Hydraulic Fracture Conductivity Research Articles

Downhole flow control: A key for developing enhanced geothermal systems in horizontal wells

Field evidence indicates that only a few large fractures in enhanced geothermal systems (EGS) may dominate fluid flow and lead to the development of thermal short-circuiting. This problem would worsen in heat harvesting through horizontal wells with abundant fractures (induced or natural ones). To limit flow shortcuts that may cause early thermal breakthroughs, we propose a temperature-sensitive flow management system and explore its potential benefits during the development of EGS in horizontal wells. The proposed downhole flow management system consists of sensors for real-time temperature monitoring, and flow control devices for adjusting injection distribution in the wellbore. We evaluate the performance of such systems over 50 years of operation by numerical analysis. The results indicate that, when the proposed system is utilized, the produced fluid temperature will be increased by up to 60 K for a field-scale example. Besides, the application of the proposed flow management system can increase the cumulative heat extraction by up to 48.25 % (0.69 × 1016 J) after 50 years. The heat extraction efficiency can be improved by up to 94.16 %. During the EGS operation, it is suggested to implement multi-stage fluid control, but it is not recommended to reopen the fluid injection that has been previously shut down. Finally, the flow management system can mitigate the negative impacts of geological heterogeneities or the heterogeneity in fracture hydraulic conductivities. This paper proposes a new concept of flow management to integrate horizontal wells into efficient EGSs for power generation and heat extraction in the future.

Layered massive fracturing of carrier beds commercially unveils the deep tight sandstone gas reserves in Sichuan Basin

Achieving commercial production from deep tight gas formations poses challenges to existing geological and engineering technologies. Xujiahe tight sandstone gas, deeply buried in the Western Sichuan Basin, is proven with enormous reserves; however, preliminary hydraulic fracturing trials mostly failed to bring up the productivity. From the angle of incorporating geological and engineering knowhow, we first adopted the carrier beds theory to distinguish the favorable zones in Xujiahe Formation, then a dual sweet spot identification criterion was established based upon analytic hierarchy process, which links major geological and engineering parameters together. Provided the identified sweet spot, hydraulic fracture conductivity was then optimized to maximize the productivity. Fracturing operational parameters consisting of fluid volume and pumping, proppant size and addition, and fluid formula were then screened to secure high conductivity. Implementation of this updated geological-engineering technical route in exploiting Xujiahe tight gas reservoirs turns out to be a great success with an average gas rate of 130 Mm3/d/well during the early production stage in 14 wells. Electromagnetic monitoring further demonstrated the effectiveness of precise massive fracturing by visualizing the morphology of fracture clusters. Comparative productivity analyses manifested the breakthrough of this technical route over preceding ones in Xuejiahe gas reservoirs, providing a superior reference for discovering and developing deep tight gas resources around the world.

Optimization Design of Hydraulic Fracturing Fracture Parameters of Horizontal Wells in Algal Limestone Reservoir

The algal limestone reservoir has extremely low permeability, developed dissolution pores and weak structural planes, and has heterogeneity. There is a problem of significant differences in single-well production after fracturing in oilfield sites. It is crucial to clarify the matching relationship between hydraulic fracture parameters and production. This article establishes a triple medium seepage mathematical model of “fracture—dissolution pore—matrix pore” considering the lithological characteristics of algal limestone, which is used to predict the cumulative production of horizontal wells after fracturing, and its reliability is verified through example well production data. The influence of fracture parameters on the production of horizontal wells was revealed through numerical simulation, filling the gap in the study of parameters for the stimulation of algal limestone reservoirs. The results indicate that the proposed triple medium model can accurately characterize the characteristics of algal limestone and is suitable for simulating the production capacity of algal limestone reservoirs. The production of horizontal wells is influenced by various hydraulic fracture parameters. The length, conductivity, and height of hydraulic fractures are positively correlated with production, while the spacing between fractures is negatively correlated with production. Taking the overall production of the platform horizontal well group as the optimization objective, and the change in production increase as the discrimination criterion, the optimal values of various fracture parameters are determined. At the same time, simulation results show that using the staggered fracture pattern is beneficial for improving the overall production. The research results have reference significance for the development of algal limestone reservoirs

