Multistage Hydraulic Fracturing Research Articles

Pressure characteristics and performance of multi-stage fractured horizontal well in shale gas reservoirs with coupled flow and geomechanics

Multi-stage hydraulic fracturing is a crucial well completion strategy in unconventional reservoirs to improve hydrocarbon production. Reservoir performance and pressure characterization in multi-stage fracture development considering elastic rock mechanics are not systematically discussed in the literature. This work considers effects of elastic rock mechanics and hydraulic fractures in unconventional reservoir development scenarios using a numerical model with coupled fluid flow and geomechanics.A fully coupled flow and geomechanics model based on finite element method is introduced to analyze shale gas flow and corresponding pressure distribution in unconventional reservoirs. The model is validated with an analytical solution and history matched with field data. Furthermore, effects of rock mechanics, elastic properties, and hydraulic fracture geometry on reservoir performance and pressure distribution are studied using the fully coupled numerical model. Pressure distribution and reservoir performance in terms of production rates of these scenarios are analyzed. It is found that consideration of elastic rock mechanics decreases the hydrocarbon production rates and alters the pressure distribution in the unconventional reservoir. Rock mechanical properties and fracture spacing/length also affect flow rates and pressure. Fracture spacing, fracture length, and Young's modulus have the greatest effect on hydrocarbon production rates. Effects of elastic rock mechanics are most significant at central areas of the fractured region, while such effects are less significant at far ends of the horizontal wellbore. This work incorporates full geomechanics with a flow model to understand reservoir performance and pressure characterization in multi-stage hydraulic fracture development scenarios and quantifies effects of geomechanics and effects of various parameters in unconventional development scenarios.

A new openhole multistage hydraulic fracturing system and the ball plug motion in a horizontal pipe

Gas well stimulation based on a ball-drop fracturing system is a widely adopted operation in the oil & gas industry. The flow resistance of a multistage fracturing pipe string increases as the number of stages grows, which is a major problem for the traditional graduated ball-drop multistage fracturing system, as it can increase the load of the pump and may ultimately result in a high-cost operation. A new openhole multistage hydraulic fracturing system, which has unlimited multistages, activated by ball plugs is proposed to improve the operation efficiency. In this system, all the downhole sliding sleeves are a single size, and a group of ball plugs activate them to achieve full-inner-diameter pipe access. As a key part of the fracturing system, the approximate cylinder-shaped ball plugs would suffer from a larger resistive force in the horizontal pipe than that of the sphere-shaped fracturing ball. Therefore, a simplified miniature indoor experiment setup is built to investigate the motion of the ball plug. The physical dimensions of the cylinder models and the velocities of the pumping flow vary in the experiment. In addition, the motion in the cylinder models are observed with a high-speed camera. Finally, the experimental data are analysed by a combination of dimensional analysis and the empirical equation method, and the results can help to determine the pumping rate during operations.

A new numerical investigation of cement sheath integrity during multistage hydraulic fracturing shale gas wells

Volume fracturing of shale gas wells has been observed to lead to the failure of cement sheath and to sustained casing pressure (SCP). This paper presents a new numerical investigation aimed at understanding the failure mechanism of the cement sheath during volume fracturing. A wellbore temperature model was established to obtain the required input parameters for the dynamic temperature boundary. The numerical model considers the coupling of casing, cement sheath, and formation rock to calculate the radial and tangential stresses in the cement sheath. In addition to the cement mechanical properties, the influencing factors considered include the casing pressure, fracturing fluid displacement, and initial temperature. The cement sheath integrity was evaluated using the Mohr-Coulomb failure criterion. The results show that the temperature of cement sheath changes drastically during fracturing. The radial and tangential stresses in the cement sheath change continuously with time. Lowering the internal wellbore pressure can effectively reduce the radial and tangential stresses in the cement sheath. Reducing the fracturing fluid displacement can significantly lower the radial and tangential stresses in the cement sheath. Increasing the initial fracturing fluid temperature will cause the radial stress of cement sheath to increase and the tangential stress to decrease. The use of cements with low Young's modulus values can significantly reduce the radial and tangential stresses in the cement sheath. The use of cements with low Poisson's ratio values can lower the tangential stress. The results obtained using the model were verified by field data that demonstrated no occurrence of casing pressure when using a cement with a low elastic modulus, as suggested by the model.

