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This paper provides a comprehensive review on the application of proppants to maintain fracture permeability over the lifetime of a well based on published observations from experiments and modeling. The review identifies and describes important processes occurring during proppant embedment, during hydraulic fracturing, laboratory testing of fracture conductivity, proppant embedment and modeling of proppant embedment. Finally, this paper identifies the challenges and knowledge gaps that also provide future avenues of research and opportunities for collaborative technological development which requires an interdisciplinary approach of science, engineering in academia, government, and private sector.

In hydraulic fracture, the choice of proppant is very crucial. It not only props the fractures in the formation but also maintains the fracture conductivity. Proppant technology is advancing rapidly with the advance in hydraulic fracture. Hence to ensure a more consistent proppant evaluation in the manufacturing of proppants, standardisation of proppant evaluation is imperative. The ISO and API have published several recommended practices for this purpose, but they are still lacking in many areas. This is because many theories underlying the performance of proppant have not been fully understood, such as the theory of proppant embedment and diagenesis, as well as their impact on proppant conductivity performance, which is the current focus of research in proppant studies. This is especially true with the high pace evolution of proppant technologies and thus requires updates from time to time. In addition to the recommended practices, different approaches had been explored in enhancing the way proppants are evaluated. This paper presents a short review of the modifications and improvements that have been proposed in the evaluation of proppant characteristics, conductivity, transportation, and erosion. The objectives of this review are to provide an overview of the current proppant testing practices, including the current standards’ limitation and challenges as well as modifications and improvements that have been proposed to laboratory-based testing, including the area that needs to be explored further.

Sulige gas field is a typical tight sandstone gas reservoir. Single well stimulation is an effective means of late fracturing. Because of the complex geological conditions in the Sulige area, there is little research on fracture parameter design of fractured horizontal wells. Based on the geological and engineering parameters of fractured horizontal wells in the block, the numerical simulation method is used to analyze the block. It is clear that the main controlling factors affecting the fracturing effect in the well area are fracture conductivity, fracture length, and fracture cluster number, and the optimal scheme to improve the single well production is proposed.

During drainage and production from coalbed methane (CBM) wells, the reservoir is prone to formation damage in the form of blockage of the seepage channels by coal fines or invasion of external water, which inevitably causes a significant decline in the productivity of the wells. To restore their productivity, temporary blocking materials (TBMs) are typically used to seal the original fractures for refracturing treatments. In this study, a special fuzzy-ball temporary blocking fluid (FTBF) was designed to effectively mitigate the formation damage through the refracturing operation. The performance of the FTBF was analysed via experiments, application to two case studies, and its formation damage mitigation mechanisms. The following results were obtained: (1) From the experimental analysis, it was observed that the FTBF increased the water resistance in the fracture and it was less than the gas resistance. (2) In Case one, there was no gas production before the refracturing; however after the refracturing, the daily gas production rose to 494 m3. In Case two, the daily gas production of the well before the refracturing was intermittent and less than 80 m3; however, after the refracturing, the gas production remained stable at 220 m3. (3) The analysis of damage mitigation mechanisms revealed that firstly, sodium dodecyl sulfate improved the viscoelasticity of FTBF and its chemical affinity to water, which enhanced the mitigation of the formation damage by water invasion; secondly, the viscoelastic characteristics of the vesicles enabled it to modify the mechanical properties of the rock and consequently improving the refracturing process; thirdly, sodium dodecyl benzene sulfonate provided excellent dispersion stability by adsorption of coal fines in the proppant pack to enhance the fracture conductivity. This study provided a reliable basis for understanding the mechanisms and application of FTBFs in mitigating the formation damage through refracturing CBM wells.

It is well acknowledged that water injection may induce formation fracturing in tight reservoir, and the injection well may experience shrinking fracture length (SFL) and variable fracture conductivity (VFC) during fracture-falloff period, which shows the bi-storage behavior. However, available pressure-transient analysis (PTA) models hardly consider these effects (SFL, VFC and bi-storage behavior) on pressure-transient response, which can lead to erroneous results. This paper aims at presenting an innovative approach to model the water injection wells considering the dynamic characteristics of waterflood-induced fracture (WIF). We first modeled fluid flow between reservoir and the fracture which characterized by fracture-storage coefficient and fracture-face skin factor, and flow between wellbore and the fracture which represented by wellbore-storage coefficient and choked-fracture skin factor. In addition, the effects of SFL and VFC were included by finite difference method. A semi-analytical solution was then derived to model injection well with waterflood-induced fracture (IWWIF). Finally, this methodology has been successfully applied in Changqing oilfield, China. There are six flow regimes for the IWWIF model in the tight reservoir, including wellbore-storage regime, transitional-flow regime, fracture-storage regime, the second transitional regime, linear flow regime and bilinear flow regime. Compared to current models, the bi-storage phenomenon is discovered and validated as two straight lines with unit slope in the pressure derivate curve of type plot. The WIF that closely links with the wellbore can be regarded as an “expanding wellbore”, which illustrates the reason that the “wellbore-storage coefficients” are increased by up to several orders of magnitude in a great many of water injection wells. The VFC behavior could cause the upward of pressure-derivative curve, which is generally recognized as the characteristic of closed boundary condition while the variable fracture-storage effect may occur because of SFL. In addition, the relation between matched fracture-storage coefficient and fracture length is given, which provides us another way to obtain the probable length of WIF. Finally, this new model has been successfully used to evaluate well performance and reservoir characteristics based on bottom-hole pressure (BHP) history of five field cases in Changqing oilfield, China.