Effect of Acid-Injection Mode on Conductivity for Acid-Fracturing Stimulation in Ultra-Deep Tight Carbonate Reservoirs

The conductivity of acid-etched fractures and the subsequent production response are influenced by the injection mode of the fracturing fluid and acid fluid during acid fracturing in a carbonate reservoir. However, there has been a lack of comprehensive and systematic experimental research on the impact of commonly used injection modes in oilfields on conductivity, which directly affects the optimal selection of acid-fracturing injection modes. To address this gap, the present study focuses on underground rock samples, acid systems, and fracturing fluid obtained from ultra-deep carbonate reservoirs in the Fuman Oilfield. Experimental investigations were conducted to examine the conductivity of hydraulic fractures etched by various types of acid fluids under five different injection modes: fracturing fluid + self-generating acid or cross-linked acid; fracturing fluid + self-generating acid + cross-linked acid. The findings demonstrate that the implementation of multi-stage alternating acid injection results in the formation of communication channels, vugular pore space, and natural micro-cracks, as well as grooves and fish-scales due to enhanced etching effects. The elevation change, amount of dissolved rock, and conductivity exhibited by rock plates are significantly higher in comparison to those achieved through the single-acid injection mode while maintaining superior conductivity. It is recommended for optimal conductivity and retention rate in the Fuman Oilfield to adopt two stages of alternating acid-fracturing injection mode. Field application demonstrated that two-stages of alternating acid-fracturing generate more pronounced production response than the adjacent wells.

Temperature, pressure, and duration impacts on the optimal stiffening of carbonates aged in diammonium phosphate solution

Diammonium phosphate (DAP) has been proven effective in improving the stiffness of weak or acid-damaged carbonates, thereby preserving hydraulic fracture conductivity. The reaction between DAP and calcite in chalk formations primarily produces hydroxyapatite (HAP), which is stiffer than calcite. However, the optimal reaction outcomes vary greatly with factors such as DAP concentration and reaction conditions. This study investigated the DAP-calcite reaction duration, pressure, and temperature effects on the stiffness magnitude of soft Austin chalk. Also, the catalyst effect and depth of HAP formation were examined. The study involved the assessment of stiffness non-destructively (impulse hammering), mineralogy (XRD, SEM), and elemental composition (XRF). The study tested 15 different DAP-chalk reaction variations, where the pressure, temperature, aging time and catalyst addition were modified in each case. The samples' elastic stiffness distributions were then collected and compared to the pre-reaction ones. The results showed that the elastic stiffness increased in all treated samples, with an 181% maximum increase achieved after 72 h at 6.9 MPa and 75 °C. However, the pressure effect was minor compared to the temperature. The SEM images revealed different HAP morphology corresponding to different treatment conditions. Although the treated samples showed an increased intensity of phosphorus throughout the entire sample, the near-surface zone (4–6 mm) was the most affected, as inferred from the XRF elemental analysis. The study's findings can help optimize hydraulic fracturing operations in weak carbonate reservoirs, improving production rates and overall well performance.

Study on fracturing fluid return pattern and production characteristics of shale gas wells

We innovatively propose a research method through micro-experiment + macro-measurement, combined with onsite proppant return test. This method can solve the problem of unclear impact of the return shut-in time, return rate control and return effect on production. We carried out a specific applied research for Fuling shale gas Jiangdong block, specifically determined the mineral composition, overburden pressure physical properties before and after fracturing fluid percolation, the changing law of resistance environment of gas production channel inside the reservoir before and after fracturing fluid percolation, and explored the settlement problem of proppant’s size, type and nature in the fracture through the situation of sand return. This study concludes that the reservoir testing process can be divided into pure fluid production stage, gas breakthrough stage, and stable production stage. The optimal contact time between shale and fracturing fluid promotes the hydration of clay minerals to produce microfractures and the formation of a complex network of intercommunicating seams facilitated by external dynamics, which promotes gas production. And the wrong return after fracturing will affect the hydraulic fracture conductivity.

