SPE-173370-MS

Examining the Impact of Hydrocarbon Drainage on Completion and In-FillDrilling Strategies in Unconventional Reservoirs

Karthik Srinivasan, Midowa Gbededo, Hongxue Hue, Jayanth Krishnamurthy, and Veronica Gonzales,Schlumberger

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 35 February 2015.

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.

Abstract

Evaluating the effects of asymmetric stress distribution around a lateral can greatly help optimizecompletion techniques and overall production from in-fill horizontal wells in unconventional shale andtight reservoirs. Several factors affect long-term production from in-fill drilled wells including but notlimited to pressure depletion from produced wells, change of effective stresses in the depleted formationand interference between hydraulic fractures when the new in-fill wells are drilled, stimulated and broughtinto production.

The study addresses a variety of key challenges that the unconventional oil and gas industry is lookingto understand. These include understanding:

1. How the presence of a depleted wellbore affects hydraulic fracture propagation from a nearbynewly drilled well

2. How refracturing considerations in a producing well are affected by hydrocarbon drainage andmodified stress contrasts

3. How fracturing/refracturing pumping designs and volumes should be optimized to address thechallenges surrounding the wellbore

Under circumstances mentioned above, pressure distribution around the wellbore from hydrocarbondrainage was estimated by history matching production data over a certain period of time. Then the impactof various types of fracturing treatments on pressure depletion profiles from offset wells was studied usinga fully numerical fracture simulator that is capable of handling asymmetric stress distribution around thelateral. Fracture geometries from this study were either asymmetric due to depletion on only one side ofthe lateral or longer due to increased stress contrast. These fracture geometries were fed to a productionmodel to forecast long-term production from in-fill wells and study drainage patterns over time.Understanding these challenges provided a sub-surface perspective of how completion techniques shouldbe optimized to get maximum hydrocarbon recovery from reservoirs consisting of laterals that havealready been on production.

IntroductionThe Bakken and Three Forks formations in the Williston basin are among the most active unconventionalplays in the continental United States. Combined together, there are over 8,000 horizontal wells that arecurrently producing and have yielded over 750 million barrels of oil since the Bakken oil boom startedin 2008. Long laterals exceeding 10,000 ft and multi-stage hydraulic fracturing techniques with optimizedcompletion methodologies have made these wells highly economical and profitable at current (October2014) oil prices.

The Bakken and Three Forks plays belong to the late Devonian to Early Missippian age andaccommodates a sediment thickness of over 16,000 ft in an intracratonic sag basin (Carlson and Anderson,1965; LeFever et al., 1991). The formations are reasonably continuous and characterized by layer-cakegeometry, with only a few structural features such as the Nesson anticline (Theloy et al. 2013).Sedimentation of the basin occurred in the North Dakota portion from Cambrian through Tertiary timeshowing cyclical transgressions and regressions with repeated deposition of carbonates and clastics(Cherian et al. 2013). The Bakken petroleum system covers an estimated area of 225,000 square miles.It consists of three members: a shaly upper member, an arenaceous limestone to siltstone middle memberand a shaly lower member. The upper and lower members are both believed to be source rocks with hightotal organic carbon (TOC), oil-prone type II kerogen, permeability range of 0.01 to 0.03 md andthicknesses up to 46 ft. in some parts of the basin. The middle member is the reservoir rock holding theoil generated by the upper and lower members. It has permeabilities ranging from 3 d to 3.4 md andvaries in thickness across the basin from 10 to 92 ft.

Understanding production drivers in unconventional reservoirs requires a science-based approachwhere multiple variables non-linearly affect flow of oil and gas to the wellbore in a hydraulically fracturedtight-rock system. The commonly used statistical approach often leads to high levels of uncertainty andreduced robustness in its ability to act as a predictive model. Normalization using non-linear multi-varianttechniques using engineering, completions and geological variables work only in small areas with little tono variation in reservoir quality (Roth and Roth. 2013). The most successful field development andoptimization studies are usually the ones with a variety of petrophysical and geomechanical measurementsthat make best use of the available data by building robust mechanical earth models, fracture models andproduction models using fully numerical simulators. Using advanced logs such as magnetic resonance, 3Dsonic and tri-axial resistivity logs and core measurements provides high levels of confidence in suchmodels and repeatability in history-matching for sensitivity analysis purposes (Cherian et al. 2013) .

