Microbial polysaccharides,due to their unique physicochemical properties,have been shown to effec-tively enhance the stability of foam fracturing fluids.However,the combined application of microbial polysaccharides an...Microbial polysaccharides,due to their unique physicochemical properties,have been shown to effec-tively enhance the stability of foam fracturing fluids.However,the combined application of microbial polysaccharides and surfactants under high-temperature and high-salinity conditions remain poorly understood.In this study,we innovatively investigate this problem with a particular focus on foam stabilization mechanisms.By employing the Waring blender method,the optimal surfactant-microbial polysaccharide blends are identified,and the foam stability,rheological properties,and decay behavior in different systems under varying conditions are systematically analyzed for the first time.The results reveal that microbial polysaccharides significantly enhance foam stability by improving the viscoelasticity of the liquid films,particularly under high-salinity and high-temperature conditions,leading to notable improvements in both foam stability and sand-carrying capacity.Additionally,scanning electron microscopy(SEM)is used to observe the microstructure of the foam liquid films,demonstrating that the network structure formed by the foam stabilizer within the liquid film effectively inhibits foam coarsening.The Lauryl betaine and Diutan gum blend exhibits outstanding foam stability,superior sand-carrying capacity,and minimal core damage,making(LAB+MPS04)it ideal for applications in enhanced production and reservoir stimulation of unconventional reservoirs.展开更多
As the global exploration and development of oil and gas resources advances into deep formations,the harsh conditions of high temperature and high salinity present significant challenges for drilling fluids.In order t...As the global exploration and development of oil and gas resources advances into deep formations,the harsh conditions of high temperature and high salinity present significant challenges for drilling fluids.In order to address the technical difficulties associated with the failure of filtrate loss reducers under high-temperature and high-salinity conditions.In this study,a hydrophobic zwitterionic filtrate loss reducer(PDA)was synthesized based on N,N-dimethylacrylamide(DMAA),2-acrylamido-2-methylpropane sulfonic acid(AMPS),diallyl dimethyl ammonium chloride(DMDAAC),styrene(ST)and a specialty vinyl monomer(A1).When the concentration of PDA was 3%,the FLAPI of PDA-WBDF was 9.8 mL and the FLHTHP(180℃,3.5 MPa)was 37.8 mL after aging at 240℃for 16 h.In the saturated NaCl environment,the FLAPI of PDA-SWBDF was 4.0 mL and the FLHTHP(180℃,3.5 MPa)was 32.0 mL after aging at 220℃ for 16 h.Under high-temperature and high-salinity conditions,the combined effect of anti-polyelectrolyte and hydrophobic association allowed PDA to adsorb on the bentonite surface tightly.The sulfonic acid groups of PDA increased the negative electronegativity and the hydration film thickness on bentonite surface,which enhanced the colloidal stability,maintained the flattened lamellar structure of bentonite and formed an appropriate particle size distribution,resulting in the formation of dense mud cakes and reducing the filtration loss effectively.展开更多
Previous studies on post-fracturing flowback fluids focus primarily on their cleaning and discharge,high salinity sources,and damage to gas reservoirs.An analysis of the geochemical characteristics of these fluids hel...Previous studies on post-fracturing flowback fluids focus primarily on their cleaning and discharge,high salinity sources,and damage to gas reservoirs.An analysis of the geochemical characteristics of these fluids helps develop an improved understanding of the preservation condition and fracturing performance of shale gas reservoirs.This study analyzed the ion,total dissolved solids(TDS)concentration,and stable isotope characteristics of post-fracturing flowback fluids from five horizontal shale gas wells in the Luzhou area.Among these wells,two were subjected to hydraulic fracturing using fresh water,and three using reused flowback fluids.The results indicate that with increasing flowback time,the post-fracturing flowback fluids from wells subjected to hydraulic fracturing using fresh water showed increased TDS concentration,heavier stable isotopes,and the presence of new ion components.These results indicate the mixing of a large volume of formation water into the fluids.In contrast,postfracturing flowback fluids from wells subjected to hydraulic fracturing using reused flowback fluids exhibited a slow increase in the TDS concentration and stable isotopes.As the flowback time increased,the trends in TDS concentration and stable isotope ratios of post-fracturing flowback fluids from shale gas wells subjected to fracturing using fresh water evolved toward those of post-fracturing flowback fluids from shale gas wells undergoing fracturing using reused flowback fluids.Measurements show that post-fracturing flowback fluids from both well types exhibited roughly the same properties after one year of shale gas production.This result suggests that post-fracturing flowback fluids from wells using reused flowback fluids progressively took on the formation water properties.In particular,postfracturing flowback fluids from well Lu 211—a well subjected to hydraulic fracturing using fresh water—showed a low sodium-chloride coefficient,a low coefficient of variation,high TDS concentration,heavy stable isotopes,and a high nitrate ion concentration.This indicates a formation water source of the fluids and the poor sealing of the formation water,which hinders shale gas enrichment.The quantification of the fracturing fluid and formation water contents in the post-fracturing flowback fluids reveals that higher TDS concentration and heavier stable isotopes in the fluids appear to correspond to higher formation water content and lower fracturing fluid content,as well as higher fracturing performance.A systematic analysis of the geochemical characteristics and flowback pattern of fracturing fluids indirectly provides insights into the flow path of formation water,water body mixing,rock-water interactions,and fluid sources.Besides,the analysis offers a new perspective for understanding the preservation conditions and fracturing performance of shale gas reservoirs.展开更多
Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do ...Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do not produce satisfactory results when conventional fracturing fluids with a low pumping rate are used.In response to the above problem,a fracturing fluid with a density of 1.2~1.4 g/cm^(3)was developed by using Potassium formatted,hydroxypropyl guanidine gum and zirconium crosslinking agents.The fracturing fluid was tested and its ability to maintain a viscosity of 100 mPa.s over more than 60 min was verified under a shear rate of 1701/s and at a temperature of 175℃.This fluid has good sand-carrying performances,a low viscosity after breaking the rubber,and the residue content is less than 200 mg/L.Compared with ordinary reconstruction fluid,it can increase the density by 30%~40%and reduce the wellhead pressure of 8000 m level reconstruction wells.Moreover,the new fracturing fluid can significantly mitigate safety risks.展开更多
Static adsorption and dynamic damage experiments were carried out on typical 8#deep coal rock of the Carboniferous Benxi Formation in the Ordos Basin,NW China,to evaluate the adsorption capacity of hydroxypropyl guar ...Static adsorption and dynamic damage experiments were carried out on typical 8#deep coal rock of the Carboniferous Benxi Formation in the Ordos Basin,NW China,to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption.The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy,and the main controlling factors of the thickener adsorption were analyzed.Meanwhile,the adsorption mechanism of the thickener was revealed by Zeta potential,Fourier infrared spectroscopy and X-ray photoelectron spectroscopy.The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g,and the permeability of coal rock after adsorption decreases by 35.24%–37.01%.The adsorption capacity of polyacrylamide is 3.29 mg/g,and the permeability of coal rock after adsorption decreases by 14.31%–21.93%.The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature,and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of polyacrylamide adsorption layer more concentrated.Functional group condensation and intermolecular force are chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock.Optimization of thickener mass fraction,chemical modification of thickener molecular,oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.展开更多
