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

Figure 2. (a) RELLIS wellbore trajectories. The white arrows represent the surface location of each well. The dotted outline represents the landing zone.

Acquisition of Eagle Ford Pressure Data

The proprietary fracture treatment files for the Eagle Ford shale Wells H2 and H3 were supplied for our study by the operator. The files include stage by stage post stimulation reports, and data on all relevant fracture treatment parameters such as treating, wellhead, pump side, wellhead and surface casing pressures, slurry flowrates, proppant and mesh size, and additive concentrations, with respect to absolute time, at a frequency of one measurement per second for each quantity. Table 2 shows the number of stages placed during the fracture treatment in each of the Eagle Ford well completions, along with the associated stage and cluster spacings.

Wells H2 and H3, the subjects of our study, have the highest number of stages (51 and 50 stages respectively), and were fractured with an average of 9 clusters per stage. Figure 5b showed the timeline for the 2017 fracture treatment progress for Wells H2 and H3. The base, start peak and end peak pressures are the three most important events for each stage of the fracture treatment and were therefore summarized and plotted (see Section 3.1) to serve as a basis for correlation with the Austin Chalk response.

In so doing, the voluminous data set supplied by the operator was significantly condensed, making it more suitable for further analysis. Eagle Ford well pumping schedules that were more prevalent in the recent past (2014), as well as common fracture treatment terminology used are discussed in Appendix B.

Table 2. Number of stages, stage spacing and perforation cluster spacing used in fracking operations for six Eagle Ford Wells, Brazos County, Texas.

Acquisition of Austin Chalk Pressure Data

The six Riverside wells were shut-in during the fracture treatment of Wells H2 and H3. Data logging pressure gauges were installed on the annuli of the Austin Chalk wellheads (Riverside 1–6) to measure any changes in the pressure. Processed data was logged at fifteen readings per minute. The time periods of successful and reliable data measurement for each well are reported in Table 3. A chronology of the pressure data acquisition in the monitored wells is developed in Figure 6. Diagnostic Fracture Injection Tests (DFIT) were conducted in both Wells H2 and H3 prior to the fracture operation in early November 2017, also shown in Figure 6.

Figure 6. Chronology for Austin Chalk Pressure Data Collection. High quality pressure readings obtained from Wells R1, R4 and R6.

Figure 6. Chronology for Austin Chalk Pressure Data Collection. High quality pressure readings obtained from Wells R1, R4 and R6.

 Table 3. Observations and interpretations for Riverside 1.

Table 3. Observations and interpretations for Riverside 1.

DFITs and other well testing procedures are more effectively investigated in more specialized work [12]. In our study, we simplify the effect of this complicated procedure by considering the DFIT pressure rise in the toe of the two Eagle Ford wells (H2, H3) as a distinct source of potential pressure communication with the Austin Chalk wells.

The pressure response readings for Wells R1, R4 and R6 are continuous during the DFIT and subsequent fracture treatment of the Eagle Ford wells and are therefore considered more extensively in developing our models and formulating conclusions. Data from Well R2 is discontinuous and is limited to just two brief entries (Part 1 and Part 2) on Figure 6. The pressure rise in Well R5 apparently killed the gauge early in the operation, so while the data set is continuous, it is not reliable data. The data collection period for Wells R2 and R5 ended permanently during the frack job. We attribute this to either memory overload or battery failure of the gauges. In spite of these technical issues, we were able to piece together a significant pressure response pattern by analysis of both the source and the response signals (Section 3).

Analysis of Results

The well head pressure data for the Eagle Ford fracture treatment were condensed to obtain a simplified input pressure signal (Section 3.1) that could then be used to visualize the correlation with the Austin Chalk pressure responses. The analysis of a fracture stage in the Eagle Ford is given in Section 3.1.1 and the combined pressure signal is discussed in Section 3.1.2. The correlated pressure response profiles are shown in Section 3.2 for Wells Riverside 1, 4 and 6, while those of Riverside 2 and 5 are discussed separately in Appendix C.

