Deep Oil Reservoirs Research Articles

Research on Calcium Chloride Weighted Polymer Fracturing Fluid for Ultra Deep and High Stress Reservoirs

To enhance fracture and conversion effects in deep and ultra-deep oil and gas reservoirs, a low-cost polymer-weighted fracturing fluid technique was developed using industrial calcium chloride as a weighting agent and synthesizing a polyacrylamide polymer, FA-31, with a molecular weight of 4-6 million, as a thickening agent. In addition, we have developed an amphoteric metal crosslinker capable of forming multiple hydroxyl bridges with crosslinked groups, a novel XG160 high-efficiency gel breaker, and a complete set of stress corrosion inhibitors. The optimal concentration for the use of calcium chloride dihydrate is 46% and the density of aqueous solution is 1.35 g/cm3. The developed highly salt-resistant polymer dissolves rapidly in a high-density calcium chloride salt solution. The industrial calcium chloride gel formed by polymer has a maximum temperature resistance of 170 °C, a shear rate of 170 s-1 for 120 min, and a viscosity of more than 100 mPa·s. It also performs well in high-temperature suspension sand conditions. The viscosity of the gel breaker is less than 5 mPa·s. Laboratory tests have shown a core damage rate of about 20% and no stress corrosion cracking. The on-site application of liquid preparation and construction has been smooth, achieving the desired effect of reducing construction pressure. For example, when refurbishing a 7500 m reservoir, the building pressure can be reduced by 10-20 MPa. On-site testing of calcium chloride-weighted frac fluids has confirmed their effectiveness as a cost-effective alternative to conventional weighted frac fluids, providing a viable solution for the conversion of deep, ultra-deep, high-stress oil and gas reservoirs.

Occurrence of deep liquid oil reservoirs in the Sichuan and Tarim basins as constrained by geological evidences and molecular simulation

The hydrocarbon phase state of deep to ultra-deep reservoirs in the Tarim and Sichuan basins has been of great interest in oil and gas exploration. Based on a combination of molecular dynamics simulation, gold-tube pyrolysis experiments, and geological-geochemical theory, this study discusses the mechanisms governing the stability of oils in deep reservoirs from the perspectives of their reservoir accumulation histories and chemical reactions. Generally, the reason for the existence of liquid oil in the Tarim Basin is widely considered to be only controlled by external geological conditions, mainly including low geothermal gradient, absence of thermal events, low maximum reservoir temperatures, and late hydrocarbon generation process. However, this study firstly proposed that the chemical composition of oil is an internal factor for its thermal stability. The simulation results reveal that the polycondensation reactions of asphaltene will release hydrogen atoms, which can provide a necessary hydrogen source for cracking of liquid chain hydrocarbons. It means that the presence of asphaltene components can promote the cracking of chain hydrocarbons and generate methane. The normal mature oil in the Sichuan Basin generally has higher contents of asphaltenes than that of the high-mature light oil of the Tarim Basin, so more hydrogen has historically been available for the cracking of oil to gas. By looking at the accumulation histories and chemical compositions of the crude oils, this study first explains the stable long-term storage of liquid hydrocarbons in the Tarim Basin, providing important guidance for future deep to ultra-deep oil and gas exploration.

Development and Gelation Mechanism of Ultra-High-Temperature-Resistant Polymer Gel.

To expand the applicability of gel fracturing fluids in ultra-high-temperature reservoirs, a temperature-resistant polymer was synthesized using the solution polymerization method. Subsequently, an ultra-high-temperature-resistant polymer gel was formulated by incorporating an organic zirconium crosslinking agent. A comprehensive investigation was carried out to systematically study and evaluate the steady shear property, dynamic viscoelasticity, and temperature and shear resistance performance, as well as the core damage characteristics of the polymer gel. The obtained results demonstrate that the viscosity remained at 147 mPa·s at a temperature of 200 °C with a shear rate of 170 s-1. Compared with the significant 30.9% average core damage rate observed in the guanidine gum fracturing fluid, the core damage attributed to the polymer gel was substantially mitigated, measuring only 16.6%. Finally, the gelation mechanism of the polymer gel was scrutinized in conjunction with microscopic morphology analysis. We expect that this study will not only contribute to the effective development of deep and ultradeep oil and gas reservoirs but also furnish a theoretical foundation for practical field applications.