Spontaneous imbibition of water-based frac- turing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix...Spontaneous imbibition of water-based frac- turing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the frac- turing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KC1 solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most impor- tant factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The aver- age ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KC1 solution can inhibit clay absorption to reduce the imbibition capacity.展开更多
China's continental shale exhibits favorable geological characteristics and substa ntial resource potential,yet oil recovery for natural energy extraction remains critically low.Investigating the mechanisms of hyd...China's continental shale exhibits favorable geological characteristics and substa ntial resource potential,yet oil recovery for natural energy extraction remains critically low.Investigating the mechanisms of hydraulically induced bedding fracture to generate complex fracture networks in continental shale,and establishing effective flow systems,is of utmost importance.This study employs laboratory experiments and numerical simulations to investigate the flow capacity and percolation behavior of hydraulically induced bedding fractures by different fluids in full-diameter shale cores.Hydraulic stimulation using different fluids generates bedding plane fracture networks,establishing effective flow systems.Eroded and detached shale fragments support localized fractures,thereby increasing their opening and enhancing flow capacity.Cetyltrimethylammonium bromide(CTAB) solution and SiO2 solution reduce the hydration of the shale surface,preventing shale fragments from swelling and disintegrating,leading to more stable percolation behavior.Eroded and spalled shale fragments near the injection point are transported to farther locations,where they help support localized fractures.This process differs from conve ntional hydraulic fractu ring.Under a constant injection rate,the velocity in the smaller flow paths near the closure is significantly higher than that in the main flow paths,leading to pronounced bypass flow behavio r.This restricts the pe rcolation of fluid du ring imbibition in shale co res.The results provide valuable insights into the mechanism of hydraulically induced bedding fracture in continental shale,offering guidance for the effective development of shale reservoirs.展开更多
This study investigated the micro-sliding frictional behavior of shale in fracturing fluids under varying operational conditions using Chang 7 shale oil reservoir core samples.Through systematic micro-sliding friction...This study investigated the micro-sliding frictional behavior of shale in fracturing fluids under varying operational conditions using Chang 7 shale oil reservoir core samples.Through systematic micro-sliding friction experiments,the characteristics and governing mechanisms of shale friction were elucidated.Complementary analyses were conducted to characterize the mineral composition,petrophysical properties,and micromorphology of the shale samples,providing insights into the relationship between microscopic structure and frictional response.In this paper,the characteristics and variation law of shale micro-sliding friction under different types of graphite materials as additives in LGF-80(Low-damage Guar Fluid)oil flooding recoverable fracturing fluid system were mainly studied.In addition,the finite element numerical simulation experiment of hydraulic fracturing was adopted to study the influence of the friction coefficient of natural fracture surfaces on fracture propagation and formation of the fracture network.The geometric complexity of fracture networks was systematically quantified under varying frictional coefficients of natural fracture surfaces through multi-parametric characterization and morphometric analysis.The research results show that graphite micro-particles reduce friction and drag.Based on this,this paper proposes a new idea of graphite micro-particles as an additive in the LGF-80 oil flooding recoverable fracturing fluid system to reduce friction on the fracture surface.展开更多
The combination of ultrasonic and acid fracturing fluid can strengthen the modification effect on the micropore structure of the coal matrix,thereby enhancing the efficiency of the acid fracturing process.In this rese...The combination of ultrasonic and acid fracturing fluid can strengthen the modification effect on the micropore structure of the coal matrix,thereby enhancing the efficiency of the acid fracturing process.In this research,acetic acid was utilized to formulate acid fracturing fluids with varying concentrations,and the evolutionary traits of both the acid fracturing fluids and ultrasonic waves in relation to coal samples were investigated.The functional group structure,mineral composition,micropore structure and surface morphology of coal samples were characterized by FTIR,XRD,N_(2)adsorption at low temperature and SEM-EDS.The results showed that aromatics(I)and branching parameters(CH_(2)/CH_(3))were reduced by 81.58%and 88.67%,respectively,after 9%acetic acid treatment.Acetic acid can dissolve carbonates and clay minerals in coal,create new pores,and increase porosity,pore volume and pore fractal dimension.After modification by 7%acetic acid,the pore volume increased by 5.7 times.SEM observation shows that the diameter of coal surface holes increases,EDS scanning shows that the content of mineral elements in coal decreases,the connectivity of coal holes increases,and the holes expand.The findings of this research offer theoretical direction for optimizing ultrasonic-enhanced acid fracturing fluid modification.展开更多
Low-salinity fracturing fluids tend to induce ion migration,alter wettability,and cause fluctuations in gas desorption efficiency when penetrating deep coal seams.Taking the No.8 coal from the Daning-Jixian area in th...Low-salinity fracturing fluids tend to induce ion migration,alter wettability,and cause fluctuations in gas desorption efficiency when penetrating deep coal seams.Taking the No.8 coal from the Daning-Jixian area in the Ordos Basin,NW China,as a representative example,this study employs physical simulation experiments to reveal the coupled control mechanism of salinity gradient on the ion-coal matrix-gas/water interfacial system and its key role in the imbibition-desorption process.The increasing ionic concentration improves the hydrophobicity of coal,with multivalent ions exhibiting particularly significant effects.The imbibition and ion diffusion occur in opposite directions,with imbibition equilibrium being achieved earlier than ionic equilibrium.Water-coal interactions induce both mineral dissolution and secondary precipitation.When a low-salinity fracturing fluid is injected into a high-salinity reservoir,the osmotic-pressure difference drives imbibition,promotes CH4 desorption,but results in higher fluid loss.Conversely,injecting high-salinity fracturing fluid into a low-salinity reservoir creates a reverse osmotic gradient that suppresses leak-off while improving flowback efficiency.Based on these findings,a high-low salinity sequential injection strategy is proposed for deep coal seams:high-salinity fluid is first injected to form stable fracture networks,followed by low-salinity fluid to enlarge the imbibition zone and enhance CH4 desorption and diffusion.Moderate well soaking is recommended to increase the imbibition volume,thereby achieving multiple positive effects such as maintaining reservoir pressure,preserving formation energy,and promoting imbibition-driven displacement.展开更多