Bakken and Three Forks CompletionsCompletion methods used in different parts of the Williston basin in the Bakken and Three Forksformations have evolved with time and are a function of a variety of parameters including but not limitedto, in-situ stresses, thickness of surrounding shales, presence of thin-bed laminations, ability to connectmultiple productive formations and impact of conductivity/type of proppant on the fracture geometries.Understanding both the individual and combined effects of rock properties on the fracture geometries iscrucial in optimizing completions for maximum hydrocarbon recovery. For example, the average netpressure in the fracture impacts fracture height growth and the number of propagating fractures simul-taneously. However, calculating the magnitude of the net pressure in the fracture requires a goodunderstanding of the in-situ stresses, stress barriers, thin-bed laminations, viscosity of the fracturing fluid,rate of pumping, fracture toughness, etc., as shown below (Smith and Shylapobersky. 2000):

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Stress anisotropy in the Middle Bakken and Three Forks formations based on fracturing data andpublished data indicates propagation of bi-wing planar fractures in most cases. In some studies, this hasbeen illustrated from micro seismic evaluation of fracturing treatments and interference tests withbottom-hole-gauges in offset wells (Cherian et al. 2013). Approximate analysis of stress profiles in theWilliston basin shows that stress conditions are favorable for normal faulting and/or strike-slip faultingwith ratios among the principal stresses (i.e. the vertical, the maximum horizontal and the minimumhorizontal stresses) of 1: 0.95-0.85:0.85-0.75 (Wang and Zeng. 2011). There is no definite work-flow inunconventional reservoirs to provide a very confident solution to our problems. The level of difficultiesand uncertainties in measurement of rock and fluid properties complicates this situation further. Optimi-zation work-flows in unconventional reservoirs should be geared towards reducing uncertainties andimproving the validity of the models by continuously evolving on our current practices. Typicaloptimization approaches start with trial-and-error techniques experimenting with multiple combinationsand learning the best combination. Statistical data are compiled during this process to look for any patternsor trends between production and completion parameters. This can be as simple as a linear relationshipbetween amount of proppant pumped per unit length of the lateral and the best 3 months of cumulativeoil production or as complex as a multi-variant analysis involving 10 or more paramters and the use ofartificial neural network algorithms. But there is no science associated with such an approach. Thenon-linear relationships that connect the dots do not have to honor physics and math behind fluid flow ina porous media nor the behavior of hydraulic fractures in a tight-rock system.

Cross-linked fluid fracture treatments using Plug-and-Perf completions are amongst the mostcommonly followed practices in the Williston basin. Recent experiments have found a good level ofsuccess with slickwater completions in the Middle Bakken (Griffin et al. 2014). Hybrid treatments offergood return-on-investment in certain areas where the combination of low water costs (relative toslickwater treatments) and productive fracture half-lengths longer than that of cross-link treatments resultsin longer sustainable production rates. In some areas, multiple negative factors such as thin stress barriers(Upper and Lower Bakken shales), presence of the silty lower Bakken member, or lateral drilled out ofzone can make propagation of multiple fractures almost impossible, and sliding-sleeve completions or lowfluid/proppant volumes may be the best choice under such circumstances.

Williston Basin In-Fill CompletionsNorth Dakotas drilling activity in the Williston basin is mainly concentrated in the western parts of thestate in Billings, Bowman, Burke, Divide, Dunn, McKenzie, Mountrail and Williams counties. Fig. 1illustrates well footprints in these counties. The plot in Fig. 2, showing the cumulative oil productionalong with active producing completions in North Dakota from 1987 2014, highlights the tremendousincrease in activity in the area in the past 10 years. Oil [and gas] production from the Bakken petroleumsystem has increased 10 times in the last 10 years.

Several upfront considerations are necessary when developing the plans for unconventional reservoirwells. These include orientation of the well, present day stress-state in the reservoir, required well spacing,plans to drill and complete in-fill wells, and the need for secondary/tertiary recovery techniques in thefuture (Miskimins. 2008). According to a North Dakota Geological Survey (NDGS) report, typicalrecovery factors for oil wells in many parts of Middle Bakken and Three Forks is between 15 to 20%. Toimprove recovery factors, operators have attempted various Enhanced Oil recovery (EOR) projects acrossthe Williston basin, but the most popular method being used to improve recovery has been infill-drillingprograms. Although in-fill wells may add up to overall hydrocarbon recovery from the field, they are noteconomical all the time. EOR studies in the Middle Bakken and Three Forks formations have shown thatinjectivity (CO2 flooding or water flooding) is very poor in most areas regardless of the injected fluid anddelaying drilling of in-fill wells for more than 2 years usually results in production loss at early time(Iwere et al. 2012).