Characteristics and genetic mechanisms of fault-controlled ultra-deep carbonate reservoirs: A case study of Ordovician reservoirs in the Tabei paleo-uplift, Tarim Basin, western China

To reveal the effect of faults in the deep and ultra-deep oil and gas reservoirs, based on the comprehensive analysis of drilling logs and the core and seismic data, the development and fault-controlled regularity of the reservoirs in the high and low inner part of the Ordovician carbonate of the Tabei paleo-uplift have been discussed. The results show that large fracture-cave reservoirs are developed in the Tabei paleo-uplift, and as main reservoir, the cave-type reservoirs usually appeared as lumps or patches in the north of the pinch-out line of O3s, and gradually transitioned to isolated dots to the south. Due to the difference in control effect of faults, the degree of reservoir development differs greatly from north to south. The effective reservoir thicknesses are relatively stable and the porosity are relatively high in north, which are mainly controlled by karst and fractures, and the effect of faults on reservoir is not obvious. To the south, the reservoirs are gradually banded along the fault, and the control effect of large strike-slip faults are enhanced. This indicates that the strike-slip faults are more important to the development of reservoir in the low inner part. This difference is caused by the differences in fault controlling factors during different evolution periods of the paleo-uplift.

Molecular Insight into the Occurrence Characteristics of Deep Oil with Associated Gas Methane and the Displacement Resistance in Water Flooding in Nano-Pore Throat

In deep oil reservoirs, the existence of associated gas generally has a crucial impact on crude oil properties and flow performance. In this work, adopting molecular dynamic simulation, we studied the occurrence characteristics of oil with associate gas methane (the molar ratio of methane to oil rm/o were 1/4, 2/3, 3/2, and 4/1) in nano-pore throat and the displacement behavior of oil and methane in the water flooding process. Simulation results indicated: (1) an increasing replacement of the adsorption-status oil by methane as the methane content increased; (2) the oil and methane displacement efficiency was enhanced as the methane content increased in the water displacement oil and gas process; (3) the threshold displacement pressure gradually decreases as the methane content increases. The microscopic characteristics of the occurrence features and displacement performance of crude oil with associated methane in nano-pore throat were discussed in detail, and the underlying mechanism was discussed at the length concerning the interaction between different components. Our work provides an in-depth understanding of the occurrence characteristics and flow resistance of oil with associated gas in deep oil reservoirs.

Seafloor activity and deep-subsurface geology of gas hydrate areas revealed from δ13C of methane-derived authigenic carbonates along the eastern margin of the Sea of Japan

The collection of microbial CH4 hydrates and methane-derived authigenic carbonates (MDACs) around Sado Island in the Sea of Japan has recently increased. In this study, the carbon isotopic composition of CaCO3 in MDAC (δ13CCaCO3) within these microbial CH4 hydrate areas was compared to that observed at the thermogenic CH4 hydrate mounds of the Umitaka Spur offshore of Joetsu, Sea of Japan. δ13CCaCO3 from thermogenic CH4 hydrate mounds (‐39.1 to -6.1‰ Vienna Pee Dee Belemnite [VPDB]) was more enriched in 13C than those of microbial CH4 areas (‐57.6 to -41.0‰ VPDB). The δ13CCaCO3 variations represented by 2σ standard deviations were also greater for the thermogenic CH4 hydrate mounds (8–11‰) compared to those of the microbial CH4 areas (6–7‰). Because the precipitation of MDACs with various δ13CCaCO3 compositions can occur over areas undergoing dynamic geochemical changes, larger variations suggest that the current thermogenic CH4 hydrate mounds with active gas seepage must have been geochemically dynamic during past MDAC precipitation. Oil-containing gas hydrates in the thermogenic CH4 hydrate mounds suggest a link with deep oil and gas reservoirs. CH4 leakage from deep-subsurface gas reservoirs may drive the higher activity observed at shallow sediment depths in thermogenic CH4 hydrate mounds. δ13CCaCO3 variations revealed differences in paleogeochemical dynamics at shallow sediment depths, and the geochemical characteristics may provide insights into deep-subsurface geological situations for CH4 supply.

