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ACS Omega
ACS Omega
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acsodf
ACS Omega
2470-1343
American Chemical Society

10.1021/acsomega.4c04919
Article
Application of Endothermic Fluids to Lower the Breakdown Pressure of Unconventional Reservoirs: Implications for Hydraulic Fracturing
https://orcid.org/0000-0002-6709-6444
Khan Fahad †
https://orcid.org/0000-0002-4395-9567
Mahmoud Mohamed *†
https://orcid.org/0000-0001-7706-1002
Raza Arshad *†
AlTammar Murtadha J. ‡
https://orcid.org/0000-0002-0131-4912
Patil Shirish †
https://orcid.org/0000-0003-4279-4665
Murtaza Mobeen §
https://orcid.org/0000-0003-2359-836X
Kamal Muhammad Shahzad §
† Department of Petroleum Engineering, College of Petroleum and Geosciences, King Fahd University of Petroleum and Minerals, Dhahran 31261 , Saudi Arabia
‡ EXPEC Advanced Research Center, Saudi Aramco, Dhahran 34466, Saudi Arabia
§ Center for Integrative Petroleum Research, King Fahd University of Petroleum and Minerals, Dhahran 31261, Saudi Arabia
* Email: mmahmoud@kfupm.edu.sa.
* Email: arshad.raza@kfupm.edu.sa.
22 08 2024
03 09 2024
9 35 3725337264
24 05 2024
14 08 2024
08 07 2024
© 2024 The Authors. Published by American Chemical Society
2024
The Authors
https://creativecommons.org/licenses/by-nc-nd/4.0/ Permits non-commercial access and re-use, provided that author attribution and integrity are maintained; but does not permit creation of adaptations or other derivative works (https://creativecommons.org/licenses/by-nc-nd/4.0/).

Unconventional hydrocarbon reservoirs are challenging media to exploit and develop for energy due to very low permeability. As such, unconventional means, such as horizontal drilling and hydraulic fracturing, are typically practiced. During hydraulic fracturing, the formation breakdown pressure is of great importance and determines the fluid pumping cost. Less attention has been given to breakdown pressure reduction for a cost-effective and enhanced hydraulic fracturing operation. The objective of this study is to explore the application of thermochemical fluids to induce thermal shock with the purpose of generating microcracks and reducing the breakdown pressure in high-temperature unconventional reservoirs. For this, thermochemical fluids of an endothermic nature (reduces the temperature when mixed) and Kentucky Sandstone and Eagle Ford Shale were utilized. In particular, we investigated the effect of endothermic reactions between ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) on the strength and breakdown pressure of both samples by applying multiple cycle treatments. The obtained results indicated a significant reduction in both the strength and breakdown pressure of the rocks, with Kentucky Sandstone showing a reduction of 53.07% and Eagle Ford Shale by 34.71% in breakdown pressure. This novel approach not only provides a promising alternative to traditional fracturing methods in high-temperature reservoirs but also could bring a significant reduction in fluid pumping requirements as well as the operational cost of hydraulic fracturing.

College of Petroleum Engineering and Geosciences, King Fahd University of Petroleum and Minerals 10.13039/501100020361 Sf24002 document-id-old-9ao4c04919
document-id-new-14ao4c04919
ccc-price
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pmc1 Introduction

The oil and gas industry is required to develop and utilize more advanced techniques for hydrocarbon extraction to meet the rising global energy demand.1−3 Reservoirs with easy oil production are becoming depleted, and the industry has started gradually turning its attention toward more challenging unconventional hydrocarbon reservoirs (UHRs) that are characterized with low/ultralow permeability, low porosity, high temperature, and pressure. UHRs are generally stress-sensitive, and fluids flowing in their porous media are very complex at the pore level due to the associated low porosity and permeability.4 The development of these reservoirs required unconventional ways such as horizontal drilling and stimulation by hydraulic fracturing or acidizing to create a conductive path for the movement of hydrocarbons from the reservoir to the wellbore.5,6 Fracturing the formation is the viable and recognized approach to producing UHR under economic constraints.7 Fracturing is generally done by a technique called hydraulic fracturing (HF) in which a large amount of artificial fractures is created mechanically by pumping huge amounts of fracturing fluid and proppants into the reservoir.8 A massive HF job may exceed 1000 cubic meters of fluid and one million kilograms of proppant.9 These artificial fractures allow the trapped hydrocarbon to move through the fractures toward the wellbore and help to enhance total hydrocarbon production. For any rock, there is a minimum pressure that is required to initiate a fracture which is known as breakdown pressure or fracture pressure. It is one of the most important parameters that is considered while designing the HF job. Figure 1 illustrates different stages and rock behaviors during fracturing as a result of pumping pressure. The graph plots pumping pressure against time, showcasing different stages of the fracturing process. As pumping starts, the pressure increases rapidly. This phase represents the initial fluid injection into the wellbore. The pressure continues to rise until it reaches the breakdown pressure. This is the point where the rock formation starts to fracture. The rock undergoes tensile failure, creating a fracture in the formation. After the breakdown pressure, there is a slight drop in pressure as the fracture starts to propagate. During this phase, the fracture extends into the formation as the fluid continues to be pumped. The pressure stabilizes, and then the pumping is stopped at the end of the treatment stage. The pressure is measured immediately after the pumps are shut off, reflecting the pressure within the fracture, and is termed as instantaneous shut-in pressure (ISIP). Over time, the pressure declines as the fracture begins to close. The closure stress is the pressure at which the fracture closes and the rock formation returns to its prefracture state. The rock undergoes elastic deformation and potentially some permanent deformation as the fracture closes.