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Taking a closer look at three of the major pro-ducing counties in North Dakota - McKenzie,Mountrail and Williams, infill-drilling patterns startto emerge. McKenzie County has on an averagethree horizontal wells per section; Mountrail Countyhas on an average five horizontal wells per section;while Williams County has on an average four wellsper section.

Effect of pressuredepletion/hydrocarbon drainage onin-fill CompletionsConsider the drilling unit shown in Fig. 4. A drillingunit is two sections (5,280 x 10,560 ft). Standardand most recent drilling practices in the MiddleBakken and Three Forks follow are to have fourwells per drilling unit with lateral lengths ranging from 9000 to 10500 ft. Local experience, step-downtests and published case studies in the basin indicate that depending on the type of fracturing treatment,rock mechanics, and the pressure profile distribution in the reservoir, the average productive half lengthsfrom the transverse fractures can range from 100 to 400 ft. Typically, longer the half-lengths mean lessproppant-pack conductivity in the fracture. Based on simple material balance calculations, multiplefractures with evenly distributed proppant and fluid volumes will result in shorter, highly conductivefractures compared to a single long fracture with sparse distribution of the proppant along the length. Inlaterals with stress variation along the length, geomechanics dictates the behavior of the system as thefracture pressure and hence the resulting net pressure competes against the differential pressure requiredto overcome frictional losses between multiple fracture zones. In areas where horizontal stress anisotropyis well established, the battle to grow in one dominant direction (height or length) is usually wellunderstood using a fully numerical planar simulator, provided the stress profiles are reasonably accurateand tectonic effects are insignificant.

As shown in the Fig. 3, most of the core acreage of the Middle Bakken and Upper Three Forksmembers have been drilled and completed with many wells on production for more than a year.Depending on the reservoir quality and completion quality, average hydrocarbon recovery from thesehorizontals can range from 5% to 20% of the Original Oil in Place (OOIP). Although these reservoirsexhibit low permeabilities and low effective porosities, the extent of drainage of hydrocarbons is usuallylimited to the area around the fractures while movement of hydrocarbons from the reservoir boundary tothe hydraulic fracture system is very slow. Fig. 4 illustrates the pressure transient profiles from twohorizontal well-bores spaced 1320 ft from a four-well drilling unit after being on production for a year.Most of the depletion and movement of pressure is restricted to the area around the black dotted box andthe reservoir pressure at distances farther from the wellbore are still at virgin conditions. However, witha productive fracture half-length of 250ft on either side of the lateral, the area between the two lateralsis no longer at virgin conditions. As an example, if the initial reservoir pressure is approximately 6500 psi,then the reservoir pressure at a distance right in the middle of the two producing laterals (shown by dottedred line) is approximately 6340 psi, a slight depletion caused by hydrocarbon drainage from around thetwo wells.

With operators running out of acreage to drill, many resort to in-fill wells to recover hydrocarbons fromareas not swept by existing wells. In this example, with a drainage area of 1,280 acres and four laterals,assuming an 18% recovery, each of the four wells would produce roughly approximately 220,000 bbl of

Figure 1North Dakota Williston Basin well density

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oil over its life cycle. The decision to drill an in-fill well to drain maximum hydrocarbon out of the groundshould take into account the parameters listed below:

Fracture length and extent of depletion from existing producer wells Pressure interference between producer wells (usually takes several years) Impact of depletion on the horizontal stresses which in turn may affect fracture propagation inin-fill wells

Capital expenditure on drilling and completion of new in-fill wells Fracture geometry in in-fill wells, which should be designed to reduce well-to-well interference asmuch as possible

Figure 2Cumulative oil production history North Dakota (IHS Energy)

Figure 3Well densities of Middle Bakken/Three Forks in North Dakota by county

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Let us compare two different scenarios:

a. Produce from two wells spaced 1,320 ft apart for a period of 5 yearsb. Produce from two wells spaced 1,320 ft apart for 6 months, drill and complete an in-fill well and

continue producing from all the three wells for a period of 5 yearsFig. 5 shows the pressure distribution profile in the reservoir at the end of 5 years. Fig. 6 shows

cumulative oil production from each of the three wells at the end of 5 years. Clearly, the parallel gap

Figure 4Standard well spacing in the Bakken/Three Forks and pressure transient profiles from existing producer wells

Figure 5Pressure depletion profile from producer/in-fill wells after 5 years of production

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between the curves indicates the impact of pressure depletion on the estimated ultimate recovery (EUR)of the in-fill well.

