Current oil prices and global financial situations underline the need for the best engineering practices to recover remaining oil from unconventional hydrocarbon reservoirs. These hydrocarbon reservoirs are mostly situated in deep and overpressured formations, with high rock strength and integrity. Breakdown pressure of the rock is a function of their tensile strength and in situ stresses acting on them. Fracturing stimulation techniques become challenging when treating these types of rocks, and many cases approached to the operational limits. This leaves a small operational window to initiate and place hydraulic fractures. In this study, a new methodology to reduce the breakdown pressure of the high stressed rock is presented. The new method enables the fracturing of high stressed rocks more economically and efficiently. Fracturing experiments were carried out on different blocks, and the breakdown pressure was measured by creating a simulated borehole at the center of the block. Thermochemical fluids were injected to create the microfractures. These microfractures improved the permeability and porosity and reduced the elastic strength of the subjected samples prior to the main hydraulic fracturing job. The posttreatment experimental analysis confirmed the presence of microfractures which were originated due to the pressure pulse generated from the thermochemical reaction. The results of this study showed that the newly formulated method of thermochemical fracturing reduced the breakdown pressure by 38% in slim borehole blocks and 60% in large borehole blocks. Results also showed that the breakdown time to initiate the fractures was reduced to 19% in slim borehole blocks and 17% in large borehole blocks. The reduction in breakdown pressure and breakdown time happened due to the creation of microfractures by the pressure rise phenomenon in a new thermochemical fracturing approach.

1. Introduction

The paradigm shift from the conventional resources to the unconventional resources is the consequence of a global increase in energy utilization. Conventional resources can be defined as those formations where the recovery of hydrocarbons is possible without any stimulation method. Unconventional resources can be defined as those formations in which hydrocarbon recovery is not economically possible without the implementation of specialized stimulation treatments such as matrix acidizing or fracturing. Therefore, the recovery of hydrocarbons from the unconventional resources in an attractive economic proportion requires state-of-the-art well stimulation and completion technologies. Unconventional resources such as the shale gas, tight sands, heavy oil, and tar sands are some of the examples of formations that need stimulation for economical production [19].

Oil and gas stored in unconventional reservoirs need extensive fracturing treatments to produce commercially viable hydrocarbons. One way to produce from these reservoirs is by drilling a horizontal well and by conducting multistage fracturing to increase stimulated reservoir volume (SRV), but this method of increasing SRV involves high costs of equipment, material, and operations [7]. The present expensive multistage hydraulic fracturing treatment is working, but there is always a quest for the cost-effective stimulation treatment. Waterless fracturing is an embryonic and cost-effective technology that reduces the fracturing fluid remains within the generated fractures and the damaging water-phase trapping within the rock matrix. Both damage mechanisms are linked with the conventional water-based fracturing treatment of tight sands. To overcome operational and technical challenges involved in a conventional water-based hydraulic fracturing, the alternative way to increase SRV is by creating synthetic sweet spots or multiple radial fractures by performing pulse fracturing. Pulse fracturing is a relatively new stimulation technique in which a dynamic release of fluid energy pressurizes a wellbore to initiate multiple fractures and extend them by injecting a fluid pressurization rate. Pulse fracturing can be achieved by many ways such as explosive shooting and dynamic loading and by high energized gases. The pulse fracturing treatment depends on many parameters such as rock strength, in situ stresses, pressurization rate, and technology in hand. Pulse fracturing is commonly known with other names such as dynamic fracturing, propellant gas fracturing, tailored pulse loading, dynamic impact loading fracturing, high energized gas fracturing (HEGF), and multiple radial stress fracturing [1020]. In HEGF, the downhole combustion is initiated by both oxidizer and fuel to generate the sudden expansion of gas to quickly raise the pressure which results in synthetic sweet spot.

Pulse fracturing treatment can be applied as a stand-alone technique or can be combined with the conventional hydraulic fracturing treatments, and in many cases, the combination is more attractive than the only conventional hydraulic fracturing operation. Some of the examples include but are not limited to water availability on the wellsite [21, 22], connecting preexisting fractures with induced fractures in naturally fractured carbonate reservoirs [2326], stimulating heavy oil reservoirs [27, 28], removing condensate banking near the region of the wellbore [29], and reducing formation damage near the vicinity of the wellbore [30]. A comprehensive review of the pulse fracturing technique and its field implementation can be found in our previous publication [31].