Figure 1 Different stages and rock behavior during the increase in pumping pressure.

The fracture breakdown pressure is an essential parameter of a reservoir formation, influencing the efficiency of hydraulic fracturing, which in turn is related to hydrocarbon extraction. It directly impacts operational costs, environmental safety, and ultimate recovery. A large fraction of hydraulic fracturing cost is comprised of fracturing fluid pumping cost that is highly variable and is much dependent on the horsepower and the number of fracture stages requirement.10 The horsepower requirement is generally determined by the fracture pressure, rock strength, and maximum injection rate.11,12 A typical unconventional Bakken well costs 8–10 million dollars with around 1.5–2.5 million dollars in fracking job.13 Deep reservoirs with very low permeability and high pressure with high-temperature conditions can cause various operational challenges while performing hydraulic fracturing job due to the high breakdown pressure.14−16 Several fields around the world have very high breakdown pressures, which sometime exceed the pressure rating of the equipment. Briner et al. (2015) discussed that in Oman, heavy brine was used for the stimulation job to overcome the high breakdown pressure of the formation.17 In Sichuan basin, China, several stages of the horizontal well were not able to get stimulated due to the exceeding of equipment’s pressure rating from the breakdown pressure.18 In such conditions, the breakdown pressure can even rise to higher than 15,000 psi making the stimulation job much more challenging and expensive. Equipment with very high ratings needs to be deployed for such fracturing jobs in addition to the requirement of extra perforation or sand jetting of near-wellbore formation before formation breakdown.18 AlTammar et al. (2020) showed an actual field case in which the deep formation was not able to fracture due to the high breakdown pressure. There were three failed attempts to fracture the formation with the peak bottom hole pressure reaching around 18,000 psi, exceeding the equipment rating which results in failed fracturing job and adding the additional cost for the operator in terms of production, time, and money.19

Another possible approach for the stimulation process of such reservoirs is by reducing the breakdown pressure before the actual fracturing job. Various studies have been performed to reduce the breakdown pressure by utilizing different fluids or techniques. Diaz et al. (2020) demonstrated the cyclic fracturing method to reduce the breakdown pressure in the Pocheon Granite Core Sample. They also concluded that the number of cycles required to break the formation at a lower breakdown pressure decreases exponentially with the increase in time for each cycle.20 However, the cyclic injection method may not be successful all the time. AlTammar et al. (2020) showed a real field problem from a tight gas sandstone reservoir that was not able to get fractures even after various cyclic injections.19 Tariq et al. (2019) performed a thermochemical injection in unconventional carbonate rocks to reduce the breakdown pressure.21 They showed that the injected thermochemical upon reaction generates heat and nitrogen gas providing a pressure pulse and creating microfractures in the rock that reduce the breakdown pressure. Mahmoud et al. (2022) presented a new method of acid etching for controlling the location and orientation and reducing the breakdown pressure in unconventional reservoirs.22 They demonstrated that the acid etching can initiate small wormholes around the horizontal wellbore at designated locations and reduce the breakdown pressure, and later the fracturing fluid can create fractures in the conventional way. Gou et al. (2021) reported that the utilization of gelled acid can reduce the breakdown pressure to 56.7% which is caused by water.23 Another possible way to reduce breakdown pressure is by injecting cold fluids into heated reservoirs. This generates a thermal shock and induces micro cracks in the formation resulting in the lowering of breakdown pressure. Siratovich et al. (2015) discussed that this technique depends on various characteristics of reservoir rocks such as reservoir temperature, pressure, thermal expansion, mineralogy, chemistry, and the presence of natural fractures.24Table 1 summarizes various studies of cold fluid injections for reducing the breakdown pressure of reservoir rocks.

