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.

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.

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.

Comparative assessment of mechanical and chemical fluid diversion techniques during hydraulic fracturing in horizontal wells

The application of fluid diversion during hydraulic fracturing is an evolving technology and has become popular amongst E&P operators over the past few years.The primary objective of the fluid diversion is to improve hydraulic fracturing treatment by increasing stimulated reservoir volume and improving hydrocarbon recovery.This is possible by achieving any of the following objectives:creating uniform distribution of treatment slurry within the target zone;treating unstimulated and under-stimulated zones;or by increasing fracture density by creating a complex fracture network.The fluid diversion application is also helpful in decreasing the number of stages(by increasing stage length)for multi-stage plug-n-perf(PnP)fracturing treatment.It is also applied to prevent fracture-driven interactions between adjacent wells,which is currently a major issue,especially in shale.In addition,for successful refracturing treatment,the diverter application is essential for isolating the existing fractures and redirecting the treatment slurry to the desired unstimulated zones.The diversion methods can be broadly categorized into the mechanical and chemical diversion.Several established mechanical diversion techniques are frac plugs,expandable casing patches,expandable liners,swellable packers,straddle packer assembly,sand plugs,frac sleeves,perforation ball sealers,and limited entry technique.The different chemical diversion techniques are particulates,fibers,gels,surfactants,perforation pods,and composite diverting.This paper describes the current status of established mechanical and chemical diverter technologies and examines their comparative advantages and challenges.Various techniques are suitable for diverter application,but the technique is selected based on the desired objective and conditions of the wellbore and reservoir.The general guidelines for selecting diversion techniques and operational considerations are also provided in the paper.The diagnosis of diversion treatment plays an essential role in diversion technique selection and optimization of selection parameters for the subsequent treatments.Therefore,the application of conventional surface pressure monitoring techniques and advanced diagnostic tools to evaluate diversion effectiveness are briefly described.Presently no standard laboratory testing method is established for the performance evaluation of diverting agents.Therefore,researchers have implemented various laboratory methods,which are briefly summarized in the paper.Significant insight into the diversion technology and guidelines for its selection and successful implementation is provided to help engineers to increase the effectiveness of hydraulic fracturing treatments.The limitations of individual diversion techniques are clarified,which provide the future scope of research for improvement in various diversion technologies.

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).

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.

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.

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.

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.

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.

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.

Fracturing and Episodic Fluid Expulsion in Pressure Compartments

The fracturing of the pressure compartments in sedimentary basins may not be caused completely by natural hydraulic fracturing. On the bases of fracture mechanics and numerical simulation, we consider that there are two mechanisms concerning the fracturing of pressure compartments, which are as follows: (1) natural hydraulic fracturing of the sediments within pressure compartments, and (2) tensile fracturing due to tangential traction. When the fracture, formed in the sediments within pressure compartments due to hydraulic fracturing, arrives at the base of the seal, the intensely tangential tensile stresses are created and lead to the fracturing of the seal. After the seal fractured, the fluid escaped from the pressure compartments. In a shallow pressure compartment, the duration of fracture opening and fluid expulsion is about 10-20 years in a cycle.

Experimental study on the adverse effect of gel fracturing fluid on gas sorption behavior for Illinois coal

Hydraulic fracturing is an effective technology for coal reservoir stimulation.After fracturing operation and flowback,a fraction of fracturing fluid will be essentially remained in the formation which ultimately damages the flowability of the formation.In this study,we quantified the gel-based fracturing fluid induced damages on gas sorption for Illinois coal in US.We conducted the high-pressure methane and CO_(2)sorption experiments to investigate the sorption damage due to the gel residue.The infrared spectroscopy tests were used to analyze the evolution of the functional group of the coal during fracturing fluid treatment.The results show that there is no significant chemical reaction between the fracturing fluid and coal,and the damage of sorption is attributed to the physical blockage and interactions.As the concentration of fracturing fluid increases,the density of residues on the coal surface increases and the adhesion film becomes progressively denser.The adhesion film on coal can apparently reduce the number of adsorption sites for gas and lead to a decrease of gas sorption capacity.In addition,the gel residue can decrease the interconnectivity of pore structure of coal which can also limit the sorption capacity by isolating the gas from the potential sorption sites.For the low concentration of fracturing fluid,the Langmuir volume was reduced to less than one-half of that of raw coal.After the fracturing fluid invades,the desorption hysteresis of methane and CO_(2)in coal was found to be amplified.The impact on the methane desorption hysteresis is significantly higher than CO_(2)does.The reason for the increasing of hysteresis may be that the adsorption swelling caused by the residue adhered on the pore edge,or the pore blockage caused by the residue invasion under high gas pressure.The results of this study quantitatively confirm the fracturing fluid induced gas sorption damage on coal and provide a baseline assessment for coal fracturing fluid formulation and technology.

