Flowback Period Research Articles

The Indicative Role of Geochemical Characteristics of Fracturing Flowback Fluid in Shale Gas Wells on Production Performance

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (IR) to denote the intensity of these reactions. Based on the IR value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater IR, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well.

Study Details Evolution of Operator’s Completions in Vaca Muerta

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212574, “From Exploration to Development: The Completion Evolution in Vaca Muerta,” by Juan C. Bonapace, SPE, Luis A. Riolfo, and Rodrigo Zrain, Total, et al. The paper has not been peer reviewed. _ Operators in the Neuquén Basin have developed Vaca Muerta with different results. In the case of the operator whose work is featured in the complete paper, vertical exploratory wells almost 10 years ago have given way to a current development phase with multihorizontal well pads targeting different landings. The authors discuss how the operator has become more efficient and cost-effective by increasing production and reducing well-delivery-cycle time, while fostering the long-term sustainability of the project by reducing the environmental impact of operations. Evolution of Field Completions The authors focus on the operator’s Field A, where the most progress has been made over the years. The exploratory and appraisal phases of the development are detailed in the complete paper. Pilot Phase. The primary goal for this phase was to validate the productivity of two previously identified landing zones, namely Zones B and D. The wells were located near the vertical wells. Completion. The campaign program accounted for 12 drilled horizontal wells, only 10 of which were completed (two wells were lost because of drilling and casing-integrity issues). Well lateral length ranged between 1000 and 1500 m. The final well architecture was composed of three strings: a 13⅜-in. surface casing, a 9⅝-in. intermediate casing, and a 5½-in. production casing. The completion technique applied was plug-and-perf (PnP) and considered an average stage length of 100 m. Two base designs were defined for each landing zone according to the results obtained in the vertical exploratory wells. An initial sensitivity trial was completed in Zone B, with two different treatment sizes, base and alternative, designed to evaluate the effect on cost and production performance. The results showed a lower production for the wells with the alternative treatment. Operational Issues. Operational problems included casing restriction, detected only once in a well in Zone D during plug drillout operations; and well interference, in that one well presented a change in production during the flowback period on a new neighboring well. This was the result of reduced spacing because of drilling conditions between the new well and the pre-existing one. This phase showed wells in Zone B performing beyond expected production, while those in Zone D underperformed. Development Phase I. It was decided to locate all wells of this phase on the east side of the pilot in the dry-gas window. The main driver for this decision was expected lower CO2 production in this region, based on observations from appraisal wells. Completion. Initial development considered 20 horizontal wells, mainly targeting Zone B. Two additional target zones were added for testing, Zones A and C. In pursuing cost optimization for this development phase, a change to a slimmer architecture was made. Finally, 19 wells were completed. The final well architecture was composed of three strings: a 10¾-in. surface casing, a 7⅝-in. intermediate casing, and a final 4½-in. production casing.

Application of micro-substance tracer test in fractured horizontal wells

This paper delves into a novel micro-substance tracer test in fractured horizontal well C-15. The experimental results are highly encouraging as they demonstrate that the trace material tracer is capable of satisfying the testing demands, even when there are large numbers of fracturing stages involved. Data interpretation process involved dividing the test duration into two stages-fluid flowback period and stable production period. The tracer test data were employed to analyze the production profile of the well. The findings made it evident that the primary production stage underwent alterations in different production stages. Moreover, the degree of heterogeneity pertaining to each fracturing stage was characterized by employing the residence time distribution method. It was observed that the Lorentz coefficient lying between the primary production stage and the remaining fracturing stages ranged from 0.46 to 0.68. This study expands the application of the residence time distribution method for evaluating tracer testing. Through a comprehensive analysis of heterogeneity data within the fracturing stages and the production dynamics of the well, the effectiveness of the fracturing process can be assessed. This research enables reservoir operators to gain deeper insights into the dynamics of test wells, ultimately leading to increased production efficiency.

Flowback Characteristics Analysis and Rational Strategy Optimization for Tight Oil Fractured Horizontal Well Pattern in Mahu Sag

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag.

