.

CO2 flooding and cyclic CO2 injection process (huff-n-puff) are two widely used CO2-based EORtechniques. The applicability of either EOR technique mainly relies on reservoir conditions, reservoir fluidsand formation properties, and the availability of CO2 sources (Wang et. al., 2013). Gas injection is typicallya multiple contact process since it is hard for the injection gas to be miscible with the in-situ oil at thebeginning, especially for the light and medium oil reservoirs (Wang et. al., 2013). One of the advantagesof CO2 miscible injection is that miscibility pressure is significantly lower than the pressure required fora miscible process with other gases, such as nitrogen, flue gas, or natural gas. This makes CO2 miscibleinjection attainable under a broad spectrum of reservoir pressures, and, has been studied in various forms,such as continuous CO2 injection (Shoaib et. al., 2009; Hawthorne et. al., 2013), CO2 Huff-n-Puff in Bakkentight oil reservoirs (Yu et. al., 2014) and WAG injection using CO2 as the gas (Ghaderi et. al., 2012).Technically, these studies show the advantage of using miscible gas injection in terms of oil swelling and

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reduced oil viscosity – thus assisting in oil recovery. They also point out what might be required in termsof reservoir properties and well configuration to improve oil recovery in these processes.

While the physical processes associated with each recovery process may be generally understood withthe current research, the formula for field-level success has not been established yet. Consequently, thereare no comprehensive techno-economic analyses of these processes; and methods for identifying the bestrecovery process for a given reservoir along with identification of optimal well and fracture configurationare missing. This paper attempts to provide a workflow for the same.

WorkflowA realistic synthetic model of a tight oil reservoir was used for performing this study. The workflow usedcan be broadly classified into the following major phases:

1. Phase-0: Base Reservoir Model Preparation – This involved creating an accurate geomodel, correctlydefining the fluid properties (black oil as well as compositional), setting up base values for parameterssuch as hydraulic fracture spacing and conductivity, and identifying the possible EOR schemes thatcan be applied in the given reservoir.

2. Phase-1: Technical and Economic Analysis – This was done to understand the impact of variousoperational parameters (such as hydraulic fracture spacing and inter-well spacing) on the overallperformance of the reservoir – both in terms of recovery as well as economics, for each of the EORschemes.

3. Phase-2: Best Case Identification – This step was to identify the best EOR scheme based on theeconomic analysis performed in the previous step. Additionally, it was also used to identify thecombinations of operational parameters that provided the best results for each EOR scheme separately.

4. Phase-3: Refined Sensitivity and Screening Study – Finally, another sensitivity study was performedto identify the average matrix permeability and associated operational parameters under which eachof EOR processes may become more economical than primary depletion.

Phase-0: Base reservoir model preparation

i. Reservoir Model. The reservoir simulation model was based on Western Canadian and Northern UStight oil reservoirs (like Bakken, Torquay/Three Forks, Cardium and Lower Shaunavon) with significantheterogeneity in the horizontal as well as the vertical direction. The geomodel was prepared using theSequential Gaussian Geostatistical Simulation technique. The reservoir had a downward degradation interms of quality – thus the porosity values were higher in the upper part of the reservoir. In addition, thedepositional sequence was in a SW-NE direction leading to a better rock quality in the SW region of thereservoir and poorer rock quality in the NE region of the reservoir. The permeability was dependent onporosity through a poro-perm transform obtained from an analog reservoir. Table 1 shows the average rockproperties in the reservoir model. Figure 1 shows the permeability distribution along with one possible welllocation and fracture placement scenario.

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Table 1—Average Reservoir Properties

Property Average Value

Porosity 0.06

Permeability 0.33 mD

Dykstra Parsons Coefficient 0.27

Water Saturation 0.34

Original Oil in Place (OOIP) 6.8 MMsm3

Areal Extent 4000 m × 1500 m

Thickness 35 m ~45 m

Figure 1—Permeability distribution

ii. Fluid Modelling. A Western Canadian tight oil fluid was chosen for this study. This fluid was blackoil with a low-to-medium level of volatility. The fluid composition was available and several experimentswere performed in a fluid PVT package to identify properties such as fluid density, GOR, and viscosity atvarious pressures.