Analysis and prediction of contact characteristics of rock fracture surfaces under normal loading

The real contact area of rock fractures is smaller than the nominal area, and actual stresses on contacts are significantly higher. Evaluating contact characteristics and predicting potential contact areas are crucial for understanding mechanical and hydraulic properties of geological fractures under compression or shear. We measured the real contact area of mated tensile fractures using pressure-sensitive films and studied their contact characteristics and evolution under different normal stresses through point cloud analysis. It is revealed that the initial aperture of mated tensile fractures determines the contact state. Under conditions of low normal stress, regions exhibiting higher mean curvature are more susceptible to contact formation, particularly when aperture sizes are comparable. This propensity is further influenced by the directional orientation of the normal vector components within these regions. Increasing normal stress leads to faster development of new contacts in regions with smaller initial apertures. Additionally, we predicted contact characteristics and real contact area of tensile fractures using back propagation artificial neural network. Comparison between predictions and laboratory measurements demonstrated accurate prediction of contact distribution and area values by the neural network. Our findings enable the prediction of real stress states, potential failure areas, and hydraulic conductivity of rock fractures in slope and underground rock engineering.

Skin Factor Consideration in Decline Curve Analysis

Summary This paper introduces an approach for the impact of skin factor on the decline curve analysis of hydraulically fractured reservoirs. The objective is to consider this impact in the production forecasting and the ultimate recovery estimation. The approach focuses on reducing the uncertainties that could be raised from this impact on the production history and increasing the accuracy of the predicted flow rates. It proposes an easy and promising tool for the decline curve analysis that could be applied confidently to different oil- and gas-producing wells and different reservoirs. This approach utilizes the rate-normalized flow rate derivative β behavior of the fractured reservoirs. This derivative demonstrates a constant behavior with time for each flow regime when the production history has not undergone the impact of the skin factor. However, the constant behavior no longer exists when this impact has influenced the production history. Instead, a power-law type model governs the relationship between the flow rate derivative and production time. New analytical flow rate decline curve models, exponential-type, are derived from the flow rate derivative power-law type models for the flow regimes. Different models for calculating the skin factor are developed for the three linear flow regimes that could be observed during the transient state flow conditions. The proposed flow rate models are used to simulate the production history and forecast the future performance. Moreover, the hydraulic fracture conductivity can be calculated using these models as well as the flow rate loss caused by skin factor. Several case studies are examined by the proposed approach where the production history is used to characterize the dominant flow regimes. The study has reached several observations and conclusions. The impact of skin factor is seen clearly throughout transient state flow regimes; however, this impact declines sharply before reaching pseudosteady-state flow (boundary-dominated flow regime). The impact of the skin factor alternates the constant behavior of the flow rate derivative with time to a power-law type relationship. A straight line of a slope (0.5) is diagnosed during hydraulic fracture and formation linear flow regime on the log-log plot of the flow rate derivative β and time, while the bilinear flow regime demonstrates a straight line of a slope (0.25). Because of the skin factor, exponential decline curve models replace the power-law type models of the flow rate during the abovementioned flow regimes. These models exhibit an excellent match between the calculated flow rate and the production history. The maximum flow rate loss occurs during very early production time even though the skin factor during this time is less than the intermediate production time. This study presents a novel approach for the decline curve analysis taking into account the impact of skin factor. The novelty is represented by considering the flow regimes in the production forecasting of hydraulically fractured reservoirs. This approach is smoothly applied to predict the future performance with no need to know the wellbore and reservoir parameters. It can be used to predict the declining flow rate for a constant or varied bottomhole flowing pressure.