Study for Improvement of Multi-stage Hydraulic Fracturing Design for Eagle Ford Shale Reservoir Using Rate Transient Analysis

다단계 수압파쇄 기술은 셰일과 같은 치밀 저류층에 부존하는 석유자원의 상업적인 개발을 위해 널리 적용 하는 검증된 방법이다. 셰일 저류층의 공당 생산성은 적용된 수압파쇄 설계에 따라 달라지기 때문에 이에 대한 개선방 안 마련은 셰일 저류층 개발업계가 지속적으로 도출해 나가야할 과제이다. 이 연구에서는 미국 Eagle Ford 셰일 저류 층을 대상으로 다단계 수압파쇄 적용으로 발생하는 균열대 분포를 예측하고 이에 의한 생산능력의 영향을 분석하기 위해 생산천이분석을 활용하였다. 이를 통해 균열대 발달 특성을 규명하고 민감도 분석을 통한 궁극가채량과 상관관 계를 분석함으로써 수압파쇄 설계 개선방안을 도출하였다. 또한 몬테카를로 시뮬레이션을 적용한 생산천이분석을 통해 셰일 저류층 평가에 내재하는 불확실성을 정량화 하였다.

INTEGRATED MONITORING OF HORIZONTAL WELLS WITH MULTISTAGE HYDRAULIC FRACTURING AT THE IMPLEMENTATION STAGE WITHIN THE PRIOBSKIY OIL FIELD FOR THEIR WORK EFFECTIVENESS

Background. Priobsky license area is one of the largest in terms of assets production of Oil Company Rosneft», as well as the leader in the number of initiated pilot industrial tests and pilot works (PW). It was within the framework of the PW that the first clusters were drilled by horizontal wells and carrying out multistage hydraulic fracturing of the reservoir (HW with MHF), which resulted in the decision to introduce them massively throughout the Priobsky license area. Like any new technology at the implementation phase, the technology of HW with MHF in its realization stage also requires optimization solutions, and it may take years to evaluate the effectiveness of these decisions. Aims and Objectives. There considered issues related to: • creation of an integrated system for monitoring HW with MHF for determining the effectiveness of their operation; • increasing the effectiveness of the HW with MHF. Rezults. There proposed the approaches to create the system of monitoring and analysis of the effectiveness of HW with MHF at the implementation stage, as well as a primary assessment of problem wells with a view to further increasing their efficiency through the implementation of measures. The optimal variants of the formation of a reservoir pressure maintenance system (PMS) and the timing of mining in injection wells for clusters with different geological conditions are determined. The calculated terms of transfers are already used for an operative assessment of the appropriateness of transfers of directional wells in the PMS at a number of fields. Optimal quantities of MHF stages and proppant loading on HW are determined depending on different geological conditions. The actual implementation of the first three wells with an increased number of stages of MHF confirmed the success of this direction.

Numerical investigation for different casing deformation reasons in Weiyuan-Changning shale gas field during multistage hydraulic fracturing

Casing deformation has been found to be a very significant issue in the development process of shale gas in China. The rate of casing deformation is 34.34% (34 wells of 101), and statistical data show that it decreased the test output of wells by approximately 30%. Based on investigation and analysis of the engineering and geological conditions of 25 wells, 12 of which have casing deformations, both physical models and finite element models were established. Furthermore, the effects of fracturing pressure, geostress, anisotropy, lithologic interface, temperature variation, and cement void were analyzed. The results show the following. a) When the casing deformation points appear far away from point A (the landing point, which is the starting point of the horizontal segment), the influence of the lithologic interface on casing stress plays a decisive role under the combined effect of internal and external pressures when the cement sheath is completed. b) Under the same conditions, but when the casing is in contact with the borehole wall near the bottom because of gravity, a narrow fluid retention space was formed, leading to cementing sheath voids. The effect of cement void pressure reduction is the main reason behind the casing deformation. c) When casing deformation points appear near point A, the activation of the weak plane in the beddings during fracturing causes the casing deformation. The stress of 14 casing deformation points was calculated according to actual engineering and geological conditions, and 78.6% of the results were consistent with field measurements.

