Microscopic characteristics of tight sandstone reservoirs and their effects on the imbibition efficiency of fracturing fluids:A case study of the Linxing area,Ordos Basin

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.

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

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.

A review of reservoir damage during hydraulic fracturing of deep and ultra-deep reservoirs

Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide.These reservoirs present unique challenges due to their deep burial depth(4500-8882 m),low matrix permeability,complex crustal stress conditions,high temperature and pressure(HTHP,150-200℃,105-155 MPa),coupled with high salinity of formation water.Consequently,the costs associated with their exploitation and development are exceptionally high.In deep and ultra-deep reservoirs,hydraulic fracturing is commonly used to achieve high and stable production.During hydraulic fracturing,a substantial volume of fluid is injected into the reservoir.However,statistical analysis reveals that the flowback rate is typically less than 30%,leaving the majority of the fluid trapped within the reservoir.Therefore,hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved.The challenging“three-high”environment of a deep reservoir,characterized by high temperature,high pressure,and high salinity,exacerbates conventional forms of damage,including water sensitivity,retention of fracturing fluids,rock creep,and proppant breakage.In addition,specific damage mechanisms come into play,such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions.Presently,the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing,comprehending the underlying mechanisms,and selecting appropriate solutions.It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs,with limited attention given to deep reservoirs and a lack of systematic summaries.In light of this,our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs.Subsequently,we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs,taking into account the unique reservoir characteristics of high temperature,high pressure,and high in-situ stress.In addition,we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix,both artificial and natural fractures,and sand-packed fractures.We conclude by offering a summary of current research advancements and future directions,which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage.

Influences of clean fracturing fluid viscosity and horizontal in-situ stress difference on hydraulic fracture propagation and morphology in coal seam

The viscosity of fracturing fluid and in-situ stress difference are the two important factors that affect the hydraulic fracturing pressure and propagation morphology. In this study, raw coal was used to prepare coal samples for experiments, and clean fracturing fluid samples were prepared using CTAB surfactant. A series of hydraulic fracturing tests were conducted with an in-house developed triaxial hydraulic fracturing simulator and the fracturing process was monitored with an acoustic emission instrument to analyze the influences of fracturing fluid viscosity and horizontal in-situ stress difference on coal fracture propagation. The results show that the number of branched fractures decreased, the fracture pattern became simpler, the fractures width increased obviously, and the distribution of AE event points was concentrated with the increase of the fracturing fluid viscosity or the horizontal in-situ stress difference. The acoustic emission energy decreases with the increase of fracturing fluid viscosity and increases with the increase of horizontal in situ stress difference. The low viscosity clean fracturing fluid has strong elasticity and is easy to be compressed into the tip of fractures, resulting in complex fractures. The high viscosity clean fracturing fluids are the opposite. Our experimental results provide a reference and scientific basis for the design and optimization of field hydraulic fracturing parameters.

Supramolecular polymer-based gel fracturing fluid with a double network applied in ultra-deep hydraulic fracturing

A gel based on polyacrylamide,exhibiting delayed crosslinking characteristics,emerges as the preferred solution for mitigating degradation under conditions of high temperature and extended shear in ultralong wellbores.High viscosity/viscoelasticity of the fracturing fluid was required to maintain excellent proppant suspension properties before gelling.Taking into account both the cost and the potential damage to reservoirs,polymers with lower concentrations and molecular weights are generally preferred.In this work,the supramolecular action was integrated into the polymer,resulting in significant increases in the viscosity and viscoelasticity of the synthesized supramolecular polymer system.The double network gel,which is formed by the combination of the supramolecular polymer system and a small quantity of Zr-crosslinker,effectively resists temperature while minimizing permeability damage to the reservoir.The results indicate that the supramolecular polymer system with a molecular weight of(268—380)×10^(4)g/mol can achieve the same viscosity and viscoelasticity at 0.4 wt%due to the supramolecular interaction between polymers,compared to the 0.6 wt%traditional polymer(hydrolyzed polyacrylamide,molecular weight of 1078×10^(4)g/mol).The supramolecular polymer system possessed excellent proppant suspension properties with a 0.55 cm/min sedimentation rate at 0.4 wt%,whereas the0.6 wt%traditional polymer had a rate of 0.57 cm/min.In comparison to the traditional gel with a Zrcrosslinker concentration of 0.6 wt%and an elastic modulus of 7.77 Pa,the double network gel with a higher elastic modulus(9.00 Pa)could be formed only at 0.1 wt%Zr-crosslinker,which greatly reduced the amount of residue of the fluid after gel-breaking.The viscosity of the double network gel was66 m Pa s after 2 h shearing,whereas the traditional gel only reached 27 m Pa s.

