**2. Quality of pressure maintenance in CI operations**

Figure 1 provides a long-term assessment on batch cuttings injection. Four periods of pressure responses can be divided into:


**1. Introduction**

794 Effective and Sustainable Hydraulic Fracturing

by Barree (see reference [5]).

continues to be a challenge to the current technology.

volume.

As regulatory restriction on the disposal of solid wastes such as drilling cuttings becomes increasingly tightened worldwide, cuttings injection (CI) into an existing well or a dedicated well becomes standard and required operation in drilling. Various guidelines and best practices in CI operations were established to accommodate local conditions and requirements.

One of the very important tasks to ensure a successful CI operation is to continuously monitor injection pressure behavior. Among various pressure responses, the characteristics of fracture closure after shut-in directly relate to the quality of pressure control and thus to the ability to

Fracture closure can be assessed empirically by capturing the inflection point in the pressure decline curve. The inflection point generally reflects the transition between linear or bi-linear flow within the hydraulic fracture and pseudo-radial flow outside the hydraulic fracture.

Fracture closure can also be evaluated more accurately using analytical methods. Among various methods, popular ones are: a) the square-root time method to determine the transition between bi-linear flow and pseudo-radial flow using the filtration theory proposed by reference [2]; b) the Horner time method to determine early time fracture flow and late time pseudo-radial flow (see reference [3]); c) the *G* function method to identify the onset of fracture closure by examining the transition of the flow pattern proposed by Knolte (see reference [4]); and d) the superposition *G* function derivative method to determine the reversal of the *G* derivative that signals the transition between bi-linear flow and pseudo-radial flow proposed

This paper is intended to explore the physics of fracture closure behind the pressure decline curves. By examining the pressure responses in the CI pressure monitoring cases, patterns of both successful and unsuccessful pressure control were captured. Observations reveal that the length of duration in the shut-in period between the injections is a critical parame‐ ter with respect to the quality of pressure dissipation and fracture closure. Cuttings injection efficiency is a function of the magnitude of the disposal domain of the stimulated fracture

Sensibly interpreting the physics of fracture closure from bottom-hole pressure responses can be difficult due to the inability to directly measure hydraulic fracture evolution. By comparing various fracture decline curves with reference to their relation to the *G* function and superpo‐ sition derivatives, this paper identifies the key parameter as the pressure decline curve shape. The conventional interpretation of pressure decline with regard to the physical behavior of hydraulic fractures appears to be insightful. However, verification of this interpretation

A systematically designed CI operation can be seen in reference [1].

prevent near-well screen outs and unexpected shut down of injection wells.


Periods A and D form a repeat cycle with slightly higher peak pressures in Period D than in Period A. It is easily seen that the longest time for pressure dissipation was during Period C. This also led to the best possible fracture closure and lowest terminal pressure among all pressure decline curves.

The physics of fracture closing and its relation to pressure response can be more complex than from the stated single event or relation alone. For example, the fracture could be closed on cuttings so that the terminal pressure is high. In general, a slow leakoff can be envisioned as the equivalence of difficult in fracture closing. The sufficient pressure dissipation can also be caused by the initiation of a new fracture in a different orientation from the previous one, or an increase in fracture aperture due to its connection to natural fractures, or anything else. For simplicity in this paper, however, we contribute the pressure dissipation to the fracture closure without resourcing to its physical origins.

Figure 2 shows the pressure responses from 28 batches of cuttings injection separated into five periods (A-E). Significant rising peak pressures during Periods A, B, C and E reflect difficulties in cuttings injection. This is in contrast to the smaller peak pressure increase in Period D that indicates relatively easy injections. A couple of good pressure relief or deep drop terminal pressures are seen in injection periods B and E.

**Figure 1.** Pressure responses over long period of cuttings injection. (A): gradual pressure build up due to insufficient fracture closing; (B): good fracture closing; (C): excellent fracture closing with sufficient time; and (D): gradual pressure build up due to insufficient fracture closing.