2. Literature Review

Since the last four decades, oil and gas industries have witnessed fracturing with the explosive material to enhance the production from petroleum-bearing rocks. The successful application of pulse fracturing can be found in both oil and gas wells located in both onshore and offshore fields [27, 30, 32]. The reservoir types range from conventional naturally fractured carbonate reservoirs to tight gas sands and shales [17]. In early days of explosive fracturing, wells were stimulated with nitroglycerin shaped charged materials. Few experiments were conducted by Soviet and United States governments in the 1960’s to investigate the success of explosive fracturing. Smith et al. [10] conducted a chemical explosion-based field experiment at 425 meters down the surface of the earth on the ash fall tuff. The results showed that fractures were created in the formation in the range beyond the compressive stress region and the orientation of the fracture was controlled by the in situ stresses of the earth. Cuderman [16] carried out a series of explosive tests in the Nevada test site. To control the pressurization rate, he performed tests with the mixture of propellants in a liquid-filled wellbore. Through his experiments, he found that multiple fractures are a function of the pressurization rate, wellbore diameter, and wellbore fluid.

Cuderman and Northrop [17] developed a propellant-based approach to create multiple fractures in a naturally fractured Devonian shale gas reservoir. Their objective was to increase the production from the Devonian shale reservoir by connecting nonintersecting faults in the reservoir with the wellbore. To achieve their objective, they carried out several field experiments using different propellant materials with different burning characteristics.

Zeigler et al. [15] investigated the optimal use of propellant materials by conducting several experiments. To achieve their purpose, they have compared three experimental approaches, namely, single burn, multiple burn, and pulse tailoring approach. All of these experiments were conducted on a ‐inch solid block made up of gypsum-based cement. They have found that the pulse tailoring fracturing technique was the most efficient one in terms of increasing stimulated reservoir volume.

Yang and Risnes [11] carried out an impact test using a dynamic compression testing machine. They performed experiments by free falling weight on the piston. The main objective of their study was to investigate the critical pressurization rate above which multiple fractures were generated. They carried out the experiments on cylindrical core samples of different rocks.

Page and Miskimins [33] compared the performances of hydraulic fracturing and propellant gas fracturing on a Mancos shale sample. They carried out laboratory experiments and field trials. Laboratory experiments were conducted on ‐inch blocks of the Mancos shale sample. From their experiments and field tests, they have concluded that both techniques can be valid if properly applied for a given set of conditions.

Malhotra et al. [20] experimentally investigated the crack growth and pattern of multiple fractures with the new explosive material used in a propellant-based technology. They compared their results with the previously published results by Wieland et al. [34]. They carried out laboratory experiments on a large block of sandstone with a borehole diameter of 2 inches. Through their experiments, they have shown that the new propellant used has a much higher burn rate than the propellant used by Wieland et al. [34].

Based on the literature survey, most of the previous methods used to create sweet spots involved explosive materials which may be dangerously ignitable at the surface if not handled properly. In addition, these materials can damage the downhole equipment. To prevent the damage to the downhole equipment while creating the synthetic sweet spot, a novel and more controlled fracturing treatment with thermochemical is introduced in this study. The proposed study provides simple solution to reduce breakdown pressure by creating microfractures which can be served as synthetic sweet spot.

Thermochemical reaction is an exothermic reaction which produces heat and pressure during the experiment. It gives net energy to its surroundings, as the energy needed to initiate the reaction is less than the energy released. It can be expressed in a chemical equation as