The longer the gap in completion time between the producer wells and the in-fill wells, larger is theimpact on the EURs. This is illustrated in Fig. 7, where the plots show cumulative oil production fromthe in-fill well that is completed after 1 year and 2 years after the producer wells respectively. Anotherimportant aspect that needs to be taken into account is the impact of depletion on geomechanics. Let usassume, in the above example, an in-fill well is drilled and ready to be completed after a year from thetime the two surrounding producer wells are completed. Using publicly available data, several stressprofiles are constructed at various distances from the in-fill well and a fracture model is built to comparewith the fracture model observed from the two producer wells at virgin reservoir conditions.

Generally, three principal in-situ stresses are assumed for the convenience of description and study:vertical stress (V), maximum horizontal stress (H), and minimum horizontal stress (h). The in-situstresses, especially the smallest principal stress, are the most important factors in hydraulic fracturepropagation and containment. The vertical normal stress is assumed to be equal to the weight of theoverlying rock and can be computed by integrating the bulk density log data:

Figure 6Comparison of cumulative oil production between in-fill and offset producer wells within 6 month time gap in completion

Figure 7Comparison of cumulative oil production between in-fill and offset producer wells with 1 year and 2 years time-gap in completionrespectively

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(1)

where V is the vertical stress, b is the bulk density, g is the acceleration due to gravity, and z is thetrue vertical depth.

The following poroelastic equations are the most commonly used in analysis of unconventionalresources:

(2)

(3)

where V is the vertical Biots poroelastic coefficient, h is the horizontal Biots poroelastic coefficient,vV is the vertical Poissons ratio, vh is the horizontal Poissons ratio, EV is the vertical Youngs modulus,Eh is the horizontal Youngs modulus, Pp is pore pressure, H and h are tectonic components in maximumand minimum horizontal stress directions.

The above calculation gives the virgin state of in-situ stresses and is controlled by geological eventssuch as sedimentation and far-field stresses imposed on the basin boundary. However, it is widelyunderstood that injection and production activities can induce additional stress that may trigger complexhydraulic processes. In a single well scenario, we can calculate the stress variations due to depletion usingthe above equations. In three dimensional scenarios, when production of underground fluids happenwithout large amounts of injection, the process leads to an increase in effective stresses and a decrease inreservoir volume. The volume diminution of the reservoir induced by a reduction in porosity is termedcompaction, which is usually associated with depletion.

Throughout the development cycle of an oilfield, production activities reduce in-situ stresses in thedepletion zone and, as a balance effect, increase the stresses in the underlying and overlying formations.Stresses in areas adjacent (horizontally) to the depletion area will be increased. This increase will act asadditional tectonic components (H and h) if we calculate stresses along nearby single well using theabove poroelastic equations. However, the magnitude of these additional H and h, or the induced stressesdue to oilfield production are not easy to estimate using the single well method, neither are they easy tomeasure in-situ. In our study, we apply a finite- elemental model coupled with reservoir simulation topredict the varied stresses.

Because in-situ stresses are the primary factors controlling the fracture geometry in the hydraulicfracturing treatment, unbalanced stresses will result in asymmetric hydraulic fractures in the infill wellsand therefore impact the strategy of well spacing and timing of drilling and production. If an infill wellis drilled next to a parent well with significant production, the hydraulic fracture of the infill well willpropagate a greater distance in the direction of the parent well than in the opposite direction. A smallvolume of cross-link fluid (~14000 gal) is simulated with a fully numerical three-dimensional fracturesimulator and the geometries are observed. Fig. 8 shows the 3D fracture geometries in the in-fill wellwhen they are completed at virgin reservoir conditions, depletion from both sides and depletion from onlyone side.