These three well-head pressure values can be simply divided into two pressure groups:

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With respect to the trend of well-head pressure in peak, ISIP, and terminal values over time shown in Figure 3, Figure 4 shows the linear increasing trend correlating pressure and elapsed time with good correlation for the peak pressure, average correlation for the terminal value,

Examining four individual injections (i.e. injections A, B, C and D) as shown in Figure 5, it is noted that the time between injections A and B is quite short. As a result, there is not sufficient time for pressure to dissipate in injection A. For other injections (i.e. injections B, C, and D),

If sufficient time is not given between injections, the result of the injection will not be as effective. Figure 6 shows that batches 17 and 19 are almost unnecessary because they are close to batches 16 and 18 so the pressure decline curves follow the same trend lines of batches 16 and 18 without being affected by injections 17 and 19. On the other hand, injections 17 and 19 may be viewed as two "free" injections because the general pressure fall-off behavior has not been affected. Figure 6 also shows the gradual increase of ISIP from 4627 psi in batch 16 to 4724 psi in batch 18, and finally to 4820 psi in batch 20. The rising ISIP is an indication in the increase of fracture closure pressure and collectively the pressure build up due to insufficient fracture

**Figure 3.** Observed WHP over 36 injection batches with an average pressure increase of 400 psi and differences be‐

tween peak WHP and terminal WHP of 800 psi. The rate of pressure increase is 50%.

there is sufficient time for the pressure to dissipate to the initial injection value.

**•** Group A: injection pressure (before shut-in)

**•** Group B: declining pressure (after ISIP)

and poor correlation for the ISIP value.

closing.

**Figure 2.** Observed bottom-hole pressures during 28 injection batches. Durations A, B, C and E show the rising peak pressures that are the indication of difficulties in cuttings injection. Duration D shows a slight rise of peak pressure that is the indication of easier cuttings injection.

When the injection batches were extended to 36 and we examined the well-head pres‐ sure, Figure 3 indicates that the average difference between the peak well-head pressure and terminal well-head pressure is 800 psi, while the average increase of well-head pressure (WHP) over the entire injection period is 400 psi. Therefore, the rate of pressure increase is 50% (i.e., rate = ΔP/P = 0.5). Experience tells us that a 50% increase in pres‐ sure could be too high. For pressure to be manageable, the increase should be under 40%. Either injection pressure has reached its maximum value or the disposal domain capacity is restricted due to intersecting low permeable zones or as a result of stress reorientation when crossing the stress barrier. Either an adjustment to the injection plan or an alterna‐ tive approach needs to be implemented. The good news from Figure 3 is that both peak pressure and terminal pressure at the final injection period show the declining trend, an indication of pressure relief.

The following information can be obtained from Figure 3 for each injection cycle:


These three well-head pressure values can be simply divided into two pressure groups:


**Figure 2.** Observed bottom-hole pressures during 28 injection batches. Durations A, B, C and E show the rising peak pressures that are the indication of difficulties in cuttings injection. Duration D shows a slight rise of peak pressure

When the injection batches were extended to 36 and we examined the well-head pres‐ sure, Figure 3 indicates that the average difference between the peak well-head pressure and terminal well-head pressure is 800 psi, while the average increase of well-head pressure (WHP) over the entire injection period is 400 psi. Therefore, the rate of pressure increase is 50% (i.e., rate = ΔP/P = 0.5). Experience tells us that a 50% increase in pres‐ sure could be too high. For pressure to be manageable, the increase should be under 40%. Either injection pressure has reached its maximum value or the disposal domain capacity is restricted due to intersecting low permeable zones or as a result of stress reorientation when crossing the stress barrier. Either an adjustment to the injection plan or an alterna‐ tive approach needs to be implemented. The good news from Figure 3 is that both peak pressure and terminal pressure at the final injection period show the declining trend, an

The following information can be obtained from Figure 3 for each injection cycle:

that is the indication of easier cuttings injection.

796 Effective and Sustainable Hydraulic Fracturing

indication of pressure relief.

**•** Peak value of well-head pressure

**•** Terminal well-head pressure

**•** Instantaneous shut-in well-head pressure (ISIP)

With respect to the trend of well-head pressure in peak, ISIP, and terminal values over time shown in Figure 3, Figure 4 shows the linear increasing trend correlating pressure and elapsed time with good correlation for the peak pressure, average correlation for the terminal value, and poor correlation for the ISIP value.

Examining four individual injections (i.e. injections A, B, C and D) as shown in Figure 5, it is noted that the time between injections A and B is quite short. As a result, there is not sufficient time for pressure to dissipate in injection A. For other injections (i.e. injections B, C, and D), there is sufficient time for the pressure to dissipate to the initial injection value.