Establishment and application of propped hydraulic fracture conductivity theoretical model based on fracturing efficiency index

Hydraulic fracturing technology is a key technology for the development of unconventional oil and gas reservoirs, and the conductivity of hydraulic fractures has a great impact on their production. The paper introduces the "fracturing efficiency index" as means of characterising the dynamic relationship between hydraulic fracture expansion and proppant filling. It also suggests a way to figure out the proppant fracture inflow capacity. This approach addresses issues such as uneven fracturing fluid dosage, a wide range of injection discharges, and inconsistent sand spreading concentration encountered during fracturing operations. Based on this model, the influencing factors of the flow-conducting capacity such as proppant particle size, sand spreading concentration, liquid injection displacement, and proppant crushing rate, were analyzed, and the calculated results of this model are closer to the experimental results of the API flow-conducting capacity test compared with the calculated results of the reference model. Finally, this model was used to optimize the fluid volume, sand volume, and displacement of hydraulic fracturing in the Jiping 1H shale gas field. The research results show that: (1) the fracturing efficiency index is negatively correlated with the conductivity of hydraulic fractures, whereas is positively correlated with the enhancement of conductivity; (2) our model is applicable to the calculation of supported fracture inflow capacity for high sand concentration, large particle size, intermediate fracture flow and low crushing rate, and the results are close to more than 98.58%, 98.29%, 95.68% and 95.08% of the experimental results, respectively; (3) On-site hydraulic fracturing does not result in higher production capacity with more fracturing fluid dosage, higher displacement and more sand addition; there are optimal fluid, optimal displacement and optimal sand intervals, which are optimized to increase production by 26.92%. It can be seen that the hydraulic fracture conductivity model can optimize various parameters of on-site fracturing construction.

Intelligent fluid flow management for enhanced geothermal system in fractured horizontal wells

The presence of thermal short-circuiting impedes the further development of enhanced geothermal systems (EGSs) with horizontal wells. The objective of this research is to explore the effectiveness of a new technique, i.e., tunable fracture conductivity, in the control of thermal short-circuiting in EGSs with horizontal wells. The core idea of tunable fracture conductivity is to adjust the hydraulic conductivity of fractures according to the surrounding temperature at any point and seal any dominant flow path with a low temperature that may short-circuit the fluid flow. By utilizing this technique, thermal shortcuts between the wells can be effectively suppressed, and uniform heat extraction from each flow path can be expected. The performance of tunable fracture conductivity is investigated based on numerical simulations. According to the simulation results, tunable fracture conductivity can significantly improve heat sweeping between the injection and production well. After 50 years of operation, this technique increases production temperature by approximately 50 K, from 358.71 K to 410.32 K, which significantly elongates the effective period of operation in an EGS. Furthermore, using temperature-adaptive fracture conductivity improves heat extraction efficiency by 113.2 % which can be translated as an extra reduction in greenhouse gas (GHG) emission for 1.15 – 3.21 Mt with only one pair of wells. Besides, smaller fracture half-length and fracture spacing can also help the tunable fracture conductivity to better control the thermal short-circuiting and maintain the high-efficient EGS operation. This study provides a new method to achieve cleaner, more profitable, and highly efficient geothermal systems in the future.

A New Fracturing Method to Improve Stimulation Effect of Marl Tight Oil Reservoir in Sichuan Basin