Injection rate is crucial for determining the hydraulic fracturing effectiveness;however,the effects of the injection rate on the pore and fracture structure(PFS)and fluid infiltration during injection pressurization ...Injection rate is crucial for determining the hydraulic fracturing effectiveness;however,the effects of the injection rate on the pore and fracture structure(PFS)and fluid infiltration during injection pressurization have rarely been explored.In this study,the cylindrical sandstone samples were hydraulically fractured at various injection rates on a self-developed integrated nuclear magnetic resonance(NMR)and hydraulic fracturing experimental system.The results show that low injection rates predominantly resulted in macropore-scale damage by creating intergranular cracks,whereas high injection rates facilitated micropore-scale damage,probably owing to the adsorption swelling effect of clay minerals within pores.Additionally,the water contents of the samples with low injection rates exhibited a continuous increase,whereas those of the samples with high injection rates initially increased and subsequently stabilized.Magnetic resonance imaging(MRI)indicated that fluid infiltration during the fracturing process exhibited high anisotropy owing to the inherent heterogeneous PFS distributions around the wellbore.Moreover,a primary fluid infiltration path exists that aligns with the initiation direction of the hydraulic fractures.However,the fluid infiltration damage distance along the hydraulic fracture direction decreased with increasing injection rate,whereas the fluid infiltration damage distance perpendicular to the hydraulic fracture direction was approximately equal to the characteristic length,regardless of the injection rate.Finally,we recommend using the pore damage during fluid pressurization as the basis for selecting the proppant size and employing a primary fluid infiltration path to predict hydraulic fracture initiation.These findings provide valuable insights into the design of hydraulic fracturing in tight gas reservoirs.展开更多
As oil and gas development increasingly targets unconventional reservoirs,the limitations of conventional hydraulic fracturing,namely high water consumption and significant reservoir damage,have become more pronounced...As oil and gas development increasingly targets unconventional reservoirs,the limitations of conventional hydraulic fracturing,namely high water consumption and significant reservoir damage,have become more pronounced.This has driven growing interest in the development of clean fracturing fluids that minimize both water usage and formation impairment.In this study,a low-liquid-content viscoelastic surfactant(VES)foam fracturing fluid system was formulated and evaluated through laboratory experiments.The optimized formulation comprises 0.2%foaming agent CTAB(cetyltrimethylammonium bromide)and 2%foam stabilizer EAPB(erucamidopropyl betaine).Laboratory tests demonstrated that the VES foam system achieved a composite foam value of 56,700 mL・s,reflecting excellent foaming performance.Proppant transport experiments revealed minimal variation in suspended sand volume over 120 min across different sand ratios,indicating robust sand-carrying capacity even at high proppant concentrations.Rheological measurements showed that the fluid maintained a viscosity above 120 mPa・s after 120 min of shearing at 70℃ and a shear rate of 170 s−1,with the elastic modulus exceeding the viscous modulus,confirming the system’s exceptional stability and resilience.Furthermore,core damage tests indicated that the VES foam caused only 4.42%formation damage,highlighting its potential for efficient and low-damage stimulation of tight reservoirs.Overall,the findings demonstrate that this low-liquid-content VES foam provides a highly effective,environmentally considerate alternative for hydraulic fracturing in unconventional formations,combining superior proppant transport,rheological stability,and minimal reservoir impairment.展开更多
To understand the applicability of high-temperature preformed particle gel(HT-PPG)for control of short-circuiting in enhanced geothermal systems(EGSs),core flooding experiments were conducted on fractured granite core...To understand the applicability of high-temperature preformed particle gel(HT-PPG)for control of short-circuiting in enhanced geothermal systems(EGSs),core flooding experiments were conducted on fractured granite cores under varying fracture widths,gel particle sizes and swelling ratios.Key parameters such as injection pressure,water breakthrough pressure,and residual resistance factor were measured to evaluate HT-PPG performance.The gel exhibited strong injectability,entering granite fractures at pressure gradients as low as 0.656 MPa/m;HT-PPG yields a superior sealing performance by significantly reducing the permeability;and dehydration occurs during HT-PPG propagation,with a dehydration ratio ranging from 4.71%to 11.36%.This study reveals that HT-PPG can be injected into geothermal formations with minimal pressure yet provides strong resistance to breakthrough once in place.This balance of injectability and sealing strength makes HT-PPG effective for addressing thermal short-circuiting in EGS reservoirs.展开更多
To elucidate the adsorption characteristics and retention mechanisms of fracturing fluids in diverse clay minerals,we conducted on-line nuclear magnetic resonance(NMR)and atomic force microscopy(AFM)experiments.The de...To elucidate the adsorption characteristics and retention mechanisms of fracturing fluids in diverse clay minerals,we conducted on-line nuclear magnetic resonance(NMR)and atomic force microscopy(AFM)experiments.The depth and extent of solid phase damage are determined by the ratio between the size of fine fractions in fracturing fluid residue and the pore-throat size in experiments.Poor physical properties(K<0.5 mD)result in a more preferential flow pathway effect during flowback,and the stepwise incremental pressure differential proves to be more effective for the discharge of fracturing fluid in submicron pore throats.The permeability is significantly influenced by the differential distri-bution of retained fracturing fluid,as supported by direct experimental evidence.The presence of good physical properties(K>0.5 mD)combined with a scattered distribution of retained fracturing fluid is associated with high gas phase recovery permeability,whereas a continuous sheet-like distribution results in low recovery permeability.The expansive surface area and presence of filamentous illite minerals facilitate the multiple winding and adsorption of fracturing fluids,demonstrating strong hydrogen-bonding,multi-layering and multiple adsorption properties.The geological characteristics of the main gas formations exhibit significant variation,and the severity of damage caused by fracturing fluids occurs in diverse sequences.To address this issue,a differentiated strategy for optimizing frac-turing fluids has been proposed.展开更多
With the widespread adoption of hydraulic fracturing technology in oil and gas resource development,improving the accuracy and efficiency of fracturing simulations has become a critical research focus.This paper propo...With the widespread adoption of hydraulic fracturing technology in oil and gas resource development,improving the accuracy and efficiency of fracturing simulations has become a critical research focus.This paper proposes an improved fluid flow algorithm,aiming to enhance the computational efficiency of hydraulic fracturing simulations while ensuring computational accuracy.The algorithm optimizes the aperture law and iteration criteria,focusing on improving the domain volume and crack pressure update strategy,thereby enabling precise capture of dynamic borehole pressure variations during injection tests.The effectiveness of the algorithm is verified through three flow-solid coupling cases.The study also analyzes the effects of borehole size,domain volume,and crack pressure update strategy on fracturing behavior.Furthermore,the performance of the improved algorithm in terms of crack propagation rate,micro-crack formation,and fluid pressure distribution was further evaluated.The results indicate that while large-size boreholes delay crack initiation,the cracks propagate more rapidly once formed.Additionally,the optimized domain volume calculation and crack pressure update strategy significantly shorten the pressure propagation stage,promote crack propagation,and improve computational efficiency.展开更多
