High Closure Stress Research Articles

Multi-Parameter Experimental Investigation on the Characteristics of Acidizing Effectiveness in High-Temperature Carbonate Formation

Carbonate formation is the key reservoir in Sichuan Basin for natural gas development. Compared with the early stage of development, the burial depth of targeted formation becomes deeper, and the formation temperature gets higher. So, the characteristics of acidizing effectiveness in high-temperature carbonate formations make this evaluation slightly difficult. Currently, it is common that a single parameter is considered to study acidizing effectiveness by simulation and experiment methods. In this paper, for a more accurate investigation of acidizing effectiveness, multiple parameters, including permeability change rate, fracture conductivity, and surface roughness, were introduced by a series of experiments. It is revealed that the permeability change rate is more than 57% when using gelled acid. As the amount of diverting agent increases in diverting acid, the viscosity of the acid grows to its peak with the reaction, making it easier to block the high permeability core temporarily and divert to acidify the low permeability core, where the permeability change rate of the low permeability core goes from 51.6% to 64.2%, which shows well acidizing effectiveness. In addition, the short-term and long-term conductivity of the samples from the three different formations are more than 200 mD∙m under high closure stress. The conductivity of Maokou Formation is the largest due to its high content of carbonate minerals and high dissolution rate. And the results of long-term conductivity are consistent with those of surface roughness, making the evaluation results more reliable for acidizing effectiveness. It is worth noting that temperature is a factor that cannot be ignored in the evaluation of acidizing effectiveness because it has a great influence on the performance of the acid system, such as viscosity and the reaction-reduced rate, leading to an acidizing effectiveness affect. So, the temperature resistance of an acid system is important as well.

Quantifying micro-proppants crushing rate and evaluating propped micro-fractures

Micro-proppants used in reservoir stimulation to enable oil and gas recovery from tight hydrocarbon reservoirs can be delivered deeper with slick water and prop microfracture networks during hydraulic fracturing. The production of a multi-fractured well system depends on fracture permeability, which is ultimately a function of proppant strength and concentration. However, it is challenging to evaluate the performance of micro-proppants due to their tiny particle size. This paper proposed a practical method for assessing micro-proppant strength based on micro-proppant crushing rates and optimizing micro-proppant delivery to achieve effective concentrations in the pad fluid to prop up the micro-fractures more effectively. Micro-proppants undergo two crushing steps when transported in the fluid and when hydraulic fractures close. Under a pressure of 70 MPa, the crushing rate is 12%–25% of the hydraulic loading, and 42%–66% of the solid loading for three types of micro-proppants. The concentration of micro-proppants in the pad fluid should be higher than 0.9 lbm/gal to maintain economic permeability under high closure stress of 50 MPa. The numerical simulation results demonstrate that adding micro-proppants to the pad fluid will increase the effective propped fracture area, and the initial productivity and stable productivity increase by more than 40% and 20%, respectively. This study has a guiding value for selecting micro-proppants and the number of micro-proppants used in hydraulic fracturing.

A New Compound Staged Gelling Acid Fracturing Method for Ultra-Deep Horizontal Wells.

Carbonate gas reservoirs in Sichuan are deeply buried, high temperature and strong heterogeneity. Staged acid fracturing is an effective means to improve production. Staged acidizing fracturing of ultra-deep horizontal wells faces the following problems: 1. Strong reservoir heterogeneity leads to the difficulty of fine segmentation; 2. The horizontal well section is long and running too many packers increases the completion risk; 3. Under high temperatures, the reaction speed between acid and rock is rapid and the acid action distance is short; and 4. The fracture conductivity is low under high-closure stress. In view of the above problems, the optimal fracture spacing is determined through productivity simulation. The composite temporary plugging of fibers and particles can increase the plugging layer pressure to 17.9 MPa, which can meet the requirements of the staged acid fracturing of horizontal wells. Through the gelling acid finger characteristic simulation and conductivity test, it is clear that the crosslinked authigenic acid and gelling acid in the Sichuan carbonate gas reservoir are injected alternately in three stages. When the proportion of gelling acid injected into a single section is 75% and the acid strength is 1.6 m3/m, the length and conductivity of acid corrosion fracture are the best. A total of 12 staged acid fracturing horizontal wells have been completed in the Sichuan carbonate gas reservoir, and the production is 2.1 times that of ordinary acid fracturing horizontal wells.