Based on the fluid behavior, it was decided that a black-oil reservoir simulator can be used for most ofthe EOR processes. The black-oil reservoir simulations were compared against the results of compositionalreservoir simulations for some cases to ensure accuracy. However, for the miscible injection cases, it wasdecided to use compositional reservoir simulations because using black-oil simulations for this could proveerroneous, given the physics of the process and the significant amount of medium and heavy componentsin the reservoir oil.

Slim-tube experiments were simulated to identify the Minimum Miscibility Pressure (MMP) of CO2 inthe reservoir oil under constant reservoir temperature. Various reservoir fluid properties are listed in Table 2.

SPE-185037-MS 5

Table 2—Fluid Data

Property Value

Oil Density 869.5 kg/m3

Viscosity 0.9431 cP

GOR 102.2 m3/m3

Initial Pressure 18195 kPa

Bubble Point 13973 kPa

CO2 miscibility Pressure ~14000 kPa

Reservoir Temperature 60 C

iii. Black Oil vs. Compositional Simulation. If computing resources, data availability, and time wereunlimited, a reservoir engineer would always choose compositional simulation to perform all reservoirstudies as it is a more realistic representation of the reservoir fluid. However, it is not practical in some casesespecially when dealing with hundreds of simulations for large reservoir models. As a result, the simulationsshould be simplified whenever there is a justification. In this workflow, the same approach was applied.Based on the fluid data, it was expected that some of the EOR schemes (such as waterflooding) could bemodeled using a black-oil simulator. However, it is necessary to ensure that the results are not compromisedby making this simplification. As a result, for some of the cases where a black-oil simulation was justified,compositional simulations were also performed and the results from the two were compared. To do this,the same fluid composition data was used to create a black-oil description as well as an EoS description ofthe fluid by using a PVT package. The comparison between black-oil and compositional simulations for aprimary production scenario is shown in Figure 2.

Figure 2—Black oil (IMEX) and Compositional (GEM) Simulation Comparison for primary production

As mentioned earlier, only compositional simulation was used for CO2 based miscible injection as onlythen can the fluid miscibility be modeled correctly.

iv. Recovery Techniques. In this paper, four recovery schemes were selected and a technical and economicassessment was performed on each of them to identify the most profitable one. These four techniques were:

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• Natural depletion – where the reservoir would only be operated under primary pressure depletion.

• Water Flooding – where some of the producers in the reservoir would be converted to waterinjectors after 5 years of primary production.

• Nitrogen Injection – Immiscible gas injection, where some of the producers would be convertedto nitrogen injectors after 5 years of primary production.

• CO2 Injection – Miscible gas injection, where some of the producers would be converted to CO2

injectors after 5 years of primary production.

Phase-1: Technical and Economic AnalysisA sensitivity study was performed on each recovery technique to identify the effects of operationalparameters. To ensure a consistent comparison, identical injector bottom-hole fluid rate and injector bottom-hole pressure constraints were applied to all injectors in the three injection schemes. The maximum bottom-hole pressure was set as 18 MPa for all injectors – higher than the MMP of the reservoir fluid with CO2 butlower than the expected regional fracture gradient.

This study was performed by using an automated sensitivity analysis tool. The various aspects of thisstudy were:

i. Parameters. Three operational parameters were chosen for sensitivity study. These were:

• Well spacing

• Hydraulic fracture spacing

• Hydraulic fracture half-length

ii. Objective Functions and Economics. For ranking the various scenarios, a comprehensive economicanalysis was performed. The income from the oil and gas production was considered, as was the expenditureassociated with producing the incremental oil. The data for various incomes and expenses associated ispresented in Table 3. The data was based on general industry knowledge as well as the referenced sources.