Investigating Gas–Adsorption, Stress–Dependence, and Non–Darcy–Flow Effects on Gas Storage and Transfer in Nanopores by Use of Simplified Local Density Model

Summary As an unconventional rock, shale contains all the features of coalbed and tight sandstone specified as gas-adsorption capacity, microscale and nanoscale porosity, and extremely low permeability. The gas-storage mechanism of shale rocks not only is dominated by free gas in macropores and natural fractures, but also is controlled by adsorbed gas in microporous organic matter (kerogen) and clay minerals. Furthermore, Darcy's law is no longer applicable to describe gas transport in nanopores (Javadpour 2009; Wu et al. 2015). Therefore, developing a reliable model to calculate effective porosity and permeability in nanopores considering the effects of gas adsorption, stress dependence, and non-Darcy flow is crucial to characterize properties of shale-gas reservoirs and explain gas-flow behavior in nanopores. In this study, the simplified local density (SLD) model, which has been successfully applied to analyze gas adsorption on coal, activated carbon, and shale in recent studies, is used to analyze methane-adsorption data measured from five shale-core plugs in the laboratory (Mohammad et al. 2011; Chareonsuppanimit et al. 2012; Clarkson and Haghshenas 2016). A new approach to determine the thickness of adsorbed gas dependent on the density profile of the SLD model is proposed, which in turn provides the correction of methane adsorption to pore volume (PV). Furthermore, stress-dependence effect is incorporated into the gas-adsorption effect to generate an effective porosity function in shale rocks. In addition, non-Darcy-flow effect on gas transfer in nanopores is derived from the slit-shaped pore geometry of the SLD model and is represented by a weighted sum of second-order gas slippage and Knudsen diffusion. Consequently, the effective permeability is established as a function of the effects of gas adsorption, stress dependence, and non-Darcy flow. Moreover, the functions of effective porosity and permeability are incorporated into a numerical simulator to perform history matching for gas-production data from a horizontal well with multistage hydraulic fractures in a Barnett Shale reservoir. The simulation results properly match the gas-production data at the field scale. Finally, sensitivity studies on gas adsorption, stress dependence, and non-Darcy-flow effects are conducted to investigate their contributions to evaluating and estimating gas production from shale-gas reservoirs. The results of this study suggest that gas adsorption and non-Darcy-flow effects are two competitive aspects that have major influences on shale-gas production. The developed model including gas-adsorption, stress-dependence, and non-Darcy-flow effects provides insight into the characterization of rock properties and the description of gas-transport behavior in shale-gas reservoirs.

Hydraulic Fracturing and Production Optimization in Eagle Ford Shale Using Coupled Geomechanics and Fluid Flow Model

With increasing production from shale gas and tight oil reservoirs, horizontal drilling and multistage hydraulic fracturing processes have become a routine procedure in unconventional field development efforts. Natural fractures play a critical role in hydraulic fracture growth, subsequently affecting stimulated reservoir volume and the production efficiency. Moreover, the existing fractures can also contribute to the pressure-dependent fluid leak-off during the operations. Hence, a reliable identification of the discrete fracture network covering the zone of interest prior to the hydraulic fracturing design needs to be incorporated into the hydraulic fracturing and reservoir simulations for realistic representation of the in situ reservoir conditions. In this research study, an integrated 3-D fracture and fluid flow model have been developed using a new approach to simulate the fluid flow and deliver reliable production forecasting in naturally fractured and hydraulically stimulated tight reservoirs. The model was created with three key modules. A complex 3-D discrete fracture network model introduces realistic natural fracture geometry with the associated fractured reservoir characteristics. A hydraulic fracturing model is created utilizing the discrete fracture network for simulation of the hydraulic fracture and flow in the complex discrete fracture network. Finally, a reservoir model with the production grid system is used allowing the user to efficiently perform the fluid flow simulation in tight formations with complex fracture networks. The complex discrete natural fracture model, the integrated discrete fracture model for the hydraulic fracturing, the fluid flow model, and the input dataset have been validated against microseismic fracture mapping and commingled production data obtained from a well pad with three horizontal production wells located in the Eagle Ford oil window in south Texas. Two other fracturing geometries were also evaluated to optimize the cumulative production and for the three wells individually. Significant reduction in the production rate in early production times is anticipated in tight reservoirs regardless of the fracturing techniques implemented. The simulations conducted using the alternating fracturing technique led to more oil production than when zipper fracturing was used for a 20-year production period. Yet, due to the decline experienced, the differences in cumulative production get smaller, and the alternating fracturing is not practically implementable while field application of zipper fracturing technique is more practical and widely used.