A composite temporary plugging technology for hydraulic fracture diverting treatment in gas shales: Using degradable particle/powder gels (DPGs) and proppants as temporary plugging agents

Temporary plugging and diverting fracturing is one kind of technology for efficiency-enhancing the productivity of oil and gas wells, which is widely used in hydraulic fracturing treatments in shale gas reservoirs. However, the closure of unpropped fractures at the temporary plugging zone under the high closure stress post fracturing treatment may influence the efficiency of shale gas well productivity-enhancing. The unpropped temporary plugging zone plays the role of a “closed valve” that would intercept the connection of the old fractures to the flowable fracture system. Thus, a composite temporary plugging technology for hydraulic fracture diverting treatment in gas shales is proposed for solving this problem by using degradable particle/powder gels (DPGs) and proppants as temporary plugging agents. This study examined the adaptability of the DPGs, as well as the proper combinations for composite temporary plugging technology. Moreover, the temporary plugging mechanism and behavior of the composite temporary plugging zone are discussed. Experimental investigation results show that the DPGs have good adaptability for composite temporary plugging technology, and meet the requirements of diverting fracturing within the hydraulic fractures. The optimum experimental combinations are determined, the mass ratio of DPGs to proppants for temporary plugging is 16%, which can ensure the temporary plugging efficiency, as well as the timely removal of plugging. Temporary plugging mechanism and behavior of composite temporary plugging zone are closely related to the internal structure evolution of composite temporary plugging zone, the plugging processes can be divided into bridging and plugging, deformation, adhesiveness, and degradation of DPGs. This study provides the understanding and mechanism of the composite temporary plugging behavior during hydraulic fracture diverting treatment. This technology is of great significance to achieve enhanced and stable production in shale gas reservoirs.

Numerical simulation of proppant embedment in rough surfaces based on full reverse reconstruction

In the hydraulic fracturing process of shale reservoir, proppant will embed and deform under the action of high closure stress. Thus, it is necessary to analyze the mechanical process and influencing factors of proppant embedding in shale. This study reproduced rough fracture surface of real rock slabs based on the reverse reconstruction method and obtained the mechanical parameters of the rock slab and proppant. In this study, a numerical model for the elastoplastic deformation of the proppant embedding in the rough fracture surface, along with mechanical test experiments, is proposed. The reliability of the numerical model is verified by the proppant embedding simulation experiment. Based on this model, the process of proppant embedding in a rough fracture under the action of closing stress and the factors influencing the width of supporting fracture were analyzed. The results show that the embedment degree of the proppant is different in different areas of the rough fracture surface. Furthermore, a stress concentration effect is apparent. The proppant embedment becomes significant after the slab enters the plastic deformation stage under high closure stress. The slabs with high roughness and low Young's modulus or proppants with small particle sizes and high Young's moduli result in a smaller width of the propped fracture.

Thermal-shock-induced surface softening and conductivity evolution of hydraulic fracture in enhanced geothermal system

To reveal the thermal shock effect on micromechanical properties and conductivity evolution of hydraulic fracture in enhanced geothermal system, nanoindentation tests and fracture conductivity tests were performed on granite samples after different thermal treatments. Experimental results show that the hardness and the Young's modulus of fracture surface decreased with the increasing thermal treatment temperature. This degradation of micromechanical properties indicates the softening of fracture surface due to thermal shock effect which further influence the conductivity evolution. For propped fractures, the higher thermal treatment temperature, the lower fracture conductivity under the same closure stress. Particularly, at the thermal treatment temperature of 300°C, the dominant mechanism of quick fracture conductivity loss transformed from the proppant crushing under high closure stress (>50 MPa) to the enhancement of proppant embedment under low closure stress (<30 MPa). For self-propped fracture with small roughness, the thermal shock effect enhanced the conductivity under in-situ closure condition, while reduced that in case of shear slip. When the rough fracture was characterized by a local hump, it increased the flow resistance of in-situ closed fracture under high closure stress and reduced the fracture conductivity, but may form an effective flow channel with ultra-high conductivity once shear slip occurred.