Optimizing In-Fill Completions to Maximize RecoveryThere are several secondary and tertiary recovery techniques to improve recovery from unconventionalreservoirs. The decision to choose refracturing existing wells, Enhanced Oil Recovery (EOR) techniques,pressure maintenance techniques or drilling in-fill wells is dictated by economics and rate of return on theinvestment. This, in turn, depends on a combination of parameters, including but not limited to, reservoir

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quality, effective completion procedures, and a clear understanding of maximum achievable productionthat should be practical and reasonable within a certain time frame.

In tight rock systems, there is little to no change in propagating half lengths when the proppant startsentering the formation. In the Middle Bakken and Three Forks formations, most of the depletion occursin the zone of productivity whereas the shale barriers/source rocks simply provide pressure support.Vertical permeability in these shales is usually a huge unknown and production contribution from theshales by downward migration to the Middle Bakken or Three Forks can significantly impact overallhydrocarbon recovery. For example, a change in vertical to horizontal permeability ratio from 0.001 to 0.1can change the recovery factors by 10 to 12%. Completing an in-fill well taking into account parameterslisted previously can be a challenge. Fig. 9 below lays out guidelines and a detailed workflow to identifythe most optimum methodology to complete an in-fill well.

In the Middle Bakken and Three Forks formations, where 1,320-ft spacing between laterals is normal,it is nearly impossible to produce the same volume of oil from an in-fill well as that of a new well.Depending on the reservoir permeability and fracture half-lengths, the pressure transient lines willencounter interference at some point in time; higher the permeability, the less time it takes. Depletion ina producing zone from an offset well offers a few advantages:

Figure 8Comparison of Fracture geometry from in-fill wells from a small injection volume showing the impact of pressure depletion on fracturepropagation

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Reduction in horizontal stresses as a function of pore pressure is usually limited to the producingzone. This in turn results in higher stress differential and better height containment.

Depletion in multiple producing zones makes it easier to achieve connectivity between these zonesfrom the same lateral.

Reduced PAD and proppant volumes can still help achieve fracture containment and uniformdistribution of proppant in the fracture without having to worry about losing proppant tonon-productive zones.

As shown in the workflow, for the purpose of this study, two horizontal wells are produced for a periodof 1 year, and the depletion profile around the wellbore is observed. Based on the extent of pressuremovement, a new three-dimensional stress profile is constructed at various distances from the wellbore.Four different cases were considered:

1. X-Link treatment on the in-fill well with depletion on both sides2. X-link treatment on the in-fill well with depletion on one side only (only one of the two horizontalsare produced)

3. Slickwater treatment on the in-fill well with depletion on both sides4. Slickwater treatment on the in-fill well with depletion on one side only

Fig. 10 shows the three dimensional fracture geometries resulting from cases 1 and 2 respectively.Comparing the two plots in Fig. 10, one can notice that although there is little to no variation in propped

lengths between the two cases, there is a noticeable asymmetric hydraulic fracture growth towards oneside in case 2. The hydraulic length to the left side (which is at virgin reservoir conditions) is reduced from550 ft to 410 ft whereas it increases by a small amount to the right side (depleted reservoir). Averagepermeability of the Middle Bakken in this area is around 0.009 mD and it should be noted that these

Figure 9Workflow to optimize completions in in-fill wells as a function of hydrocarbon drainage and its impact on geomechanics

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asymmetry effects can be magnified even with an increase in permeability of approximately 0.01 mD fromwhat it is now. Also, the timing of completion of the in-fill is a key factor. Fig. 11 shows the fractureprofile from the same in-fill well if it is completed after producing the offset well for 2 years instead of1 year.

As observed in Fig. 11, the longer the time gap in completion between the producer wells and in-fillwells, the more pronounced is the effect of pressure depletion on fracture asymmetry. In this case, boththe propped and hydraulic half-lengths are longer on the depleted side extending to lengths greater than600 ft compared to 400 ft at virgin reservoir conditions. A similar experiment was done with Slickwaterfractures to examine case 3 and 4 and the results are shown in Fig. 12.