Table 3—Costs and Prices Considered

Parameter Cost

Oil Price $40/bbl

Gas Price $2.5/MSCF

Water Cost $0.75/bbl (EPAC, 2015)

Nitrogen Cost $1/MSCF (Mitariten, 2009)

Carbon Dioxide Cost $2.25/MSCF (Godec, 2014)

Oil lift Cost $10/bbl (EPAC, 2015)

Gas Processing Cost $0.25/MSCF (EPAC, 2015)

Water Handling Cost $0.5/bbl (EPAC, 2015)

Drilling Cost $2000000/well

Completions and Tie in Cost $1500000/well

Total Fracturing Cost See figure below.

Discount rate 10%

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The stage-wise hydraulic fracturing costs depends on the half-length of the principal hydraulicfracture (Schweitzer et. al., 2009) and the amount of proppant pumped (associated to hydraulic fractureconductivity). The formula for fracture cost was scaled to represent values more typical of the type ofreservoir studied in this paper. The stage costs estimates are shown in Figure 3.

Figure 3—Hydraulic fracturing stage cost vs fracture half-length

Total Fracturing Cost = Fixed Fracture/well ($1.5 MM) + Number of Stages * [Fixed Stage Cost ($150K)+Cost/per meter (half length) ($691)*Half Length]

Various technical performance and economic performance indicators were chosen as the objectivefunction to aid in analyzing simulation results. These were:

• Cumulative oil production

• Investment Amount – representing the capital expenditures (CAPEX)

• Cumulative Undiscounted Net Cash Flow

• Project Net Present Value (NPV) – discounted at a rate of 10%

• Project Incremental Rate of Return (IRR) – This represents the discount rate that makes the NPVequal to zero (i.e. the growth rate that project is expected to generate)

Phase-1 Results and Discussion

i. Natural Depletion. The first method evaluated was Natural Depletion and it was used as the basis forthe various other EOR models. A total of 56 simulations were performed and well-spacing, fracture spacingand fracture half-lengths were used as sensitivity parameters. A combination of an automated sensitivityanalysis tool and manual dataset creation was used to ensure that enough simulations were run to explorethe search space of the parameters. For these primary production cases, the wells mainly operated on aminimum BHP of 2000 kPa (290 psi) with an initial pressure drawdown constraint of 1000 kPa.

The results for the natural depletion cases are presented in the following section. Figure 4 shows a crossplot of cumulative oil versus fracture spacing. Figure 5 shows the cross plots of NPV and IRR versusfracture spacing. These objective functions were identified as the most compelling in terms of technical andeconomic success. From the figures, it was observed that the higher cumulative oil was at the closest wellspacing (300 m) and closer fracture spacings (25-50 m), whereas the best NPV cases trended towards themiddle well spacing (400 m) and highest fracture spacings (100-125 m). At the closest well and fracturespacings, more number of wells and fractures led to a better sweep and a better oil recovery. However, the

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increased cost associated with these cases did not translate into sufficiently increased revenue to result ina greater profit.

Figure 4—Natural Depletion: Crossplot (Cumulative Oil Produced vs. Fracture Spacing), colours represent the well spacing.

Figure 5—Natural depletion economic performance indicators: (a) NPV vsFracture Spacing, (b) IRR vs Fracture Spacing, colours represent the well spacing.

The IRR for these cases showed that the higher well and fracture spacings resulted in a greater return oninvestment. The economical indicator IRR is heavily influenced by CAPEX and therefore favours a fewernumber of wells and fractures. A higher IRR translates into a lower risk due to less investment requirements.Therefore, given two cases with similar NPV, the one with a higher IRR might be the more attractive option.

The same analysis was done for evaluating the impact fracture half-length as well. For cumulative oil,the cases with the higher half-length resulted in the most production as shown in Figure 6. For the caseswith a larger half-length, the additional production of oil was negated by the additional cost required. Thisyielded a very weak trend between the half-length and calculated NPV and IRR.

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Figure 6—Natural Depletion: Crossplot (Cumulative Oil Producedvs. Fracture Half Length), colours represent the well spacing.