A semi-analytical flowback data history-matching approach that rigorously accounts for fracture dynamics

Flowback data analysis methods used for unconventional reservoirs are still in their infancy. Until now, the dynamics of fracture closure during flowback have not been rigorously accounted for in analytical or semi-analytical models. In some cases, at the start of flowback, fracture pressure may be higher than the minimum horizontal stress, which means the fracture is still closing during the early flowback period. For such cases, the commonly-applied assumption of a static fracture width in flowback modeling will be in significant error. Moreover, previous analytical and semi-analytical modeling approaches have ignored fluid leakoff from the fracture when the fracture pressure is greater than reservoir pressure, which could also lead to significant errors when analyzing early flowback data in a stress-sensitive reservoir.In the current work, a semi-analytical history-matching approach for characterizing hydraulic fractures, which captures the dynamic behavior of hydraulic fractures during the early production period, is presented. The proposed methodology accounts for varying fracture width, cumulative leakoff from the fracture to the matrix, and spontaneous imbibition, during early flowback. The new method is verified using numerically simulated data and its practical application demonstrated by history matching a field case (shale gas well) exhibiting evidence of dynamic fracture properties during flowback. History matching of the same field case using models that do not account for fracture dynamics or fluid leakoff reveals that these models may overestimate fracture properties such as initial fracture permeability. In addition, history matching of the field case with the new model without spontaneous imbibition effects implemented yields fracture properties (initial fracture permeability and fracture half-length) that are greater than when both geomechanics and spontaneous imbibition are implemented.When compared to existing flowback models, the proposed semi-analytical model may yield more accurate estimates of fracture properties when fracture dynamics cannot be ignored during the early flowback period.

Engineered flowback and reservoir evaluation for unconventional wells

A flowback procedure is presented that uses a wellbore model coupled with thermal and fluid modelling to calculate the bottomhole pressure (BHP) and maximise the safe initial production/drawdown without over-stressing and damaging the fracture system. After obtaining the BHP, it is then possible to determine the fractured reservoir volume, fracture-dominated volume, and matrix contribution. The paper presents a case history validating the model calculations in an unconventional well. Two methods of decline analysis are presented, ‘Conventional’ and ‘Thermodynamic Transient Analysis’ (TTA), and together, these methods provide insights into the fracture system and overall reservoir volumes by recognising and applying the appropriate equation for the proper reservoir flow regime. The early flowback period can be used to determine the frac volume, while later periods will begin showing the increasing amount of matrix contribution. The wellbore flow model and decline analysis calculations are verified by a case history presented in the paper, where this flowback process was utilised on a hydraulically fractured East Texas well. The wellhead pressures (WHPs) in this case study highlight the need to accurately calculate BHPs based on the WHP and rates, due to significant differences between the trends and decline rates of the respective pressures.

Flowback rate-transient analysis with spontaneous imbibition effects

Analysis of flowback data, gathered immediately after fracture stimulation, can be performed to understand the fluid flow physics, investigate flow regimes, and obtain early estimates of fracture properties. During a hydraulic fracturing treatment, significant amounts of fracturing fluid will leak-off from the fractures into the reservoir due to Darcy flow, capillary, osmotic and electrostatic forces. Capillary invasion of fluids into the reservoir can cause a loss in gas relative permeability, leading to an altered zone near the fracture-matrix interface, therefore impeding the flow of hydrocarbons into the fracture. Due to this phenomenon and other fluid transport mechanisms, a simple application of Darcy's law might not be adequate for describing the fluid flow physics when solid-liquid interaction is significant. To overcome some of the above limitations, spontaneous imbibition effects are modeled at the fracture/matrix interface during the flowback period in this study.This paper presents a semi-analytical model for analyzing two-phase water and gas flowback data, when spontaneous imbibition occurs. This model was developed by solving the fracture and reservoir matrix flow equations simultaneously. The effects of fracture and reservoir matrix pressure gradients on gas and water influx at the fracture-matrix interface are accounted for in order to evaluate the reservoir matrix hydrocarbon influx. The proposed model accounted for spontaneous imbibition driven by capillary forces by quantifying the fluid influx due to capillary processes and adding it to the mass flow equations. Further, capillary pressure effects were incorporated into the PVT properties of matrix pseudovariables. The average phase pressures in the fracture and matrix were calculated iteratively using a modified material balance approach.The proposed semi-analytical model was successfully verified using fully-numerical simulation data. Practical application of the proposed model was then demonstrated using production data from a multi-fractured horizontal well.