CO_(2) foam fracturing fluid can effectively integrate CCUS technology into oil and gas field development,and its core advantages include low water consumption,excellent flowback performance,and strong sand-carrying c...CO_(2) foam fracturing fluid can effectively integrate CCUS technology into oil and gas field development,and its core advantages include low water consumption,excellent flowback performance,and strong sand-carrying capacity.For these reasons,it has received increasing attention in the oil and gas field development field.However,this type of fracturing fluid still has some prominent problems:The residue from gel breaking can easily cause formation pollution,the system cost is relatively high,and the utilization rate is low,which forms a significant technical bottleneck.In response to these issues,this study,based on the theory of clean fracturing fluid gel breaking without residue and the reusability of CO_(2)-responsive wormlike micelles,innovatively combines CO_(2)-responsive wormlike micelles with different types of surfactant-based foaming agents to construct a new CO_(2)-responsive foam fracturing fluid system.A systematic performance evaluation of the system was conducted to clarify its defoaming rules under different temperature conditions.Compared with the traditional guar gum CO_(2) foam fracturing fluid,the new system has significant performance advantages.At 90℃,its foam comprehensive value reached 19720 mL·min,6150 mL·min higher than the guar gum fluid.After a 5400 s high-temperature and high-shear test at the same temperature,the residual viscosity of the new system was 67 mPa·s,which is higher than the guar gum fluid.This CO_(2)-responsive foam fracturing fluid simultaneously possesses the application potential of both clean fracturing fluid and foam fracturing fluid.It can effectively solve key problems such as formation pollution and low system utilization rates,and laboratory evaluation experiments confirmed its excellent foaming and rheological properties.These results are of great significance for promoting CO_(2) foam fracturing technology to reach an advanced international level and supporting the low-carbon and highefficiency development of unconventional oil and gas resources in China.展开更多
The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved ...The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation(also referred to as the He 8 Member)in the study area,as well as their effects on fracturing fluid imbibition.Utilizing experimental techniques such as nuclear magnetic resonance(NMR),high-pressure mercury intrusion(HPMI),and gas adsorption,this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments.The findings reveal that:①The reservoir,with average porosity of 8.40%and average permeability of 0.642×10^(-3)μm^(2),consists principally of quartz,feldspar,and lithic fragments,with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral;②Nano-scale micro-pores and throats dominate the reservoir,with dissolution pores and intercrystalline pores serving as predominant pore types,exhibiting relatively high pore connectivity;③Imbibition efficiency is influenced by petrophysical properties,clay mineral content,and microscopic pore structure.Due to the heterogeneity of the tight sandstone reservoir,microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids;④A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency,followed by petrophysical properties and clay mineral content.In contrast,the pore type has minimal impact.Micropores are vital in the imbibition process,while meso-pores and macro-pores offer primary spaces for imbibition.This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones.展开更多
Hydraulic fracturing has become the main technology for the efficient development of geothermal energy in hot dry rock(HDR),however,few studies on the propagation behavior and mechanism of HDR hydraulic fractures unde...Hydraulic fracturing has become the main technology for the efficient development of geothermal energy in hot dry rock(HDR),however,few studies on the propagation behavior and mechanism of HDR hydraulic fractures under high-temperature conditions have investigated.In this paper,a large-size high-temperature true triaxial hydraulic fracturing physical modeling apparatus is designed,and hydraulic fracturing experiments with it are performed to investigate the fracture initiation and propagation behavior in natural granite samples collected from Gonghe Basin,thefirst HDR site in China.The experimental results show that the designed high-temperature apparatus provides a constant-temperature condition during the whole hydraulic fracturing process and the maximum temperature can reach 600℃,showing its ability to simulate realistic temperatures and pressures in both ultra-deep and HDR formations.Although the tensile strength of the rock samples remains almost unchanged at a temperature of 200℃,the cooling effects of the fracturingfluid in high-temperature rock can induce the formation of microfractures and significantly reduce the rock strength,thus lowering the breakdown pressure and increasing the complexity of the hydraulic fracture morphology.Compared with traditional oil and gas reservoirs,the hydraulic fractures in HDR are rougher and the specific surface area of a single fracture is larger,which can be helpful for heat extraction.This study provides a basis for understanding hydraulic fracture geometries andfield construction design in HDRs.展开更多
Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymerbased fractur...Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymerbased fracturing fluids(such as guar gum(GG), polyacrylamide(HPAM), etc.) are high-viscosity fluids formed by viscosifiers and crosslinking agents, the degree of gel breakage after the fracturing operation directly influences the damage degree to the reservoir matrix and the mobility of oil angd gas produced from the reservoir into the wellbore. This study compared the viscosity, molecular weight, and particle size of the fracturing fluid after gel breakage prepared by GG and HPAM as viscosifiers, as well as evaluate their damage to the core. Results show that the viscosities of the gel-breaking fluid increased with the concentration of the viscosifier for both the HPAM-based and GG-based fracturing fluids. For the breaking fluid with the same viscosity, the molecular weight in the HPAM-based gel-breaking fluid was much larger than that in the GG-based system. Moreover, for the gel-breaking fluid with the same viscosity, the molecular particle size of the residual polymers in the HPAM-based system was smaller than that in the GG-based system. The damage to the core with the permeability of 1 × 10^(-3)μm^(2) caused by both the HPAM-based and GG-based gel-breaking fluids decreased with the increase in the solution viscosity. For the gel-breaking fluid systems with the same viscosity(i.e., 2-4 mPa s), the damage of HPAM-based fracturing fluid to low-permeability cores was greater than the GG-based fracturing fluid(45.6%-80.2%) since it had a smaller molecular particle size, ranging from 66.2% to 77.0%. This paper proposed that the damage caused by hydraulic fracturing in rock cores was related to the partilce size of residual polymers in gel-breaking solution, rather than its molecular weight. It was helpful for screening and optimizing viscosifiers used in hydraulic fracturing process.展开更多
The variable-density flow model-SEAWAT Version 4, was used to evaluate the hydrogeological conditions associatedwith hydraulic fracturing （fracking） the limestone oil reservoir in the Lower Cretaceous Sunniland Form...The variable-density flow model-SEAWAT Version 4, was used to evaluate the hydrogeological conditions associatedwith hydraulic fracturing （fracking） the limestone oil reservoir in the Lower Cretaceous Sunniland Formation of Southwest Florida.This research contributes to the understanding of the controls on fluid and potential contaminant migration, following high pressurehydraulic fracturing. A hydraulic fracturing treatment used recently in this formation at the Collier-Hogan 20-3H well represents thebase case simulation. Multiple stage fracturing using typical stress periods, a modelled fracture zone radius, and various injectionrates were tested to evaluate the potential for horizontal and vertical fluid migration in and from the reservoir under dynamicconditions, with TDS used as a tracer. Hypothetical scenarios including preferential vertical pathways between the SunnilandFormation and the Lower Floridan aquifer Boulder Zone were also simulated. Results indicate that injected fluids do not migratesignificantly in the lateral and vertical directions beyond the design fractured zone, unless a preferential pathway exists within closeproximity to the fractured zone. In a worst-case scenario under the simulated conditions, vertical heads are approximately 580 metersgreater than static conditions and fluids associated with hydraulic fracturing vertically migrate approximately 500 meters; therefore,the quality of the deepest sources of drinking water is not compromised. Analytical results from a monitoring well installed in theimmediate vicinity of the Collier-Hogan 20-3H well and at the base of the deepest source of drinking water support the conclusionthat impacts from hydraulic fracturing fluids have not migrated into the deepest sources of drinking water.展开更多
基金supported by the Key Technology Research on Increasing Recovery Rate in Tight Sandstone Gas Reservoirs,a Major Scientific and Technological Special Project of China National Petroleum Corporation(Project No.2023ZZ25).