Table 1 Summary of Recent Studies on Breakdown Pressure Reduction Using Cold Fluids

reference	year	fluid used	conclusion	
Cai et al.25	2023	liquid nitrogen	the breakdown pressure of high-temperature granite decreased by 40.63%	
the failure mode is mainly in the form of tensile fractures	
the increase in initial temperature reduces breakdown pressure	
Zhu et al.26	2019	cold water	uniaxial compressive strength and Elastic modulus reduces	
with more cycles, the failure mode transforms from brittle to plastic	
deterioration of the physical and mechanical properties is mainly due to the development of microcracks	
Xue et al.27	2023	cold water	normalized elastic modulus and tensile strength from 5 different research studies were found to decrease with the rise in the initial temperature of the rock	
Enayatpour et al.28	2019	modeling study of thermal shock	thermal shock increases the tensile stress around the wellbore which exceeds the strength of the rock and break it at lower breakdown pressure	
Almarri et al.29	2021	numerical study of near wellbore cooling	the total minimum horizontal stress is inversely proportional to the temperature reduction	
the pressure reduced by 60% with the near-wellbore temperature reduced of 60 °F	
large reduction in temperature provides larger average fracture widths	
Wu et al.30	2021	liquid nitrogen	liquid nitrogen cooling generates additional hoop stress at near-wellbore resulting in reduction of injection pressure requirement	
The reduction in breakdown pressure increases with the increase in initial reservoir temperature	
Zeng et al.31	2020	numerical model of cold fluid injection	cold fluid injection induces tensile cracks in the rock matrix. With high temperature difference the tensile cracks propagate, two groups of tensile cracks would coalesce and lead to rock failure	
Song et al.32	2016	cold brine	both experimental and numerical results shows generation of cracks due to the thermal shock	
cold fluid facilitates cracks initiation in weak planes and/or causes the natural fractures to open and propagate some distance away from the hydraulic fracture surface	
this phenomenon is more prominent around the tip of crack due to severe thermal straining	

Aforementioned studies focus on injecting cold fluid from the surface to induce thermal shock. This requires additional cost of handling them at such a low temperature at the surface. Moreover, due to the geothermal gradient, the temperature will start increasing as it is injected into the wellbore. The current study tries to overcome these issues by utilizing a thermochemical fluid of endothermic nature. Ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) are used as thermochemical fluids which when reacted reduce the temperature of the rock. These fluids can be injected inside the reservoir, where they react instantaneously to provide thermal shock. Moreover, the reaction also generates ammonia gas, which can provide additional pressure to reduce the breakdown pressure of the rock. The utilization of these thermochemical fluids is ground breaking and provides a novel approach to the challenges posed by high-temperature reservoirs during the hydraulic fracturing job.

2 Methodology

2.1 Materials Required

Core samples of Kentucky Sandstone and Eagle Ford Shale having a diameter of 1.5 in. and a length of 3 in. were obtained from Kocurek Industries. The Kentucky Sandstone has a porosity of around 10–12% and a permeability of 0.98mD, while the Eagle Ford Shale has a porosity of 2.6% and a permeability of 21.39 μD.33 Ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) having a molecular mass of 53.49 and 40 g/mol, respectively, were used as thermochemical fluids and procured from Honeywell. Sodium carbonate (Na2CO3) and sodium bicarbonate (NaHCO3) of analytical grade having a molecular mass of 105.98 and 84 g/mol, respectively, were taken from PanReac AppliChem. Acetic acid (CH3COOH) solution having a molarity of 1 M was obtained from Sigma-Aldrich. A temperature logger (Omega-RDXL4SD) was used to record the real-time temperature reduction. Jeiotech vacuum oven having a maximum temperature range of 300 °C was used for heating purpose. All of the experiments were conducted using deionized water collected from Merck Millipore having a resistivity of 18.2 MΩ-cm.

2.2 XRD Analysis

X-ray diffraction (XRD) analysis of the two rock samples was performed to know their mineralogical composition using the Malvern Panalytical XRD machine. A small piece was cut from the core samples, and its powdered form was placed in the sample holder of the XRD machine. The measurements were taken at the angle ranges of 4° to 70° at an interval of 0.01°, which was programmed in the system. The curve between “intensity counts” and “2θ” was plotted and analyzed using X’Pert HighScore software using the ICSD database, which includes a huge library of known mineral patterns for the identification of minerals.