A new temperature-resistant and fast dissolving nano-silica/poly (AM-AMPS) composite drag reducer for slickwater fracturing

Polyacrylamide-based drag reducers are an essential component of slickwater fracturing fluids and are used to reduce friction during the fracturing process. However, the elevated temperature accelerates the mechanical and oxidative degradation of polyacrylamide, resulting in a dramatic decrease in the drag reduction capability. To improve the temperature resistance of polyacrylamide, many researchers have focused on introducing rigid groups into the side chains of polyacrylamide. However, the improvement in the temperature resistance of polyacrylamide is limited. To address this problem, a novel water-in-water nanocomposite drag reducer, called ANS-PAA, was developed. ANS-PAA was synthesized by in-situ dispersion polymerization, which involved the use of amino-functionalized nano-silica, acrylamide, and 2-acrylamido-2-methylpropane sulfonic acid. The nanoparticles were linked to the polymer through hydrogen bonding and electrostatic interactions, which dramatically improved the thermal stability of ANS-PAA molecules. The drag reducer exhibits fast dissolving and strong temperature-resistant. Its dissolution time in tap water is 19 s and its drag reduction rate at 120 °C is 70.2 %. In addition, the nanoparticles embedded in the polymer network enhanced the strength of the structure. This study provides valuable insights into the development of drag reducers in slickwater fracturing fluids that more efficiently handle the high temperatures encountered in deep oil and gas reservoirs.

Supramolecular self-assembly of robust, ultra-stable, and high-temperature-resistant viscoelastic worm-like micelles

HypothesisWorm-like micelles are susceptible to heating owing to the fast dynamic exchange of molecules between micelles. Inhibition of such exchange could afford robust worm-like micelles, which is expected to largely improve rheology properties at high temperatures. ExperimentsA cationic surfactant docosyl(trimethyl)azanium chloride (DCTAC) and a strongly hydrophobic organic counterion 3-hydroxy naphthalene-2-carboxylate (SHNC) were used for the worm-like micelles fabrication. The microstructure was characterized using cryogenic transmission electron microscopy and small-angle neutron scattering, and the interactions between DCTAC and SHNC were characterized using nuclear magnetic resonance spectroscopy. Rheometer was employed to measure the rheological properties of the solution. FindingsSHNC/DCTAC at the molar ration of 1:2 forms ultra-stable worm-like micelles, whose viscosity remain stable at temperature up to 130 °C. SHNC is found to strongly adsorbs on DCTAC micelle with the orientation on the surface of micelle, keeping the naphthalene backbone entire penetration into the palisade layer while both carboxylic and hydroxyl groups protrude out of the micelle. With temperature increasing, this adsorption further strengthens, resulting in the growth contour length and accompanying the enhancement of rheological properties. One SHNC molecule and two DCTAC molecules are speculated to form a stable complex via multiple interactions including hydrophobic, cationic-π, and π-π interactions, which decreases the dynamic exchange of them between micelles. These findings are helpful to understand surfactant aggregates stability and assist the development of novel stable supramolecular nanostructures. Additionally, the excellent thermal stability of this worm-like micellar fluid makes it a potential high-temperature resistant clean fracturing fluid for deep oil reservoirs.

Influence of mechanical characteristics of deep composite salt-gypsum layers on safe drilling of directional wells: a case study of Palaeogene in the Kuqa Piedmont structure, Tarim Basin, China

The directional wells can effectively improve the development efficiency of deep and ultra-deep pre-salt oil and gas reservoirs in the Kuqa Mountains of Tarim basin. Under the condition of deep temperature and pressure, the mechanical properties of the composite salt-gypsum layers are complex. During the directional drilling process, that the salt rock is easy to creep causes the drill stick. Under the condition of controlling the well inclination, it is difficult to choose the appropriate drilling fluid density to resist creep and thus maintain the stability of the wellbore. On the basis of rock mechanics experiments, this study established a two-dimensional finite element model considering the combination of composite salt-gypsum layers and inclined well with the effect of in-situ stress, analyzed the influence of temperature, differential stress and well deviation on the salt rock creep. The density of drilling fluid for preventing creep sticking is calculated, and a safe drilling fluid density chart for preventing creep shrinkage of composite salt-gypsum layers is compiled. The results show that when the differential stress is less than 10 MPa, the creep rate of the Tarim composite salt-gypsum layers are at least 10 times higher than that of the Gulf of Mexico salt layers; the creep rate increases with the increase of the differential stress and temperature, and the creep rate is an incremental curve; taking the highly deviated well in the Bozi area as an example, where the shrinkage ratio caused by sticking is set to be 5%, the drilling fluid density chart for creep resistance at 45° and 60° inclination is built, which is consistent with the actual drilling in the field. The results can provide design basis for the selection of anti-creep drilling fluid density in the directional wells in the Kuqa Piedmont composite salt-gypsum layers.