Piecewise Gilbert-type correlation for two-phase flowback through wellhead chokes in hydraulically fractured shale gas wells

Wellhead chokes play key roles in liquid-flowback and gas-production processes of hydraulically fractured shale-gas wells. The characteristic of choke flow is quite complex and involves many factors, such as choke size, pressure and liquid-gas ratio (LGR). Gilbert-type correlations have been widely used in choke flow studying, but they are empirical and their accuracy is easily affected by operational conditions or special reservoir properties. Therefore, it is worth paying attention to the applicability of Gilbert-type correlation. This paper collected over 10,000 sets of data from 12 shale gas wells in Changning region, analyzed the influence of LGR on the prediction accuracy of Gilbert-type correlations, and developed a new correlation named Piecewise Gilbert-type Correlation (PGC) for gas-liquid two-phase flow through chokes. The results showed that LGR had a great impact on the prediction accuracy, and therefore the LGR data during the flowback period could be divided into several stages for data-fitting separately. PGC was established on multiple LGR stages, which led to multiple different groups of empirical coefficients, and had been proved to be more accurate on the whole. Specifically, the overall error and the mean error of PGC for the testing data were reduced to 13.3 and 0.0839.

A novel model for oil-water two-phase relative permeability of shale formation during flowback based on fractal method

As an abundant type of unconventional hydrocarbon resources on the earth, shale oil has been widely concerned by scholars across the world. During flowback period, flow-back resistance of fracturing fluids increases because of the existence of shale oil. Therefore, it is of practical significance to study the flow-back capability of fracturing fluid for high well performance. In this paper, fractal method of porous media has been used for calculation of relative permeability of oil-water two phase flow in shale pores. First, we built up flow equation of single nanopore with four layers: boundary layer, bulk wetting phase layer, oil-water two phase layer, and nonwetting phase layer. Furthermore, boundary slip, boundary, viscosity change in boundary layer and threshold pressure gradient is considered for correction flow rate equation. The pores of shale matrix can be simplified into capillary bundle model, and fractal theory is suitable for this model. Aperture fractal dimension and tortuosity fractal dimension is used to expand its scale to porosity media with fractal method. Then the model is verified by experimential results and classic models. Furthermore, serval main factors affecting the relative permeability of water are primarily analyzed, and the more essential factors out of the aforementioned ones are extracted and further studied. The results show that with the increase in the thickness of oil-water two phase layer, the relative permeability of water is affected more seriously; The relative permeability of water is positively correlated with slip length and thickness of boundary layer. This work provides a more convenient approach to calculate relative permeability with no experiments, and provide permeability for numerical simulation in flow back period.

Estimating Reservoir Permeability and Fracture Surface Area Using the Flowback DFIT (DFIT-FBA)

Summary The main parameters of interest derived from a diagnostic fracture injection test (DFIT) are minimum in-situ stress, reservoir pressure, and permeability. The latter two can only be obtained uniquely from the transient reservoir responses, often requiring days to weeks of test time. The DFIT flowback analysis (DFIT-FBA) method, a sequence of pump-in/flowback (PIFB), is a fast alternative to the pump-in/falloff (conventional) DFIT for estimating minimum in-situ stress and reservoir pressure. Because the properties of the fracture are unknown, reservoir permeability cannot be estimated directly and therefore well productivity index (PI) has been reported in previous DFIT-FBA studies. The goal of the current study is to develop a methodology for estimating reservoir permeability and fracture properties from a DFIT-FBA test. In this study, a fully coupled hydraulic fracturing, reservoir, and wellbore simulator was used as a first step to identify critical mechanisms operating during the flowback period of a DFIT-FBA test. Subsequently, findings from the simulator were used to develop an analytical solution to estimate reservoir permeability, fracture surface area, open fracture stiffness, and contact pressure. The analytical model relies on a new rate-transient analysis (RTA) technique that accounts for the dynamic behavior of the fracture and changing leakoff rate during the before-closure period. The proposed approach was validated against a simulation case, and its practical application was demonstrated using a field example performed in a tight reservoir. The reservoir permeability and fracture surface area, derived from the analytical model at the contact point, agree within 2% of the simulation model input. The field example examined herein exhibited flow regimes similar to the simulation case, and fracture surface area, open fracture stiffness, contact pressure, minimum in-situ stress, reservoir pressure, and permeability were all obtained in a fraction of the time required by conventional DFITs.