2.3 Selection of Thermochemicals

Four chemical reactions were shortlisted which are capable of reducing the temperature upon reaction and could provide a thermal shock. The chemical reactions in their balanced form are listed in Table 2. The best chemical reaction was selected by performing the reaction on a setup consisting of a reaction beaker, a magnetic stirrer, and a temperature logger for real- time temperature recording. A schematic diagram of the setup is shown in Figure 2. Initially, all four chemical reactions were performed, and their temperature drop along with time to regain the initial temperature was recorded. Based on the maximum temperature reduction for a longer time, the best chemical reaction was shortlisted. After that, the impact of the initial concentration of reactants on the temperature reduction capability was determined on the best selected reaction by varying their initial concentrations. The best performing reaction was shortlisted to perform the thermal shock on core samples.

Table 2 Potential Endothermic Chemical Reactions

reaction	chemical reaction	references	
A	NH4Cl + NaOH → NH3 + H2O + NaCl	(34)	
B	NH4Cl + H2O → NH4OH + HCl	(35)	
C	2CH3COOH + Na2CO3 → 2CH3COONa + CO2 + H2O	(36)	
D	CH3COOH + NaHCO3 → CH3COONa + CO2 + H2O	(37)	

Figure 2 Experiment setup for chemical screening.

2.4 Strength Measurements

2.4.1 Impact of Heating and Natural Cooling

It is important to understand the heating and natural cooling impact on the strength of core samples in order to compare this with the effect of thermal shock. The core samples (Kentucky sandstone and Eagleford shale) were heated by exposing to controlled heating up to 150 °C using a Jeio Tech Vacuum Oven (OV-12) for 24 h. After that, the core samples were taken out and allowed to cool at room temperature naturally. The effect of this heating and natural cooling cycle on the strength of core samples was determined by performing a scratch test using the scratch testing machine (EPS Log Engineering). The machine was run 10 times on each core sample during the strength measurement, and the average value of strength was recorded. The machine determines the strength of samples by recording the force exerted on the cutter that moves over the entire length and generates a continuous strength profile along its length. The samples were tested both before and after the heating and cooling cycles to determine their effect on the core strength.

2.4.2 Impact of Surface Thermal Shock Using Thermochemicals

The core samples, both Kentucky sandstone and Eagleford shale, were subjected to thermal shock using the shortlisted chemical reaction. First, the core samples were heated to a temperature of 150 °C using a Jeio Tech Vacuum Oven (OV-12). After that, the thermochemicals were put in the beaker, and they reacted on the surface of the cores, which suddenly reduces their temperature and provides a thermal shock effect. The cycle was repeated three times by heating the cores again and cooling them suddenly using the chemicals. The effect of thermal shock on the core was determined by performing the scratch test. Ten measurements of the strength were taken over the core length, and the average value of strength were reported. The strength reduction due to thermal shock was then compared to the strength reduction due to heating and natural cooling.

2.5 Thermochemical Injection and Its Effect on Breakdown Pressure

2.5.1 Sample Preparation

The core samples of Kentucky Sandstone and Eagleford Shale were drilled at the center location using a bit of diameter 6 mm to a length of 1.5 in. (half of total length). A steel pipe of 6 mm diameter was placed in the drilled hole up to a length of 1 in. leaving 0.5 in. of open hole. The steel pipe was fixed using high-temperature high-pressure epoxy adhesive to avoid any leakage (Figure 3). The steel pipe on the other side has fitting to connect the injection line for chemical injection and breakdown experiment.

Figure 3 Sample preparation for breakdown pressure measurement.

2.5.2 Thermal Shock with Chemical Injection

The steel pipe placed inside the core samples was connected with a digital pressure transducer and injection line as shown in Figure 4. The core was placed inside a small cell and heated using a heating jacket up to a temperature of 150 °C. The thermochemicals having volume equal to the total connection lines were injected from the injection line, and the pressure valve was closed. These chemicals reach the bottom of the drilled open hole and provide thermal shock. The thermochemicals, upon reaction and getting the surrounding heats, form ammonia gas which generates pressure in the core samples. This pressure was recorded using the pressure transducer with time. The thermal shock cycle was repeated three times by releasing the valve to depressurize the gas and reinjecting the thermochemicals. It should be noted that during this chemical injection process, no extra pressure was applied from the lines. The pressure shown in the transducer reading is only due to the generation of ammonia gas.

Figure 4 Schematic and actual experimental setup for thermochemical injection.