Pressure Analysis of Eagle Ford Wells H2 and H3

Analysis of Raw Data

Wellhead pressures for the fracture stages of the Eagle Ford wells provided by operators were used for later correlation with our pressure gauge measurements for Austin Chalk wells. The pressure build-up and subsequent pressure dissipation for Well H2 Stage 1 are shown in Figure 7. Treatment graphs show wellhead pressure variations plotted along time for a given stage, along with other relevant quantities like slurry rate and proppant concentration on the same axes. The base, start peak and end peak pressures are the three most important events in each stage of the fracture treatment. The three primary pressure states during the fracture treatment of each individual stage are labeled on Figure 7. Apart from minor operational differences, the treatment graphs for each stage in Wells H2 and H3 follow the same general pattern/shape of Figure 7.

    Start Peak Pressure: Highest pressure peak, which occurs at the very start of the plateau region of the pressure-time graph and corresponds to formation break down. Circulation fluid is pumped with no proppant to ensure the fractures are wide enough to accept the proppants, which is called creating a “pad”. Proppant circulation then typically commences at 100 mesh and low concentrations (20–50 ppg) and increases over time (terminology explained in Table A2, Appendix B). Sometimes during this process, a viscous proppant-free solution called “sweep” is used to remove any solid residuals and clean the well before circulating more proppant.

    Base Pressure: Pressure that persists for a longer time, and is represented by the lowest pressure that occurred between the starting and ending peak pressures, which is the stable pressure required for injection of the constant rate of the slurry. Base pressure is attributed to fracture propagation in all directions away from the perforation, although preferential fracture growth occurs in the direction of maximum horizontal stress, perpendicular to the wellbore in the lateral direction [13]. Wells H2 and H3 were fracked with 27 perforations per stage (on average).

This being the first stage for Well H2 fracturing, acid was circulated after formation breakdown, after which proppants of increasing concentrations are circulated up to 100 mesh. In the region between the starting peak and base pressure, the fractures propagate in all directions, confined between assumed lower and upper frack barriers. Lateral growth is assumed for the period where the pressure is stable, and subsequently increasing with respect to time, that is, between the base pressure and ending peak. In a typical fracture treatment, operators seek to maximize lateral fracture propagation to maximize the stimulated rock volume, by orienting wellbores and initiating fractures accordingly.

    End Peak Pressure: This corresponds to the time when pumping ceases and a pronounced end peak pressure occurs due to the highest proppant concentrations at the tip of the fracture (“screenout”). In order to avoid further pressure rise for Well H2 Stage 1 the operator cuts proppant supply. Operators need to be careful about pressure surges when ceasing pumping to end a stage. The goal is to regulate the proppant concentration precisely enough to minimize pressure build up towards the end of the stage.

The final proppant concentration value for this well was 1.80 ppg at 100 mesh. Once this value was reached, the well was flushed with a fluid with no proppants to remove any residual acid and the stage was completed.

Figure 7. Fracture treatment graph for Stage 1 of Eagle Ford Well H2. All stages had a similar fracture treatment schedule.

Figure 7. Fracture treatment graph for Stage 1 of Eagle Ford Well H2. All stages had a similar fracture treatment schedule.

Pressure Summary for all Stages of Eagle Ford Fracture Treatment

The post-stimulation reports provided by the operator were condensed by preparing summarized stage reports. The magnitudes of starting peak, base pressure and ending peak pressures of each stage in Wells H2 and H3 provide a first insight into the pressure profile, plotted in Figure 8a–c respectively. Figure 8d combines the starting peak, base peak and ending peak pressures in a combined plot for both wells. The plots provide an overview of the condensed Eagle Ford frack job pressure data against their relative timing. Next, the pressure signal of Figure 8a–d will be used to explain the nature of the pressure communication with the Austin Chalk Formation.

