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Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation PART 2

Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs


Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation


Sriniketh Sukumar, Ruud Weijermars*, Ibere Alves and Sam Noynaert

Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX 77843, USA;

Received: 11 February 2019 / Accepted: 29 March 2019 / Published: 18 April 2019

Interpretation of Results

The principal purpose of our study is to develop a conceptual model for the observed pressure communication between the two reservoirs (Eagle Ford and Austin Chalk). The estimated pressure acting on the boundary between the two reservoirs during the fracking of the Eagle Ford wells is modelled based on the pressure responses observed in the Austin Chalk wells discussed in Section 3.2.

Our analysis will quantify (and qualify) the correlation of the pressure response profiles using the following observations:

  1. The relative lateral spacings between Eagle Ford Wells H2 and H3 and the Austin Chalk observation wells (Section 4.1)
  2. Changes in average production in wells in the vicinity of the H2–H3 pair, including impact on the Riverside production unit (Section 4.2)

We then develop a conceptual model using the results of our analysis (Section 4.3 and Section 4.4) that serves to explain the principal mechanisms responsible for the observed pressure communication across the reservoir boundary between the Eagle Ford and the Austin Chalk Formations.

Vertical Communication

The reservoir pressures in the Eagle Ford an Austin Chalk reservoirs immediately prior to the the fracking operations in Wells H2 and H3 (Section 2.2), and the Austin Chalk pressure responses during the fracture treatment (Section 3.2 and Appendix C) are used to better understand the detailed nature of the pressure communication between the Eagle Ford and Austin Chalk reservoirs.

The principal pressure response magnitude, rate and durations for each of the observation wells are calculated in Appendix D. Pressure response magnitude is highlighted by the thickness of arrows in the gun barrel view of Figure 12a, which shows that the pressure communication intensifies from SW to NE.

Figure 12. (a) Gun barrel view with pressure response intensity in monitored Austin Chalk wells emphasized by arrow width. Well spacings are estimated using Well R3 as a reference line. The horizontal axis represents spacing relative to the midpoint of Wells H2 and H3. Vertical axis represents true vertical depth, and is exaggerated 6.6× relative to the horizontal length scale. (b) Plot of logarithm of pressure response against diagonal well spacings calculated from Figure 12a. Data labels are the Austin Chalk well names (R1, R4, R5, R2) with measured diagonal spacings in ft. A strong parabolic correlation is obtained.

Based on the observations from Figure 12a, one may suggest that the magnitude of pressure response is a function of distance to the fracked Wells H2 and H3. Diagonal spacings of Austin Chalk wells relative to the midpoint of H2–H3 pair are calculated and plotted against the logarithm of the pressure response in Figure 12b, correlating the information presented in Figure 12a. Diagonal well spacing and logarithm of pressure response therefore have a parabolic relationship.

One possible explanation for the pressure communication intensifying from SW to NE is that a denser natural fracture network occurs in the NE part of the Austin Chalk, which establishes a better connection with the hydraulic fractures from the Eagle Ford. We assume that some hydraulic fractures in the vertical direction in the Eagle Ford wells will connect with a natural fracture, which will ultimately lead up to a Riverside wellbore.

Natural fractures farther away from the wellbore have a better chance of activation if they fall within the influence zone of a long hydraulic fracture [14]. Alternatively, some of the observed pressure communication may occur by fluid transmission through the primary pore network of the Austin Chalk, which has a 12% average porosity (in a potential range of 10% to 22%) and an average permeability of 0.12 mD (in a range of 0.01 md to 15 mD), according to local field studies [7].

One may also speculate that the hydraulic fractures of Well H3 have wider apertures, because that well was fractured with coarser proppants (40/70 mesh heavy) much more frequently than Well H2 (100 mesh heavy), which would allow transmission of more frack-fluid and energy, and therefore could have resulted in a stronger series of connections with the natural fracture network in the Austin Chalk. In any case, Wells R2 and R5 show the highest intensity pressure response because these wells are relatively close to Well H3.

Observed Production Uplifts

Independent evidence for temporary pressure uplift in the Austin Chalk due to the fracking operation in the Eagle Ford Wells H2 and H3 is provided by increases in nearby Austin Chalk well productivity. For example, the Fazzino Well (API 04131486) operated by Wild Horse showed a distinct production uplift (Figure 13), which more than doubled its production of both oil and natural gas on the time scale of the fracture operation, and persisted for several months afterwards. We reason that the natural fracture networks being activated through the intensity of the hydraulic fractures from the Eagle Ford is responsible for the uplift.

The temporary pressure uplift observed resembles a fracture hit [6,15] which in our case did not result in permanent interwell communication. Earlier production uplifts seen in Figure 13 can be attributed to well workovers and shut-ins. Typically, such periods of zero production are followed by brief episodes of enhanced production. However, no shut-in preceded the latest rise in the Fazzino well, which the operator therefore attributed to the nearby fracking operation in the Eagle Ford Wells H2 and H3.