Formation damage mechanism and control strategy of the compound function of drilling fluid and fracturing fluid in shale reservoirs

For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid,the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid.With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface,fracture closure and rock powder blocking,the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid.The formation damage mechanism during drilling and completion process in shale reservoir is revealed,and the protection measures are raised.The drilling fluid can deeply invade into the shale formation through natural and induced fractures,erode shale minerals and weaken the mechanical properties of shale during the drilling process.In the process of hydraulic fracturing,the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale,results in fracture closure and rock powder shedding,and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures.The damage can yield significant conductivity decrease of fractures,and restrict the high and stable production of shale oil and gas wells.The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section,forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface,strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid,optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.

Optimization method of fracturing fluid volume intensity for SRV fracturing technique in shale oil reservoir based on forced imbibition:A case study of well X-1 in Biyang Sag of Nanxiang Basin,China

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example.The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing.The optimization of the stimulated reservoir volume(SRV)fracturing fluid volume strength should meet the requirements of estimated ultimate recovery(EUR),increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount.Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed,above which the single-well EUR increase rate kept decreasing.An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production.Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

A Novel Fracturing Fluid with High-Temperature Resistance for Ultra-Deep Reservoirs

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.

Research on the Performance of New Weighted Slippery Water Fracturing Fluid System

Deep and ultra-deep reservoirs have dense matrix and high fracture pressure, which leads to high pressure and difficulty in fracturing construction. Conventional aggravated fracturing fluids have the problems of low aggravation efficiency, high friction resistance, etc., and the reduction of construction pressure cannot reach the theoretical effect. In view of the above problems, this paper adopts the weighting agent HD160 and the drag reducing agent JHFR-2 to form a new type of weighted slippery water fracturing fluid system. And the weighting performance, drag reduction performance, corrosion performance, anti-expansion performance and reservoir damage of this system were studied. The results show that the density of the system is adjustable within 1.1 - 1.6 g·cm−3, and the drag reduction rate can be up to 68% at 1.5 g·cm−3, with low corrosion rate, surface tension less than 28 mN·m−1, anti-expansion rate as high as 94.5%, and the damage rate of the reservoir permeability is less than 10%, which is of good application prospect.

Intermolecular interactions induced property improvement for clean fracturing fluid by deep eutectic solvents

Fracturing fluid property play a critical role in developing unconventional reservoirs.Deep eutectic solvents(DESs)show fascinating potential for property improvement of clean fracturing fluids(CFFs)due to their low-price,low-toxicity,chemical stability and flexible designability.In this work,DESs were synthesized by mixing hydrogen bond acceptors(HBAs)and a given hydrogen bond donor(HBD)to explore their underlying influence on CFF properties based on the intermolecular interactions.The hydrogen-bonding,van der Waals and electrostatic interactions between DES components and surfactants improved the CFF properties by promoting the arrangement of surfactants at interface and enhancing the micelle network strength.The HBD enhanced the resistance of CFF for Ca^(2+) due to coordination-bonding interaction.The DESs composed of choline chloride(ChCl)and malonic acid show great enhancement for surface,rheology,temperature resistance,salt tolerance,drag reduction,and gel-breaking performance of CFFs.The DESs also improved the gel-breaking CFF-oil interactions,increasing the imbibition efficiencies to 44.2%in 74 h.Adjusting HBAs can effectively strengthen the intermolecular interactions(e.g.,HBA-surfactant and HBD-surfactant interactions)to improve CFF properties.The DESs developed in this study provide a novel strategy to intensify CFF properties.