If sufficient time is not given between injections, the result of the injection will not be as effective. Figure 6 shows that batches 17 and 19 are almost unnecessary because they are close to batches 16 and 18 so the pressure decline curves follow the same trend lines of batches 16 and 18 without being affected by injections 17 and 19. On the other hand, injections 17 and 19 may be viewed as two "free" injections because the general pressure fall-off behavior has not been affected. Figure 6 also shows the gradual increase of ISIP from 4627 psi in batch 16 to 4724 psi in batch 18, and finally to 4820 psi in batch 20. The rising ISIP is an indication in the increase of fracture closure pressure and collectively the pressure build up due to insufficient fracture closing.

**Figure 3.** Observed WHP over 36 injection batches with an average pressure increase of 400 psi and differences be‐ tween peak WHP and terminal WHP of 800 psi. The rate of pressure increase is 50%.

**Figure 4.** The trend of the well-head pressure in peak, ISIP, and terminal values over the injection period showing good linear correlation for the peak value, average linear correlation for the ISIP value, and poor linear correlation for the terminal value.

**Figure 6.** Injection pressure responses for batches 16 through 20. Injection batches 17 and 19 appear to be unneces‐ sary because they are too close to batches 16 and 18, respectively. The pressure decline for batches 17 and 19 follows

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Accurately determining fracture closure pressure is important for the following factors: a) minimum horizontal stress or fracture gradient, b) fracture efficiency, and c) formation properties and responses. The most popular method used to determine closure pressure is a MiniFrac test. Figure 7 shows the BHP and corresponding step injection rate from a MiniFrac test. The point of LOP in BHP is defined as the leakoff point that is an indica‐ tion of initial near-well fracturing. LOP is also termed as an extension pressure point. The point of BP in BHP is defined as the breakdown pressure that may indicate the initiation of substantial fracturing into the formation. The vertical pressure drop after the peak of BHP depicts the range of the instantaneous shut-in pressure (i.e., upper and lower boundaries of ISIP). The vertical pressure drop is the result of perforation friction loss. After ISIP, pressure declines are accompanied by injection fluid leakoff and fracture closing. Fracturing treatment efficiency is defined as the ratio of fracture volume at the end of

the same trend lines as batches 16 and 18.

**3. Fracture closure analysis**

pumping to the total injected volume (see reference [6]).

**Figure 5.** Pressure responses from four injections where the red line is bottom-hole pressure (BHP), the pink line is injec‐ tion rate, and the green line is temperature. Pressure dissipation for injection A is insufficient. Pressure dissipations for in‐ jections B, C, and D are sufficient. The temperature drop validates the entry of injection fluid at the perforation.

**Figure 6.** Injection pressure responses for batches 16 through 20. Injection batches 17 and 19 appear to be unneces‐ sary because they are too close to batches 16 and 18, respectively. The pressure decline for batches 17 and 19 follows the same trend lines as batches 16 and 18.

#### **3. Fracture closure analysis**

**Figure 4.** The trend of the well-head pressure in peak, ISIP, and terminal values over the injection period showing good linear correlation for the peak value, average linear correlation for the ISIP value, and poor linear correlation for

**Figure 5.** Pressure responses from four injections where the red line is bottom-hole pressure (BHP), the pink line is injec‐ tion rate, and the green line is temperature. Pressure dissipation for injection A is insufficient. Pressure dissipations for in‐

jections B, C, and D are sufficient. The temperature drop validates the entry of injection fluid at the perforation.

the terminal value.

798 Effective and Sustainable Hydraulic Fracturing

Accurately determining fracture closure pressure is important for the following factors: a) minimum horizontal stress or fracture gradient, b) fracture efficiency, and c) formation properties and responses. The most popular method used to determine closure pressure is a MiniFrac test. Figure 7 shows the BHP and corresponding step injection rate from a MiniFrac test. The point of LOP in BHP is defined as the leakoff point that is an indica‐ tion of initial near-well fracturing. LOP is also termed as an extension pressure point. The point of BP in BHP is defined as the breakdown pressure that may indicate the initiation of substantial fracturing into the formation. The vertical pressure drop after the peak of BHP depicts the range of the instantaneous shut-in pressure (i.e., upper and lower boundaries of ISIP). The vertical pressure drop is the result of perforation friction loss. After ISIP, pressure declines are accompanied by injection fluid leakoff and fracture closing. Fracturing treatment efficiency is defined as the ratio of fracture volume at the end of pumping to the total injected volume (see reference [6]).

**Figure 7.** Responses of BHP (in red) and corresponding injection rate (step rate, in blue) from a MiniFrac test: a) pres‐ sure increased sharply until generating a small fracture in LOP; b) formation breakdown at BP and small fracture prop‐ agation; c) shut-in, and d) pressure leakoff and fracture closing.