Figure 13. Production profile of Fazzino Well, including a zoomed in section showing with greater resolution the production uplift attributed to the fracturing of Wells H2 and H3.

Figure 13. Production profile of Fazzino Well, including a zoomed in section showing with greater resolution the production uplift attributed to the fracturing of Wells H2 and H3. The vertical axes for both plots have the same units. That is, bbl for oil and Mcf for gas. The production data used was obtained from the Texas Railroad Commission’s public sources.

Further, although Texas RRC reports that the Fazzino Well of approximately 3000 ft from the pressure signal (i.e., the H2–H3 Well pad), it is entirely possible that the production uplift observed was caused as a result of pressure communication due to the fracking of Wells H2 and H3. A similar incident occurred in 2014, in which a significant frack hit was observed in two other Eagle Ford wells in the same area. In that instance, Well O responded considerably to the fracking of Well H1, which is located 4000 ft away (in horizontal direction to the wells) from Well O.

Additionally, production data from the Texas Railroad Commission was considered in computing average changes in production for offset wells in the vicinity of the H2–H3 pair in the three months prior to and succeeding the fracture operation (which started on 14 November 2018). Three-month averages were computed for both oil and natural gas. The most significant production uplifts are summarized in Table 6. Some of the production uplifts may have occured as a result of other refracks and workover operations taking place in the county at about the same time.

Additionally, whether or not a well shows an average increase or decrease in production depends on how the average values are computed. For Table 6, average before includes monthly data from August, September and October 2017 and average after includes December 2017, January and February 2018. However, the data in Table 6 shows that the production uplift of the Fazzino Well emphasized in Figure 13 is attributable to the fracture operations, given that Table 6 reports 387% and 83% increases in oil and gas production, respectively.

Interpretations of Pressure Response Profiles and Conceptual Model

To build a conceptual model that can explain the temporary nature of and the physical process of pressure communication, we first consider the following additional details from the pressure response profiles presented in Section 3.2. Our reference is the response of Riverside 1 (Figure 9), but similar pressure response patterns and inferences were observed in the other Riverside wells (see Figure 10, Figure 11, Figure A2 and Figure A3)

The typical DFIT response [16] is characterized by a sudden surge in pressure that is dominated by the input pressure signal, followed by a rapid release of pressure, known as the reservoir dominated region in which the reservoir returns to its original pressure state. Interestingly, the response patterns for the main fracture treatments of all five observation wells (see Figure 9, Figure 10 and Figure 11, Figure A2 and Figure A3) also shows this pattern, to varying degrees. We identify four phases that characterize the pressure response pattern of Well R1, as follows:

(1)    The first increase in pressure (regions F1 and G1 labeled on Figure 9) is due to the hydraulic fractures propagating outwards in the vertical direction and connecting to the naturally fractured Austin Chalk system. As frack fluid enters the natural fracture network, the reservoir pressure of the Austin Chalk increases, which causes fluids to migrate towards Riverside wellbores, which were shut-in for the period of the fracking operation, but resumed production soon after the operation concluded. (Correspondingly, Table 6 showed the later increase in both oil and gas production of the Riverside production pad, as a result of the fracture treatment, in the months following the operation).

(2)    The plateau region (region H1 labeled on Figure 9) can be attributed to the zipper fracturing nature of the operation. In a zipper fracking operation, the fractures propagate towards each other so that the induced stresses near the tips force fracture propagation in a direction perpendicular to the wellbores [10]. The lateral fracture propagation prevents further vertical fracture growth, which results in a nearly constant pressure response in the Riverside well, given that each stage of the Eagle Ford fracture treatment was conducted in a similar way. The small bumps on the pressure response (region H1 labeled on Figure 9) suggest that the Austin Chalk reservoir pressure would increase further, if not restricted by the induced stresses at the fracture tips caused by the zipper fracking operation. This method of zipper fracturing is also highly effective in creating an altered zone within the Eagle Ford itself (in the horizontal direction).

(3)    The second increase in pressure (region I1 labeled on Figure 9) begins towards the end of the treatment of Well H3. Since there is no more interference from an additional fracture treatment, the pressure increases until after the treatment of Well H2 ends, and pressure declines to its original state.

(4)    The rapid decline in pressure occurs after a small time delay due to the residual effect of fracture treatment. If we model the entire response phenomena as a single fracture stage, the maximum response point (point J1 labeled on Figure 9) would be analogous to a closure pressure after which the flow becomes reservoir dominated. Stress shadows are then able to close the induced/connected fractures and fracture fluid is no longer forced into the Austin Chalk. Correspondingly, the production uplift effect for the Riverside well pad declined over a longer time span, as was shown by production data for three months after the fracking operation ended (Table 6).