Geological characteristics and models of fault-fold-fracture body in deep tight sandstone of the second member of Upper Triassic Xujiahe Formation in Xinchang structural belt of Sichuan Basin, SW China

In the second member of the Upper Triassic Xujiahe Formation (T3x2) in the Xinchang area, western Sichuan Basin, only a low percent of reserves has been recovered, and the geological model of gas reservoir sweet spot remains unclear. Based on a large number of core, field outcrop, test and logging-seismic data, the T3x2 gas reservoir in the Xinchang area is examined. The concept of fault-fold-fracture body (FFFB) is proposed, and its types are recognized. The main factors controlling fracture development are identified, and the geological models of FFFB are established. FFFB refers to faults, folds and associated fractures reservoirs. According to the characteristics and genesis, FFFBs can be divided into three types: fault-fracture body, fold-fracture body, and fault-fold body. In the hanging wall of the fault, the closer to the fault, the more developed the effective fractures; the greater the fold amplitude and the closer to the fold hinge plane, the more developed the effective fractures. Two types of geological models of FFFB are established: fault-fold fracture, and matrix storage and permeability. The former can be divided into two subtypes: network fracture, and single structural fracture, and the later can be divided into three subtypes: bedding fracture, low permeability pore, and extremely low permeability pore. The process for evaluating favorable FFFB zones was formed to define favorable development targets and support the well deployment for purpose of high production. The study results provide a reference for the exploration and development of deep tight sandstone oil and gas reservoirs in China.

Bacterial co-occurrence patterns are more complex but less stable than archaea in enhanced oil recovery applied oil reservoirs

A complex microbial community exists in oil reservoirs after the application of chemical enhanced oil recovery (EOR) technologies, where the dynamic interactions of microorganisms are thought to be critical to petroleum composition, recovery, and production technologies but are poorly understood. Here, we used the 16S rRNA gene to construct co-occurrence networks for bacterial and archaeal communities associated with water-, polymer-, and alkaline surfactant polymer (ASP)-flooded oil reservoirs. Nonmetric multidimensional scaling analysis showed that bacterial and archaeal community structures differed significantly (p < 0.01) among the oil reservoirs with different EOR compositions. The microbial co-occurrence pattern in water-flooded reservoirs was more complex, with more nodes, edges, and average degrees (i.e., average links per node in the network) than in the polymer- and ASP-flooded reservoirs. However, the archaeal co-occurrence pattern maintained a more robust structure than that of bacteria under the application of polymer and ASP flooding technologies, suggesting that the application of different enhanced oil recovery techniques has diverse effects on the bacterial and archaeal co-occurrence patterns in reservoirs. The pH and [HCO3−] were significantly correlated with the variations in bacterial and archaeal network structures. Our findings provide new insights into the response of microbes to diverse EOR processes by regulating their interactions in deep oil reservoirs. Revealing the effects of water, polymer, and ASP flooding on the co-occurrence patterns of bacteria and archaea in oil reservoirs, which may facilitate the implementation of microbial enhanced oil recovery technology in the future.

A novel temperature-resistant fracturing fluid for tight oil reservoirs: CO2-responsive clean fracturing fluid

With the increasing demand for oil and gas resources, deep tight oil and gas reservoirs have gradually become the focus of global oil and gas exploration and development. Hydraulic fracturing technology based on water-base fracturing fluid plays a more and more important role in improving the recovery of tight oil reservoirs. Under the background of global CO2 emission reduction, a CO2-responsive clean fracturing fluid with controllable gelling/gel breaking at high temperatures was constructed in this paper. The system was not only friendly to the reservoir and environment, but also overcame the shortcomings of the traditional clean fracturing fluid with undesirable temperature resistance. The viscosity characteristics and viscoelastic behavior of temperature-resistant clean fracturing fluid were investigated through high-temperature rheology experiments. The interaction between fluid and rock was investigated through the core flow experiment. The results showed that the clean fracturing fluid had the characteristics of good CO2 responsiveness, excellent shear resistance at high temperatures, high drag reduction, satisfactory gel breaking performance, low filtration and low core damage. The complex three-dimensional network structure formed by the intertwined micelles and vesicles improves the temperature resistance of the clean fracturing fluid. It is expected that the fluid can not only be used to improve oil recovery in tight oil reservoirs, but also be used to solve the leakage problem in CO2 storage underground.