Multi-Phase Rate Transient Behaviors of the Multi-Fractured Horizontal Well With Complex Fracture Networks

Abstract Complex fracture networks (CFN) provide flow channels and significantly affect well performance in unconventional reservoirs. However, traditional rate transient analysis (RTA) models barely consider the effect of CFN on production performance. The impact of multi-phase flow on rate transient behaviors is still unclear especially under CFN. Neglecting these effects could cause incorrect rate transient response and erroneous estimation of well and fracture parameters. This paper investigates multi-phase rate transient behaviors considering CFN and tries to investigate in what situations the multi-phase models should be used to obtain more accurate results. First, an embedded discrete fracture model (EDFM) is generated instead of Local Grid Refinement method to overcome time-intensive computation. The model is coupled with reservoir models using non-neighboring connections (NNCs). Second, eight cases are designed using the EDFM technology to analyze effect of natural fractures, formation permeability, and relative permeability on rate transient behaviors. Third, Blasingame plot, log–log plot, and linear flow plot are used to analyze the differences of rate transient response between single-phase and multi-phase flow in reservoirs with CFN. For multi-phase flow, severe deviations can be observed on RTA plots compared with single-phase model. Combination of three RTA type curves can characterize the differences from early to late flow regimes and improve the interpretation accuracy as well as reduce the non-unicity. Finally, field data analysis in Permian Basin demonstrates that multi-phase RTA analysis are required for analyzing production and pressure data since single-phase RTA analysis will lead to big errors especially under high water cut during fracturing fluid flowback period, early production of unconventional gas wells or after waterflooding, or water huff-n-puff.

Performance evaluation of a novel CO2-induced clean fracturing fluid in low permeability formations

After the limitations of polymer-based fracturing due to poor clean-up property during flowback after fracturing treatment, viscoelastic surfactant (VES) received very huge attention in the last three decades, especially in low permeability reservoirs. In this study, a Novel CO 2 -induced clean fracturing fluid (SDS-TMTAD-CO 2 ) is formulated with simulated formation water (23,003 mg L −1 ) after optimization experiments according to the proposed parameters (i.e., 70 °C, economical, easily preparation, and environment-friendly). The results of rheological experiments show that the apparent viscosity of the fracturing fluid system increases to a certain extent under high salt conditions and possesses sufficient self-healing property against high shear tolerance. At different temperatures (25, 50, and 70 °C), the thermodynamic properties, fluid viscoelasticity, and proppant carrying capacity meet the requirements of the fracturing fluid industry standards. After adding kerosene (0.02 mol L −1 ); the gel breaking fluid viscosity (3.2 mPa s), anti-swelling rate (91.3%), and interfacial tension (2.3 × 10 −2 mN m −1 ) are holding promising conditions during the flowback period, clay swelling, and residual oil saturation, respectively. The filtration and core damage experimental results meet the national industry standard for fracturing fluids. The SEM results show that the fluid system after reaction forms a unified adsorption film on the core surface. Hopefully, this fluid system will be proved as a good candidate by means of excellent proppant transportation ability, anti-swelling, easy gel structure breaking, low filtration, and less formation damage in low permeable formations with an increase in productivity. • Easy preparation of an economical and environment-friendly CO 2 -induced clean fracturing fluid system (SDS-TMTAD-CO 2 ). • Rheological and functional performances of the system meet the “SY/T 6376-2008, SY/T 5107-2016, and SY/T 5971-2016” standards. • Can fracture the low permeable formations with less filtration and low formation damage.

Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone

The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (RFF/FW) between recovered hydraulic fracturing fluid (FF) and formation water (FW) – besides gas production (GP) and flowback efficiency (FE) – as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (RFF/FW) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/FW ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/FW ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted clastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.

Integrity Evaluation of Cement Ring during Fracturing and Flowback of Horizontal Well in Jimsar Shale Oil

Abstract Horizontal well volume fracturing has become the main technology for effective development of unconventional oil and gas. In the process of fracturing and flowback of horizontal wells, the changes of wellbore temperature and pressure will affect the magnitude and distribution of stress in cement sheath, which may lead to compression or tensile failure of cement sheath, or a microclearance between casing and cement sheath. Therefore, based on the elastic theory of thick-walled cylinder, the elastic model of casing cement sheath and formation combination is established, and the finite difference program FLAC3D (Fast Lagrangian Analysis of Contimua in Three-Dimensional) was used to solve the model. The simulation evaluation of several horizontal wells in Jimusar shale oil shows that the main failure mode of cement sheath in horizontal well section is radial compression or circumferential tensile failure in fracturing period, and the main failure mode is a microclearance failure in flowback period. Taking Jimusar shale oil horizontal well JHW00421 as an example, the critical values of wellbore pressure and mechanical parameters of cement when cement sheath fails during fracturing flowback and their relationship are predicted or evaluated. The findings of this study are helpful to better understand and evaluate how different fracturing or flowback operation parameters affect the integrity of cement sheath and the effectiveness of interlayer sealing in horizontal well sections.