Experimental modeling of sanding fracturing and conductivity of propped fractures in conglomerate: A case study of tight conglomerate of Mahu sag in Junggar Basin, NW China

True tri-axial sanding fracturing experiments are carried out on conglomerate samples from the Permian Wuerhe Formation of Mahu sag, Junggar Basin, to study hydraulic fracture propagation geometry and quartz sand transport in matrix-supported fine conglomerate and grain-supported medium conglomerate. The effect of rough fracture surface on conductivity is analyzed using the 3D-printing technology to reconstruct the rough surface formed in the fractured conglomerate. The hydraulic fractures formed in the matrix-supported fine conglomerate are fairly straight, and only more tortuous when encountering large gravels at local parts; thus, proppants can get into the fractures easily with transport distance about 70%–90% of the fracture length. By contrast, in the grain-supported medium conglomerate, hydraulic fractures tend to bypass the gravels to propagate in tortuous paths and frequently change in width; therefore, proppants are difficult to transport in these fractures and only move less than 30% of the fracture length. As the matrix-supported fine conglomerate has high matrix content and low hardness, proppants embed in the fracture surface severely. In contrast, the grain-supported medium conglomerate has higher gravel content and hardness, so the quartz sand is crushed more severely. Under the high proppant concentration of 5 kg/m2, when the closure stress is increased (above 60 MPa), fractures formed in both matrix-supported fine conglomerate and grain-supported medium conglomerate decrease in width significantly, and drop 88% and 92% in conductivity respectively compared with the case under the low closure stress of 20 MPa. The field tests prove that under high closure stress above 60 MPa, using a high proportion of fine proppants with high concentration allow the proppant to move further in the fracture; meanwhile proppant places more uniformly in the rough fracture, resulting in a higher fracture conductivity and an improved well performance.

Research and Application of Segmented Acid Fracturing by Temporary Plugging in Ultradeep Carbonate Reservoirs.

The ultradeep carbonate reservoir in Sichuan Basin is characterized by deep burial depth, high temperature, and strong heterogeneity. In the early stage of production, the vertical well acid fracturing is the main reservoir stimulation method, and the horizontal well stimulation technology is not mature enough to release the production capacity of gas wells. Segmented acid fracturing of the ultradeep horizontal wells currently faces the following problems: the strong heterogeneity of reservoir leads to the difficulty of fine segmentation; the high reservoir temperature requires higher performance of working fluid; the reaction rate between acid and rock is fast and the action distance of acid is short, and there is low fracture conductivity under high closure stress. In view of the above problems, the fine segmented design method was studied, and the high-temperature-resistant authigenic acid and gelling acid systems were developed. The viscosity of authigenic acid is greater than 150 mPa s after shearing at 160 °C and 170 s–1 for 50 min, and the highest acid generation concentration is 4.05 mol/L. The gelling acid system has both the properties of high-temperature resistance and low friction resistance; not only canit meet the requirements of the retarding rate and the corrosion inhibition ability when the reservoir temperature is 160 °C but also the resistance reduction rate is up to more than 70%. By alternating injection of authigenic acid and gelling acid, the acid-etched fracture length and conductivity were, respectively, increased by 80% and 45%. The application of this technology in the horizontal well of the ultradeep carbonate reservoir in Sichuan Basin can increase the productivity by 3 times when compared with the vertical well acid fracturing, and a better stimulation effect has been achieved.

Unconventional Well Test Analysis for Assessing Individual Fracture Stages through Post-Treatment Pressure Falloffs: Case Study

Researchers and operators have recently become interested in the individual stage optimization of unconventional reservoir hydraulic fracture. These professionals aim to maximize well performance during an unconventional well’s early-stage and potential Enhanced Oil Recovery (EOR) lifespan. Although there have been advances in hydraulic fracturing technology that allow for the creation of large stimulated reservoir volumes (SRVs), it may not be optimal to use the same treatment design for all stages of a well or many wells in an area. We present a comprehensive review of the main approaches used to discuss applicability, pros and cons, and a detailed comparison between different methodologies. Our research outlines a combination of the Diagnostic Fracture Injection Test (DFIT) and falloff pressure analysis, which can help to design intelligent production and improve well performance. Our field study presents an unconventional well to explain the objective optimization workflow. The analysis indicates that most of the fracturing fluid was leaked off through natural fracture surface area and resulted in the estimation of larger values compared to the hydraulic fracture calculated area. These phenomena might represent a secondary fracture set with a high fracture closure stress activated in neighbor stages that was not well-developed in other sections. The falloff pressure analysis provides significant and vital information, assisting operators in fully understanding models for fracture network characterization.

