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Article Cite This: Environ. Sci. Technol. 2018, 52, 14547−14555

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Predictive Modeling of Energy and Emissions from Shale Gas Development Evar C. Umeozor and Ian D. Gates* University of Calgary, 2500 University Drive N.W., Calgary, Alberta T2N 1N4, Canada

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S Supporting Information *

ABSTRACT: Contributions of individual preproduction activities to overall energy use and greenhouse gas (GHG) emissions during shale gas development are not well understood nor quantified. This paper uses predictive modeling combining the physics of reservoir development operations with depositional attributes of shale gas basins to account for energy requirements and GHG emissions during shale gas well development. We focus on shale gas development from the Montney basin in Canada and account for the energy use during drilling and fluid pumping for reservoir stimulation, in addition to preproduction emissions arising from energy use and potential gas releases during operations. Detailed modeling of activities and events that take place during each stage of development is described. Relative to the hydraulic fracturing activity, we observe significantly higher energy intensity for the well drilling and mud circulation activities. Well completion flowback gas is found to be the predominant potential source of GHG emission. When these results are expressed on an annual basis, consistent with the convention of most climate policy goals and directives, environmental impacts of our growing natural gas economy are better appreciated. Estimated likely GHG emission from new development wells in 2017 in the Montney Formation alone is 2.68 Mt CO2e. However, on a preproduction requirements basis and dependent on mean estimated ultimate recovery (EUR), energy return on invested energy for shale gas from the Montney Formation in Canada is estimated to be about 3400. The approach described here can be reliably extended to areas, globally, where natural gas development is becoming prominent.

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INTRODUCTION Ever since horizontal drilling with multistage hydraulic stimulation unlocked vast shale resources in many areas in North America and beyond, global natural gas production has increased tremendously, resulting in abundant, cheap gas.1 For this reason, gas-based energy technologies have become favorable for business decision reasons, including desires to curtail climate effects of a growing global energy demand.2 However, concerns about the actual environmental benefits of unconventional gas in the energy mix, particularly against coal and coupled with depleting conventional gas, have triggered a lot of scrutiny of the operational practices of natural gas producers, especially at upstream operations where both development and production activities occur.1,3 In combustion, it is known that natural gaswhether conventional or not burns cleaner than other fossil fuels, with up to 50% less carbon generation.3 Moreover, between conventional and unconventional natural gas, it is primarily the difference in their development techniques, occasioned by resource deposition attributes, which may translate to disparate energy, emissions, and economic impacts.4−9 At production, both natural gas sources can be piped into the same supply chain.9 Shale gas is a type of unconventional resource with the depositional attribute of entrapment, or exceedingly low permeability, within pockets of petroleum reservoir rock. Shale is also deeper underground than conventional natural gas.10 As such, relatively greater investment and energy input © 2018 American Chemical Society

are required for development than for conventional gas. Generally, this energy requirement is met by fossil fuel (often diesel) combustion at the predominantly remote locations where the resources are exploited.5 Higher energy penalty implies more greenhouse gas (GHG) emissions, yet there is a lack of clarity on how the resource development activities distribute energy and emission intensities of the operation. This apparent lack of understanding of preproduction impacts becomes amplified when the scope of analyses is reduced to an individual gas well basis, without accounting for the annual scale of shale resource development campaigns since the shale revolution started. As of 2013, unconventional gas contributed about 64% of total U.S. natural gas production and is expected to climb to 70% by 2020.11 In Canada, unconventional gas accounted for 51% of total gas production in 2014 and is projected to represent 80% of all gas production by 2035.12 In the Canadian province of Alberta alone, a total of about 2000 gas wells were drilled in 2015 of which over 1000 were for unconventional gas.13 Given that global GHG emission reduction policies and targets are normally designed on the basis of annual emissions to be reduced to particular baseline year values, better insights Received: Revised: Accepted: Published: 14547

October 3, 2018 November 12, 2018 November 19, 2018 November 19, 2018 DOI: 10.1021/acs.est.8b05562 Environ. Sci. Technol. 2018, 52, 14547−14555

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Environmental Science & Technology

Figure 1. Preproduction operations (in dashed box) during shale gas development.