Application of thermochemical is widely found in petroleum engineering applications. Recently, Mahmoud [35] used thermochemical to remove a filter cake and provide experimental evidences to clean up the oil and gas wells after drilling operations. Hassan et al. [36] presented a new technique to remove condensate banking by using thermochemical. They have found that thermochemical reduces the viscosity of the condensate because of the in situ generation of heat and high-pressure gases. Wang et al. [37] carried out core-flooding experiments to investigate the increase in oil recovery in the enhance oil recovery (EOR) phase of the reservoir. They generated in situ heat foams by mixing thermochemical and surfactant. The heat foams were generated as a result of nitrogen gas liberation from thermochemical experiments. Through their experiments, they have found that thermochemical-based technology increased the oil recovery by 33.9% in homogenous rocks and 20.4% in heterogeneous rocks. Mustafa et al. [38] carried out core-flooding experiments on the Scioto and Berea sandstones with thermochemical. The objective of their experiments was to observe the effect of thermochemical on rock mechanical properties. Through their experiments, they have found that thermochemical reduces the rock strength significantly which reduces the pumping pressure in a typical hydraulic fracturing job. Al-Nakhli et al. [39] experimentally investigate the increase in production from heavy oil due to in situ generation of steam by applying new thermochemical technology. Al-Nakhli et al. [4042] also investigated the effect of thermochemical on different rock samples. The objective of their work was to investigate the enlargement of SRV due to thermochemical. They successfully carried out laboratory experiments on shale, Indiana limestone, Berea sandstone, and cement samples. Singh et al. [43] presented a unique study of using a chemically induced thermochemical system to remove organic deposits around the vicinity of the wellbore and production tubing of the wells located in the brown fields. They successfully implemented this technology in twenty-three wells and observed that average production increased by 100%. Amin et al. [44] also carried out a similar study to remove organic deposits in a brown field using thermochemical.

This research work intended to develop a novel pulse fracturing technique using thermochemical to increase stimulated reservoir volume (SRV) around the region of the wellbore and fractured area. The study shows the results of laboratory experiments on different blocks of cement samples having artificial miniholes to inject chemical reactants. Multiple experiments were performed on different block samples with different borehole diameters, and breakdown pressures were measured with and without thermochemical treatments. To avoid the effect of rock heterogeneity and to see the effect of thermochemical on reducing the breakdown pressure, all the experiments in this study were carried out on homogeneous cement samples.

3. Materials and Experimental Methods

3.1. Sample Preparation

Different rectangular cement blocks with a cement and sand ratio of one to two were casted. The blocks were 4-inch cubes. The cement and sand were mixed in the specified proportion and stirred until the homogenous mixture was obtained. Then, the dedicated amount of water was added to the cement mortar slurry. The mixing water and cement ratio was one to two. Cube mortar specimens with edge length of 101.6 mm were prepared by using the standard metallic cube molds, as shown in Figure 1(a). After 24 hours, all specimens were removed from the metallic mold and submerged in the water-filled chamber at a constant ambient condition up till the age of 14 days. After 14 days, all samples were ready for the testing. Figure 1(b) shows a part of the samples after curing of 14 days. The average chemical composition of the prepared cement samples is given in Table 1 which was determined by the X-ray fluorescence (XRF) technique.

3.2. Petrophysical Measurement

Routine core analysis (SCAL) was carried out on the prepared cement samples. Porosity and permeability for each sample were measured. The average porosity and permeability of the cement samples were 17.3% and 0.20 md, respectively. The approximate density of the samples was 3.1 g/cc.

3.3. Scratch Test Analysis

The scratch test machine was used for generating continuous profile of strength over the entire length of the core sample by scratching several successive grooves with varying depths of cuts on the surface of a material sample using a cutter. Ultrasonic (P- and S-waves) velocities were also measured from the scratch test using the sonic mode of the scratch test machine. To perform the scratch test, cylindrical cement samples of 4-inch length and 1.5-inch diameter were prepared using the same procedure given in Section 3.1. A brittle mode of destruction was avoided while trying to estimate the rock strength. The ductile mode takes place at a shallow depth of cut and is associated with plastic flow, while the brittle mode occurs above a threshold depth of cut and is characterized by the propagation of tensile crack. In the ductile mode, experiments with a sharp cutter show that the energy required to remove a unit volume of rock, referred to as the intrinsic specific energy , is well correlated with the uniaxial compressive strength [45, 46]. The width of the cutter used was 10 mm. The rake angle set throughout the experiment was 15 degrees. The rake angle is the inclination of the cutter with respect to the vertical. Figure 2 shows the view of the scratch test machine used in this study.