In summary, it was seen that the technical performance indicator (oil produced) and the economicperformance indicators (IRR and NPV) were affected differently by the same parameters. Overall, it wasseen that the best economic performance can be achieved by using the middle well spacing (400 m) alongwith spaced out fractures (100-125 m fracture spacing). The fracture half-length had no impact on economicperformance of depletion and could range from 50-150 m. This conclusion is reiterated in Figure 7, whichshows the cross plot between NPV and cumulative oil produced. It also shows that 400 m well spacing caseshave less variation in NPV for similar ranges of oil production, and thus means less risk.

Figure 7—Natural Depletion: Crossplot (NPV vs. Cumulative Oil Produced)

ii. Water Flood. For all of the EOR processes, the recovery methods were implemented after a primaryproduction period of 5 years – the reservoir's oil production rate had significantly reduced by this time. Toimplement the enhanced recovery techniques, every alternate well was converted into an injector and thewells at the end of the flood pattern were left as producers. In addition to a maximum injection pressure of18000 kPa, a maximum bottom hole fluid rate (BHF) was also applied on injectors. This was done to keepthe comparisons consistent and was based on the maximum BHF observed in the natural depletion cases.

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Similar to natural depletion, the case with closest well spacing (300 m) and closer fracture spacings(25-75 m) resulted in the highest cumulative oil (Figure 8). However, the NPV showed a different trendwhen compared to natural depletion. There was little difference in the NPV obtained from 300 m wellspacing versus 400 m well spacing and the waterflooding cases did not necessarily favour the 400 m spacingcase. This is because at low permeabilities, the injection of water is generally ineffective at providing thenecessary sweep over large distances. From an economical stand point, the larger fracture spacings weresuperior. This was because the fracture spacing had minimal impact on cumulative oil but the smallerfracture spacing had a higher cost because of more propped fractures (Figure 8).

Figure 8—Water Flooding Crossplots Cumulative oil and NPV versus Fracture Spacing, colours represent well spacing

For the water flood, longer half-lengths were found to be favourable in terms of oil produced, becauseinter-well communication needed to be established between the injectors and producers for a flood processto work. This was seen for all well spacing scenarios (Figure 9). However, a weak trend was seen between theeconomic indicators (NPV and IRR) and the fracture half-length. The reason was that in several cases, theincremental oil produced by having longer fractures was offset by the increased pumping costs of creatingthem.

Figure 9—Cumulative Oil versus Half-length for waterflooding

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A comparison of the natural depletion cases to the waterflood cases shows that for equivalentconfigurations, the natural depletion simulations always yielded a higher NPV and with the exception of afew cases a higher cumulative oil. It can therefore be concluded that at this permeability level waterfloodingis not an effective recovery method.

In field operations, water injection has been shown to have a limited benefit for some oil reservoirsconsidered to be tight (Thomas et al, 2014), but these reservoirs have a unique characteristic such as a highpermeability streak or higher average permeability. In order to determine at which levels waterflooding canbecome practical, some sensitivities on average matrix permeability were performed for this reservoir andare described in a later section.

iii. Immiscible Gas (Nitrogen) Flood. The nitrogen injection simulations were performed with the sameoperating constraints as the waterflooding ones. The injectors were allowed to inject the maximum amountof fluid under the operating constraints. This offered a fair comparison when determining which process isthe most effective as each process was allowed to inject its maximum amount of available fluid.

For each of the parameters, the nitrogen injection showed trends similar to that of water flooding in termsof the impact of each parameter (Figure 10), but the magnitude of that impact was higher. For example,waterflooding with a profitable well-fracture configuration showed an increase of 13% in oil productionover waterflooding with a different well-fracture configuration. Comparing the same two configurations fornitrogen injection revealed an increase of 30%.

Figure 10—Nitrogen Flooding Cumulative Oil and NPV versus Fracture Spacing, Colours represent well spacing

Apart from a few exceptions for the 300 m and 400 m well spacing, nitrogen injection provided a betterrecovery and profitability over natural depletion and water injection. The primary recovery mechanismfor the nitrogen injection was pressure support and areal sweep and it was able to maintain an averagereservoir pressure between 11500-12500 kPa in all cases. By contrast the average pressure in waterfloodingand natural depletion was on the order of 10000 and 5500 kPa, respectively. Nitrogen injection being moreeffective than waterflooding could be related to the significantly lower viscosity of nitrogen.