A Multiwalled Carbon Nanotube-Based Polyurethane Nanocomposite-Coated Sand/Proppant for Improved Mechanical Strength and Flowback Control in Hydraulic Fracturing Applications.

A novel resin-based nanocomposite-coated sand proppant is introduced to address the issue of proppant flowback in post-fracturing fluid flowback treatments and hydrocarbon production. Self-aggregation in the water environment is the most attractive aspect of these developed proppants. In this work, sand was sieve-coated with 0.1% multiwalled carbon nanotubes (MWCNTs) followed by optimized thin and uniform resin (polyurethane) spray coating in the concentration range of 2 to 10%. Quantitative and qualitative evaluations have been carried out to assess the self-aggregation capabilities of the proposed sand proppants where no flowback was witnessed at 4% polyurethane coating containing 0.1% MWCNTs. This applied resin incorporating MWCNT coating was characterized by field emission scanning electron microscopy, and energy-dispersive X-ray spectroscopy depicted the dispersed presence of MWCNTs into polyurethane resin corroborated by the presence of 38% elemental carbon on the sand substrate. Proppant crushing resistance tests were conducted, including proppant pack stress–strain response, compaction, and fines production. It was found that the proposed sand proppant decreased the proppant pack compaction by ∼25% compared to commonly used silica sand with the ability to withstand high closure stress as high as 55 MPa with less than 10 wt % fines production. The surface wettability was determined by the sessile drop method. The application of resin incorporating MWCNT coating layers changed the sand proppant wetting behavior to oil-wet with a contact angle of ∼124°. Thermogravimetric analyses revealed a significant increment in thermal stability, which reached up to 280 °C due to the addition of MWCNTs as reinforcing nanofillers.

Acid-etching fracture morphology and conductivity for alternate stages of self-generating acid and gelled acid during acid-fracturing

Initial fracture morphology and variation of acid-rock reaction temperature caused by alternate stages were ignored in the traditional alternate multistage acid-fracturing experiments, so a new design method of experiment simulation was proposed with these considerations in this paper. Alternate multistage acid-fracturing experiments were carried out based on this new method through using self-generating acid and gelled acid, while the influence of alternate stages on acid-etching fracture morphology and conductivity were also investigated. The study shows that acid smoothing the peaks are stronger than deepening the valleys on rough fracture during alternate acid-fracturing and the tortuosity of fracture surface also increased after acidizing. Injection time of self-generating acid at high temperature caused by alternate stages is the main influences on the acid-etching pattern, while that of gelled acid has little effect. Excessive dissolved-rock of one alternate stage is beneficial to creating high initial conductivity, but the retention rate of conductivity is the lowest under medium and high closure stress. Although rough initial fracture has a little contribution to generation high conductivity, two alternate stages with moderate acid-etching creates high conductivity and improves the retention rate of conductivity under medium and high closure stress. It is useful to select reasonable alternate stages for self-generating acid and gelled acid in multistage acid-fracturing treatment.

Characterization of Baram and Tanjung sands as potential proppants

Baram and Tanjung sands were evaluated for potential use as proppants. Experiment was conducted on Baram and Tanjung sands following ISO and ASTM recommended standards. Results showed that Baram and Tanjung sand mineralogy is predominantly quartz with presence of metal oxides. Shape descriptors of both sands for sphericity and roundness were above 0.7. Baram sand was retained by 20/40 mesh size with mean size of 448.2 μm, bulk density of 1.32 g/cc, acid solubility of 1.5% and crush resistance of 4000 psi. While Tanjung sand was retained by 30/50 mesh size with mean size of 383.2 μm, bulk density of 1.30 g/cc, acid solubility of 1.20% and crush resistance of 8000 psi. This indicates that Baram sand has larger grain size that supports high permeability at low closure stress, making this sand suitable for shallow depth hydraulic fracturing operations, whereas Tanjung sand is more suitable for deeper domains with high closure stress. Experimental results and economic comparison with commercial frac sand and other proppant types support using Baram and Tanjung sands as potential proppants.