文摘Microbial polysaccharides,due to their unique physicochemical properties,have been shown to effec-tively enhance the stability of foam fracturing fluids.However,the combined application of microbial polysaccharides and surfactants under high-temperature and high-salinity conditions remain poorly understood.In this study,we innovatively investigate this problem with a particular focus on foam stabilization mechanisms.By employing the Waring blender method,the optimal surfactant-microbial polysaccharide blends are identified,and the foam stability,rheological properties,and decay behavior in different systems under varying conditions are systematically analyzed for the first time.The results reveal that microbial polysaccharides significantly enhance foam stability by improving the viscoelasticity of the liquid films,particularly under high-salinity and high-temperature conditions,leading to notable improvements in both foam stability and sand-carrying capacity.Additionally,scanning electron microscopy(SEM)is used to observe the microstructure of the foam liquid films,demonstrating that the network structure formed by the foam stabilizer within the liquid film effectively inhibits foam coarsening.The Lauryl betaine and Diutan gum blend exhibits outstanding foam stability,superior sand-carrying capacity,and minimal core damage,making(LAB+MPS04)it ideal for applications in enhanced production and reservoir stimulation of unconventional reservoirs.
基金supported by State Key Laboratory of Deep Oil and Gas(No.SKLDOG2024-ZYRC-03)supported by the Excellent Young Scientists Fund of the National Natural Science Foundation of China(No.52322401)the National Natural Science Foundation of China(52288101).
文摘As the global exploration and development of oil and gas resources advances into deep formations,the harsh conditions of high temperature and high salinity present significant challenges for drilling fluids.In order to address the technical difficulties associated with the failure of filtrate loss reducers under high-temperature and high-salinity conditions.In this study,a hydrophobic zwitterionic filtrate loss reducer(PDA)was synthesized based on N,N-dimethylacrylamide(DMAA),2-acrylamido-2-methylpropane sulfonic acid(AMPS),diallyl dimethyl ammonium chloride(DMDAAC),styrene(ST)and a specialty vinyl monomer(A1).When the concentration of PDA was 3%,the FLAPI of PDA-WBDF was 9.8 mL and the FLHTHP(180℃,3.5 MPa)was 37.8 mL after aging at 240℃for 16 h.In the saturated NaCl environment,the FLAPI of PDA-SWBDF was 4.0 mL and the FLHTHP(180℃,3.5 MPa)was 32.0 mL after aging at 220℃ for 16 h.Under high-temperature and high-salinity conditions,the combined effect of anti-polyelectrolyte and hydrophobic association allowed PDA to adsorb on the bentonite surface tightly.The sulfonic acid groups of PDA increased the negative electronegativity and the hydration film thickness on bentonite surface,which enhanced the colloidal stability,maintained the flattened lamellar structure of bentonite and formed an appropriate particle size distribution,resulting in the formation of dense mud cakes and reducing the filtration loss effectively.
基金supported by China National Petroleum Corporation(NO:2023ZZ21)。
文摘Previous studies on post-fracturing flowback fluids focus primarily on their cleaning and discharge,high salinity sources,and damage to gas reservoirs.An analysis of the geochemical characteristics of these fluids helps develop an improved understanding of the preservation condition and fracturing performance of shale gas reservoirs.This study analyzed the ion,total dissolved solids(TDS)concentration,and stable isotope characteristics of post-fracturing flowback fluids from five horizontal shale gas wells in the Luzhou area.Among these wells,two were subjected to hydraulic fracturing using fresh water,and three using reused flowback fluids.The results indicate that with increasing flowback time,the post-fracturing flowback fluids from wells subjected to hydraulic fracturing using fresh water showed increased TDS concentration,heavier stable isotopes,and the presence of new ion components.These results indicate the mixing of a large volume of formation water into the fluids.In contrast,postfracturing flowback fluids from wells subjected to hydraulic fracturing using reused flowback fluids exhibited a slow increase in the TDS concentration and stable isotopes.As the flowback time increased,the trends in TDS concentration and stable isotope ratios of post-fracturing flowback fluids from shale gas wells subjected to fracturing using fresh water evolved toward those of post-fracturing flowback fluids from shale gas wells undergoing fracturing using reused flowback fluids.Measurements show that post-fracturing flowback fluids from both well types exhibited roughly the same properties after one year of shale gas production.This result suggests that post-fracturing flowback fluids from wells using reused flowback fluids progressively took on the formation water properties.In particular,postfracturing flowback fluids from well Lu 211—a well subjected to hydraulic fracturing using fresh water—showed a low sodium-chloride coefficient,a low coefficient of variation,high TDS concentration,heavy stable isotopes,and a high nitrate ion concentration.This indicates a formation water source of the fluids and the poor sealing of the formation water,which hinders shale gas enrichment.The quantification of the fracturing fluid and formation water contents in the post-fracturing flowback fluids reveals that higher TDS concentration and heavier stable isotopes in the fluids appear to correspond to higher formation water content and lower fracturing fluid content,as well as higher fracturing performance.A systematic analysis of the geochemical characteristics and flowback pattern of fracturing fluids indirectly provides insights into the flow path of formation water,water body mixing,rock-water interactions,and fluid sources.Besides,the analysis offers a new perspective for understanding the preservation conditions and fracturing performance of shale gas reservoirs.
文摘Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do not produce satisfactory results when conventional fracturing fluids with a low pumping rate are used.In response to the above problem,a fracturing fluid with a density of 1.2~1.4 g/cm^(3)was developed by using Potassium formatted,hydroxypropyl guanidine gum and zirconium crosslinking agents.The fracturing fluid was tested and its ability to maintain a viscosity of 100 mPa.s over more than 60 min was verified under a shear rate of 1701/s and at a temperature of 175℃.This fluid has good sand-carrying performances,a low viscosity after breaking the rubber,and the residue content is less than 200 mg/L.Compared with ordinary reconstruction fluid,it can increase the density by 30%~40%and reduce the wellhead pressure of 8000 m level reconstruction wells.Moreover,the new fracturing fluid can significantly mitigate safety risks.
基金Supported by National Natural Science Foundation of China(51674209)Sichuan Province Youth Science and Technology Innovation Team(2021JDTD0017).
文摘Static adsorption and dynamic damage experiments were carried out on typical 8#deep coal rock of the Carboniferous Benxi Formation in the Ordos Basin,NW China,to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption.The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy,and the main controlling factors of the thickener adsorption were analyzed.Meanwhile,the adsorption mechanism of the thickener was revealed by Zeta potential,Fourier infrared spectroscopy and X-ray photoelectron spectroscopy.The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g,and the permeability of coal rock after adsorption decreases by 35.24%–37.01%.The adsorption capacity of polyacrylamide is 3.29 mg/g,and the permeability of coal rock after adsorption decreases by 14.31%–21.93%.The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature,and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of polyacrylamide adsorption layer more concentrated.Functional group condensation and intermolecular force are chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock.Optimization of thickener mass fraction,chemical modification of thickener molecular,oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.
基金financially supported by the National Basic Research Program of China (973 Program) Granted No. 2015CB250903the National Natural Science Foundation of China Granted No. 51490652The Chongqing Institute of Geology and Mineral Resources supported this field work
文摘Spontaneous imbibition of water-based frac- turing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the frac- turing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KC1 solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most impor- tant factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The aver- age ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KC1 solution can inhibit clay absorption to reduce the imbibition capacity.