Figure 10 shows that 300 m well spacing combined with a high fracture spacing of 75-125 m and fracturehalf-lengths in the wide range of 75-150 m yielded the best results in terms of economic viability of Nitrogenflood.

iv. Miscible Gas (CO2) Flood. The final method evaluated was a miscible gas flood for which Carbondioxide was selected. Unlike the other methods, a fully compositional simulator was used to evaluate this

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technique. From a simulated slim-tube experiment the minimum miscibility pressure was identified as 14MPa, which is 4 MPa below the maximum injection pressure.

The success of CO2 injection was heavily influenced by well spacing, with the closest well spacing (300m) with spaced out fractures (75-125 m) resulting in both the best oil recovery and net present value (Figure11). At 300 m and 400 m well spacing the CO2 injection offered an improved recovery when compared tothe nitrogen injection case. The improvement in recovery associated with CO2 injection can be credited tothe CO2 dissolution in the oil, effectively reducing its viscosity and residual oil saturation. In addition to themiscibility of CO2 contributing to a higher recovery, the gas also provides the necessary pressure supportrequired to move the flood front from the injectors to the producers. This pressure support, however, is lesseffective than the nitrogen injection case. This is because the CO2 is dissolved in the oil contributing lessto the pressure increase, and also has a higher viscosity than nitrogen. This is the reason for CO2 injectionperforming better at 300 m well spacing as compared to bigger well spacings.

Figure 11—CO2 Flooding Cumulative Oil and NPV versus Fracture Spacing, colours represent well spacing.

Despite the improved recovery observed with the CO2 injection the NPV and IRR are lower. This isbecause of the higher cost and higher injection rate associated with CO2. The cost of CO2 used in this studyis 2.25 times larger than that of nitrogen. In reality, the cost of CO2 can vary significantly from one field toanother as it depends heavily on access and availability (Ghaderi, 2013). If CO2 can be obtained at a cheaperprice it could be the more attractive option for recovery.

In some cases, when a smaller half-length was used it resulted in a higher oil recovery, but less NPV.This could be counter-intuitive because logic dictates that the higher cost of the larger half-length shouldresult in a smaller NPV, especially if the cumulative oil is less. However, the EOR response is much quickerin cases where longer fractures lead to better injector-producer connectivity and therefore, breakthrough ofthe injected fluid into the producer happens quicker. When breakthrough is fast, the produced CO2 can thenbe recycled and its impact on operational expenditures is less. For the shorter half-length cases the sweepefficiency is slightly better thus contributing to a slight increase in oil recovery (but lower NPV becauseof higher CO2 expenses).

Based on the results for each of the processes, well spacing was the most important parameter in termsof oil recovery while fracture spacing was the most influential parameter for economic analyses. This isemphasized in the Sobol analyses plots presented in Figure 12.

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Figure 12—Sobol Analyses of CO2 (a) Cumulative Oil, and (b) NPV

Phase-2: Best Case Identification

Results and DiscussionThe following two tables summarize the best cases based on NPV, and Cumulative Oil for each recoveryprocess and their associated parameters.

Table 4—Best cases based on oil recovery factor

ProcessWell Spacing Fracture

SpacingFracture

Half-lengthBest Cum.

Oil (MMm3)Oil Recovery

Factor

Natural Depletion 300 25 150 0.77 11%

Water Flooding 300 25 150 1.07 16%

Nitrogen Injection 300 25 100 1.14 17%

CO2 EOR 300 25 80 1.53 23%

Table 5—Best cases based on NPV

Process Well Spacing FractureSpacing

FractureHalf-length

Best NPV($MM)

Natural Depletion 400 125 150 60.33

Water Flooding 400 125 150 52.61

Nitrogen Injection 300 125 120 63.64

CO2 EOR 300 125 120 58.36

The best cases in terms of oil recovery had the closest well spacing and the closest fracture spacing. Thisis intuitive as it results in the highest amount of stimulated reservoir volume. However, these cases are notpractical from an economic standpoint as they often result in a very high capital expenditure. Therefore,the optimal NPV cases required higher fracture and well spacing. However, for CO2 EOR and nitrogeninjection, the optimal NPV cases were still at the closest well spacing of 300 m. This is because most EORtechniques require communication between the injectors and producers to be successful, which could beachieved effectively only with the closest well spacing. A case-by-case comparison of the four processesin terms of cumulative oil production is presented in Figure 13.