China’s argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize fracturing parameters. The second problem is that there are a lot of natural fractures in the argillaceous limestone reservoir, which leads to a lot of fracturing fluid loss. The third problem is that the closure pressure of the argillaceous limestone reservoir is high, and the conductivity of fractures decreases rapidly under high closure pressure. The last problem is that the fracture shape of the argillaceous limestone reservoir is complex, and the law of proppant migration is unclear. The main research methods in this paper include reservoir numerical simulation, fluid-loss-reducer performance evaluation, flow conductivity tests and proppant migration visualization. To solve the above problems, this paper establishes the fracturing productivity prediction model of complex lithology reservoirs and defines the optimal hydraulic fracturing parameters of the argillous limestone reservoir in the Sichuan Basin. The 70/140 mesh ceramide was selected as the fluid loss additive after an evaluation of the sealing properties of different mesh ceramides. At the same time, the hydraulic fracture conductivity test is carried out in this paper, and it is confirmed that the fracture conductivity of 70/140 mesh and 40/70 mesh composite particle-size ceramics mixed according to the mass ratio of 5:5 is the highest. When the closure pressure is 40 MPa, the conductivity of a mixture of 70/140 mesh ceramic and 40/70 mesh ceramic is 35.6% higher than that of a mixture of 70/140 mesh ceramic and 30/50 mesh ceramic. The proppant migration visualization device is used to evaluate the morphology of the sand dike formed by the ceramsite, and it is clear that the shape of the sand dike is the best when the mass ratio of 70/140 mesh ceramsite and 40/70 mesh ceramsite is 6:4. The research results achieved a good stimulation effect in the SC1 well. The daily oil production of the SC1 well is 20 t, and the monitoring results of the wide-area electromagnetic method show that the fracturing fracture length of the SC1 well is up to 129 m.

Model and Analysis of Pump-Stopping Pressure Drop with Consideration of Hydraulic Fracture Network in Tight Oil Reservoirs

The existing pump-stopping pressure drop models for the hydraulic fracturing operation of tight oil reservoirs only consider the main hydraulic fracture and the single-phase flow of fracturing fluid. In this paper, a new pump-stopping pressure drop model for fracturing operation based on coupling calculation of the secondary fracture and oil-water two-phase flow is proposed. The physical model includes the horizontal wellbore, the fracture network and the tight oil reservoir. Through the numerical simulation and calculation, the wellbore afterflow performance, the crossflow performance between the main hydraulic fracture and the secondary fracture, the fracturing fluid leakoff and the oil-water replacement after termination of pumping are obtained. The pressure drop characteristic curve is drawn out by the bottom-hole flow pressure calculated through the numerical simulation, and a series of analyses are carried out on the calculated pressure drop curve, which is helpful to diagnose the -oil-water two-phase flow state and the fracture closure performance under the control of the fracture network after hydraulic fracturing pumping. Finally, taking a multi-stage fractured horizontal well in a tight oil reservoir in the Junggar basin, China as an example, the pump-stopping pressure drop data of each stage after hydraulic fracturing are analyzed. Through the history fitting of the pressure drop characteristic curve, the key parameters such as fracture network parameters, which include the half-length of main hydraulic fracture, the conductivity of main hydraulic fracture and the density of secondary fracture, the fracture closure pressure are obtained by inversion, thus, the hydraulic fracturing effect of fractured horizontal well in tight oil reservoirs is further quantified.

Modelling and optimization of shallow underground thermal energy storage

Shallow geothermal reservoirs are excellent candidates for low-enthalpy energy storage, and can serve as heat batteries providing constant discharge of base heat, as well as rapid discharge of heat in periods of high demand. Recharging can be done by pumping down hot water, heated using excess heat from e.g. waste incinerators. In addition to having a very low carbon footprint, such systems also require limited surface infrastructure, and can easily be placed near or under the end-user, such as below residential buildings. The geological setting is typically complex, with horizons, faults, and intertwined patterns of natural fractures, and the nearwell region is often hydraulically fractured to enhance inter-well communication. Therefore, in order to fully utilize the potential of shallow geothermal heat storage, numerical simulations are imperative. In this work, we show how to practically model such systems, including generation of computational grids with a large number of wells and fractures, numerical discretizations with discrete fractures, and complex storage strategies with multiple wells working together under common group targets. We also discuss how adjoint-based methods can be used to tune model parameters (e.g. well injectivities, rock properties, and hydraulic fracture conductivities) so that the model fits observed data, and to find well controls (e.g. rates and temperatures) that optimize storage operations. The methodology is demonstrated using one artificial and two real underground thermal energy storage projects currently under development, and we highlight important challenges and our suggested solutions related to each of them. Thematic collection: This article is part of the Earth as a thermal battery: future directions in subsurface thermal energy storage systems collection available at: https://www.lyellcollection.org/topic/collections/thermal-energy