Sand Production of the Shale Gas Well in Different Production Periods: Structure and Component

Complex geology and fracturing operations have led to frequent sand production problem in the shale gas well. Sand production brings huge engineering risks and seriously affects the normal production of the shale gas well. In order to study the property and source of the yielded sand, sand samples in three production periods of flowback, production test and gas production are collected from Sichuan Basin of China. Combining the methods of particle size analysis, microscope observation, scanning electron microscope, CT scanning, infrared spectroscopy and energy dispersive spectrum analysis, the multi-scale structure and composition characteristics of the yielded sand from different production periods were investigated. Results show that the sand size is the largest in the production test period and the smallest in the gas production period. The large-size sand is blocky in the flowback period, while it is flaky in the period of production test and gas production. The roundness of sand becomes worse as the sand size decreasing. Sand composition has the characteristics of fracturing proppant and shale mineral. Cementing material between large-size sands has the network structure and the higher content of aluminum and iron. Organic chemicals are found to be adhered to the sand surface in all three periods. Both shale fracture and proppant failure can generate particles that provide the material source for sand production. This research provides the source of the yielded sand and a theoretical guidance for the sand production mechanism.

Formation and rheology of CO2-responsive anionic wormlike micelles based clear fracturing fluid system

In recent years, a polymer-free fracturing fluid is under research to minimize the conductivity damage in formation and fracture during and after fracturing. Through extensive experiments, we prepared CO2-sensitive wormlike micelles (WLMs) based fracturing fluid system using anionic surfactant NaOA (Sodium Oleate-C18H33NaO2) and TMTAD (2,6,10-trimethyl-2,6,10-triazaundecane-C11H27N3). Rheological results from viscosity variation with steady shear rate using CO2/pH/time-response after CO2 bubbling confirm that the 3NaOA-TMTAD (3:1) was found as the best one in the properties of WLMs structure and the intermolecular interactions when comparing to 1NaOA-TMTAD and 2NaOA-TMTAD. Further, the surface tension after CO2 bubbling shows a good capability to decrease about 27.01 mN·m−1 at a CMC of 0.543 mM. The cryo-TEM test justifies the occurrence of spherical and WLMs in the fluid, before and after CO2 injection. The fluid system presents an outstanding sand suspension and gel breaking property, which are the positive features during the fracturing and flow back period; respectively. Good response with the alternative changes in CO2 pressures possesses an effective influence on shear viscosity using different temperatures (25 and 85 °C) and shear rates (20, 170, and 200 s−1). Also, the results of a linear relationship and low filtration coefficients verify that the fluid system has good filtration property. Such an easy and environmentally benign fluid system may be involved as a potential candidate in fracturing in unconventional hydrocarbon reservoirs, to reduce the formation damage which is usually very common in the polymer-based fracturing fluid.

Mathematical Modeling and Numerical Simulation of Water‐Rock Interaction in Shale Under Fracturing‐Fluid Flowback Conditions

AbstractWater‐rock interaction cannot be ignored for shale reservoirs with high‐salinity formation brine and complex rock composition, and stimulated by massive slick‐water fracturing treatment. However, there have been few studies on the flowback model fully coupled with different effects of water‐rock interaction. This paper presents the development of a coupled hydro‐chemical‐mechanical model for modeling water‐rock interaction in fractured shale during the post‐fracturing flowback period. The model considers distinguishing water‐rock interaction phenomena, that is, mineral dissolution, clay swelling and chemical osmosis, and accounts for multi‐phase flow in a fractured shale reservoir. The coupling and solution method and a numerical simulator were developed. Numerical simulation indicates that the swelling volume of clay minerals occupies the pores and leads to a decline in matrix porosity, while mineral dissolution increases both the matrix porosity and the solute concentration in the aqueous phase in matrix pores. Clay swelling mainly affects the shape of the porosity ratio profiles. The effect of mineral dissolution becomes increasingly stronger as flowback progresses. Mineral dissolution mainly affects the relative positions of the porosity ratio curves with the progress of flowback. The water‐rock interaction coupled flowback modeling and the numerical simulation results in this study quantify the effects of chemical osmosis, clay swelling and mineral dissolution. Results from this study provide new insights into the mechanisms of fracturing‐fluid flowback and value to flowback transient analysis.