Figure 2. Study focus area showing the spread of Montney over British Columbia and Alberta with developed wells highlighted in red.

covering developed wells within the provinces of British Columbia and Alberta. Well-level data are obtained from the HPDI and geoSCOUT databases.19,20 Detailed modeling of sources and the implementation workflow is presented to enable the transferability of our method to other areas where shale gas development activity is growing.

can be gained on climate impacts as more gas is consumed in global energy flows by taking a more holistic and systematic approach in the analysis of energy and environmental implications of unconventional gas development.6,7 The energy requirement for drilling shale gas wells depends on a number of factors: the attributes of the drilling machinery (e.g., efficiency), the type and properties of the formation being drilled, and the measured depth of the wellbore to be developed, among others. After drilling is completed, energy is still required for hydraulic fracturing, that is, to pump fluids, including proppant, into the reservoir to create and sustain fractures. At every stage in the development, GHG emissions are generated, as energy for drilling and fracturing operations are furnishedoften from fossil fuel combustionto provide the mechanical drive needed to drill or pump fluids into the formation.6,14 Emissions could also arise from leakages of hydrocarbons and other GHGs as the drilling operations or well completion activities expose the subsurface during development. Figure 1 breaks down shale gas preproduction activities into three steps, including drilling, hydraulic fracturing, and flowback. Previous reports in the literature have used reported data or heuristic approaches based on assessments of primary energy feedstocks for development operations to gauge preproduction emissions.14−18 These approaches lead to limitations in the transferability of the results when the conditions for measurements, type of energy source, or attributes of the resource depositions differ from one development project to another, which in turn creates pitfalls for applying emission factors arising from such studies. This study presents a predictive modeling approach with a strong analytical background to account for energy use and GHG emissions during shale gas development. We identify the activities and events which trigger energy-derived or direct methane emissions. The applicability of our approach is demonstrated using data from 1403 shale gas wells in the Montney Formation in Western Canada. Figure 2 shows the Montney Basin area

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METHOD We focus on energy and methane emissions from preproduction activities during shale gas development covering drilling, hydraulic fracturing, and flowback operations. Diesel is used as the primary energy source for both drilling and fracturing operations. Overall preproduction emission is computed as the combination of energy consumption emissions and potential direct releases of methane during each development operation. The principal activities requiring energy input during shale gas development include drilling, drilling mud circulation, and hydraulic fracturing. The total potential preproduction emissions can be expressed as a sum of potential direct and energy emissions: Q CO

2eq

= ´drilling flowÖÆ + ´mud gasÖÆ ÖÖÖÖÖÖÖÖÖÖÖ≠ÖÖÖÖÖÖÖÖÖÖ ÖÖÖÖÖÖÖÖ≠ÖÖÖÖÖÖÖÖÆ + ´mud ÖÖÖÖÖÖÖÖÖ≠ÖÖÖÖÖÖÖÖ energy

energy

direct

+ ´hydraulic gasÆ ÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖ≠fracturing ÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÖÆ + ´flowback ÖÖÖÖÖÖÖÖÖÖÖÖÖÖ≠ÖÖÖÖÖÖÖÖÖÖÖÖÖÖ energy

direct

(1)

Actual emissions depend on whether the potential direct methane releases are captured, flared, or vented. There is no reason to restrict gas handling to either capturing or flaring scenarios, since the current regulatory requirement does not demand a strict adherence to either option.21−23 Therefore, we estimate total preproduction emission on the basis of energy and potential preproduction methane emissions. Flowback gas is assumed to have a volumetric methane content of 78.8%, which agrees with the recorded Montney Formation, air-free, natural gas methane composition. A methane density of 19 kg/ Mcf is used to calculate the mass, and the CO2-equivalent 14548

DOI: 10.1021/acs.est.8b05562 Environ. Sci. Technol. 2018, 52, 14547−14555

Article


Figure 3. Workflow for calculating the drilling energy requirement.