A review of crosslinked fracturing fluids prepared with produced water

The rapidly increasing implementations of oilfield technologies such as horizontal wells and multistage hydraulic fracturing,particularly in unconventional formations,have expanded the need for fresh water in many oilfield locations.In the meantime,it is costly for services companies and operators to properly dispose large volumes of produced water,generated annually at about 21 billion barrels in the United States alone.The high operating costs in obtaining fresh water and dealing with produced water have motivated scientists and engineers,especially in recent years,to use produced water in place of fresh water to formulate well treatment fluids.The objective of this brief review is to provide a summary of the up-to-date technologies of reusing oilfield produced water in preparations of a series of crosslinked fluids implemented mainly in hydraulic fracturing operations.The crosslinked fluids formulated with produced water include borate-and metalcrosslinked guar and derivatized guar fluids,as well as other types of crosslinked fluid systems such as crosslinked synthetic polymer fluids and crosslinked derivatized cellulose fluids.The boratecrosslinked guar fluids have been successfully formulated with produced water and used in oilfield operations with bottomhole temperatures up to about 250
F.The produced water sources involved showed total dissolved solids(TDS)up to about 115,000 mg/L and hardness up to about 11,000 mg/L.The metal-crosslinked guar fluids prepared with produced water were successfully used in wells at bottomhole temperatures up to about 250
F,with produced water TDS up to about 300,000 mg/L and hardness up to about 44,000 mg/L.The Zr-crosslinked carboxymethyl hydroxypropyl guar(CMHPG)fluids have been successfully made with produced water and implemented in operations with bottomhole temperatures at about 250t
F,with produced water TDS up to about 280,000 mg/L and hardness up to about 91,000 mg/L.In most of the cases investigated,the produced water involved was either untreated,or the treatments were minimum such as simple filtration without significantly changing the concentrations of monovalent and divalent ions in the water.Due to the compositional similarity(high salinity and hardness)between produced water and seawater,crosslinked fluids formulated with seawater for offshore and onshore jobs were also included.The crosslinked guar and derivatized guar fluids have been successfully formulated with seawater for operations at bottomhole temperatures up to about 300
F.Operating costs have been significantly reduced when produced water or seawater is used to formulate fracturing fluids in place of fresh water.With various challenges and limitations still existing,the paper emphasizes the needs for new developments and further expansion of produced water reuse in oilfield operations.

Probing the influence of secondary fracture connectivity on fracturing fluid flowback efficiency

A deep understanding of the geometric impacts of fracture on fracturing fluid flowback efficiency is essential for unconventional oil development. Using nuclear magnetic resonance and 2.5-dimensional matrix-fracture visualization microfluidic models, qualitative and quantitative descriptions of the influences of connectivity between primary fracture and secondary fracture on flowback were given from core scale to pore network scale. The flow patterns of oil-gel breaking fluid two-phase flow during flowback under different fracture connectivity were analyzed. We found some counterintuitive results that non-connected secondary fracture (NCSF, not connect with artificial primary fracture and embedded in the matrix) is detrimental to flowbackefficiency. The NCSF accelerates the formation of oil channeling during flowback, resulting in a large amount of fracturing fluid trapped in the matrix, which is not beneficial for flowback. Whereas the connected secondary fracture (CSF, connected with the artificial primary fracture) is conducive to flowback. The walls of CSF become part of primary fracture, which expands the drainage area with low resistance, and delays the formation of the oil flow channel. Thus, CSF increases the high-speed flowback stage duration, thereby enhancing the flowback efficiency. The fracturing fluid flowback efficiency investigated here follows the sequence of the connected secondary fracture model (72%) > the matrix model (66%) > the non-connected secondary fracture model (38%). Our results contribute to hydraulic fracturing design and the prediction of flowback efficiency.

A novel triple responsive smart fluid for tight oil fracturing-oil expulsion integration

The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies,such as low recovery efficiency,rapid production decline,high cost,and complexity,etc.Therefore,a new technology,the so-called fracturing-oil expulsion integration,which does not need flowback after fracturing while making full use of the fracturing energy and gel breaking fluids,are needed to enable efficient exploitation of tight oil.A novel triple-responsive smart fluid based on“pseudo-Gemini”zwitterionic viscoelastic surfactant(VES)consisting of N-erucylamidopropyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate(EHSB),N,N,N′,N′-tetramethyl-1,3-propanediamine(TMEDA)and sodium p-toluenesulfonate(NaPts),is developed.Then,the rheology of smart fluid is systematically studied at varying conditions(CO_(2),temperature and pressure).Moreover,the mechanism of triple-response is discussed in detail.Finally,a series of fracturing and spontaneous imbibition performances are systematically investigated.The smart fluid shows excellent CO_(2)-,thermal-,and pressure-triple responsive behavior.It can meet the technical requirement of tight oil fracturing construction at 140°C in the presence of 3.5 MPa CO_(2).The gel breaking fluid shows excellent spontaneous imbibition oil expulsion(∼40%),salt resistance(1.2×104 mg/L Na+),temperature resistance(140°C)and aging stability(30 days).