Research and Application of the Composite Reservoir Stimulation Technology for Ultra-High-Temperature Ultra-Deep Naturally-Fractured Carbonate Reservoirs

The Ordovician buried-hill carbonate reservoir in the northern Jizhong Sag of China is seen with abundance in hydrocarbon resources. Nonetheless, attempts of multiple reservoir stimulation technologies have all failed to make breakthrough, due to its lithological complexity (mixture of dolomite and limestone), ultra-high temperatures (180°C) and high in-situ stress gradients (0.023 MPa/m), Given the aforementioned reservoir geological challenges, reservoir evaluation, technology optimization and plan design starting from the reservoir geological characteristics have been carried out, and the “composite” reservoir stimulation technology for ultra-high-temperature ultra-deep naturally-fractured carbonate reservoirs has been proposed. In terms of the short effective affected distance of acid under high temperatures (180°C), low conductivity sustainability owing to high closure stresses (induced by the burial depth of 5,000 m), extreme difficulties in expanding stimulated reservoir volumes (large lateral in-situ stress differences and long vertical spans), the practice of “multi-stage injection, temporary plugging and diversion, and propped acid fracturing” highlighting high pump rates and combination of low- and high-viscosity fluids (acid and fracturing fluids) has been developed and evolves into the network fracturing technology capable of inter-layer temporary isolation and within-layer diversion. The above technology has been applied in Well AT1x, with high volumes of fluid consumption and the maximum pump rate of 11 m3/min. Safe and efficient operation over six hours featuring challenges such as 3,000 m3 of composite fluids, ultra-high temperatures and ultra-high pressures is achieved. On-site monitoring such as the micro-seismic monitoring and simulation results show that compared with the previous reservoir stimulation, the developed technology presents SRV 3.5 times larger, and results in three-dimensional reservoir reconstruction. The post-fracturing daily gas production amounts to 409,000 m3 and daily oil production, 71 m3. In production testing, the wellhead pressure maintained over 25 MPa, and the daily gas production exceeds 100,000 m3, which indicate stable pressures and production, and a safe wellbore. The application accomplishes the design goal of integrated exploration and exploitation, and geology and engineering, and provides references for reservoir simulation of analogous reservoirs.

A rock self-supporting high conductivity acid fracturing technique in a deep carbonate reservoir

As carbonate reservoirs in deeper strata continue to develop, reservoir closure stress has significantly increased, where conventional acid fracturing technology cannot maintain acid-etched fracture conductivity and single well production rates are decreasing more quickly. This study proposes a rock self-supporting, highly conductive acid fracturing technique, where the shielding materials cover a portion of the primary hydraulic fracture surface to block the acid rock reaction. After acid injection, the unetched part will be a bearing surface, which serves as a large area and self-supporting high strength rock. This technique fundamentally changes the existing point support pattern of acid-etched fractures. Experimental results demonstrate that when the closed stress is <50 MPa, the self-supporting conductivity is 42% higher than the conventionally acid etched fractures. At 90 MPa closed stress, it can still maintain high support strength, which is more than eight times that of a conventional acid etched fracture. The equilibrium relationship between the fracture conductivity and rock support strength was determined using finite element stress simulation and fluid mechanics simulation. The results demonstrate that using a small cylindrical area, dislocation support, and multi-point support is conducive to the dispersion of high closure stress; moreover, the concentrated stress intensity of supporting rock can be reduced by 3–12 MPa. With decrease in supporting area, the stress intensity of the supporting rock is higher. Considering the compressive strength of the rock, the supporting area is >25%. When the rock is in the form of a dislocation support, the fluid disperses in the larger void channels, thus effectively maintaining fracture conductivity. The self-supporting acid fracturing technique is useful for increasing the utility of acid fracturing stimulation in deep and ultra-deep wells.