| l ij sin αk − sin αk − 1 o cos αk − 1 − cos αk yzzo o o βωΔlr jjj +μ m zz} o o j αk − αk − 1 z o α − α k k−1 i ∈ CS n k {o ~i

(CO2e) emission is obtained by applying a global warming potential of 36. Model parameter values are chosen for ease of comparison of results with previous studies. However, sensitivities of emission estimates are evaluated by using upto-date parameter values. The ranges of modeling input parameter and variable values are available in the Supporting Information (SI.1). Detailed modeling of preproduction activities and events is presented individually below. Drilling Energy Use and Emission. Well drilling is a major activity in the development of shale gas. Unfortunately, existing lifecycle impact assessment studies have not presented a systematic and elaborate approach to quantify energy and emission impacts of the drilling operations during shale gas development. Vafi and Brandt24 were the first to attempt to shed more light in this area through careful modeling of some of the events during oil and gas well development. However, their work did not cover all sources (like mud gas and completion emissions) and generally handled some of the critical variables as time-invariant. Fazaelizadeh25 used analytical modeling to investigate the forces on the drillstring during a drilling operation. This modeling approach enables understanding the effects of changes in design and operational variables when treating different types of wells within a play or among wells in various basins. The required drilling torque can be obtained for the straight (vertical, horizontal, or inclined) and curved sections of the target wellbore design by summing the effective and lost torque components as TSS =

∑ {βωΔlr(cos α + μ sin α)}i i ∈ SS

TCS =

∑

(3)

where SS and CS indicate the sections of the target wellbore being developed. To estimate the total drilling energy requirement supplied by a top-drive system, if i represents each section of the drillstring (in addition to the drill bit), j indicates straight sections of the wellbore to be created, and k stands for the curved parts of the wellbore, then the energy use can be expressed as Ed =

∑ ∑ (βwΔlrφ)i ,j (cos αi ,j + μ sin αi ,j) j

i sin αi , k − sin αi , k − 1

∑ ∑ (βwΔlrφ)i ,k jjjjj i

k αi , k − αi , k − 1 cos αi , k − 1 − cos αi , k yzz zz + μi , k z αi , k − αi , k − 1 { +

k

i

(4)

where φ is the total angular displacement of section i of the drillstring through the j/k segment of the wellbore. This can be evaluated sequentially by following the entire path of the drill bit through the wellbore, as illustrated in Figure 3. The energy use accounts for the rotational motion of the drilling assembly as propelled solely by a top-drive system. Therefore, this value only represents the useful energy requirement for the drilling operation. To evaluate the actual energy input, we apply the efficiencies of the systems

(2) 14549


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Environmental Science & Technology ED =

Ed ηdηpm

j

(5)

where ηd is the drilling motor efficiency and ηpm is the primemover efficiency. Obtaining this result enables us to quantify the actual CO2 emissions from energy use based on the carbon content of the input energy source: Q CO e,d = χCO E D 2

∑ ∑ ΔPijQ ijΔtij

Em =

2

(8)

i

where i and j are indexes for sections of the drillstring and wellbore segments, respectively. To calculate the actual primary energy input, we apply efficiencies of pump and prime-mover, and the energy emission is calculated by multiplying with the carbon content of fuel:

(6)

EM =

Mud Circulation Energy Use and Emission. Another aspect of the drilling operation involves pumping of drilling mud to provide balance, lubrication, and cooling at the cutting edge of the driller.26 Mud circulation has been reported as a major source of GHG emission arising from the pumping energy requirements.24 Generally, the drilling operation is conducted in either an underbalanced or overbalanced condition; underbalanced is where the mud pressure is lower than that of the formation and overbalanced is the opposite.27 Here, we consider an overbalanced drilling operation, which is a common practice. Figure 4 illustrates mud circulation in a simplified drilling setup. Vafi and Brandt24 gave an elaborate discussion on

Em ηpηpm

(9)