The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS_(2)nanosheets

Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing;however,lots of challenges and limitations such as low viscosity,poor salt tolerance,and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid.In addition,nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater.In this paper,molybdenum disulfide(MoS_(2))nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid.Firstly,the microstructure characteristics and crystal type of the MoS_(2)nanosheets were analyzed by SEM,EDS,TEM,XPS,and Raman spectroscopy techniques.Then,a series of evaluation experiments were carried out to compare the performance of MoS_(2)nanosheet-modified slickwater with the conventional slickwater,including rheology,drag reduction,and sand suspension.Finally,the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated.The results showed that the self-synthesized MoS_(2)nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers.In the nano-composites,each MoS_(2)nanosheet plays the role of cross-linking point,so as to make the spatial structure of the entire system more compact.Moreover,nanosheet-modified slickwater demonstrates more excellent properties in rheology,drag reduction,and sand suspension.The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90℃ and 170 s^(−1).The maximum drag reduction rate achieved 76.3%at 20℃,and the sand settling time of proppants with different mesh in the nano-composites was prolonged.Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching,and increase the oil recovery to∼35.43%.By observing and analyzing the interfacial behavior of MoS_(2)nanosheets under stimulated reservoir conditions,it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism.This work innovatively uses two-dimensional MoS_(2)nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater.The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites.

Preparation of a functional fracturing fluid with temperature-and salt-resistance,and low damage using a double crosslinking network

Fracturing fluids(FFs)have been widely used to stimulate the tight reservoir.However,current FFs will not only lose their rheological property at high temperatures and high salt but also show an incomplete gel-breaking property.Herein,a double crosslinking network FF with pretty superiorities in rheology and low damage to the core was constructed by introducing both physical crosslinking and chemical crosslinking into the system.The construction of double crosslinking networks enhanced the rheology of this functional FF.The particle sizes of gel-breaking fluids are mainly distributed in 1.0e10,000 nm;furthermore,for every 10,000 mg/L increase in salinity,the particle size of the gel-breaking fluid is decreased by almost half.The adsorption capacity(<1.0 mg/g)gradually decreased with the increase of salinity at 20℃.Moreover,the adsorption of gel-breaking fluids on the rock decreased first and then kept stable with temperature increasing at a salinity of ≤30,000 mg/L,however,showed the opposite trend at 40,000 mg/L.The results of rheology,particle size,static adsorption,and core damage showed that this functional FF could be an alternative for the stimulation of a tight reservoir with high temperature and recycling of produced water with high salinity.

Sensitivity assessment of strontium isotope as indicator of polluted groundwater for hydraulic fracturing flowback fluids produced in the Dameigou Shale of Qaidam Basin

Hydrogeochemical processes that would occur in polluted groundwater and aquifer system,may reduce the sensitivity of Sr isotope being the indicator of hydraulic fracturing flowback fluids(HFFF)in groundwater.In this paper,the Dameigou shale gas field in the northern Qaidam Basin was taken as the study area,where the hydrogeochemical processes affecting Sr isotope was analysed.Then,the model for Sr isotope in HFFF-polluted groundwater was constructed to assess the sensitivity of Sr isotope as HFFF indicator.The results show that the dissolution can release little Sr to polluted groundwater and cannot affect the εSr(the deviation of the 87Sr/86Sr ratio)of polluted groundwater.In the meantime,cation exchange can considerably affect Sr composition in the polluted groundwater.The Sr with low εSr is constantly released to groundwater from the solid phase of aquifer media by cation exchange with pollution of Quaternary groundwater by the HFFF and it accounts for 4.6% and 11.0% of Sr in polluted groundwater when the HFFF flux reaches 10% and 30% of the polluted groundwater,respectively.However,the Sr from cation exchange has limited impact on Sr isotope in polluted groundwater.Addition of Sr from cation exchange would only cause a 0.2%and 1.2% decrease in εSr of the polluted groundwater when the HFFF flux reaches 10% and 30% of the polluted groundwater,respectively.These results demonstrate that hydrogeochemical processes have little effect on the sensitivity of Sr isotope being the HFFF indicator in groundwater of the study area.For the scenario of groundwater pollution by HFFF,when the HFFF accounts for 5%(in volume percentage)of the polluted groundwater,the HFFF can result in detectable shifts of εSr(Δ_(εSr)=0.86)in natural groundwater.Therefore,after consideration of hydrogeochemical processes occurred in aquifer with input of the HFFF,Sr isotope is still a sensitive indicator of the Quaternary groundwater pollution by the HFFF produced in the Dameigou shale of Qaidam Basin.