Figure 8. (a) Starting peak pressure (b) Base pressure, and (c) Ending peak pressure for each stage in Eagle Ford Wells H2 and H3, interpolated to more clearly show variation.

Figure 8. (a) Starting peak pressure (b) Base pressure, and (c) Ending peak pressure for each stage in Eagle Ford Wells H2 and H3, interpolated to more clearly show variation. Data points are labeled with corresponding stage number. Stage 1 is at the toe end and stage 51 and 50 are the final stages of the treatment, at the heel end of Wells H2 and H3, respectively. (d) Summary of Pressure change over time for 51 stage fracturing of Well H2 and 50 stage fracturing of H3. Data points represent discrete measurements and therefore the connections presented between data points are interpolations.

Pressure Response of Austin Chalk (Wells R1–R6)

Pressure responses of the five monitored Austin Chalk wells (R1 through R6, except R3) are discussed in detail in our study. The Eagle Ford pressure signal in the plots produced in this section consists of the combined pressure sources for Wells H2 and H3 as individually condensed in Figure 8d, but stage numbers are omitted in the correlated plots for the sake of clarity.

The following plots of Austin Chalk pressure response are based on high frequency pressure recordings (every 2 seconds) by the pressure gauges at the Austin Chalk wells. Given the difference in magnitudes between Eagle Ford and Austin Chalk pressures, the latter are plotted on a secondary axis (right-hand vertical scale in Figure 9, Figure 10 and Figure 11), which produces one plot per well. Observations and interpretations made are displayed below each graph (Table 3, Table 4 and Table 5). Pressure response profiles and interpretations of Wells R2 and R5 are discussed in Appendix C.

Figure 9. Correlated plots for Riverside 1. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. The significance of each labeled box is discussed in Table 3.

Figure 9. Correlated plots for Riverside 1. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. The significance of each labeled box is discussed in Table 3.

 Figure 10. Correlated plots for Riverside 4. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. The significance of each labeled box is discussed below.

Figure 10. Correlated plots for Riverside 4. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. The significance of each labeled box is discussed below.

 Figure 11. Correlated plots for Riverside 6. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. Significance of each labeled box is discussed below.

Figure 11. Correlated plots for Riverside 6. The left vertical axis is the pressure in Wells H2 and H3. The right axis is the pressure in the annulus of the Riverside wellhead. Significance of each labeled box is discussed below.

 Table 4. Observations and interpretations for Riverside 4.

Table 4. Observations and interpretations for Riverside 4.

 Table 5. Observations and interpretations for Riverside 6.

Table 5. Observations and interpretations for Riverside 6.

Riverside 1

Figure 9 shows the correlations between the signal of the pressure sources of fracture treatment stages in Well H2 and H3, and the responses in Well R1 on an absolute time scale. The plot for Well R1 is annotated with more detail than for the other wells to establish the causes for pressure variations before and after the job. Little wriggles can be noticed in the flat trend of the R1 pressure response curve in region H1. These wriggles loosely correlate with the start of the stages, most likely due to formation breakdown or starting peak pressure. This trend holds for most of the Eagle Ford operation. Towards the end of the operation in region I1, there is a large increase in Well R1 pressure response that persists for a few days after the Eagle Ford frack job ceases for a certain time period, and then rapidly decreases.

The steep drop of the pressure response curve is attributed to leakoff and final closure of the pressure conduit between Well R1 and the Eagle Ford pressure source, and can be observed to some degrees in all the wells. Table 3 presents observations and interpretations for each region of the plot highlighted in Figure 9. The table also specifies approximate date/time values for the selected regions. These observations will all be useful in developing a conceptual model for pressure communication in later sections, and recording time intervals will help in making further correlations.