Thermochemical acid fracturing of tight and unconventional rocks: Experimental and modeling investigations

The exploitation of unconventional formations requires propped hydraulic fracturing treatments. Propped fracturing is an expensive process that usually suffers from operational challenges. In this study, a new technology is proposed which targets implementing thermochemical fluids to stimulate unconventional formations. These fluids release large pressure pulses upon a reaction that creates networks of cracks along the fracture. Triggering thermochemical fluids with acid creates differential etching along the fracture surfaces due to the acid/rock dissolution. The new technology was tested experimentally through coreflooding on Indiana limestone and Kentucky sandstone samples and through breakdown pressure experiments on Eagle Ford shale samples. The breakdown pressure of the Eagle Ford shale samples was reduced from 2400 to 900 pisa using thermochemical fluids triggered with acid. It was also observed that the acid triggered thermochemical fluids could maintain the permeability of the fractures at high closure stresses due to the acid/rock dissolution. A laboratory and field-scale models were also developed in this study to understand thermochemical reactions. The laboratory-scale model could capture the pressure pulses generated experimentally and the system temperature. The field-scale model was then used to understand the thermochemical reactive transport in a hydraulic fracture. The model showed that thermochemical concentration is the most significant parameter in controlling the temperature and pressure magnitudes in the field.

Proppant embedment in coal and shale: Impacts of stress hardening and sorption

During methane production in CBM reservoirs, the influence of proppant embedment and permeability damage cannot be neglected – especially where the wall-rock is soft. Effective stresses are elevated during methane recovery, increasing both normal loading stress and confinement and simultaneously overprinting sorption-induced volumetric strains. Experiments and analytic modeling are conducted to define key mechanisms controlling these competitive effects. We independently measure overall sample compaction (external LVDT) and local strain (strain gauge) in the matrix to deconvolve proppant embedment in a propped fracture for different conditions of confining stress. The results show symptomatic behaviors of elastic (shale) and elastoplastic (coal) responses of embedment. Different from shale, the evolution of embedment is convex upwards with increased stress where indented depth increases more rapidly as loading stress increases under constant confinement. In addition, a stress-hardening effect is found to play a pivotal role in determining the characteristics of indentation, which are examined in terms of evolution profiles, deformation regimes, embedment slopes, curvatures, yield points and irreversible indentations. Based on the experimental observations a semianalytical model predicts indentation and the evolution of propped permeability under recreated in-situ stress conditions. A simplified case study is conducted to further illustrate the evolution of aperture and permeability of a propped fracture in CBM reservoirs. The modeling results suggest that proppant embedment is significantly overestimated if the variable stress-hardening (VSH) effect is neglected, especially when effective stress is large. Moreover, a decrease in indentation depth possibly occurs during late stage methane production, resulting in a reversal/recovery in fracture closure. This is because desorption-induced shrinkage becomes the predominant effect, causing an increase in aperture and a reduction in the indented volume of proppant. The resulting recovery in permeability implies that the propped coal fracture has the potential to optimally facilitate methane production as a pathway, even at high closure stresses generated by methane drainage.

Urethane based nanocomposite coated proppants for improved crush resistance during hydraulic fracturing

Hydraulic fracturing is one of the stimulation techniques that has been used to increase the hydrocarbon flow in unconventional reservoirs. Proppants are normally used to maintain the fracture conductivity and increase the permeability to oil. Due to high closure stress of the fractured formation, the conventional or uncoated proppants are easily crushed. Therefore, this project aims to increase the compressive strength of proppants by coating it with urethane based nanocomposite. Glass beads and fracking sands are coated with urethane resin and mixed with reduced graphene oxide (rGO) and carbon nanotubes (CNTs) respectively. Analysis testing using optical microscopy (OM) was conducted to study the morphology and microstructures of the coated proppants before and after crush test. Results showed remarkable improvement in proppants compression strength up to 41% and 35% after adding only 0.5% of CNTs and 0.1% of rGO respectively to the urethane resin coating. Therefore, it is recommended to utilize this material for coating the proppant with the optimized concentration to prevent pore plugging and proppant from flowing back, achieving the objective and solving both problem statements.