Geomechanical implications of dissolution of mineralized natural fractures in shale formations

Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures — so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.

A New Approach to Determining Multistage Hydraulic Fracture Size by Well Production Data

The simplified two-zone model to describe fluid flow in steady-state horizontal holes with multistage hydraulic fracturing is proposed, and the analytical solution in order to calculate sizes of hydrofractures is presented. The new procedure to determine size of multistage hydrofractures in horizontal holes is tested using field data on China deposits. The calculation results prove the efficiency of the procedure in the determination of steady-state conditions. The procedure can be used in optimization of hydraulic fracturing.

Effect of non-uniform pore pressure fields on hydraulic fracture propagation

In elastic materials, it is evident that the path of a propagating fracture is deflected from its normal course in presence of imperfections of the material or loading conditions. This paper aims at investigating hydraulic fracture deviation induced by non-uniformity of pore pressure fields with the use of a fully coupled poroelastic model based on the finite element method. The model includes a poroelastic domain in which pressurized hydraulic fractures are explicitly embedded, thus allowing to realistically model the fluid flow inside the fracture and to intrinsically consider the fracturing fluid load on the fracture walls as well as fluid leak-off into the formation. The latter process (fluid leak-off into the formation) controls both the length and the orientation of the fracture by changing the local pore pressure which in turn leads to a change in magnitude and direction of local principal stresses around the fracture tip. An innovative method, Mean Rotation Angle (MRA) is utilised for post-processing of evolving stress data at the vicinity of the fracture tip. The MRA predicts the potential growth path of pressurized fractures. In this paper pore pressure induced fracture reorientation is studied for a single fracture as well as closely spaced fractures. Results of this study indicate that presence of a pore pressure anomaly changes the growth path of a hydraulic fracture, towards or away from the anomaly. A higher than average pore pressure zone attracts the fracture while a lower pressure anomaly zone repulses the growing fracture. The fracture growth direction depends on the differential pressure and the distance between the anomaly and the fracture tip. Also in case of two simultaneously growing transverse fractures pressurized by injected fluid, it has been observed that the fluid leak-off controls the potential deviation angle of the fractures through changing the local pore pressure distribution pattern. It is shown that there are three distinct trends for the change of potential deviation angle due to fluid leak-off and that these three trends are linked to three corresponding stages of hydraulic communication between the two fractures. Furthermore, this study shows that change in matrix permeability, stress anisotropy, fracture half-length, spacing and the rate of leak-off influence the timing of each of the stages to the extent to which the corresponding stage of hydraulic communication of the two fractures are affected. This new understanding gives a better insight into the mechanism by which closely spaced hydraulic fractures interact and help optimize the design of multi-stage hydraulic fracture treatments.

Utilizing multiplets as an independent assessment of relative microseismic location uncertainty

Location uncertainty is a key factor affecting interpretation of microseismic data associated with multistage hydraulic fracturing. We provide an independent assessment of relative microseismic event location uncertainty using multiplets — microseismic events that occur in essentially the same place with the same source characteristics. We establish a relationship between waveform similarity and hypocentral separation using synthetic events in a representative velocity model, finding an upper bound of 15 m between events in any given multiplet group. This implies that greater separation of locations for events within a multiplet reflects relative location error. We identified hundreds of multiplet groups in a case study in the Barnett with unusually high-quality data. All stages were recorded with two downhole monitoring arrays. Although the events within each multiplet group must be within 15 m of each other to produce nearly identical waveforms on the recording arrays, the scatter in contractor-provided event locations from the multiplet centroid is about 60 m for the most well-located multiplet events with source receiver distances of 150–200 m, despite a stated absolute location uncertainty of about 30 m. The scatter in event locations increases to 120 m when the source receiver distance is more than 250 m.