基金supported by the Frontier and Fundamental Research of Active Nanofluids Flooding for Enhanced Oil Recovery through Discontinuous and Variable-circle Modes in High Temperature and High Salinity Offshore Oilfields(U22B6005)National Natural Science Foundation of China(No.52274037)Study on Key Issues of Enhanced Oil Recovery of Gulong Shale Oil(DQYT-2022-JS-761).
文摘China's continental shale exhibits favorable geological characteristics and substa ntial resource potential,yet oil recovery for natural energy extraction remains critically low.Investigating the mechanisms of hydraulically induced bedding fracture to generate complex fracture networks in continental shale,and establishing effective flow systems,is of utmost importance.This study employs laboratory experiments and numerical simulations to investigate the flow capacity and percolation behavior of hydraulically induced bedding fractures by different fluids in full-diameter shale cores.Hydraulic stimulation using different fluids generates bedding plane fracture networks,establishing effective flow systems.Eroded and detached shale fragments support localized fractures,thereby increasing their opening and enhancing flow capacity.Cetyltrimethylammonium bromide(CTAB) solution and SiO2 solution reduce the hydration of the shale surface,preventing shale fragments from swelling and disintegrating,leading to more stable percolation behavior.Eroded and spalled shale fragments near the injection point are transported to farther locations,where they help support localized fractures.This process differs from conve ntional hydraulic fractu ring.Under a constant injection rate,the velocity in the smaller flow paths near the closure is significantly higher than that in the main flow paths,leading to pronounced bypass flow behavio r.This restricts the pe rcolation of fluid du ring imbibition in shale co res.The results provide valuable insights into the mechanism of hydraulically induced bedding fracture in continental shale,offering guidance for the effective development of shale reservoirs.
文摘This study investigated the micro-sliding frictional behavior of shale in fracturing fluids under varying operational conditions using Chang 7 shale oil reservoir core samples.Through systematic micro-sliding friction experiments,the characteristics and governing mechanisms of shale friction were elucidated.Complementary analyses were conducted to characterize the mineral composition,petrophysical properties,and micromorphology of the shale samples,providing insights into the relationship between microscopic structure and frictional response.In this paper,the characteristics and variation law of shale micro-sliding friction under different types of graphite materials as additives in LGF-80(Low-damage Guar Fluid)oil flooding recoverable fracturing fluid system were mainly studied.In addition,the finite element numerical simulation experiment of hydraulic fracturing was adopted to study the influence of the friction coefficient of natural fracture surfaces on fracture propagation and formation of the fracture network.The geometric complexity of fracture networks was systematically quantified under varying frictional coefficients of natural fracture surfaces through multi-parametric characterization and morphometric analysis.The research results show that graphite micro-particles reduce friction and drag.Based on this,this paper proposes a new idea of graphite micro-particles as an additive in the LGF-80 oil flooding recoverable fracturing fluid system to reduce friction on the fracture surface.
基金financially supported by the National Natural Science Foundation of China(Nos.52304129 and 52274130)Natural Science Foundation of Sichuan Province(No.2024NSFSC0971)+1 种基金Guizhou Provincial Basic Research Program(Natural Science)(No.ZK[2023]general 070)Shandong Key Laboratory of Mining Disaster Prevention and Control,Shandong University of Science and Technology(No.SMDPC202403)。
文摘The combination of ultrasonic and acid fracturing fluid can strengthen the modification effect on the micropore structure of the coal matrix,thereby enhancing the efficiency of the acid fracturing process.In this research,acetic acid was utilized to formulate acid fracturing fluids with varying concentrations,and the evolutionary traits of both the acid fracturing fluids and ultrasonic waves in relation to coal samples were investigated.The functional group structure,mineral composition,micropore structure and surface morphology of coal samples were characterized by FTIR,XRD,N_(2)adsorption at low temperature and SEM-EDS.The results showed that aromatics(I)and branching parameters(CH_(2)/CH_(3))were reduced by 81.58%and 88.67%,respectively,after 9%acetic acid treatment.Acetic acid can dissolve carbonates and clay minerals in coal,create new pores,and increase porosity,pore volume and pore fractal dimension.After modification by 7%acetic acid,the pore volume increased by 5.7 times.SEM observation shows that the diameter of coal surface holes increases,EDS scanning shows that the content of mineral elements in coal decreases,the connectivity of coal holes increases,and the holes expand.The findings of this research offer theoretical direction for optimizing ultrasonic-enhanced acid fracturing fluid modification.
基金Supported by the National Natural Science Foundation of China(NSFC)-Enterprise Innovation and Development Joint Fund Key Project(U24B2018)the Distinguished Young Scholars Program of the National Natural Science Foundation of China(42125205).
文摘Low-salinity fracturing fluids tend to induce ion migration,alter wettability,and cause fluctuations in gas desorption efficiency when penetrating deep coal seams.Taking the No.8 coal from the Daning-Jixian area in the Ordos Basin,NW China,as a representative example,this study employs physical simulation experiments to reveal the coupled control mechanism of salinity gradient on the ion-coal matrix-gas/water interfacial system and its key role in the imbibition-desorption process.The increasing ionic concentration improves the hydrophobicity of coal,with multivalent ions exhibiting particularly significant effects.The imbibition and ion diffusion occur in opposite directions,with imbibition equilibrium being achieved earlier than ionic equilibrium.Water-coal interactions induce both mineral dissolution and secondary precipitation.When a low-salinity fracturing fluid is injected into a high-salinity reservoir,the osmotic-pressure difference drives imbibition,promotes CH4 desorption,but results in higher fluid loss.Conversely,injecting high-salinity fracturing fluid into a low-salinity reservoir creates a reverse osmotic gradient that suppresses leak-off while improving flowback efficiency.Based on these findings,a high-low salinity sequential injection strategy is proposed for deep coal seams:high-salinity fluid is first injected to form stable fracture networks,followed by low-salinity fluid to enlarge the imbibition zone and enhance CH4 desorption and diffusion.Moderate well soaking is recommended to increase the imbibition volume,thereby achieving multiple positive effects such as maintaining reservoir pressure,preserving formation energy,and promoting imbibition-driven displacement.
基金supported by the National Natural Science Foundation of China(Grant.Nos.52364004,52464005)the Youth Talent Growth Project of Guizhou Provincial Department of Education(Grant No.QianJiaoJi[2024]18).
文摘Injection rate is crucial for determining the hydraulic fracturing effectiveness;however,the effects of the injection rate on the pore and fracture structure(PFS)and fluid infiltration during injection pressurization have rarely been explored.In this study,the cylindrical sandstone samples were hydraulically fractured at various injection rates on a self-developed integrated nuclear magnetic resonance(NMR)and hydraulic fracturing experimental system.The results show that low injection rates predominantly resulted in macropore-scale damage by creating intergranular cracks,whereas high injection rates facilitated micropore-scale damage,probably owing to the adsorption swelling effect of clay minerals within pores.Additionally,the water contents of the samples with low injection rates exhibited a continuous increase,whereas those of the samples with high injection rates initially increased and subsequently stabilized.Magnetic resonance imaging(MRI)indicated that fluid infiltration during the fracturing process exhibited high anisotropy owing to the inherent heterogeneous PFS distributions around the wellbore.Moreover,a primary fluid infiltration path exists that aligns with the initiation direction of the hydraulic fractures.However,the fluid infiltration damage distance along the hydraulic fracture direction decreased with increasing injection rate,whereas the fluid infiltration damage distance perpendicular to the hydraulic fracture direction was approximately equal to the characteristic length,regardless of the injection rate.Finally,we recommend using the pore damage during fluid pressurization as the basis for selecting the proppant size and employing a primary fluid infiltration path to predict hydraulic fracture initiation.These findings provide valuable insights into the design of hydraulic fracturing in tight gas reservoirs.