Insights on equation of state modeling PVT experiments for deep volatile oil reservoir

Accurate prediction of the PVT properties and phase behavior plays an important role in developing volatile oil reservoirs. The objective of this study is to characterize volatile oil sample using our improved Perturbation from n-Alkane (PnA) method and validate the results by use of high-quality PVT experimental data from GT1 well through detailed PVT simulation. We implemented PnA method for reservoir fluid characterization and simulated all PVT experiments through an in-house programming package. We compared the modeling results to the experimental data and found that the equation of state (EOS) parameters characterized by the PnA method is able to describe the PVT properties and phase behavior of volatile oil very well. According to the PVT modeling results, we suggested that (1) constant volume depletion test for GT1 volatile oil can be replaced by differential liberation experiment, combined with the data obtained from reliable EOS calculations; (2) the amount of surface-produced condensate for a volatile oil reservoir is up to 4.5% OOIP depending on reservoir abandonment pressure. Therefore, for GT1 volatile oil, condensate production should be carefully evaluated throughout the entire development life-cycle in order to make an optimum design of surface processing facilities for condensate recovery.

Modification of Inclusions by Rare Earth Elements in a High-Strength Oil Casing Steel for Improved Sulfur Resistance

Steel casing pipes used in the construction of deep oil wells usually require both high strength and corrosion-resistant behavior. Due to the exploration of deep H2S-bearing oil reservoirs, sulfide stress cracking (SSC) is becoming an increasingly serious concern for casing steel. The nonmetallic inclusions in the steel are among the key reasons for its service failure. The rare earth element Ce can be used to modify the inclusions in casing steel and improve its SSC resistance. Here, taking C110 grade casing steel (the highest class currently in service) as the investigated object, the modification behavior of Ce inclusions in the steel and the effect of the addition of Ce in varying amounts (0.01, 0.024, and 0.042 wt.%) on the modified products were studied through high-temperature tube furnace experiments and thermodynamic calculations. The results showed that Ce had an obvious modification effect on the CaO·Al2O3 inclusions in casing steel, and the diffusion of dissolved Ce in the steel was the limiting step of the modification reaction. With the extension of reaction time, the sequence describing the modification of inclusions in the steel was determined as follows: CaO·Al2O3 → CeAlO3 → Ce2O3/Ce2O2S. The final stable product after modification depended on the amount of Ce added. With 0.01 wt.% Ce, the stable phase in molten steel was Ce2O3; on the other hand, upon adding ≥0.024 wt.% Ce, the stable phase became Ce2O2S. In addition, the thermodynamic stability of Ce2O3 decreased, and it was transformed into CeAlO3, Ce2O2S, Ce2S3, and CeS during solidification. On the basis of our results and the considerations for smooth casting, the addition of a proper amount of a rare earth element is suggested for industrial trials, following the achievement of a significant and surprising improvement in the qualified rate of SSC resistance for the final steel products. The relevant mechanism is also analyzed.

Experimental Study on Gas Injection for Ultra Deep and high-pressure Fractured-vuggy Carbonate Oil Reservoirs

Experimental Study on Gas Injection for Ultra Deep and high-pressure Fractured-vuggy Carbonate Oil Reservoirs

Breakthrough in drilling and completion equipment and key technologies for 8000m-class ultra-deep wells onshore China

With the exploration and development of a group of deep ultra-deep large oil and gas fields in Tarim basin and Sichuan Basin, deep oil and gas reservoirs will be the main productivity replacement area and the main exploration focus area. Drilling and completion still face severe challenges such as high temperature and high pressure, complex pressure systems, complex accidents and poor drillability. This paper describes the technology of domestic oil and gas fields with 8000m level drilling and completion. Considering the demand of exploration and development of local oil and gas fields while standardizing the international advanced level, the insufficiency of technology and equipment improvement demand of each block are discussed, and the research direction of technology and equipment is prospected.

A Fracture Toughness-Based Evaluation Method for Deep Shale Oil Reservoir Compressibility

A Fracture Toughness-Based Evaluation Method for Deep Shale Oil Reservoir Compressibility

Dynamic Behaviors and Mechanisms of Air-Foam Flooding at High Pressure and Reservoir Temperature via Microfluidic Experiments.