ANALYSIS OF EFFICENCY OF MULTI-STAGE HYDRAULIC FRACTURING IN HORIZONTAL WELLS AT VYNGAPUROVSKOYE GAS FIELD

The analysis of efficiency at engaging into development of hard-to-recover reserves of oil of horizontal wells using multistage hydraulic fracturing has been conducted. The results are presented as a comparison of the dynamics of their work to directional wells, in which also hydraulic fracturing had been held.

Numerical investigation of the well shut-in and fracture uncertainty on fluid-loss and production performance in gas-shale reservoirs

Interacting with the pre-existing natural fractures, multi-stage hydraulic fracturing along with long horizontal well creates complex fracture networks in gas-shale reservoirs. Field data indicate that only a small fraction of the hugely injected fracturing fluid can be recovered during the clean-up period, especially when the well undergo an extended shut-in period. Therefore, it is essential to investigate the interaction between the non-recovered fluid and the fracture to understand the behavior of fluid-loss and production performance.A series of mechanistic simulation models consisting of hydraulic fracture (HF) and natural/secondary fracture (NF) were constructed to simulate imbibition, fluid re-distribution, and flowback during well shut-in and cleanup periods. Firstly, the established 3-D model system was used to investigate the impact of shut-in immediately after the production and a certain period of flowback. Furthermore, sensitivity analysis was subsequently performed with corresponding stochastic 2-D model, which systematically quantified the impact of fracture uncertainties in 1) fracture complexity and, 2) fracture distribution.The results indicate that, after incorporated with the imbibition hysteresis, water saturation of fracture is close to 1 even if the well has been shut in for a long period before flowback, and the saturation increases with the extending of shut-in during flowback. In addition, the rate fluid imbibition into the reservoir is extremely slow, and the invasion depth is less than 3 m after 100 days’ shut-in. It is also concluded that shut-in duration is not proportional to gas production when we divide the shut-in situation into two cases. Therefore, it is inappropriate to judge that the longer the shut-in period is, the more favorable the production will be. For the fracture networks, we linked the density of NF with the half-length of HF to investigate the fracture complexities. The results show that more complicated fracture will greatly enhance gas production and reduce water recovery efficiency (flowback rate). Finally, different distribution patterns have different impact on well performance, but, the overall influence is much less than that of complexity.

Application of Reservoir Flow Simulation Integrated with Geomechanics in Unconventional Tight Play

Multistage hydraulic fracturing techniques, combined with horizontal drilling, have enabled commercial production from the vast reserves of unconventional tight formations. During hydraulic fracturing, fracturing fluid and proppants are pumped into the reservoir matrix to create the hydraulic fractures. Understanding the propagation mechanism of hydraulic fractures is essential to estimate their properties, such as half-length. In addition, natural fractures are often present in tight formations, which might be activated during the fracturing process and contribute to the post-stimulation well production rates. In this study, reservoir simulation is integrated with rock geomechanics to predict the well post-stimulation productivities. Firstly, a reservoir geological model is built based on the field data collected from the Montney formation in the Western Canadian Sedimentary Basin. The hydraulic fracturing process is then simulated through an integrated approach of fracturing fluid injection, rock geomechanics, and tensile failure criteria. In such a process, the reservoir pore pressure increases with a continuous injection of the fracturing fluid and proppants, decreasing the effective stress exerted on the rock matrix accordingly as the overburden pressure remains constant. Once the effective stress drops to a threshold value, tensile failure of the reservoir rock occurs, creating hydraulic fractures in the formation. The early production history of the stimulated well is history-matched to validate the predicted fracture geometries (e.g., half-length) generated from the fracturing simulation process. The effects of the natural fracture properties and well bottom-hole pressures on well productivity are also studied. It has been found that nearly 40% of hydraulic fractures propagate in the beginning stage (the pad step) of the fracturing schedule. In addition, well post-stimulation productivity will increase significantly if the natural fractures are propped or partially propped by the proppants. This paper provides insights on fracture propagation and can be a reference for fracturing treatments in unconventional tight reservoirs.