文摘As oil and gas development increasingly targets unconventional reservoirs,the limitations of conventional hydraulic fracturing,namely high water consumption and significant reservoir damage,have become more pronounced.This has driven growing interest in the development of clean fracturing fluids that minimize both water usage and formation impairment.In this study,a low-liquid-content viscoelastic surfactant(VES)foam fracturing fluid system was formulated and evaluated through laboratory experiments.The optimized formulation comprises 0.2%foaming agent CTAB(cetyltrimethylammonium bromide)and 2%foam stabilizer EAPB(erucamidopropyl betaine).Laboratory tests demonstrated that the VES foam system achieved a composite foam value of 56,700 mL・s,reflecting excellent foaming performance.Proppant transport experiments revealed minimal variation in suspended sand volume over 120 min across different sand ratios,indicating robust sand-carrying capacity even at high proppant concentrations.Rheological measurements showed that the fluid maintained a viscosity above 120 mPa・s after 120 min of shearing at 70℃ and a shear rate of 170 s−1,with the elastic modulus exceeding the viscous modulus,confirming the system’s exceptional stability and resilience.Furthermore,core damage tests indicated that the VES foam caused only 4.42%formation damage,highlighting its potential for efficient and low-damage stimulation of tight reservoirs.Overall,the findings demonstrate that this low-liquid-content VES foam provides a highly effective,environmentally considerate alternative for hydraulic fracturing in unconventional formations,combining superior proppant transport,rheological stability,and minimal reservoir impairment.
基金Supported by the U.S.Department of Energy’s Office of Energy Efficiency and Renewable Energy(EERE)under the Geothermal Technologies Office(GTO)“Innovative Methods to Control Hydraulic Properties of Enhanced Geothermal Systems”(DE-EE0009790).
文摘To understand the applicability of high-temperature preformed particle gel(HT-PPG)for control of short-circuiting in enhanced geothermal systems(EGSs),core flooding experiments were conducted on fractured granite cores under varying fracture widths,gel particle sizes and swelling ratios.Key parameters such as injection pressure,water breakthrough pressure,and residual resistance factor were measured to evaluate HT-PPG performance.The gel exhibited strong injectability,entering granite fractures at pressure gradients as low as 0.656 MPa/m;HT-PPG yields a superior sealing performance by significantly reducing the permeability;and dehydration occurs during HT-PPG propagation,with a dehydration ratio ranging from 4.71%to 11.36%.This study reveals that HT-PPG can be injected into geothermal formations with minimal pressure yet provides strong resistance to breakthrough once in place.This balance of injectability and sealing strength makes HT-PPG effective for addressing thermal short-circuiting in EGS reservoirs.
基金supported by the Sichuan Youth Science and Technology Innovation Research Team Project(No.2021JDTDO017)the open Fund(PLN2022-11)of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation(Southwest Petroleum University)+1 种基金Southwest Petroleum University Graduate Innovation Fund(No.2022KYCX021)Jian Tian would like to acknowledge the funding from the National Natural Science Foundation of China(52404023).
文摘To elucidate the adsorption characteristics and retention mechanisms of fracturing fluids in diverse clay minerals,we conducted on-line nuclear magnetic resonance(NMR)and atomic force microscopy(AFM)experiments.The depth and extent of solid phase damage are determined by the ratio between the size of fine fractions in fracturing fluid residue and the pore-throat size in experiments.Poor physical properties(K<0.5 mD)result in a more preferential flow pathway effect during flowback,and the stepwise incremental pressure differential proves to be more effective for the discharge of fracturing fluid in submicron pore throats.The permeability is significantly influenced by the differential distri-bution of retained fracturing fluid,as supported by direct experimental evidence.The presence of good physical properties(K>0.5 mD)combined with a scattered distribution of retained fracturing fluid is associated with high gas phase recovery permeability,whereas a continuous sheet-like distribution results in low recovery permeability.The expansive surface area and presence of filamentous illite minerals facilitate the multiple winding and adsorption of fracturing fluids,demonstrating strong hydrogen-bonding,multi-layering and multiple adsorption properties.The geological characteristics of the main gas formations exhibit significant variation,and the severity of damage caused by fracturing fluids occurs in diverse sequences.To address this issue,a differentiated strategy for optimizing frac-turing fluids has been proposed.
基金supported by the National Natural Science Foundation of China(Nos.52164001,52064006,52004072 and 52364004)the Science and Technology Support Project of Guizhou(Nos.[2020]4Y044,[2021]N404 and[2021]N511)+1 种基金the Guizhou Provincial Science and Technology Foundation(No.GCC[2022]005-1),Talents of Guizhou University(No.201901)the Special Research Funds of Guizhou University(Nos.201903,202011,and 202012).
文摘With the widespread adoption of hydraulic fracturing technology in oil and gas resource development,improving the accuracy and efficiency of fracturing simulations has become a critical research focus.This paper proposes an improved fluid flow algorithm,aiming to enhance the computational efficiency of hydraulic fracturing simulations while ensuring computational accuracy.The algorithm optimizes the aperture law and iteration criteria,focusing on improving the domain volume and crack pressure update strategy,thereby enabling precise capture of dynamic borehole pressure variations during injection tests.The effectiveness of the algorithm is verified through three flow-solid coupling cases.The study also analyzes the effects of borehole size,domain volume,and crack pressure update strategy on fracturing behavior.Furthermore,the performance of the improved algorithm in terms of crack propagation rate,micro-crack formation,and fluid pressure distribution was further evaluated.The results indicate that while large-size boreholes delay crack initiation,the cracks propagate more rapidly once formed.Additionally,the optimized domain volume calculation and crack pressure update strategy significantly shorten the pressure propagation stage,promote crack propagation,and improve computational efficiency.
基金supported by the National Natural Science Foundation of China(Grant No.52222403 and U24B2033)Taishan Scholar Program,China(Grant No.tsqn202211079)State Key Laboratory of Deep Oil and Gas,China(Grant No.SKLDOG2024-ZYTS-15).