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Figure 13—Comparison of cumulative oil produced during various processes for a 300m well spacing. Notice that CO2 EOR produces the maximum amount of oil in each case.

To help demonstrate why certain processes are more effective at oil recovery, a plot of oil recovery andaverage reservoir pressure versus time for a typical case is presented in Figure 14. In this case the wellspacing was set to 300m, and fracture spacing and half-length were both at 100m. The nitrogen was moreeffective in the early stages due to the pressure support it provides and the better injectivity it has comparedto CO2 and water. Overall, the CO2 injection was most the effective at recovering oil because of its abilityto reduce the residual oil saturation and still provide the necessary pressure support.

Figure 14—Oil Recovery Factor and Average Reservoir Pressure versus time

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However, as indicated earlier, the process or configuration that produces the maximum amount of oilmay not be the most economical one. Thus, NPV would be a better indicator of the economically successfulprocesses. In almost all the scenarios, Nitrogen injection proved to be the one with the highest NPV, followedby CO2 EOR. Furthermore, there are many configurations within each process that produced NPVs close tothe optimal case. In such scenarios, the IRR can be used as a secondary economic indicator to see if there isa case that produced an attractive NPV but at a lower risk. For example, for both CO2 and nitrogen injectionthe highest IRR was attainable in the highest well spacing where risk was lowest. In all cases the naturaldepletion had the highest internal rate of return, owing to the least amount of investment. Therefore, givenunlimited oil resources, it may be more beneficial to continue to develop green fields with natural depletion,rather than investing the additional capital in enhanced recovery techniques. A case-by-case comparison ofthe four processes in terms of NPV is presented in Figure 15.

Figure 15—Comparison of NPV for various processes for a 300 m well spacing.Notice that Nitrogen injection produces the maximum NPV in each case.

Phase-3: Permeability SensitivityThe average reservoir permeability is one of the most sensitive parameters when it comes to recovery fromtight reservoirs with hydraulic fractures. The final phase of this study was to perform a sensitivity study onthe average matrix permeability to identify at which average permeability values the recovery methods arepractical and become an attractive alternative to primary production.

Since the recovery processes can be quantified both in terms of economical as well as technicalproficiency, two sensitivities were performed for each of the three injection recovery processes. Globalpermeability multipliers in the range of 0.001 to 5.00 were used in each of the best cases identified inPhase-2. To quantify the benefit of the secondary and tertiary recovery techniques, the equivalent naturaldepletion case was also run at the same permeability levels.

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The following plots summarize the results of the permeability sensitivity:

Figure 16—Results of permeability sensitivity on (a) Incremental Oil using various recovery techniques,and (b) Incremental NPV using various recovery techniques, with respect to natural depletion

i. Incremental Oil.

• When the average permeability was less than about 0.03 mD, none of the enhanced recoverymethods were more effective than natural depletion.

• At average permeability in the range of 0.03-0.10 mD, the nitrogen injection yielded the mostpromising results. This is because at the lower permeability carbon dioxide and water wereineffective at moving through the reservoir whereas the lower viscosity of nitrogen allowed it tomaintain a certain degree of pressure support.

• At a higher average permeability (> 0.10 mD) the carbon dioxide became the superior optionallowing for the full benefits of a miscible flood.

ii. Incremental NPV.

• When comparing the best NPV cases, all EOR processes showed an improved NPV over naturaldepletion when the average permeability was above 1 mD.