Q CO e,m = χCO EM 2

2

(10)

Apart from energy used for drilling mud circulation, mud gas is released whenever a gas-bearing zone is encroached. As drilling cuts through the reservoir pay zone, entrapped gas and cuttings are entrained to the surface by the mud. Emission at this stage is primarily from released mud gas, which gets vented. This mud gas volume (Vm) can be estimated from the relationship Vm =

πdb 2Lpzϕ(1 − S l) 4Bg

(11)

where Lpz is the well length within the pay zone, ϕ is the reservoir porosity, Sl is the liquid saturation, and Bg is the gas formation volume factor. The HPDI database contains information on gas-to-oil and water-to-oil ratios (gor and wor, respectively) from which the liquid saturation can be calculated from wor + 1 gor + wor + 1

Sl =

At this point, we can define the GHG content of formation gas based on formation gas compositions for individual wells or shale basins. Considering the GHG components of the raw gas (a), potential GHG emissions can be estimated from

Figure 4. Schematic of the drilling arrangement with vertical, curved, and horizontal sections, showing mud circulation (not drawn to scale).

Q CO e,m = 2

∑ GWPaξaρVm a

(13)

where ξa is the composition of the GHG component a in the gas and ρ is the gas density. For our analysis, only the methane content of the gas is accounted for using an average methane content of 78.8% and a global warming potential of 36, in line with updated IPCC methane climate warming potency. We further bracket these estimates in the sensitivity analyses using reported ranges of shale gas methane content of 45−95% and the published range of methane GWP of 21−36 to enable comparison with past studies.22 Hydraulic Fracturing Energy Use and Emission. Energy is required to pump fluids into the reservoir to create fractures. The fractures enhance hydrocarbon flow in the formation by connecting the reservoir and the wellbore.10 Energy emission is the primary emission source at this stage, and it depends on the type of energy source being used. The field profile of the typical reservoir stimulation operation indicates that the fracturing fluid is injected from the surface at a specific rate via perforations in the well casing and then into the formation.10 The reservoir pressure builds up to the formation breakdown pressure, at which the targeted shale rocks start to break. Hydraulic fracturing is a complex process influenced by a number of factors, including injection rate,

drilling mud circulation dynamics in terms of mud differential pressure, considering frictional, dynamic, discharge, and hydrostatic elements of the overall pressure drop. However, their model did not demonstrate the dynamics of the differential pressures as drilling progresses through the various segments of the wellbore being developed. Given that the hydrostatic component in the model is zero, and without a downhole motor in the drilling assembly, the pressure differential can be expressed in terms of frictional and dynamic losses:24 ΔPpump = ΔPfriction + ΔPdynamic

(12)

(7)

The total losses occurring over the course of the drilling operations can be computed consecutively following segments of the drilling assembly through the wellbore. Frictional losses are computed for each drillstring segment as it penetrates through the subsurface, covering both flows of the mud within the pipe and through the annular area between the pipe and wellbore contact. Dynamic losses at the drill bit are computed for each bit used and through its coverage of measured depth of the wellbore. Consequently, the total energy required for mud circulation is then 14550


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Environmental Science & Technology fracturing fluid, wellbore dimensions, state of stress, and reservoir rock properties, among others.28 The pressure needed for hydraulic fracturing derives from the bottomhole pressure, given as24 Pfrac = Psurface + Phead − Pfriction

Efric =

where j represents each fracturing stage along the horizontal section of the well. Given that Eh represents the ideal energy requirement, the actual energy input considering pumping and prime-mover efficiencies (ηp, ηpm), depending on the type of energy source, is then

(14)

EH =

2

The pump work needed to achieve this can be determined on the basis of thermodynamic relations: ΔU = Q − W

(18)

Considering that ΔV is relatively unchanged for an incompressible fracturing fluid and only the flow work is provided by the pump (i.e., ΔH and Q are zero), the input rate of pumping energy that supplies the flow work needed for hydraulic fracturing becomes dEfrac = qΔP dt

qfb = qg,peak (1 − e−λ − λe−λ)

where q is the volumetric injection rate and ΔP is defined with respect to the reference pressure by (20)