2.5.3 Breakdown Pressure Measurements

The impact of thermal shock on the breakdown pressure was determined by measuring the breakdown pressure of both core samples before and after the chemical injection. The core sample connected with the steel pipe was placed inside a core holder in such a way that the steel pipe comes outside the core holder as shown in Figure 5. The core holder was placed inside the oven at a temperature of 150 °C. The steel pipe was connected with the fluid injection line which was further connected to a syringe pump (Teledyne) from which water was injected to break the core samples. A pressure transducer was connected in the injection line to record real-time pressure values for the determination of the breakdown pressure. As the fluid was injected, the pressure value starts to increase to a maximum peak value at which the core breaks. The pressure values were plotted versus time, and the peak value was noted as the breakdown pressure value.

Figure 5 Experimental setup for breakdown pressure measurement.

3 Result and Discussion

3.1 XRD Analysis

XRD analysis is one of the most widely utilized nondestructive technique that provides mineralogical composition, crystallographic structure, and physical properties of the material.38,39 The XRD results of both Kentucky Sandstone and Eagle Ford Shale are shown in Figure 6. It can be seen in Figure 6a that the major minerals present in Kentucky Sandstone is quartz (61%) followed by albite (23%) and orthoclase (7.5%). Some clay minerals, such as illite (5.1%) and traces of biotite, were also present in the sandstone. The Eagle Ford Shale majorly consisted of calcite (88.6%) followed by quartz (11.4%) (Figure 6b). These results show that the main composition for the shale formation is carbonate. Some previous studies have also found similar results.40

Figure 6 XRD analysis: (a) Kentucky Sandstone; (b) Eagle Ford Shale.

3.2 Selection of Thermochemicals

Thermochemicals can be of exothermic or endothermic nature based on their capability to release or absorb heat upon reactions. Various thermochemicals that react and undergo endothermic reactions are available and can be utilized for thermal shock. These reactions can be spontaneous or triggered by some acid or temperature and have their own kinetics, which need to be studied. In order to provide effective thermal shock, these chemicals should reduce the formation temperature quickly in a very short time and hold the temperature for a longer duration. The potential of decreasing the formation temperature varies with different chemical reactions. Thus, it is necessary to study various reactions and their temperature reduction abilities to utilize them for thermal shock. The four endothermic chemical reactions shown in Table 1 were checked for their feasibility to reduce temperature. The exact concentrations of each reactant are listed in Table 3. The thermochemicals upon reaction reduces the temperature, and their temperature reduction was plotted versus time as shown in Figure 7. It can be observed that reactions A and B show the highest temperature reduction followed by reactions C and D. Reaction A reduces the temperature from 26.4 to 9.7 °C in 52 s and then reaches back to 20 °C after 24 min (1440 s), while reaction B reduces the temperature from 24.3 to 11.8 °C in 58 s and takes 19.5 min (1176 s) to reach back to 20 °C. The Reactions C and D show lesser temperature reduction and for a small duration. From these observations, it can be concluded that reaction A shows the best result. It reduced the temperature by 62.1% and took the longest time (24 min) to reach back to 20 °C, and thus, it is shortlisted for further analysis.

Table 3 Reactant Concentration Used in the Experiment

reaction name	1st reactant	2nd reactant	
A	26.7 g NH4Cl	2 g NaOH in 50 mL (1 M solution)	
B	26.7 g NH4Cl	50 mL H2O	
C	50 mL CH3COOH (1M)	5.3 g Na2CO3 in 50 mL (1 M solution)	
D	50 mL CH3COOH (1M)	4.2 g NaHCO3 in 50 mL (1 M solution)	

Figure 7 Temperature reduction capability of chemical reactions.

The initial concentration of the reactants is also an important factor and can highly influence the temperature reduction capability. Thus, it is important to study the variation in the initial concentration of the reaction on temperature reduction. The concentration of shortlisted reaction A was varied, and the temperature reduction was plotted versus time. The reactants concentration is shown in Table 4, and the resultant temperature reduction profile with time for each case is shown in Figure 8. The reactant concentration was varied in five cases from A-1 to A-5). It can be observed that the best temperature reduction and keeping it for a longer duration are shown in reactions A-2 and A-5. It should be noted that the amount of reactant in reaction A-5 is exactly 2 times that in reaction A-2. Thus, the temperature reduction capability is not only a function of the initial concentration but also the amount of reactant used. Increasing the amount of reactant will take more time for the reaction; hence, the exposure time of thermal shock can be increased. In the field scale, the amount of the reactant will be much higher and could provide an even better thermal shock for a higher duration.