Figure 10Comparison of fracture geometries on an in-fill well for Cases (1) and (2)

Figure 11Fracture geometry from an in-fill well for Cases (2) with increased time gap in completions between in-fill well and offset well

SPE-173370-MS 11

It can be clearly observed from the Figs. 1012 that asymmetry effects are more pronounced inslickwater treatments with propped half lengths extending to greater than 1,500 ft. towards the depletedside. This is partly due to the low viscosity of the proppant-carrying fluid resulting in faster settling andpartly due to height confinement/reduced fracture width resulting in most of the proppant staying in zone.It can also be observed from the lower plot in Fig. 12 that there is significant reduction in proppedhalf-length towards the undepleted side of the wellbore with more than half the proppant transported tothe other side. As indicated in the workflow, it is important to identify the optimum conductive half-lengthfor the in-fill well that can yield the highest hydrocarbon recovery from a drilling unit. A productionanalysis was performed for cases 1 and 2 taking into account several scenarios and comparing long termcumulative oil production from the in-fill well as described below:

Case 1: Depletion on Both Sides of the Lateral. Production analysis performed for the followingscenarios for case 1

a. Using the same fracture design as the offset producer wellsb. Using the same fracture design as the offset producer well but with fewer perforation clusters per

stagec. Using a fracture design to achieve the same half-length as the offset producer well with higher

fracture conductivityd. Using a fracture design optimized to achieve maximum conductive half-length and still avoid

fracture to fracture interference

Cumulative oil production from the in-fill well over a period of 5 years for each of these cases is shownin Fig. 13. As seen from the figure, the highest cumulative production was achieved from Case 1d inwhich the optimum conductive half-length required to achieve maximum recovery was calculated usingdepletion-based-frac-models. Case 1c shows slightly higher production compared to Case 1a and this is

Figure 12Comparison of fracture geometries on an in-fill well for Cases (3) and (4)

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clearly an indication that conductivity is not a huge driver for production in this case. Case 1b obviouslyshows less production than all the other cases and proves that more fractures lead to higher productionuntil a certain maximum economic limit is reached.

Case 2: Depletion on one side of the lateral only. A similar analysis to that performed forsymmetric fracture propagation (case 1) was performed on a combination of scenarios withasymmetri fracture propagation (case 2)

a. Using the same fracture design as the offset producer wellb. Using the same fracture design as the offset producer well but with fewer perforation clusters per

stagec. Using a fracture design optimized to achieve maximum conductive half-length and still avoid

fracture to fracture interference

Figure 13Comparison of cumulative oil productions between Cases 1(a),(b),(c) and (d)

Figure 14Comparison of cumulative oil productions between cases 2a, 2b and 2c

SPE-173370-MS 13

The results from this analysis are shown in Fig. 14Very similar to results observed from the symmetric fracture propagation case, cumulative production

with optimized-fracture-length (case 2c) yields maximum recovery compared to the other two cases. Incases where the initial producer wells are treated with slickwater fracturing treatments, the additionalconductive half-length generated can lead to faster depletion and bigger drainage radius around the lateralresulting in lesser optimum half-lengths required to recover oil from the unstimulated area of the reservoir.A complete analysis would require a detailed understanding of the fracture profiles from the originalwells, a descriptive depletion profile from the producer wells, changes in stress profiles at variousdistances from the producing wells as a function of reservoir pressure, and a fracture model simulatingthese new stress conditions.

Conclusions

1. Maturity of the basin, depositional environment and geological structure can cause drasticvariations in mineralogy, reservoir quality and geomechanical properties across formations in thesame basin.As exploration and understanding of rock quality reaches a mature phase, enhancedrecovery methods may be required to recover hydrocarbons from reservoir acreage not stimulatedby existing producer wells.

2. The decision to drill in-fill wells to maximize overall recovery will depend on a combination ofmultiple parameters includinga. Depletion/drainage profile of existing completed producer wellsb. Estimated incremental hydrocarbon recovery from in-fill wellsc. Calculating new stress profiles as a function of pore-pressure variability and compactiond. Asymmetry of fracture propagation resulting from non-uniform depletione. Optimizing fracture geometries in in-fill wells for maximum recovery

3. A detailed workflow to decide on the best completion procedures for in-fill drilling is presentedas part of the study

4. Analysis of fracture profiles from completed wells is very important to determine the rightcompletion methods for in-fill wells

5. Production analysis as a function of completion time-gap and economic analysis based onEstimated Ultimate Recovery from in-fill wells will dictate the decision to drill and complete them.

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Basin, AAPG2. Cherian et alet al. 2013, Asset Development Drivers in the Bakken and Three ForkS. Presented

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