Fracture conductivity management to improve heat extraction in enhanced geothermal systems

The efficiency of an enhanced geothermal reservoir (EGS) depends on the effective circulation of the working fluid through the geothermal formation. To remove the thermal shortcut that leads to thermal short-circuiting in the EGS, we present a method of fracture hydraulic conductivity management and present some practical ways to implement it in the field. The core idea is to correlate the flow resistance in different flow channels with temperature, in order to make uniform heat extraction through each flow path. The presented technique is an adaptive and reversible system and is trying to engineer the fracture system for effective delay of the early thermal breakthrough in EGS. Results indicate that the proposed fracture conductivity tuning technique (FCTT) can help to avoid flow and thermal shortcuts between the wells and maintain high heat extraction rates. The autonomous management of fracture conductivity may increase cumulative heat extraction by more than 214 %, and reduce an extra 1.06 – 3.65 Mt of greenhouse gas emission through electricity generation after 50 years of EGS development, which is highly considerable for EGS development. Besides, we found that it could be still beneficial to apply such methods solely to the injection wells, which can also bring a heat extraction improvement of 201.9 %. Furthermore, we look at the situations when the special conductivity tuning agents are placed in the middle between the wells, it is still very effective to control the fluid flow in the reservoir and enhance heat extraction. By proposing the tunable fracture conductivity, we are trying to revisit the old problem of thermal short-circuiting and provide new insight into the efficient EGS operation.

Improving enhanced geothermal systems performance using adaptive fracture conductivity

Maximizing heat extraction from enhanced geothermal systems (EGS) depends heavily on an efficient heat sweeping or basically an effective circulation of water through fracture networks. Fracture hydraulic conductivity can play a critical role in controlling potential thermal breakthroughs; however, the exact geometry and properties of these fractures cannot be determined in practice. Thermal breakthrough remains a main challenge for maintaining efficient heat extraction throughout the lifespan of an EGS project. In this work, we explore the concept of fracture conductivity tuning using temperature-sensitive proppants to extract more heat and delay thermal breakthrough from the particle scale to the reservoir scale. We derive an empirical equation to describe fracture conductivity as a function of proppant properties and in-situ conditions including closure stress and temperature. Sensitivity analysis are performed to determine which parameters are the most crucial in determining the temperature-sensitive proppant permeability. Temperature and thermal expansion coefficient are the main contributing factors to the change in proppant permeability. Poisson’s ratio is found to have negligible impact on the proppant permeability. The derived equation is used to quantify the improvement in heat extraction from EGS at the field scale. The outcome shows that using temperature-sensitive proppant can increase the heat extracted by 47.8% compared to using typical proppant. This work assesses the feasibility of using temperature-sensitive proppants to effectively delay thermal breakthrough and sweep larger amounts of heat from EGS. In addition, this paper provides a quick and robust method to determine the required properties of such temperature-sensitive proppants to achieve uniform thermal gradient along different flow paths in the subsurface autonomously.