Pref = Phead

(21)

Q fb = qg,peak [(λ − 2) + (λ + 2)e−λ]

(28)

In relative initial production (IP) based models, peak gas production data is easily available and the historical range of its values within a basin or play can be used to bracket potential emissions from new well developments. IP-based models also require more data inputs, which may introduce more uncertainty in estimation results.4 Peak gas data for North American shale plays can be found in the Drilling Info database.19 The parameter λ can be calibrated for a given shale gas well due to differences in the attributes of each shale gas reservoir/basin. Further details on the parameter estimation can be found in the Supporting Information (SI.2). Calibrated values for individual shale basins range from 0.6 to 1. However, for the generality of wells considered in this study, a representative value of parameter λ is equal to 0.75.

For a given injection rate, the energy use for fracturing operations can be obtained from the integral of the input rate of pumping energy given by qc Efrac = (t − ti)n + 1 − qPref (t − ti) (22) n+1 However, the flow of fracturing fluid through the well suffers frictional losses that must be included, and thus, the total energy requirement is the sum of the fracturing energy input and losses: E h = Efrac + Efric

(27)

where qg,peak is the peak gas rate from the well and λ is a parameter that characterizes the shape of the flowback profile of the gas well. Therefore, λ can be related to the flowback duration and peak gas value and takes values between 0 and 1. To evaluate potential emissions from flowback (Qfb), we integrate the equation over the flowback regime to obtain

(19)

ΔP = Pfrac − Pref

(26)

2

Flowback Emission. Methane leakage during flowback operations occurs as fracturing fluid is cleared from a shale gas reservoir to the surface in the absence of an arrangement to capture the flowback gas.31 Reduced emission completion (REC) technologies, otherwise called green completions, are used by some operators to recover flowback gas for use or sales. Although not all injected fluid is recovered in most cases due to leak-off, the flowback regime covers the period from initiation until all fracturing fluid has been removed or the production of liquid levels off.4 Umeozor et al.4 used field data and flowback analysis to describe the three regimes of the lifetime of a shale gas well. On the basis of the observed flowback profile, we propose that the flowback rate from a well can be represented by the equation

(16)

(17)

(25)

Q CO e,h = χCO E H

(15)

ΔH = ΔU + V ΔP + P ΔV

Eh ηpηpm

Then, the emissions for the fracturing operation is obtained by using the emission intensity of the input fuel:

Analysis of fracturing pressure demonstrates that it follows a power dependence with treatment time, as reported in refs 29 and 30. Pfrac = c(t − ti)n

(24)

j

where Psurface is the fracturing treatment pressure applied at the surface by the pump system, Phead is the hydrostatic pressure due to the fluid column in the wellbore, and Pfriction accounts for all frictional losses.10,28 After rock breakdown is achieved or in residence of natural fractures in the formation, the net fracturing pressure, which is responsible for propagating fractures in the reservoir rock, can be expressed as the bottomhole pressure less of the closure stress (or fracture reopening pressure):10,28 Pfrac = Psurface + Phead − Pfriction − Pclosure

∑ qjΔPjΔt j

(23)

where Efric is the frictional losses as fracturing fluid pressure drops along the well. Determination of frictional pressure losses for Newtonian and non-Newtonian fluids are elaborately treated for different flow regimes by ref 26. Our model incorporates the equations for both laminar and turbulent flow regimes. To evaluate total energy losses, the number of fracturing stages have to be accounted for in the modelgiven that each stage is located at a unique measured depthas follows

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RESULTS Figure 5 compares the modeled flowback gas estimate to actual field measurement data. The mean value of estimated potential emission is 4810 Mg CO2e (±190 Mg CO2e at 95% CI), which is within 95% confidence limits of actual field measurements of potential flowback emissions. Table 1 lists descriptive statistics of the model along with those of 14551


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Figure 5. Comparison of proposed flowback gas model results with actual field measurements.