The above pressure response observations for Well R1 largely apply to the other Riverside wells as follows:

    Riverside 4: Although there is no early pressure increase in Well R4, the pressure is slowly increasing throughout the frack job (regions B4, C4 and D4 labeled on Figure 10), and the magnitude of pressure communication is higher than for Riverside 1 (Figure 9), suggesting that Riverside 4 has better communication with a naturally fractured zone, allowing for greater extent of fracture network development.

The sudden spike in pressure in the middle of the fracture treatment job (Region A4 on Figure 10) could mean that a direct fracture connection was formed, allowing for pressure to surge, that even momentarily stuns the gauge as shown by a momentary negative pressure value (region A4, labeled on Figure 10). Similar to Riverside 1 (region I1 labeled on Figure 9), Riverside 4 shows a second pressure increase (region C4 labeled on Figure 10) at the end of the treatment of Well H3 that ends when the treatment of H2 ends, after which there is a slight increase for a short duration, due to the residual effect of the treatment. Reservoir dominated portion subsequently returns the reservoir to its original state.

    Riverside 6: Similar to Wells Riverside 1 and 4 (region H1 labeled on Figure 9, and region B4 labeled on Figure 10 respectively), Well R6 shows a plateau region (region A6 labeled on Figure 11) for the entirety of the frack job. The difference is that for Well R6, the increase in pressure (region B6 labeled on Figure 11) occurs immediately after the end of the treatment of H2. The pressure subsequently declines in the same way as in Wells R1 and R4. The magnitude of communication is significantly lower in this well because it is spaced further apart from wells H2 and H3 than the other Riverside wells (Well R6 does not appear on the gun barrel cross section in Figure 5a and Figure 12a) Further, the lateral section of this well could have a weak connection to natural fractures, which means fewer hydraulic fractures can develop a network.

    Riverside 2: Even though there is not enough data available, a region of pressure communication can be observed (Point B2 on Figure A2), although it is followed by a sudden decline in pressure.

    Riverside 5: Strong pressure surges are seen during and after the DFIT tests (conducted on Eagle Ford Wells H2 and H3 on 2 November 2017), in addition to observed response in middle of the fracture treatment (regions A5 and B5 respectively, labeled on Figure A3). The surges once again can be attributed to events similar to those assumed for Riverside 1 (see above), except in this case in lieu of higher quality data, we conclude that the surges correspond to two discrete, strong connections being formed.

Conceptual Model

We assume that the Eagle Ford shale and Austin Chalk form a single hydrocarbon system, in which the Eagle Ford shale is the underlying source rock [17]. Section 2.2 showed that there exists a significant pressure (2354 psi) difference between the Eagle Ford and Austin Chalk Formations. The pressure difference could cause oil from the hydrocarbon-rich Eagle Ford shale to naturally migrate upwards into the lower pressured Austin Chalk Formation. However, without any form of human intervention, this migration must happen over geologic time, since both reservoirs have very low permeabilities.

The hydraulic fracture treatment in the Eagle Ford pressurized the reservoir significantly and temporarily increased the pressure difference with the Austin Chalk. The hydraulic fracture treatment creates a fracture pattern in the Eagle Ford, which may connect to the existing natural fracture network in the Austin Chalk. Frack fluid used in the stage stimulation of Wells H2 and H3 is the ultimate source of the temporary pressure communication across the two fracture networks.

Figure 14a shows a schematic wellbore diagram of the vertical section of the Austin Chalk observation wells, highlighting the annular location of the wellhead where the pressure gauges were mounted. Figure 14b shows a conceptual model for the observed pressure communication, with a vertical cross section of the reservoirs, taken perpendicular to the panel (of the gun barrel view) shown in Figure 5a.

Figure 14b shows the base pressure signal introduced in Figure 8b superimposed onto the lateral section to show the pressure experienced for the longest duration on each section of the wellbore over the course of the fracture treatment. Arrows indicate pressure transmission which ultimately causes pressure responses in Riverside wells. Pressure communication and fluid mobility in the model are both facilitated by the network of natural fractures in the Austin Chalk.

Figure 14. (a) Schematic wellbore diagram for the vertical section of an Austin Chalk observation well, showing static fluid column for a shut-in well and highlights (in red) the annular location on the wellhead where the pressure gauges were mounted. (b) Conceptual model illustrating fluid flow and pressure communication that ultimately cause production uplifts in the Riverside production unit.

Often when fracture pressure communication is discussed, the observed pressure communication effects are attributed to changes in the in-situ stress of monitored well fractures, due to the propagation of hydraulic fractures in an offset well in the same reservoir, described further in [18]. Poroelastic interactions between monitor fractures and propagating hydraulic fractures, for a general unconventional reservoir and well configuration, are also modeled in cases where the wells are in the same, typically shale, formation [19]. These effects are not considered in our work since the Austin Chalk is a naturally fractured carbonate, which allows it to act as a conduit for actual physical fluid-based communication.

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.

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