Modern system of multiphase flow in porous media and its development trend

Fluid flow in porous media is the key scientific problem in the development of oil and gas reservoirs. The traditional mechanics of fluid flow in porous media which based on the continuum hypothesis and Darcy′s law plays an important role in developing conventional oil and gas resources. In recent years, unconventional reservoirs are drawing more and more attention all over the world, therefore the development theory and technology, especially the corresponding flow mechanisms have become the hot research issues. The unconventional reservoirs exhibit distinct multiscale characteristics, even with six orders of magnitude difference. In addition, the application of massive multi-stage hydraulic fracturing can induce strong stress interactions. Therefore, the traditional theory of fluid flow in porous media cannot accurately describe the flow characteristics in unconventional reservoirs. In essence, the development of unconventional oil and gas resources involves multiphase fluids (e.g. oil, water and gas) flow in multi-scale porous media with multi-field coupling and various flow patterns. Therefore, the concept of modern system of multiphase flow in porous media is proposed, which means multiphase fluids flowing in multi-scale porous media with multi-field coupling and various flow patterns. The research status and development tendency are reviewed from the aspects of: (1) micro- and nanoscale oil and gas flow simulation; (2) upscaling for reservoir simulation, (3) macroscale flow simulation of unconventional oil and gas reservoirs; (4) simulation of flow in large scale fractured and vuggy carbonate reservoirs and (5) physical simulation of hydrocarbon transport in porous media. More specifically, in nanoscale the density functional theory and molecular simulation method can be used to study the interfacial phenomena to understand the hydrocarbon transport behavior in nanopores and provide key parameters for mesoscale flow simulation. The current study of nanoscale simulation mainly focuses on developing more realistic molecular structure model to represent the heterogeneous shale samples. Microscale simulation methods involve pore network model, lattice Boltzmann method, direct simulation of Navies-Stokes equation, level-set method and smoothed particle hydrodynamics, etc. Digital core and pore network model are the fundamental research platforms. Various methods can be used to reconstruct digital cores with multiscale pore structures and mineral compositions. The complex physicochemical phenomena namely adsorption/desorption, wettability change and boundary effect should be considered in the microscale flow simulations and extensive works have been done in microscale gas flow simulations. The future work on microscale simulation should focus on the multiphase flow mechanisms with multi-field coupling. The multiscale characteristics of unconventional reservoirs indicate the necessity of upscaling process to introduce the microscale flow mechanisms to macroscale. Homogenization theory and volume averaging method are the main upscaling approaches. Current upscaling methods are mostly based on the periodic boundary condition and are unreliable to be used in complex oil and gas reservoirs, which needs further study. In addition, more research needs to be conducted on the upscaling from molecular scale to mesoscale. In macroscale simulations of unconventional oil and gas reservoirs, the fluid-structure interaction should be considered and high efficiency numerical algorithm needs to be established. For large scale fractured and vuggy carbonate reservoirs, the non-Darcy flow characteristics and different flow regimes in vugs and fractures should be taken into account during flow simulation. Physical simulations of hydrocarbon transport in porous media are conducted at two scales: macroscale, nano- and microscale. Macroscale physical simulations aim at monitoring the dynamic saturation and pressure fields change under the realistic reservoir conditions. Nano- and microscale physical simulations are mainly applied to study the fluid transport mechanisms in single pore or throat. In summary, the proposed theory of multiphase fluids flowing in multi-scale porous media with multi-field coupling and various flow patterns can be applied to study the fluid flow problems in unconventional oil and gas industries.