The principle of the scratch test is to control and monitor the continuous shearing action induced by the motion of a diamond (PDC) cutting tool on the surface of a rock core sample [47, 48]. The continuous high-resolution profile of rock strength (UCS) along the core sample is derived from the force acting on the cutter. The tests were performed under specific kinematic controls (cross-sectional area of the groove and cutting velocity) that remain constant along the cut. The output of the test is the log of the magnitude and inclination of the force (or two force components) acting on the cutter during the test. The magnitude of the force is controlled by the mechanical properties of the rock, the geometry of the cut, and the geometrical characteristic of the cutter. The forces obtained from the scratch tests are correlated with unconfined compressive strength of the rock as given by where is the horizontal component of the cutting force which is a mean value over few cms of groove length, is the intrinsic specific energy, and is the cross-sectional area. The intrinsic specific energy can be defined as the energy required to destroy a unit volume of rock. The word intrinsic emphasizes that this energy is strictly used to cut the rock. A strong correlation between intrinsic specific energy and uniaxial compressive strength for various rocks is well established [48, 49].

Figure 3(a) shows the grove created on the studied cement sample, and Figure 3(b) shows the continuous profile of compressive strength obtained from the scratch test over the entire scratch length. The average compressive strength was found to be 8702.26 psia (60 MPa). The average value of compressional (P-) wave velocity and shear (S-) wave velocities was found to be 4035 m/s and 2175 m/s, respectively. Dynamic Young’s modulus and dynamic Poisson’s ratio were determined by using where is the bulk density in g/cc, is the compressional wave velocity in km/s, and is the shear wave velocity in km/s. Dynamic Young’s modulus was found to 34.13 GPa, and dynamic Poisson’s ratio was 0.29.

3.4. Unconfined Compressive Strength

The unconfined compressive strength (UCS) test was carried out on the cement sample according to the ASTM [50] and the ISRM [51] standards. UCS is the rock strength measured when uniaxial loading is applied. Under the condition of unconfinement, UCS is the peak axial compressive stress that a material can endure [52]. From the experiment, the value of UCS found was 6558 psia (Figure 4). Table 2 summarizes all the mechanical and petrophysical parameters of the cement sample used in thermochemical and base case fracturing experiments.

3.5. Experimental Procedure

Figure 5 shows a schematic diagram of the breakdown pressure setup employed in this study. Two piston transfer cells with the capacity of 1 liter each were used to accumulate the fracturing fluid and thermochemical. The core holder was installed inside an electric oven to control the temperature. An ISCO syringe pump was used to displace the thermochemical and fracturing fluid from the piston accumulators to the core holder. Multiple HPHT (high pressure high temperature) valves were installed at the inlet and outlet of the accumulators to control the fluid switching during the injection process. A high frequency pressure transducer was installed to record the continuous injection pressure, and the results were sent through a data acquisition system to the computer operating software.

Before performing the experiments, it was made sure that (1)there was no air trapped in the system, and the fracturing fluid filled the piston accumulators and all the connected steel tubing(2)there was no leak in the system. All steel tubing and piston accumulators were tested by monitoring the pressure decline after pressurizing initially to 1500 psi. If any leak was observed, the corresponding steel tubing or valves were fixed

A synthetic borehole was created at the center of each block which represents the wellbore. In each case, two blocks with different borehole diameters of size 1/4 and 3/8 inches were tested. The depth of the borehole was 5/2 inches which remains constant for all the blocks tested. The borehole was created using a heavy duty drill press. The drill bit used for this purpose was a concrete drill bit. The steel tubing was then inserted inside the borehole of the block and glued with HPHT-resistant epoxy. An open hole section of 1/2 inch between the depth of the borehole and steel tubing was left for the fracturing fluid to make contact with the cementspecimen. The block was then left for twenty-four hours to ensure proper settling of epoxy. Figure 6 shows the view of cement block with steel tubing inserted and fixed with HPHT epoxy.