Table 4 Concentration Variation of Reactants in Reaction A

cases	amount of NH4Cl	amount of NaOH	
A-1	26.75 g (0.5 moles)	2 g in 50 mL (1 M solution)	
A-2	26.75 g (0.5 moles)	8 g in 50 mL (4 M solution)	
A-3	26.75 g (0.5 moles)	12 g in 50 mL (6 M solution)	
A-4	53.49 g (1 moles)	8 g in 50 mL (4 M solution)	
A-5	53.49 g (1 moles)	16 g in 100 mL (4 M solution)	

Figure 8 Impact of initial concentration on temperature drop.

3.3 Strength Measurements

3.3.1 Impact of Heating and Natural Cooling

The reservoir rocks upon heating show a substantial difference in their geomechanical properties, especially their strength. The strength of the rock may be defined as the resistance to permanent deformation or stress level that is required to develop a permanent deformation or fracture.33,41 Because of heating, the rock may undergo some mineralogical changes, microcracking, or dehydration due to the removal of crystal bound water causing variation in their strength.42 An increased porosity or permeability in the rock could be observed due to the irreversible structural damage caused by heating.43 While studying the heating and thermal shocking effect on reservoir rocks, it is extremely important to study the effect of heating and natural cooling on the rock sample and compare those results with the thermal shock. Both the core samples were heated and allowed to cool at room temperature. It was found that the rate of heating as well as cooling was higher in sandstone compared to the shale. This is possible due to the difference in their mineralogical composition. It is evident from the XRD results that sandstone is majorly composed of quartz, while shale has a major concentration of calcite in it. Labus et al. (2018) found that the thermal conductivity of quartz mineral is higher compared to calcite.44 The sandstone has thermal conductivity of around 2.50–4.20 Wm–1K–1, while that of calcite is in the range of 1.05–1.45 Wm–1K–1.45 The impact of heating and natural cooling on the strength of core samples was determined by performing the scratch test. Figure 9 shows the scratch test results having a strength profile over the length of core samples. The average strength value of the core samples is shown in Table 5 for both cases before and after heating and natural cooling. It can be seen in Figure 9a that the strength profile of Kentucky sandstone reduces after the heating cycle, and the average strength value reduces from 6079.53 to 5717.42 psi. Similar results were also found for Eagle Ford Shale in which the strength profile was reduced due to the heating cycle (Figure 9b). The average strength value for shale was found to be reduced from 20,590.47 to 19,828.67 psi. The thermal cycle causes strength reductions of around 5.9 and 3.7% for the sandstone and shale rocks, respectively. Previous studies also found similar observations.46,47 One of the possible reason for this trend is the lowering of yield stress due to heating without changing the shape of the stress–strain curve.48 The findings of heating and natural cooling impacts on rocks are crucial and will help in understanding the impact of thermal shock in the rock formations. This will help in the accurate characterization and development of effective engineering strategies in thermal fracturing.

Figure 9 Variation in strength after heating and natural cooling. (a) Kentucky Sandstone; (b) Eagle Ford Shale.

Table 5 Average Strength of Core Samples Before and After Thermal Cycle

S. no.	core	average strength (psi)	% reduction	
pre-treatment	post-treatment	
1	Kentucky Sandstone	6079.53	5717.42	5.95%	
2	Eagle Ford Shale	20,590.47	19,828.67	3.7%	

3.3.2 Impact of Surface Thermal Shock Using Thermochemicals

The strength of rock formations can be reduced through various mechanisms, one of which is generating microfractures at the stimulation location. This can be achieved by providing a thermal shock to the heated formation. In the thermal shock process, the heated reservoir rock is suddenly cooled down due to which the rock shrinks and tensile stresses are developed that reduce the effective stress and can lead to the formation of small cracks.49 The thermal shock fracturing technique relies on the principle of differential thermal expansion and contraction within a rock.50 A sudden reduction in temperature at a particular location also reduces the in situ stresses within the reservoir, resulting in the formation of microfractures.26 Some previous studies have also shown the generation of not only cracks but also the alteration in reservoir rock properties such as porosity, permeability, elastic modulus, and Poisson’s ratio in unconventional rocks by applying thermal shock.51,52 The strength reduction capability of thermal shock provided by the shortlisted reaction (A-5) needs to be investigated for its real application. The core was heated to a temperature of 150 °C before applying thermal shock, and both pre- and post-treatment strength measurements were done on the core samples. Figure 10 shows the strength profile over the core length after the thermal shock and compares it with the impact of the heating and natural cooling cycle. The average value of strength of the core samples for all of the cases is shown in Table 6. It can be observed in Figure 10a that the strength of Kentucky Sandstone decreases significantly after thermal shock. The strength reduced from 6079.54 to 4277.13 psi with four cycles of thermal shock. Compared to the heating and natural cooling cycle which reduced the strength by 5.95%, the thermal shock reduced the strength by almost 29.64%. The Eagle Ford Shale also showed a significant reduction in the strength after the thermal shock cycle. (Figure 10b). The strength reduced from 20,590.47 to 18,225.95 psi after the thermal shock cycle. There is a reduction of around 11% after the thermal shock compared to only 3.7% after heating and natural cooling. This reduction in strength of rock samples after the thermal shock can be due to the generation of small cracks at the exposed surface. The generation of microcracks within rocks is a function of various petrophysical, mechanical, and thermal properties of rock along with the temperature change. The reduction in the strength of the rock sample can be advantageous for a more efficient and easier fracturing job by reducing its fracture initiation pressure.