Effects of Heterogeneity in Mineralogy Distribution on Acid-Fracturing Efficiency

SummaryCreating sufficient and sustained fracture conductivity contributes directly to the success of acid-fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating nonuniformly etched surfaces that can withstand high closure stress. Previous studies showed that, depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate, and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid-fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestone that do not represent the highly heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity and, more importantly, the distribution of insoluble rock on acid-fracture conductivity.In this research, we conducted acid-fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity-decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were performed to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results.Results of our study showed that insoluble minerals with higher-strength mechanical properties were not crushed at high-closure stress, resulting in a less-steep conductivity decline with an increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture-conductivity model with correlation length, we matched the fracture-conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid-fracturing conductivity significantly as compared to the case when the streak is correlated against the flow direction.The results of the study show that fracture conductivity can be optimized by taking advantage of the distribution of insoluble minerals along the fracture surface and demonstrate important considerations to make the acid-fracturing treatment successful.

A new method to measure propped fracture width and proppant porosity in shale fractures

Hydraulic fracturing is the main stimulation method used to economically produce from shale formations. The method requires the injection of a fracturing fluid at a pressure, which is high enough to fracture the formation, and as a result, improves the well productivity. A proppant is pumped with the fracturing fluid to prevent the closure of the induced fractures after the treatment. The proppant inside the fracture is subjected to a high earth closure stress, which causes proppant crushing, embedment, and compaction mechanisms. The subsequent reduction of the fracture width and proppant porosity reduces the fracture conductivity and could be crucial to the success of the fracturing treatments. The available methods to evaluate such reduction do not take into account downhole stress or the compression of rock under stress. The objective of this study is to experimentally evaluate the reduction of the propped fracture width and proppant porosity between two shale samples using a new method that allows the direct viewing of the fracture at downhole conditions.A new experimental model was designed to measure fracture width and porosity of proppant under downhole conditions. Outcrop shale samples were used. Varies proppant types and sizes were used including: sand, resin-coated sand, and ceramic proppants of the sizes 20/40, 40/70, and 100-mesh. The proppants were tested at concentrations of 0.2, 0.4, and 0.6 lb/ft2. A high-pressure core holder with modified fittings was used to subject the fracture model to different closure stresses up to 8000 psia. A new method was used to evaluate the change in the propped fracture width and proppant porosity as a function of closure stress. The fracture width was measured by viewing fracture under stress using a digital borescope. The change in the proppant porosity was calculated at each stress and a sieve analysis was conducted to quantify the crushed proppant because of the applied stress.A set of tables were provided for the values of fracture width and proppant porosity under stress for each proppant type, size, and concentration. The proppant porosity under stress was found to be directly proportional to the proppant concentration and inversely proportional to the proppant size. The reduction in fracture width and proppant porosity due to stress ranged from 5.68 to 25.88%, and from 7.88 to 44.16%, respectively. The crushing of sand proppant was found to be as high as 28.03% at 8000 psia and 0.2 lb/ft2 proppant concentration, and reduced by increasing its concentration or decreasing its size. The embedment of ceramic proppant at 8000 psia reduced the fracture width by 29.2 and 32.5% for the Eagle Ford and Marcellus shale, respectively.The propped fracture width and porosity under stress can be used as inputs to well production models, reservoir simulation models, and fracture design calculations. The results can also be used in the proppant selection process to improve the fracture conductivity and maximize the well productivity of shale formations.

Influence of proppant fragmentation on fracture conductivity - Insights from three-dimensional discrete element modeling

Abstract Proppant crushing under high closure stress is widely observed in the laboratory and the field but has rarely been simulated numerically. This paper presents 3D discrete element modeling of proppant fragmentation and its influence on the fracture conductivity. A particle breakage model was implemented to simulate proppant fragmentation. A practical procedure was developed to calibrate the parameters in the breakage model using stress-strain responses and grain size distributions from laboratory crush tests. The breakage model, along with the calibrated parameters for Jordan sand, Genoa sand, and a ceramic proppant, was used in a parametric analysis for multilayer proppant packs. The influence of proppant type, particle size, and proppant mixture on proppant fragmentation and fracture conductivity was examined. The results indicate that the proppant size needed to achieve optimal fracture conductivity is greatly affected by particle fragmentation, which in turn is sensitive to closure stress and size-dependent particle strength. A Hardin breakage ratio larger than 0.05 represents the onset of excessive proppant fragmentation that can greatly decrease fracture conductivity.