Evolution of H-O isotopes from fracturing flowback fluids for shale gas wells: A case study in Chongqing, China

The hydrogen and oxygen isotopes of the fracturing flowback fluids from 3 wells in the Longmaxi Formation in Dazu area of western Chongqing, China provides insights into the source of the flowback fluids. We use the valued of δ2H and δ18O, combined with concentrations of ions to discuss the changing rule of H and O isotopes throughout the flowback period. The values of δ2H and δ18O for Z2 and Z5 wells show different changing trends. But he values of δ2H and δ18O for Z2 and Z5 wells have similar changing trends. There is no obvious correlation between hydrogen and oxygen isotopes for 3 wells. The fracturing fluids, formation brines, meteoric water, and water-rock reaction can change the H and O isotopes for flowback fluids from shale gas wells.

Modeling tracer flowback behaviour for a fractured vertical well in a tight formation by coupling fluid flow and geomechanical dynamics

In this work, a pragmatic technique has been developed to describe tracer flowback behaviour for a vertically fractured well in a tight formation by coupling fluid flow and geomechanical dynamics. More specifically, the Barton-Bandis model is employed to describe the relationship between effective stress and fracture permeability, while tracer flowback profiles, which can reveal the fracture properties, are quantified by taking tracer dispersion and adsorption into account. Subsequently, this method considering two main mechanisms (i.e., tracer flow behaviour and fracture propagation dynamics) is separately validated with previous analytical solutions and then extends its application to a field case. In addition to tracer flowback concentration, the tracer recovery factor (TRF) is generated to analyze the tracer flowback behaviour. With considering geomechanics, the TRF is nearly 20% higher than that without considering geomechanics. During the flowback period, tracer concentration profiles appear to be unimodal for reservoirs with a single fracture, while tracer concentration increases quickly at the initial stage and then decreases slowly as time proceeds. An increase in matrix permeability increases tracer flowback concentration and the TRF. A larger tracer dispersion coefficient leads to earlier arrival time for the tracer flowback concentration peak together with a lower TRF. Also, the stronger the tracer adsorption is, the lower the tracer flowback concentration and the TRF will be. A higher Young's modulus results in a lower tracer flowback concentration and TRF. An increase in minimum horizontal stress increases tracer flowback concentration. Other parameters, including maximum horizontal stress, fracture closure permeability, and normal fracture stiffness, are also examined and analyzed though less sensitive.

Predicting the potential for mineral scale precipitation in unconventional reservoirs due to fluid-rock and fluid mixing geochemical reactions

Mineral precipitation within hydraulically fractured shale may affect fluid flow pathways and impact long-term hydrocarbon production. The ability to predict geochemical reactions causing problematic mineral precipitation will lead to active reservoir management strategies for improving production. Using the Marcellus Shale as a case study, laboratory experiments and reaction path modeling were applied to determine which reactions occur during hydraulic fracturing, shut-in, flowback, and production timeframes. Experimental results indicate that contact between fracturing fluid and shale will result in dissolution of primary minerals (carbonates, quartz, feldspars, kaolinite, chlorite, pyrite) and secondary mineral precipitation over time periods of less than one week. Precipitation of secondary carbonates, barite, iron oxides, feldspars, amorphous silica and clay is likely to occur within the reservoir during shut in and early flowback due to mixing between fracturing fluid and reservoir brine as based on modeling saturation indices using experimental fluid data. Reaction path modeling corroborates the dissolution and precipitation reactions observed experimentally. Comparison of the results to injected and produced waters from a Marcellus Shale well pad in Greene County, PA, USA, shows that the mineral reactions occur during the hydraulic fracturing, shut in, and early flowback periods. The results presented here demonstrate the value in applying experimental approaches to identify mineral precipitation/dissolution reactions that may significantly impact reservoir performance. The good agreement between geochemical models and experimental results provides confidence that numerical models can be applied to screen the potential fluid-mineral and fluid-mixing reactions in unconventional reservoirs that result in undesired mineral scale precipitation.