Air injection has been proven to be an effective improved oil recovery technique for deep and light oil reservoirs with low permeability and poor water injectivity. But the efficiency of air injection in highly heterogeneous reservoirs is low due to poor gas sweeping that may lead to early oxygen breakthrough caused by gas channeling and viscous fingering. Foam can be used to assist air injection to overcome the obstacles of early gas breakthrough and to increase the displacement and sweeping efficiency. In this paper, laser-etched visual microscopic pore models were used as microfluidic devices to study the air-foam flooding process in porous media at reservoir temperature and high pressure. The dynamic behaviors and relevant mechanisms of air-foam flooding were investigated. Typical mechanisms of foam generation in porous media are achieved in different parts of the micromodel, which can be listed as follows: lamella leave-behind, lamella division, and snap off. Analysis on flow states of air foam showed that foams migrate in porous media by bursting and regenerating during the flooding process. It can be observed that the flow mode of foam in porous media is the separate flow of gas and liquid through microscopic displacement experiments, suggesting that foam should not be treated as a homogeneous phase in heterogeneous porous media. The pressing, occupying, and selective blocking effects of foam in porous media exhibited different oil displacement performances with the presence of various pore geometries and networks. Tiny foams also showed stripping and carrying effects on larger oil droplets benefiting from the lipophilicity of foam. Through comprehensive analysis on overall and local oil displacement mechanisms, air-foam injection could enhance the microscopic sweep volume and improve the oil displacement efficiency.

Damage of reservoir rock induced by CO2 injection

The study of reservoir rock damage induced by gas injection is of great significance to the design of reservoir stimulation and the improvement of oil and gas recovery. Based on an example horizontal well in the Hudson Oilfield of the Tarim Basin and considering the multi-physics coupling effects among high-pressure fluid, rock deformation, and damage propagation during CO 2 injection, a three-dimensional finite element model for CO 2 injection in deep reservoir considering seepage-stress-damage coupling was developed. The evolution of reservoir rock damage under different CO 2 injection conditions was systematically investigated. The results show that tensile damage and shear damage are concentrated in the vertical direction and the horizontal maximum compressive principal stress direction, respectively, and the tensile damage is the main damage mode. At higher CO 2 injection rate and pressure, the damaged areas near the wellbore are mainly distributed in the direction of the maximum compressive principal stress, and the development of the damaged area near the wellbore will be inhibited by the formation and evolution of far-field damage. CO 2 injection aggravates the extension of tensile damage, but inhibits the initiation of shear damage, and eventually leads to the gradual transition from shear damage to tensile damage. Under the same injection conditions, CO 2 injection has superior performance in creating rock damage compared with the injection of nitrogen and water. The results in this study provide guidance for enhanced oil recovery in deep oil and gas reservoirs with CO 2 injection.

Dynamic Propagation and Shear Stress Disturbance of Multiple Hydraulic Fractures: Numerical Cases Study via Multi-Well Hydrofracturing Model with Varying Adjacent Spacings

Multi-well hydrofracturing is an important technology for forming complex fracture networks and increasing reservoir permeability. The distribution and design of horizontal wells affect fracture propagation; however, it is still unclear how the spacing between adjacent wells leads to fracture propagation, deflection and connection. In this study, the thermal-hydro-mechanical coupling effect in the hydrofracturing process is comprehensively considered and a multi-well hydrofracturing model based on the finite element–discrete element method is established. Using typical cases, the unstable propagation of hydraulic fractures in multiple horizontal wells under varying adjacent well spacings is studied. Combined with the shear stress shadow caused by in situ stress disturbed by fracture tip propagation, quantitative indexes (such as length, volume, deflection and unstable propagation behaviors of hydrofracturing fracture networks) are analyzed. The results show that the shear stress disturbance caused by multiple hydraulic fractures is a significant factor for multi-well hydrofracturing. Reducing well spacing will increase the stress shadow area and aggravate the mutual disturbance and deflection between fractures. The results of quantitative analysis show that the total length of hydraulic fractures decreases with the decrease of well spacing, and the total volume of hydraulic fractures increases with the decrease of well spacing. The results of unstable propagation and stress evolution of hydraulic fracture networks considering thermal-hydro-mechanical coupling obtained in this study can provide useful guidance for the valuation and design of hydrofracturing fracture networks in deep unconventional oil and gas reservoirs.