Figure 6. Comparison of modeled emission estimates to the data, with an inset parity line.

measurement data. The results indicate good agreement and the capability of the model to capture the range of variability in measured potential emissions. High standard deviations in both results reflect discrepancies in the emissions from a few high-emitters and a majority of wells that do not release as much emissions. To further explore the predictiveness of the model, the data and model estimates are visualized on a parity plot in Figure 6, and uncertainty is evaluated on the basis of the relative error to be 5.2%. An important use of the flowback model is that it requires only one variable input, which is the anticipated peak gas production from the well. Therefore, information on the range of historical peak gas volumes at any shale gas basin can be used to bracket estimates of potential methane emissions during development. Such knowledge would be useful for decision making on the gas-handling scenario to deploy for either economic or regulatory reasons. To understand the contribution of each preproduction activity and event to overall development potential emissions, a breakdown of direct and energy emissions is presented in Figure 7. As can be observed from the results, completions flowback gas is a major potential source of preproduction GHG emissions, accounting for 4810 Mg CO2e per well. It must be mentioned that this represents the potential emission that can be avoided, reduced, or released, depending on the jurisdictional regulatory requirements or the gas-handling decisions of the operator. The next main source of emissions is the well-drilling activity. We have subdivided the entire drilling operation into circulation of drilling mud and the actual rotary drilling activity powered by a top-drive system. Both the mud pump and rotary driver are assumed to be powered by a diesel prime mover. A diesel energy content (LHV) of 42.8 MJ per kg and emission factor of 69.4 kg CO2 per GJ (i.e., 2.97 kg CO2/kg diesel) is applied in the model. Although dependent on the borehole dimensions and well design, most of the CO2 emitted during the drilling stage arises

Figure 7. Breakdown of preproduction energy and direct emissions by activity.

from energy used for circulating drilling mud. This stems from pressure losses as mud is pumped into the bottom through the drillstring to the drill bit and up again to the surface via the annulus. In this operation, the mud also clears drill cuttings to the surface. For a 5 in. lateral casing in a 6.125 in. open hole, this accounts for about 91% of the total preproduction energy requirements. Well-drilling energy requirement captures the rotational energy needed by a top-drive system to develop the borehole considering just rotational motion as the drilling assembly makes its way into the shale gas reservoir. Additionally, mud gas is released when the drilling operation encounters a gasbearing zone. For our model, we have estimated the amount of mud gas from drill cuttings through the lateral section of the wellbore. Since our method assumes an overbalanced drilling operation, it should be expected that this approach determines the lower bound of the potential mud gas emission. The mud gas emission is estimated as 0.04 Mg CO2e per well. Total CO2 emissions for all activities during the drilling stage is estimated as 678.87 Mg per well. For the same lateral casing design, the hydraulic fracturing energy use represents about 2% of the

Table 1. Descriptive Statistics Comparison for Model and Measured Completions Flowback Potential Methane Emissions method

mean

median

SD

min

max

P25

P75

95% CI

estimated (Mg CO2e) measured (Mg CO2e)

4810 4400

4070 1610

3530 7650

3 7

32970 37270

2100 230

6490 4490

4810 ± 190 4400 ± 2200

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Figure 8. Energy requirements for shale gas well development with lateral casing sizes corresponding to 61/8, 71/2, and 83/4 in. lateral borehole diameters, respectively.