Once the steel tubing was properly attached with the cement block using epoxy, the block was placed inside the electric oven and connected with the flow lines. For the base case experiments on the blocks with 1/4- and 3/8-inch borehole diameters, distilled water was used as a fracturing fluid, and injection was done at the ambient temperature. For the thermochemical fracturing experiments, two experiments were performed. The first experiment was done on the block with 1/4-inch borehole diameter, and the second experiment was done on the block with 3/8-inch hole diameter. Both experiments were carried out at the reaction triggering temperature of 80°C. The samples were left inside the oven for a few hours in order to ensure that the sample temperature reached exactly the oven set temperature. After that fracturing, fluid was pumped at the constant flow rate of 5 ml/min. The injection pressure was continuously logged until the specimen breakdown happens. To remove the effect of long flow lines (dead volume), all the experiments were carried out at initial pressure of approximately 100 psia.

Different injection rates from 3 ml/min to 25 ml/min were used for injecting fracturing fluid to fracture the cement samples. The breakdown pressure increased with the increase of the injection flow rate as shown in Figure 7. Similar results were also reported by many researchers such as Farid Ibrahim and Nasr-El-Din [53], Haimson and Zhao [54], Ito [55], Schwartzkopff et al. [56], and Zhuang et al. [57]. Finally, a flow rate of 5 ml/min was selected because it gives the breakdown pressure of 1359 psia which is closer to the tensile strength value of 1300 psia measured from the standard dog bone test, also given in Table 2.

3.6. Thermochemical Preparation

The chemical reaction of thermochemical can be described by the following equation: where ΔH is the heat generated from the reaction. The reaction needs high temperature to trigger; the reaction time is a strong function of the initial temperature. This reaction at one to one molar ratio generated an additional temperature of 90°C, and reaction at two to two molar ratio generated additional temperature of 115°C. Different initial temperatures were used from 50 to 100°C; these temperatures represent the downhole reservoir temperatures as shown in Figure 8.

The resulted nitrogen from the reaction creates a pressure pulse; this pulse is a function of the thermochemical concentration. A cell with a 20 cm3 volume was used to determine the pressure pulse level that can be generated by the thermochemicals. Heating was used to trigger the reaction; the cell was heated up to 100°C, and the reaction described by the latter equation was triggered. Figure 9 shows the results of the generated pressure pulse as a function of reactant concentrations (NH4Cl and NaNO2). The initial pressure of the cell was 1000 psi, and the generated pressure was recorded versus time. Figure 7 shows that the pressure pulse was generated few seconds after the reaction starts (at 100°C). In the case of 2 : 2 molar concentration of the reactants, the pressure pulse reached 5550 psi with an additional pressure of 4550 psi due to the reaction. This pulse was due to the generation of the nitrogen gas. This pressure pulse will decline due to the fluid conversion to hot water and gas; also, the nitrogen gas will dissolve in the reaction product, and the pressure pulse will decline. The pressure pulse was generated a few seconds after the reaction; in the rock, this pulse will create microfractures, and this will reduce the breakdown pressure required during the hydraulic fracturing operations. The pressure pulse resulted in the case of 1 : 1 molar concentration was 3500 psi which is 2000 psi less than that generated in the 2 : 2 molar concentration case. This is due to the less nitrogen generated compared to the high concentration case.

A one to one solution was prepared by mixing two thermochemical reagents, ammonium chloride (NH4Cl) and sodium nitrite (NaNO2), at ambient conditions. The solution was then used as a fracturing fluid.

4. Results and Discussions

4.1. Fracturing with Distilled Water

Two base case experiments were carried out on the block samples with the hole diameter of 1/4 inch and 3/8 inch, respectively. Distilled water with a pH of 7 was used as a fracturing fluid in both experiments. A constant flow rate of 5 ml/min with no confining pressure was set throughout these base case experiments. Figure 10 shows the continuous profiles of pumping pressures and injection rates with the corresponding time for the two base case experiments. The profiles are shown until the cement specimens were broke down and fractured. The breakdown pressure for the case of the cement sample with 1/4-inch hole diameter was observed to be 1359 psia. For the case of the cement sample with a larger borehole diameter of 3/8 inch, the breakdown pressure observed was 1157 psia. Due to the increase in hole diameter, the breakdown pressure was reduced from 1359 psia to 1157 psia, an approximate reduction of 15% in breakdown pressure. Figure 11 shows the fracture pattern for two cement specimens after fracturing with the distilled water.