• In the 0.3-1 mD range, only nitrogen and CO2 could out-perform primary recovery. The NPVresponse of the gas injection was similar to the incremental oil response, where the immiscibleflood showed greater benefit at lower permeability levels (0.3-0.4 mD) and the miscible floodshowed greater benefit at higher permeability levels (higher than 0.4 mD).

• Only Nitrogen injection was profitable in the 0.1-0.3 mD range. It must be noted that in this rangeof average permeability, CO2 injection produces more oil, but is less economical because of thehigher costs associated with CO2 (For this study, the cost of CO2 was considered to be more thantwice of that of Nitrogen).

• Gas injection EOR processes are contingent on the cost of the gas injected, therefore, a smallchange to the gas price could result in one technique being favoured over the other.

• When the average permeability was less than 0.1 mD, natural depletion always produced a highereconomic return. In order to generate more oil and more economic benefit from such reservoirs, anon-flood EOR technique may be better – such as a huff ‘n’ puff cyclic process.

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Tight oil reservoirs cover a wide range of permeability values. The sensitivity presented here was a simplescreening test to determine how influential reservoir permeability can be and whether or not more thanone recovery technique can be optimal. This was best observed by looking at the effects on nitrogenand CO2 injection where each proved to be the ideal case depending on the permeability. Despite theseconclusions, there are also many other reservoir parameters that can influence recovery that were notexplored here including level of heterogeneity (Dykstra-Parsons), capillary pressure, relative permeabilities,water saturation and the fluid properties.

ConclusionsA workflow was presented in order to evaluate different recovery processes for a simulation modelrepresentative of a Western Canadian tight oil formation. Of the process examined, both nitrogen floodingand CO2 EOR were shown to increase the recovery over that of natural depletion. Waterflooding, on theother hand, proved to be detrimental in majority of the cases.

The processes were examined under different well and fracture configurations in order to identify the mostimpacting parameters and the most optimal combinations of these parameters. Well spacing was identifiedas the most influential parameter and for all processes the closest well spacing (300 m) offered the greatestrecovery. This remained true for CO2 EOR and nitrogen injection, even when quantifying the results froman economical standpoint due to the reliance of these processes on inter-well communication. Fracturespacing was the next most influential parameter where lower fracture spacings heavily hampered the capitalexpenditures resulting in low economic return.

Using oil recovery factor as the benchmark, the optimal case stemmed from the CO 2EOR which producedtwice as much oil as the best natural depletion case. Economically, however, the cost of CO2 injection wastoo great conceding to nitrogen flooding as the most optimum with a top NPV of $64 MM. Nitrogen injectionalso offered a lower risk than CO2 with the IRR greater than 40% in many 300 m well spacing scenarios.

A final sensitivity was done on matrix permeability, which showed that enhanced recovery methodsyielded benefits over primary recovery when the average permeability is greater 0.03 mD for oil recoveryand 0.1 mD for NPV. The immiscible gas flood was favoured at lower permeability whereas the misciblegas flood showed greater benefit at higher average permeability. A more comprehensive study includingparameters other than just matrix permeability will help to solidify these conclusions.

Under primary recovery alone, the majority of tight reservoirs can only recover between 5 and 10% of theoriginal oil in place. This paper successfully evaluates three potential processes under a variety of conditionswhich could be used to improve this recovery. The workflow and results presented here can be applied asscreening criteria to be used when attempting to expand a reservoir's production.

AcknowledgementsThe authors thank Computer Modelling Group Ltd. for providing resources to complete this study andpermission to publish it. The authors would also like to thank Anjani Kumar, Alex Novlesky, Jim Erdle,and Kanhaiyalal Patel for their suggestions on the paper.

NomenclatureBHF : Bottom-hole Fluid RateBHP : Bottom-hole Pressure

CAPEX : Capital ExpenditureEOR : Enhanced Oil RecoveryEoS : Equation-of-StateIRR : Incremental Rate of Return

MMP : Minimum Miscibility Pressure

18 SPE-185037-MS

NPV : Net Present ValuePVT : Pressure-Volume-Temperature

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