Riverside 4

The correlated plot for Riverside 4 is shown in Figure 10. The data for this well spans from just before the start of the fracturing in H2 and H3 and was collected until 12/8/2017, almost a week after the job in H2 and H3 ends. The plot highlights the important features of the pressure response profile (as in Figure 9) whose durations are shown in Table 4. Since the pre-frack data was not available, we cannot comment on the effect of the DFIT™ test conducted on 11/02/2017 on Riverside 4. Even so, the data set obtained for R4 is continuous, and is the most reliable out of all the wells studied (see Figure 6) and shows strong response to the fracture treatment on the same time scale. Table 6 also notes observations and durations associated with the regions of response highlighted in Figure 10.

Table 6. Offset production data. Changes in production are based on 3-month averages before and after November 2017.

Table 6. Offset production data. Changes in production are based on 3-month averages before and after November 2017.

Similar to the response profile of Riverside 1 (Figure 9), the little bumps on Figure 10 correspond to the start of stages (most likely due to formation breakdown or starting peak pressure as we defined it) in region B4. Not all fracking stages produce visibly large bumps in the Austin Chalk. This trend holds for most of the Eagle Ford operation. Another similarity is in region C4 and region I1, where there is an increase in pressure towards the end of the operation. Region D4 marks the maximum pressure reached.

However, unlike in Well R1 (region J1 labeled on Figure 9) this maximum occurs over a plateau instead of one discrete point. We know that the maximum must be a plateau because the gradient of the plot decreases sharply between regions C4 and D4. Additionally, the pressure rapidly decreases in both Wells R1 and R4 after this maximum pressure point/plateau is reached. This is another important difference between R1 and R4, since in R4, the region of highest response occurs as a second plateau (with a noticeable, but minor positive gradient) instead of a discrete point, (as in Well R1), even though the maxima occur in both wells after the treatment is completed in Well H2. Further, the maxima in both Riverside wells occur at around the same absolute time (12/04/2017).

Riverside 6

The pressure response profile of Riverside 6 is shown on Figure 11, and the observations and time durations were recorded in Table 5. The key feature of this well is that there is only one significant pressure response in R6 that almost instantaneously occurs towards the end of the fracturing in Eagle Ford. Additionally, the magnitude of response is less than those of Riverside 1 and 4 (see Figure 9 and Figure 10 respectively) and takes significantly longer duration after the treatment ends to return to its initial reservoir state.

Data for this well was collected until after the pressure returned to its initial state in about one week after the job ended. Similar to the highlighted region H1 (on Figure 9) and B4 (on Figure 10), the response for the majority of the frack job is characterized by a plateau region in pressure with wriggles loosely correlating with the starting times of stages. The selected region A6 (on Figure 11) covers the entire frack operation. R6 follows the plateau trend of a steady pressure response for the almost the entire operation, unlike in Wells R1 and R4. Similar to R1 and R4, the pressure response of Well R6 peaks at the end of the operation and rapidly declines after reaching this maximum value.

The difference in Well R6 is that the rise to this pressure occurs almost instantaneously, which could be attributed to equipment failure, but could also be a strong pressure communication between the wells. The significant pressure response commences almost instantly after the frack job in H2 is completed, unlike in R1 and R4 which began growing to a maximum after the job in H3 was complete, while the fracking of the final stages of Well H2 were still ongoing (recall the job for H2 was finished a day after H3 as shown in Figure 8d). The pressure response maxima are reached at around the same time for Wells R1, R4 and R6 (i.e., at different times on 12/04/2017).

 

In the second we’re going to see:

Interpretation of Results

  1.  Vertical Communication
  2.  Observed Production Uplifts
  3.  Interpretations of Pressure Response Profiles and Conceptual Model
  4.  Conceptual Model

Conclusions

Appendix A. Pressure Depletion Calculation in Austin Chalk

Appendix B. Pumping Schedule of Well H1 in Fracture Treatment of 2014

Appendix C. Pressure Response Profiles for Riverside 2 and Riverside 5

References

 

Contact info:

[email protected] (S.S.); [email protected] (I.A.); [email protected] (S.N.)

Correspondence: [email protected]; Tel.: +1-979-845-4067

 

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.
http://www.allaboutshale.com

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