4.2. Fracturing with Thermochemical

Two thermochemical fracturing experiments were carried out on the blocks with a borehole diameter of 1/4 inch and 3/8 inch, respectively. Both experiments were performed at an initial temperature of 80°C. A constant flow rate of 5 ml/min with no confining pressure was maintained throughout the experiments. Figure 12 shows the continuous profiles of pumping pressures and injection rates with the corresponding time for the two thermochemical fracturing experiments. The breakdown pressure for the case of cement block with 1/4-inch borehole diameter treated with thermochemical was observed to be 835 psia, and for the case of the cement sample with a larger borehole diameter of 3/8 inch, the breakdown pressure observed was 457 psia. The breakdown pressure with thermochemical fracturing was reduced by 38.5% in the block sample with 1/4 inch, and for 3/8-inch borehole diameter, the reduction was observed to be 60.5%. Table 3 summarizes the breakdown pressure observed in all four experiments.

Figure 13 shows the fracture pattern of the two cement block samples after fracturing with thermochemical (Figure 13(a) 1/4-inch borehole diameter and Figure 13(b) 3/8-inch borehole diameter). The fractures created with thermochemical were more dominant and had an etched surface compared to the fractures generated with distilled water (Figure 11).

Figure 14 clearly shows the presence of microfractures around the reaction area of one of the cement blocks due to thermochemical injection. These microfractures were generated as a result of sudden release of nitrogen gas and high heat from the reaction. These microfractures can be served as synthetic sweet spots in the reservoir. The creation of these microfractures was also responsible for weakening the specimen strength which ultimately leads to the reduction of the breakdown pressure.

Figure 15 shows the comparison of injection pressure profiles for all the cases studied. Table 3 shows the summary of the breakdown time needed to fracture the sample with distilled water and thermochemical. From the analysis of Figure 15 and Table 3, it was found that due to the thermochemical treatment, the breakdown time on the cement sample with 1/4-inch borehole diameter was reduced to 19.3%, and for the sample with 3/8-inch borehole diameter, the breakdown time was reduced by 17.3%.

Figure 16 shows the comparison of continuous scratch strength of the cement sample before and after thermochemical fracturing treatment. Continuous scratch strength clearly shows the reduction in the strength of the subjected cement specimen after thermochemical fracturing. Regions with very low strength show the presence of microfractures.

Table 4 shows the values of P-wave velocity, S-wave velocity, dynamic Poisson’s ratio, and dynamic Young’s modulus of the cement sample before and after thermochemical fracturing. The posttreatment results indicated the decrease in P- and S-wave velocities for the cement sample due to the generation of microfractures. The measured P- and S-wave velocities were 4035 m/s and 2175, respectively, which were reduced to 3000 m/s and 1800 m/s after thermochemical treatment. The stiffness of the rock samples was decreased substantially after the treatment as exhibited by elastic parameters (dynamic Poisson’s ratio and dynamic Young’s modulus). The remarkable variation has been observed in mechanical parameters in terms of decrease in Young’s modulus by 35% and Poisson’s ratio by 26%.

The microfractures created due to the thermochemical treatment resulted in the development of the synthetic sweet spots. These sweet spots were created due to high pressure and high temperature obtained from exothermic reaction caused by thermochemical. A sweet spot is generally defined as the area within a reservoir that represents the best production or potential for production which has high permeability or high-pressure zone that acts as a conductive channel and depletes the surrounding rock in a tight formation. If this reaction is initiated downhole in a wellbore, the generated pressure will develop kinetic energy leading to tensile fracturing and the generated heat will develop thermal energy leading to thermal fracturing. So, a sweet spot will be created near the wellbore or the fracture, and the drainage area will be significantly increased. To implement this concept in the field, the reactants are injected and mixed together downhole to initiate the reaction. This reaction is usually activated downhole due to the increase in the temperature, which gives the proper conditions for the reaction to take place. Also, the reaction can be triggered by buffering the reactants (pH control) by adding acid to reduce the pH to 4; acids such as acetic, citric, or formic can be used.