Modeling tracer flowback in tight oil reservoirs with complex fracture networks

Tight oil reservoirs are commonly developed by a combination of horizontal wells and multistage hydraulic fracturing techniques. The characterization of complex fracture networks after fracturing treatments is a common challenge for unconventional reservoirs. Tracer flowback profiles can reveal a fracture network at an individual stage. However, the numerical simulation of tracer transport in fractured reservoirs usually employs a dual-porosity continuum medium model or describes fractures by an enlarged fracture aperture in a regular grid system that is not capable of modeling a complex fracture network. Especially, the influences of the properties of fracturing fluid and variations in fracture permeability caused by pressure changes on tracer flowback profiles are not investigated.In this paper, a two-phase (water and oil), four-component (oil, water, fracturing fluid and tracer) numerical simulator is developed based on a discrete fracture model for modeling tracer injection and flowback in tight oil reservoirs. With respect to fracture network modeling, the simulator is capable of explicitly modeling an arbitrary distribution of fracture networks with a real fracture aperture by triangular grids. With respect to mechanism consideration, the simulator considers the influences of fracturing fluid and pressure-dependent fracture permeability on tracer flowback profiles. The properties of tracer dispersion and adsorption are also considered in both fractures and matrix. To validate the proposed model, a comparison is performed with the commercial software Eclipse. Sensitivity studies are performed to investigate the influences of parameters on tracer flowback profiles. The presented simulator is applied in the Changji oilfield to characterize individual stages using a stochastic method.Results show that the developed simulator is accurate as with Eclipse. The filed application indicates that the presented simulator can model tracer flowback and production performance. Sensitivity studies show that an increase in permeability modulus and the viscosity of fracturing fluid delays the peak arrival time. An increase in permeability modulus decreases the peak amplitude while an increase in the viscosity of the fracturing fluid increases the peak amplitude. An increase in a dead pore volume and a residual resistance factor has little impact on the peak position and lowers the tails of tracer flowback profiles. The sensitivity studies provide valuable information in characterization of a fracture network using tracer flowback data.

Effectiveness of miscible and immiscible gas flooding in recovering tight oil from Bakken reservoirs in Saskatchewan, Canada

Oil production from unconventional tight Bakken reservoirs in North America has been booming since the early 2000s because of the widespread application of horizontal well drilling and multi-stage hydraulic fracturing technologies. Tight oil recovery is made difficult by the extremely low permeability and porosity of the oil-hosting rocks. Two key characteristics in tight oil production are the steep decline in oil production rate and the low ultimate oil recovery. Therefore, maintaining oil production and improving a field project’s economic benefits become urgent issues for the development of tight oil resources. The substantial amounts of residual oil left behind in tight reservoirs demand a viable and effective enhanced oil recovery (EOR) technology after the primary recovery process. This research investigated the effectiveness of miscible or immiscible gas flooding processes using four possible injection gas candidates (i.e., CO2, CO2-enriched flue gas, oilfield-produced gas, and nitrogen) for Bakken tight oil reservoirs in southeast Saskatchewan, Canada. The phase behaviour of the reconstituted live oil–injection gas systems was studied through pressure/volume/temperature (PVT) tests in which important recovery mechanisms of gas flooding, i.e., viscosity reduction and oil swelling effects, were revealed. The minimum miscibility pressures (MMP) for the live oil–injected gas systems were determined using the rising bubble method. The experimental results demonstrated that CO2 had the lowest MMP and largest viscosity reduction and oil swelling among all the tested gases. Therefore, CO2 flooding is considered technically feasible as a miscible process at the current reservoir conditions, while the use of the other three gases would result in an immiscible process. Finally, four coreflood tests using reservoir cores from the Viewfield Bakken field were conducted to evaluate the displacement efficiency. Each coreflood comprised four stages (pressure depletion, initial waterflood, gas injection, and extended waterflood) to represent the actual field production practice. Oil recovery performance confirmed that CO2 miscible flooding was significantly more effective than immiscible flooding with the other injection gases.