total, amounting to an energy-derived CO2 emission of 13.45 Mg per well. This includes frictional losses as fracturing fluid is pumped for each stage of the fracturing job and the energy needed to break down reservoir rock and propagate fractures into the rock. As expressed in eq 14, energy input for hydraulic stimulation derives from the pump work (which is based on Psurface); therefore, the hydrostatic head contribution to the fracturing pressure is not assigned to the pump. Figure 8 shows the effect of different well dimensions and lateral casing designs on both the overall preproduction energy requirement and that of each development activity. It is observed that for the smallest lateral diameters investigated, energy use for mud circulation dominates the total inputs. For the other lateral casing design sizes, the total energy input can be significantly lower but dominated more by rotational energy for drilling with the top-driver. Consequently, variabilities in well trajectory, well casing design, formation type, and resource deposition attributes are important when considering individual development project performance in terms of energy use and GHG emissions. This awareness is also essential for optimizing well development activities by tailoring decision parameters to specific formations/plays to minimize energy intensity and GHG emission impacts. For the Montney Formation wells considered, the average overall preproduction potential GHG emission is estimated as 5300 Mg CO2e per well, corresponding to an average total energy use of 4083 GJ per well. On the basis of preproduction requirements, the energy return on invested energy (EROI) for Montney shale gas is estimated as 3400. Furthermore, if the entire shale gas development projects in the Montney Formation during 2017 of 505 wells is sampled,20,32 this amounts to an aggregate potential GHG emission impact of about 2.68 Mt CO2e from unconventional gas Montney Formation operations alone. Figure 9 illustrates the sensitivity of preproduction emission estimates to modeling parameters and other resource deposition attributes. To calculate these sensitivities, a baseline GWP of 28 is applied to methane from all sources, so that the sensitivity of results to GWP is computed over a range of 21 to 36. It can be observed that the completion flowback gas is a potential source major variability in well-level preproduction GHG emission. Nevertheless, individual well-level emission estimates might vary according to differences in parameter values and development practices as shale gas projects are initiated across many parts of the world. For instance, Vafi and Brandt24 estimated GHG emissions from drilling and hydraulic fracturing in two U.S. shale basins (Bakken and Eagle Ford)

Figure 9. Sensitivity of preproduction emission estimates to well design and estimation parameters.

and obtained values of 417 and 510 Mg CO2e per well, respectively. For the same activities, our model estimated 692 Mg CO2e per well for the Montney Formation. Taken together, at the global scale, understanding impacts of preproduction emissions on collective capacity to achieve climate targets deserves more attention than is currently accorded, and predictive modeling can serve as an essential tool to extend the current knowledge of future impacts of impending developments in the natural gas supply chain. Consequently, as more gas is increasingly tapped from various shale plays worldwide, regulatory controls can be designed to accelerate implementation of mitigative development strategies that help to curtail environmental impacts of more gas in the global energy pool. Already, technologies such as green completions have been proposed to control flowback gas emissions from unconventional oil and gas projects. Shale gas is a type of unconventional gas found in pockets within a petroleum reservoir rock. Energy use and emissions during well development are the main differentiators of conventional and unconventional gas. We propose predictive modeling as an approach to quantify preproduction energy requirements and the attendant energy and direct GHG emissions. A detailed modeling workflow is presented indicating the main activities and events contributing to the overall impacts of new shale gas development. The proposed model is applied to 1403 wells in the Montney Formation in Western Canada. Our results suggest that the distribution of energy and emission impacts among the development operations might differ from how it is normally perceived. Depending on well trajectory and dimensions, the energy use 14553


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for mud circulation can predominate those of the other activities, including the rotational energy requirement for a top-drive drilling system and the pump work utilized for hydraulic stimulation. The average preproduction energy need is estimated at 4083 GJ per well. Nevertheless, as more gas reservoirs are developed, occasioned by increasing gas demand, a proper appreciation of the implications on climate change mitigation efforts can be better grasped on the basis of overall annual preproduction emissions, in accordance with the design of climate policy directives and targets. From this viewpoint, the annual potential preproduction GHG emission from unconventional gas wells in the Montney Formation in 2017 is estimated to be 2.68 Mt CO2e.

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ASSOCIATED CONTENT

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.8b05562.

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Modeling parameters and variables data ranges, parameter estimation model and solution methods, method of analytical modeling of drilling forces, and historical drilling activities in the Montney Formation (PDF)

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

Ian D. Gates: 0000-0001-9551-6752 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors acknowledge financial support from the Natural Science and Engineering Research Council (NSERC) of Canada and the University of Calgary.

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REFERENCES

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