4.3. Effect of Overburden Pressure

Effect of overburden pressure on breakdown pressure was studied on cement core plugs instead of cement blocks due to the limitation of the experimental apparatus. The dimensions of the core plugs were 2-inch length and 2-inch diameter. These cement plugs were drilled from the sister rectangular cement cube blocks of the same composition given in Table 1. Fracturing experiments on cement plugs were carried out with water and thermochemical. With the increase of the overburden pressure, the breakdown pressure increases both with water and thermochemical. Similar results were also observed by Gomaa et al. [58] on Mancos shale when water was used as a fracturing fluid. Figure 17 shows the breakdown pressures at unconfined condition, 500 psi overburden pressure, and 1000 psi overburden pressures. For the sake of comparison, at unconfined conditions, the results of fracturing experiments on cement blocks are shown here while at the overburden conditions, the results on the cement plugs are plotted. At 500 psi overburden pressure, the breakdown pressure with water was 1515 psia while the breakdown pressure with thermochemical was 980 psia; 35% decrement in breakdown pressure is observed. At 1000 psi overburden pressure, the breakdown pressure with water was 1659 psia while the breakdown pressure with thermochemical was 1150 psia; 30% decrement in breakdown pressure happened.

5. Conclusions

The success of hydraulic fracturing depends on a better understanding of the exact pressure-time response. This study will guide production engineers to design and execute hydraulic fracturing treatment in an efficient way. Based on the conducted analysis and the discussion presented in this study, the following conclusions can be drawn: (1)Thermochemical injection results in the generation of synthetic sweet spots by creating multiple microfractures around the region of the wellbore(2)The generated microfractures result in the reduction of breakdown pressure. From the thermochemical experiments, it was found that the breakdown pressure was reduced to 38% and 60%, respectively(3)The new fracturing technique helps in reducing the pumping capacity to fracture the high strength formation. In some cases, the rock strength is too high that even after reaching the maximum pumping capacity, the formation does not fracture(4)The new fracturing technique also resulted in the reduction of breakdown time by 19.3% and 17.3%, respectively. The reduction in breakdown time reduces the volume of fracturing fluid injected and ultimately decreases the cost of overall hydraulic fracturing operation(5)The efficiency of thermochemical was not affected by the overburden pressures. A significant reduction in breakdown pressures was observed under overburden pressure experiments(6)Small cell experiment confirmed the generation of nitrogen gas by the rise of pressure pulse to 5500 psi in two molar concentrated thermochemical fluid and to 3500 psi in one molar concentrated thermochemical fluid(7)The microfractures created can also help in increasing the conductivity between the well and reservoir, ultimately increasing the production by many folds(8)The etched surface created in the fractures can also help the fractures to remain open which reduces the amount of proppant injection(9)The new fracturing technique formulation is safe to handle at the surface with no risk for corrosion because the reaction and the high pressure and temperature will take place only at the formation face(10)The reactive reagents are compatible with the formation and can be triggered with reservoir thermal energy or reduction in pH


CT:Computed tomography
:Young’s modulus (GPa)
:Dynamic Young’s modulus (GPa)
EDS:Energy dispersive X-ray spectroscopy
EOR:Enhanced oil recovery
FEM:Finite element method
HEGF:High energized gas fracturing
HPHT:High pressure high temperature
NMR:Nuclear magnetic resonance
P-:Compressional wave
PDC:Polydiamond crystalline
PR:Poisson’s ratio
S-:Shear wave
SRV:Stimulated reservoir volume
:Compressional wave velocity (km/s)
:Shear wave velocity (km/s).

Data Availability

All the data used are disclosed in the paper.

Conflicts of Interest

The authors declare that they do not have any conflict of interest.


The College of Petroleum and Geoscience, at King Fahd University of Petroleum & Minerals, and Saudi Aramco are acknowledged for the support and permission to publish this work. Saudi Aramco is also acknowledged for funding this research under project number CIPR2316. The authors would also like to acknowledge Mr. Mobeen Murtaza for helping in experimental setup arrangements.