Figure 10 Variation in strength after thermal shock. (a) Kentucky Sandstone; (b) Eagle Ford Shale.

Table 6 Average Strength of Core Samples before and after Thermal Shock

S. no.	core	average strength (psi)	% reduction	
pre-treatment	post-treatment	
1	Kentucky Sandstone	6080	4277	29.64%	
2	Eagle Ford Shale	20,590	18,226	11.5%	

3.4 Thermochemical Injection and Its Impact on Breakdown Pressure

3.4.1 Thermochemical Injection

The shortlisted thermochemical fluids upon reaction reduce the formation temperature and generate ammonia gas. The generation of ammonia gas increases with the increase in the surrounding temperature. This ammonia gas provides additional pressure to the core samples. Thermochemicals having a volume of 2 mL were injected to the heated core samples for four cycles, and the generated ammonia gas was allowed to pressurize the formation and then released. Figure 11 shows the pressure generation due to liberated gas inside the core samples. The cycles were performed by allowing the core samples to be in the pressurized state for 120 s after every 30 s interval. It can be seen in Figure 11a that the peak pressure during the thermal shock cycle for Kentucky Sandstone was around 49 to 54 psi, while in Eagle Ford Shale, the peak pressure was found to be around 39 to 41 psi (Figure 11b). The variation in peak pressure might be due to the difference in the connecting steel pipe length, which makes minor changes to the volume. The continued pressurizing and depressurizing of the core sample generated a fatigue cycle which aids in the generation of microcracks in the core samples. It is evident from the previous studies that the rock formation experiencing fatigue cycles reduces the breakdown pressure.53−55 The generated cracks will ease the hydraulic fracturing process by acting as nucleation sites.56

Figure 11 Pressure generation due to ammonia gas: (a) Kentucky Sandstone; (b) Eagleford Shale.

Once the thermochemicals are injected, the valves are closed and the pressure is monitored. The generation of ammonia gas due to the chemical reaction causes a rise in pressure inside the core samples and stabilizes at a peak value. It is worth mentioning that with the injection of just 2 mL of thermochemicals, the peak pressures of around 50 and 40 psi were obtained in Kentucky Sandstone and Eagle Ford Shale cores, respectively. The generation of pressure due to ammonia gas was confirmed by performing ion chromatography using a 850 Professional IC equipment by Metrohm. The thermochemicals after injection and generating the pressure were flown back and collected in a container. The returned mixture was then analyzed through ion chromatography by first preparing the sample and measuring its conductivity; after that, the conductivity was adjusted by the given value via dilution with distilled water to <500 μs/cm which is the preferred value to run the samples. For the cation detection, we used the mobile phase, nitric acid. The results are listed in Figure 12. It can be seen in the figure that 460 ppm of ammonia is present in the sample along with 1031.5 ppm of sodium (Na) ion. The presence of sodium is due to the injection of NaOH solution. The generated ammonia gas causes the pressure to rise and influences the breakdown pressure.

Figure 12 Ammonia detection in ion chromatography.