Analysis of Effective Porosity and Effective Permeability in Shale-Gas Reservoirs With Consideration of Gas Adsorption and Stress Effects

Summary Nanoscale porosity and permeability play important roles in the characterization of shale-gas reservoirs and predicting shale-gas-production behavior. The gas adsorption and stress effects are two crucial parameters that should be considered in shale rocks. Although stress-dependent porosity and permeability models have been introduced and applied to calculate effective porosity and permeability, the adsorption effect specified as pore volume (PV) occupied by adsorbate is not properly accounted. Generally, gas adsorption results in significant reduction of nanoscale porosity and permeability in shale-gas reservoirs because the PV is occupied by layers of adsorbed-gas molecules. In this paper, correlations of effective porosity and permeability with the consideration of combining effects of gas adsorption and stress are developed for shale. For the adsorption effect, methane-adsorption capacity of shale rocks is measured on five shale-core samples in the laboratory by use of the gravimetric method. Methane-adsorption capacity is evaluated through performing regression analysis on Gibbs adsorption data from experimental measurements by use of the modified Dubinin-Astakhov (D-A) equation (Sakurovs et al. 2007) under the supercritical condition, from which the density of adsorbate is found. In addition, the Gibbs adsorption data are converted to absolute adsorption data to determine the volume of adsorbate. Furthermore, the stress-dependent porosity and permeability are calculated by use of McKee correlations (McKee et al. 1988) with the experimentally measured constant pore compressibility by use of the nonadsorptive-gas-expansion method. The developed correlations illustrating the changes in porosity and permeability with pore pressure in shale are similar to those produced by the Shi and Durucan model (2005), which represents the decline of porosity and permeability with the increase of pore pressure in the coalbed. The tendency of porosity and permeability change is the inverse of the common stress-dependent regulation that porosity and permeability increase with the increase of pore pressure. Here, the gas-adsorption effect has a larger influence on PV than stress effect does, which is because more gas is attempting to adsorb on the surface of the matrix as pore pressure increases. Furthermore, the developed correlations are added into a numerical-simulation model at field scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in the Barnett Shale reservoir. The simulation results note that without considering the effect of PV occupied by adsorbed gas, characterization of reservoir properties and prediction of gas production by history matching cannot be performed reliably. The purpose of this study is to introduce a model to calculate the volume of the adsorbed phase through the adsorption isotherm and propose correlations of effective porosity and permeability in shale rocks, including the consideration of the effects of both gas adsorption and stress. In addition, practical application of the developed correlations to reservoir-simulation work might achieve an appropriate evaluation of effective porosity and permeability and provide an accurate estimation of gas production in shale-gas reservoirs.

Where gas is produced from a shale formation: A simulation study

Gas production from shale reservoirs has increased rapidly in the past decade, becoming an important source for natural gas supply. For tight shale formations, horizontal wells combined with multi-stage hydraulic fracturing is the key to realize commercial production. The multi-scale flowing spaces and complex flowing mechanisms of shale gas reservoirs pose challenges to elucidating their production behaviors. Existing modelling methods are not able to distinguish gas production from different regions or different forms (adsorbed-gas/free-gas). Therefore, they cannot accurately assess how much produced gas is from desorption effects and whether gas stored in the unstimulated region will support production. Answers to these questions will improve our understanding of production mechanisms and facilitate the optimization of development plans.In this study, we proposed a general component subdivision modelling method to separately model the flowing behavior of gas stored in different forms or different regions. As an example the method is incorporated in the compositional model in the UNCONG simulator. Applying this method, a conceptual model based on Fuling Jiaoshiba shale was built, and contributions from adsorbed-gas/free-gas inside of the stimulated reservoir volume (SRV) and outside of the SRV were analyzed. Sensitivity studies on fracture spacing were also performed. The results show that, for the Fuling case, when the matrix permeability is 10−4 mD, 78% of total production comes from the free-gas inside of the SRV after about 20 years of production, and free-gas outside of the SRV and adsorbed-gas inside of the SRV also help to sustain long-term production. However, when the matrix permeability is as low as 10−5 mD, almost all production comes from free-gas inside of the SRV within 20 years of production. Sensitivity studies show that network fractures play an important role to increase production. In the final case study, a more efficient way for component subdivision modelling was demonstrated. This study provides insights for shale gas production and its controlling factors, which can be utilized to optimize fracturing design and resources assessment.