Temporal variations in geochemistry of hydraulic fracturing fluid and flowback water in a tight oil reservoir

Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64.Freshwater is used for fracturing,and HFF is obtained.The chemical and isotopic parameters(including the water type,total salinity,total dissolved solids(TDS),pH,concentrations of Na^(+),Cl^(-),Ba^(+),K^(+),Fe^(2+)+Fe^(3+),and CO_(3)^(2-),dD,and δ^(18)O)are experimentally obtained,and their variations with time are systematically analyzed based on the flowback water.The results show that the water type,Na/Cl ratio,total salinity,and TDS of the FPW change periodically primarily due to the HFF mixing with formation water,thus causing δD and δ^(18)O to deviate from the meteoric water line of Xinjiang.Because of watererock interaction(WRI),the concentrations of Fe^(2+)+Fe^(3+)and CO_(3)^(2-)of the FPW increase over time,with the solution pH becoming more alkaline.Furthermore,based on the significant changes observed in the geochemistry of the FPW,three separate time intervals of flowback time are identified:Stage Ⅰ(<10 days),where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI;Stage Ⅱ(10-37 days),where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened;and finally,Stage Ⅲ(>37 days),where the FPW is dominated by the chemistry of the formation water.The methodology implemented in this study can provide critical support for the source identification of formation water.

Investigation of influence factors on CO_(2) flowback characteristics and optimization of flowback parameters during CO_(2) dry fracturing in tight gas reservoirs

CO_(2) dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs,especially in water-scarce areas such as the Loess Plateau.The CO_(2) flowback efficiency is a critical factor that affects the final gas production effect.However,there have been few studies focusing on the flowback characteristics after CO_(2) dry fracturing.In this study,an extensive core-to-field scale study was conducted to investigate CO_(2) flowback characteristics and CH_(4) production behavior.Firstly,to investigate the impact of core properties and production conditions on CO_(2) flowback,a series of laboratory experiments at the core scale were conducted.Then,the key factors affecting the flowback were analyzed using the grey correlation method based on field data.Finally,taking the construction parameters of Well S60 as an example,a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs.The production parameters after CO_(2) dry fracturing were then optimized.Experimental results demonstrate that CO_(2) dry fracturing is more effective than slickwater fracturing,with a 9.2%increase in CH_(4) recovery.The increase in core permeability plays a positive role in improving CH_(4) production and CO_(2) flowback.The soaking process is mainly affected by CO_(2) diffusion,and the soaking time should be controlled within 12 h.Increasing the flowback pressure gradient results in a significant increase in both CH_(4) recovery and CO_(2) flowback efficiency.While,an increase in CO_(2) injection is not conducive to CH_(4) production and CO_(2) flowback.Based on the experimental and field data,the important factors affecting flowback and production were comprehensively and effectively discussed.The results show that permeability is the most important factor,followed by porosity and effective thickness.Considering flowback efficiency and the influence of proppant reflux,the injection volume should be the minimum volume that meets the requirements for generating fractures.The soaking time should be short which is 1 day in this study,and the optimal bottom hole flowback pressure should be set at 10 MPa.This study aims to improve the understanding of CO_(2) dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters.

Effect of fracture fluid flowback on shale microfractures using CT scanning

The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs.At the early stage of flowback,there is no single-phase flow of the liquid phase in shale,but rather a gas-water two-phase flow,such that the single-phase flow model for tight oil and gas reservoirs is not applicable.In this study,pores and microfractures are extracted based on the experimental results of computed tomography(CT)scanning,and a spatial model of microfractures is established.Then,the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law,which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness.The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method(LBM).The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures,which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.