Enhancing Fracture Conductivity in Soft Chalk Formations With Diammonium Phosphate Treatment: A Study at High Temperature, Pressure, and Stresses

Summary This study aims to address the problem of fracture hydraulic conductivity decline in soft formations using a diammonium hydrogen phosphate (DAP) solution. A naturally weak carbonate, Austin chalk was chosen as an ideal specimen. Flat chalk samples with reduced elastic modulus and roughness were evaluated before and after aging with 1 M DAP for 72 hours at 75°C and 1,000 psi. The fracture gas conductivity of DAP-aged and untreated samples was measured at various flow rates and stresses while recording sample compaction using linear variable differential transformers (LVDTs). The study found that DAP aging increased the reduced elastic modulus of chalk specimens up to 330% of the original value, improving their resistance to deformation and failure under stress by 200 psi. The hydraulic conductivity of DAP-aged samples was at least twice that of untreated samples, with an extended hydraulic fracture conductivity seven times higher than that of the untreated ones. Scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS) analysis revealed that DAP reacted with the chalk to form hydroxyapatite (HAP), which binds the calcite grains, yielding a stiffer, more deformation-resisting rock surface. Overall, the study demonstrates the potential of chemically enhancing and extending the fracture hydraulic conductivity of weak carbonates using DAP.

Autonomous fracture flow tunning to enhance efficiency of fractured geothermal systems

To avoid any shortcuts that may “short-circuit” the fluid flow between the injection and production wells in an enhanced geothermal system (EGS), we explore the idea of autonomous in-situ tunning of fracture hydraulic conductivity (FCTT) and its potential benefits. The new technique is expected to provide variable fracture hydraulic conductivity depending on the surrounding temperature. Through FCTT, we can effectively manage the fluid flow in the reservoir and promote a uniform thermal gradient along the flow paths. A numerical finite element model is established to assess the impact of tunning magnitude and fracture network geometries on the production efficiency of EGSs. Results show that utilizing this technique could prevent an early appearance of fluid flow shortcut between injector and producer in an EGS. After 50 years of production, the output thermal power with the technique could be increased by 67.51%. Furthermore, we found that fracture density and fracture network connectivity in the reservoir could affect performance improvement reached by FCTT in production. We also present a field case with a realistic fracture network. After 50 years of production, applying this technique increases heat extraction by 101.78% in fracture networks that are expected in EGS. Since other flow-control systems in geothermal production are mainly focused on the wellbore and near-wellbore areas, this technique can provide a more effective enhancement in heat extraction by controlling flow deep inside the reservoir.

Hydraulic fracture morphology and conductivity of continental shale under the true-triaxial stress conditions

Continental shale oil formations generally exhibit more complex lithology and stronger heterogeneity than marine shale. The coexistence of dense laminas, lithologic interfaces (LIs), and mineral-filled natural fractures (NFs) in such formations can cause complex mechanisms of hydraulic fracture (HF) growth, proppant placement, and conductivity evolution. To obtain an intuitive understanding of this problem, a series of comprehensive laboratory sand fracturing experiments and fracturing conductivity tests were carried out innovatively on downhole shale cores using an improved small-size true triaxial fracturing simulation system combined with multiple examination methods in this work. HF morphology and proppant distribution were characterized through the high-precision CT scanning technique. Moreover, HF conductivity was tested on the cylindrical cores drilled from the fractured specimens. Experimental results show that high breakdown pressure and volatile wellbore pressure during the sand-adding stage were likely presented in the relatively rigid formations. HF growth path is likely to be deflected and bifurcated by the NFs laterally and by the oblique laminas vertically. “╪”-shaped HF also tends to be created due to the interaction of HF with dense horizontal laminas. The local heterogeneity in the continental shale formation can cause significant complexity and uncertainty in HF. The dominant HF nearby the wellbore contains most of the proppant, and the activated laminas, NFs, or/and branches are short of proppant. The volume and area of the proppant-filled HF can only account for less than 20% of the total HF volume and less than 65% of the total HF area, respectively. The distribution of relatively small-size proppant is more uniform and broader than that of large ones. There is a positive correlation between fracture conductivity and the proppant concentration. The conductivity of no proppant-filled fractures (including the HF, activated lamina, and NF) is low and unstable, and can almost be neglected under closure stress beyond approximately 20–25 MPa. The findings in this work are expected to provide practitioners with a bigger map of the performance and effectiveness of the hydraulic fracture they created.