文摘CO_(2) foam fracturing fluid can effectively integrate CCUS technology into oil and gas field development,and its core advantages include low water consumption,excellent flowback performance,and strong sand-carrying capacity.For these reasons,it has received increasing attention in the oil and gas field development field.However,this type of fracturing fluid still has some prominent problems:The residue from gel breaking can easily cause formation pollution,the system cost is relatively high,and the utilization rate is low,which forms a significant technical bottleneck.In response to these issues,this study,based on the theory of clean fracturing fluid gel breaking without residue and the reusability of CO_(2)-responsive wormlike micelles,innovatively combines CO_(2)-responsive wormlike micelles with different types of surfactant-based foaming agents to construct a new CO_(2)-responsive foam fracturing fluid system.A systematic performance evaluation of the system was conducted to clarify its defoaming rules under different temperature conditions.Compared with the traditional guar gum CO_(2) foam fracturing fluid,the new system has significant performance advantages.At 90℃,its foam comprehensive value reached 19720 mL·min,6150 mL·min higher than the guar gum fluid.After a 5400 s high-temperature and high-shear test at the same temperature,the residual viscosity of the new system was 67 mPa·s,which is higher than the guar gum fluid.This CO_(2)-responsive foam fracturing fluid simultaneously possesses the application potential of both clean fracturing fluid and foam fracturing fluid.It can effectively solve key problems such as formation pollution and low system utilization rates,and laboratory evaluation experiments confirmed its excellent foaming and rheological properties.These results are of great significance for promoting CO_(2) foam fracturing technology to reach an advanced international level and supporting the low-carbon and highefficiency development of unconventional oil and gas resources in China.
基金funded by the National key R&D Program of China(No.2023YFE0120700)the National Natural Science Foundation of China(No.51934005)+2 种基金the Shaanxi Province 2023 Innovation Capability Support Plan(No.2023KJXX-122)the Technology Innovation Leading Program of Shaanxi(No.2022 PT-08)the Project of Youth Innovation Team of Shaanxi Universities(No.22JP063).
文摘The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation(also referred to as the He 8 Member)in the study area,as well as their effects on fracturing fluid imbibition.Utilizing experimental techniques such as nuclear magnetic resonance(NMR),high-pressure mercury intrusion(HPMI),and gas adsorption,this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments.The findings reveal that:①The reservoir,with average porosity of 8.40%and average permeability of 0.642×10^(-3)μm^(2),consists principally of quartz,feldspar,and lithic fragments,with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral;②Nano-scale micro-pores and throats dominate the reservoir,with dissolution pores and intercrystalline pores serving as predominant pore types,exhibiting relatively high pore connectivity;③Imbibition efficiency is influenced by petrophysical properties,clay mineral content,and microscopic pore structure.Due to the heterogeneity of the tight sandstone reservoir,microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids;④A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency,followed by petrophysical properties and clay mineral content.In contrast,the pore type has minimal impact.Micropores are vital in the imbibition process,while meso-pores and macro-pores offer primary spaces for imbibition.This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones.
基金financial support from the National Natural Science Foundation of China(Grant No.52104013 and 51490651)the China Postdoctoral Science Foundation(Grant No.2022T150724).
文摘Hydraulic fracturing has become the main technology for the efficient development of geothermal energy in hot dry rock(HDR),however,few studies on the propagation behavior and mechanism of HDR hydraulic fractures under high-temperature conditions have investigated.In this paper,a large-size high-temperature true triaxial hydraulic fracturing physical modeling apparatus is designed,and hydraulic fracturing experiments with it are performed to investigate the fracture initiation and propagation behavior in natural granite samples collected from Gonghe Basin,thefirst HDR site in China.The experimental results show that the designed high-temperature apparatus provides a constant-temperature condition during the whole hydraulic fracturing process and the maximum temperature can reach 600℃,showing its ability to simulate realistic temperatures and pressures in both ultra-deep and HDR formations.Although the tensile strength of the rock samples remains almost unchanged at a temperature of 200℃,the cooling effects of the fracturingfluid in high-temperature rock can induce the formation of microfractures and significantly reduce the rock strength,thus lowering the breakdown pressure and increasing the complexity of the hydraulic fracture morphology.Compared with traditional oil and gas reservoirs,the hydraulic fractures in HDR are rougher and the specific surface area of a single fracture is larger,which can be helpful for heat extraction.This study provides a basis for understanding hydraulic fracture geometries andfield construction design in HDRs.
文摘Fracturing operations can effectively improve the production of low-permeable reservoirs. The performance of fracturing fluids directly affects the fracturing efficiency and back flow capacity. As polymerbased fracturing fluids(such as guar gum(GG), polyacrylamide(HPAM), etc.) are high-viscosity fluids formed by viscosifiers and crosslinking agents, the degree of gel breakage after the fracturing operation directly influences the damage degree to the reservoir matrix and the mobility of oil angd gas produced from the reservoir into the wellbore. This study compared the viscosity, molecular weight, and particle size of the fracturing fluid after gel breakage prepared by GG and HPAM as viscosifiers, as well as evaluate their damage to the core. Results show that the viscosities of the gel-breaking fluid increased with the concentration of the viscosifier for both the HPAM-based and GG-based fracturing fluids. For the breaking fluid with the same viscosity, the molecular weight in the HPAM-based gel-breaking fluid was much larger than that in the GG-based system. Moreover, for the gel-breaking fluid with the same viscosity, the molecular particle size of the residual polymers in the HPAM-based system was smaller than that in the GG-based system. The damage to the core with the permeability of 1 × 10^(-3)μm^(2) caused by both the HPAM-based and GG-based gel-breaking fluids decreased with the increase in the solution viscosity. For the gel-breaking fluid systems with the same viscosity(i.e., 2-4 mPa s), the damage of HPAM-based fracturing fluid to low-permeability cores was greater than the GG-based fracturing fluid(45.6%-80.2%) since it had a smaller molecular particle size, ranging from 66.2% to 77.0%. This paper proposed that the damage caused by hydraulic fracturing in rock cores was related to the partilce size of residual polymers in gel-breaking solution, rather than its molecular weight. It was helpful for screening and optimizing viscosifiers used in hydraulic fracturing process.
文摘The variable-density flow model-SEAWAT Version 4, was used to evaluate the hydrogeological conditions associatedwith hydraulic fracturing （fracking） the limestone oil reservoir in the Lower Cretaceous Sunniland Formation of Southwest Florida.This research contributes to the understanding of the controls on fluid and potential contaminant migration, following high pressurehydraulic fracturing. A hydraulic fracturing treatment used recently in this formation at the Collier-Hogan 20-3H well represents thebase case simulation. Multiple stage fracturing using typical stress periods, a modelled fracture zone radius, and various injectionrates were tested to evaluate the potential for horizontal and vertical fluid migration in and from the reservoir under dynamicconditions, with TDS used as a tracer. Hypothetical scenarios including preferential vertical pathways between the SunnilandFormation and the Lower Floridan aquifer Boulder Zone were also simulated. Results indicate that injected fluids do not migratesignificantly in the lateral and vertical directions beyond the design fractured zone, unless a preferential pathway exists within closeproximity to the fractured zone. In a worst-case scenario under the simulated conditions, vertical heads are approximately 580 metersgreater than static conditions and fluids associated with hydraulic fracturing vertically migrate approximately 500 meters; therefore,the quality of the deepest sources of drinking water is not compromised. Analytical results from a monitoring well installed in theimmediate vicinity of the Collier-Hogan 20-3H well and at the base of the deepest source of drinking water support the conclusionthat impacts from hydraulic fracturing fluids have not migrated into the deepest sources of drinking water.