3.4.2 Impact on Breakdown Pressure

The thermochemical injection induces thermal shock inside the heated rock sample. The effect of this thermal shock on the breakdown pressure was evaluated by performing a hydraulic fracturing experiment. The breakdown pressure of the core samples was measured both before and after application of thermal shock. First, for the base case without thermal shock application, distilled water having a pH value of 7 was continuously injected through the steel pipe connection inside the core sample. As the water is injected, the pressure inside the core starts to increase monotonically as shown in Figure 13. The core samples break within a short time with the breakdown pressure values of 2617 and 3472 psi for Kentucky Sandstone and Eagle Ford Shale, respectively (Table 7). The injection pressure dropped to zero after the breakdown because no confining pressure was applied on the core samples. After the base breakdown pressure for both core samples was measured, the impact of thermal shock was evaluated. Thermochemicals were injected to the core samples for four cycles, and the breakdown pressure was again measured in a similar way. It can be seen in Figure 14 that the breakdown pressure has significantly reduced after the application of thermal shock. For Kentucky Sandstone, the breakdown pressure reduces from 2617 to 1228 psi (Figure 13a), while for Eagle Ford Shale, the breakdown pressure reduces from 3472 to 2232 psi (Figure 13b). The thermal shock effect reduces the breakdown pressure of Kentucky Sandstone by almost 53.07%, while for Eagle Ford Shale, it reduces by 34.71%. The possible reasons behind the reduction in breakdown pressure is the contraction of rock upon cooling which leads to an increase in the tensile strength. When this tensile strength exceeds the rock strength, it generates some microcracks that act as propagation sites for the fractures.28,57 By reducing the strength of the rock through these secondary cracks, the need for an intensive hydraulic fracturing job could be lessened, thus saving on operational costs and time.

Figure 13 Breakdown pressure measurement: (a) Kentucky Sandstone; (b) Eagle Ford Shale.

Table 7 Comparison of Breakdown Pressure versus Rock Types

rock type	breakdown pressure	percentage reduction	
pre-treatment (psi)	post-treatment (psi)	
Kentucky Sandstone	2617	1228	53.07%	
Eagleford Shale	3472	2232	34.71%	

Figure 14 Fracture generation after breakdown: (a) Kentucky Sandstone; (b) Eagle Ford Shale.

It is worth mentioning that there is difference in the fracture propagation between the Kentucky Sandstone and Eagle Ford Shale which is evident both physically in the samples and in the pressure profiles. The difference provides insights into the mechanical properties and fracture behavior in these rock types, which is very important for hydraulic fracturing application. Eagle Ford Shale breaks immediately with complete fracture propagation along the sample, breaking it into two parts, while the fracture generated in Kentucky Sandstone does not propagate completely but moves in one direction making a small crack on the core body (Figure 14). This can also be seen in the pressure profiles; the Eagle Ford Shale immediately reaches zero pressure after breakdown, while the Kentucky Sandstone takes few seconds until the fracture reaches the surface of the core. The possible reason for this behavior is the more brittle nature of shale rock in which the rock lacks the ability to absorb energy by deforming. This results in a sudden drop to zero pressure post fracture, indicating a rapid release of all stresses accumulated within the rock.58 On the other hand, sandstone shows little ductile behavior in which some energy is absorbed in deformation. Understanding these behaviors is vital for predicting and managing fracture propagation in unconventional formations. This knowledge helps in choosing appropriate fracturing techniques tailored to the specific geological conditions of the target formation.

4 Conclusions

Unconventional hydrocarbon reservoirs can pose operational challenges during fracturing jobs. The breakdown pressure in these reservoirs may exceed the equipment’s rating without generating any fractures in the formation. The current study explored a novel way to reduce the breakdown pressure of the rock and to make a more efficient fracturing job. The use of endothermic thermochemicals for providing a thermal shock was investigated, and the reaction between NH4Cl and NaOH was found to be the most significant in providing thermal shock for a longer duration. The core samples were initially heated and allowed to cool naturally and tested for reduction in their strength due to the heating effect. The strength of Kentucky Sandstone was reduced by 5.95%, while the strength of Eagle Ford Shale was reduced by 3.7%. By inducing thermal shock in the core samples of Kentucky Sandstone and Eagle Ford Shale, the results show a promising decrease in strength and breakdown pressure. It was found that the breakdown pressure of Kentucky Sandstone was reduced by 53.07%, while for Eagle Ford Shale, it was reduced by 34.71%. This approach is particularly beneficial for high-temperature reservoirs, where traditional fracturing methods are less effective due to the higher required pressures. The generation of ammonia gas from the thermochemical reaction further contributed to the breakdown pressure reduction. The findings suggest that this technique could be adapted for broader applications across different geological formations, promising an enhanced efficiency in hydraulic fracturing operations.

Author Contributions

F.K.: Conceptualization, methodology, investigation, writing original draft, and editing. M.M.: Conceptualization, supervision, validation, and writing - review and editing. A.R.: Conceptualization, supervision, and writing - review and editing. M.J.A.: Conceptualization, supervision, and writing - review and editing. S.P.: Supervision and writing - review and editing. M.M.: Investigation and writing - review and editing. M.S.K.: Supervision and writing - review and editing.

The authors declare no competing financial interest.

Acknowledgments

The authors are thankful and acknowledge the King Fahd University of Petroleum and Minerals, Dhahran, Saudi Arabia, for providing the research facilities and funding for this research through CPG start-up fund # Sf24002.
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