A global inertial permeability for fluid flow in rock fractures: Criterion and significance

Fluid flow in rock fractures is described by Darcy's law and its nonlinear extension, the Forchheimer equation in form of a quadratic polynomial. Since the nonlinearity of the Forchheimer equation, determining its key coefficient of inertial permeability (i.e., the quadratic coefficient representing inertial losses) requires a series of flow tests under different hydraulic gradients. However, how to choose the volumetric flux range for deriving inertial permeability is never scrutinized. Here we report a seemly irrational dependency of inertial permeability on volumetric flux range by massive direct numerical simulations of fluid flow in rock fractures. This variation presents traceability and is closely related to the evolution of microscale eddies and macroscale flow regimes. A concept of global inertial permeability is thus proposed from this traceable variation, which can reproduce the whole flow regime in rock fractures. Two parametrized criterion models are subsequently established for calculating global inertial permeability using the lowest cost and ensuring its accuracy: one in terms of minimum Reynolds number for practical purposes, and the other in terms of minimum eddy volume ratio for mechanistic interpretation. Further discussions indicate that the proposed global inertial permeability is of great importance to non-Darcian flow prediction and flow regime assessment. Moreover, the parameterized criterion models in the form of power-law function for determining global inertial permeability, drawn from 2D fracture simulations, can apply to 3D fractures and large-scale fractured rock aquifers. The findings and results in this study are of great significance for accurately evaluating the hydraulic conductivity of rock fractures, especially at relatively high flow rates, and are useful for many geophysical and industrial applications.

Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

Objectives/scopeStimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO2-reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO2, can potentially be used as a less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO2 fracturing fluids outperformed other fluids such as water, CO2, and CO2/water in generating large fractures with less fluid consumed. The objective of this work is to investigate the effect of initial water saturation on the performance of StimuFrac by conducting hydraulic fracturing tests with ½ foot cubic rock samples held under representative EGS stress/temperature conditions and by using cyclic injection strategies (under constant injection rate). The resulting fracture hydraulic conductivities, breakdown pressures, and volumes of fluids required are compared. Methods/procedures/processTo simulate geothermal reservoir conditions, in all tests, the rock sample was held under triaxial confinement and at 200 °C, and different volumes of water were initially injected into the rock sample before any fracturing processes were initiated. For the single-cycle PAA (or water) alternating CO2 (PAG or WAG) injection fracturing experiments, one complete cycle consisted of two steps: (1) injecting a PAA slug (or water slug) followed by (2) injecting CO2 to initiate and propagate the fracture. For experiments involving multiple injection cycles, the CO2 injection pressure is increased until it peaks and begins to decline (indicating fracture initiation at this moment), and then continued being injected for another 30 s to propagate the fracture. Then, these two-step cycles [injection of PAA (or water) followed by CO2 injection (up to 2–4 mL/min)] are repeated. Applications/significance/noveltyThe results of this study suggest that water saturation significantly affects the fracturing fluid transmission into the rock pore space, thus affecting fracture initiation and propagation. In this study, fracturing tests via a single injection cycle or multiple injection cycles were performed. When the rock samples are split in half following testing, it is evident that fracture propagation is considerably restricted under high water saturation conditions (where a three-day initial water injection was conducted) in comparison to stimulation experiments carried out in hot and dry rock. The fractures propagate less than 1/3 of the distance from the wellbore to the outer rock surface, and in some cases, no fracture is generated. This may be caused by leak-off dominating the fracturing process and the fluid injection rate is insufficient to overcome leak-off, even under high injection rate conditions. Additionally, CO2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate sufficiently high-pressure gradients away from the near-wellbore region. Under low water saturation conditions (dry rock or after 1-day initial water injection), PAA/CO2 consistently generated significantly larger fractures compared with the other fluids. CO2 generated large fractures only in the hot dry rock and only when using high injection rates, though data variability is high.