Investigation on microscopic invasion characteristics and retention mechanism of fracturing fluid in fractured porous media

Reservoir damage caused by guar gum fracturing fluid and slick water seriously affects the subsequent oil and gas production. However, the invasion characteristics and retention mechanisms of fracturing fluids in the fracture-matrix zone are still unclear. In this work, a microscopic model reflecting the characteristics of the fracture-matrix zone was designed. Based on the microfluidic experimental method, the process of fracturing fluid invasion, flowback and retention in the fracture-matrix zone was investigated visually and characterized quantitatively. The factors and mechanisms affecting fracturing fluid retention in the fracture-matrix zone were analyzed and clarified. The results indicated that in the invasion process, the frontal swept range of slick water was larger than that of the guar gum fracturing fluid, and the oil displacement efficiency and damage rate were lower than those of the guar gum fracturing fluid under the same invasion pressure. With the increase in invasion pressure, the damage rate of slick water increased from 61.09% to 82.77%, and that of the guar gum fracturing fluid decreased from 93.45% to83.36%. Before subsequent oil production, the invaded fracturing fluid was mainly concentrated in the medium-high permeability area of the fracture-matrix zone. The main resistance of slick water was capillary force, while that of the guar fracturing fluid was mainly viscous resistance. The fracturing fluid retention was most serious in the low permeability region and the region near the end of the fracture.The experimental and numerical simulation results showed that increasing the production pressure difference could improve the velocity field distribution of the fracture-matrix zone, increase the flowback swept range and finally reduce the retention rate of the fracture fluid. The retention mechanisms of slick water in the fracture-matrix zone include emulsion retention and flow field retention, while those of the guar gum fracturing fluid include viscous retention and flow field retention. Emulsion retention is caused by capillary force and flow interception effect. Viscous retention is caused by the viscous resistance of polymer, while flow-field retention is caused by uneven distribution of flowback velocity.

Pressure transient characteristics of non-uniform conductivity fractured wells in viscoelasticity polymer flooding based on oil-water two-phase flow

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery.In contrast to water,polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening,polymer convection,diffusion,adsorption retention,inaccessible pore volume and reduced effective permeability.Meanwhile,the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution,formation damage,and proppant breakage.In this paper,we present an oil-water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior,and non-uniform fracture characteristics in fractured polymer flooding.The hydraulic fracture is firstly divided into two parts:high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section.A hybrid grid system,including perpendicular bisection(PEBI)and Cartesian grid,is applied to discrete the partial differential flow equations,and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution.The combination of polymer behavior characterizations and numerical flow simulations are applied,resulting in the calculation for the distribution of water saturation,polymer concentration and reservoir pressure.Compared with the polymer flooding well with uniform fracture conductivity,this non-uniform fracture conductivity model exhibits the larger pressure difference,and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section.The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately,and yields fracture half-lengths that better match engineering reality,enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity.The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology,as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

Experimental research on a new encapsulated heat-generating hydraulic fracturing fluid system

During fracturing treatment for low-temperature, shallow and high freezing point oil reservoirs, the first-line problems are to overcome uncompleted breakdown, uncompleted cleanup of fracturing fluids and cold damages to the formations by injecting cold fluid. To avoid those problems, it is suggested to adopt a new encapsulated heat-generating hydraulic fracturing fluid system as described in this paper.; Firstly, two kinds of chemical heat-generating systems were studied and the NH-4Cl-NaNO-2 system was selected. According to the reaction characteristics of the system, oxalic acid was chosen as a catalyst of reaction and encapsulated using ethyl cellulose and paraffin as coating materials by the phase separation method. Compatibility of NH-4Cl-NaNO-2-encapsulated oxalic acid with hydroxypropyl-guar fracturing fluid was also discussed in the paper. The results showed that the hydraulic fracturing fluid containing encapsulated heat-generating agents hare a good stability and compatibility. When the fracturing fluid contains {2.0} mol·L+{-1} NH-4Cl-NaNO-2, {0.93%} encapsulated oxalic acid and {0.08%} ammonium persulfate, the peak temperature can reach {78.0℃} and the viscosity of residual liquid is {3.12} mPa·s after 4 hours.

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.

Laboratory Research on the Performance of Fracturing Fluid System for Unconventional Oil and Gas Reservoir Transformation

Fracturing fluid is the blood of fracturing construction, which is very important for fracturing, which requires that fracturing fluid needs to have good performance. The three commonly used fracturing fluids for unconventional oil and gas reservoir transformation are: 1) Guar gum fracturing fluid;2) Water-based emulsion slippery water fracturing fluid;3) Oil-based emulsion slippery water fracturing fluid. In this paper, water samples and other experimental data provided by Mahu Oilfield are used to evaluate three different fracturing fluid systems in laboratory. The formulas of the three different fracturing fluid systems are: 1) Water-based emulsion slippery water fracturing fluid is clean slippery water fracturing fluid 0.1% JHFR-2D drag reducer + 0.2% JHFD-2 multifunctional additive;2) Oil-based emulsion slippery water fracturing fluid 0.1% A agent + 0.2% B agent;3) Guar gum fracturing fluid 0.1% guanidine gum + 0.5% drainage aid + 0.3% demulsifier. The compatibility, drag reduction performance, reservoir damage, residue content, anti-swelling performance, surface interfacial tension, viscosity and other properties of three different slippery water fracturing fluid systems were studied. Through laboratory experiments, the comprehensive indicators show that clean slippery water fracturing fluid has obvious advantages.