This paper investigates the impacts of stimulated reservoir volume (SRV) on reservoir performance for unconventional hydraulically fractured formations. It focuses also on the effects of different petrophysical properties of SRV as well as different volume and petrophysical properties of unstimulated part of porous media (USRV). The influences of hydraulic fracture conductivity, fracture assymmetricity, and non-Darcy flow permeability in reservoir pressure profile have been substantially studied in this paper. Stimulated reservoir volume represents the volume of porous media where complex network structures formed from naturally induced fractures, multiple hydraulic fractures, and original matrix. SRV is characterized by an induced or a stimulated matrix permeability which is typically greater than the original matrix permeability. The formations of interest, in this study, are considered having either stimulated reservoir volume only or both stimulated and un-stimulated reservoir volumes and depleted by multiple hydraulic fractures controlled by non-Darcy flow. The impacts of SRV and USRV on pressure distributions, flow regimes, and productivity indices have been studied using multi-linear flow regimes approach. A new analytical model has been proposed in this paper for pressure behavior of a horizontal well intersected by multiple hydraulic fractures assuming symmetrical and asymmetrical stimulated reservoir volumes. This model was developed using multi-linear flow regimes approach with an adjustment for variable SRVs and USRVs. The volume of stimulated part in the reservoir is determined by hydraulic fracture half length, number of fractures and spacing between them, and fracture height. The impact of induced or stimulated matrix permeability in the stimulated reservoir volume and fracture conductivity as well as non-Darcy flow impact on pressure behaviors have also been investigated. Several analytical models for flow regimes, expected to develop during the entire production life of reservoir, were also proposed in this study. A set of type-curves was designed for pseudo-pressure normalized rate and pseudo-pressure normalized cumulative rate with production time. The outcomes of this study can be summarized as: 1) Generating an analytical model that describes pressure behavior in unconventional reservoirs and considers variable SRVs and USRVs. This model includes stimulated matrix permeability, non-Darcy flow impact, and hydraulic fracture conductivity. 2) Understanding the impact of asymmetrical stimulated reservoir volumes on reservoir performance. 3) Developing analytical models for different linear flow regimes that could develop during the entire life of reservoir. 4) Comparing the productivity index for different stimulated and un-stimulated reservoir volumes assuming both symmetrical and asymmetrical reservoir volume. The most interesting points in this study are: 1) Productivity index drops significantly for the case of asymmetrical SRVs compared to symmetrical SRVs. 2) The SRV enhances productivity index more than USRV, however, at early production time, there is no impact for both of them on productivity index. 3) The impact of assymmetricity is seen at all production time. 4) Flow regime types are not changed with respect to the assymmetricity.

An experimental study was performed with the scope of quantifying the regain fracture conductivity in a proppant-packed API RP-61 conductivity cell which was prior injected with broken Carboxyl Methyl Cellulose (CMC) fracture fluid. The initial fracture conductivity measurement was done on a proppant-packed (30/50 CARBOprop type) API RP cell using water as test fluid. A zirconate crosslinked CMC fracture fluid was prepared and broken with sodium persulphate solution. After breaking fluid to water-like viscosity in hot water bath for about 17 h, it was injected into the API cell to measure the conductivity. Regain fracture conductivity was again measure by flushing the cell with water in a reverse direction. Results were compared with broken hydroxylpropyl guar (HPG). Scanning electron microscope image of proppant samples before and after were done to validate the result above. Results from the experiments showed that there was a significant regain in conductivity in the use for broken CMC fracture fluid when compared with HPG. CMC showed a regain fracture conductivity of about 96% while HPG showed a regain fracture conductivity of about 75.6%. The result indicated that HPG produced higher residue which blocked the pore spaces in the proppant pack and thereby causing more damage and reducing fracture conductivity. CMC on the other hand produced less damage and residue in proppant pack, therefore excellent regain fracture conductivity was achieved. The SEM image experiments performed on proppants samples showed evidence of residue from the broken HPG fluid blocking the pores. After flushing with water, there were still significant amount of residue adhering to the proppant particles. However, SEM images containing CMC fluid showed fewer residues and less adhesion of residue fragments to the proppant particles after flushing with water. The result from this research work was found to be very rich because of the way we matched/compare the SEM result with the regain fracture conductivity test. This comparative process was able to validate the reason why there was excellent regain fracture conductivity in use of CMC fracture fluid.

The conventional mechanical and permeability models for proppant pack consider proppant as an elastic material, however, loading stresses cause proppant rearrangement and crush, leading irreversible material hardening, structure damage of proppant pack, strong reduction of pore space and damage of fracture conductivity. In this work, a confined compression and conductivity test on proppant pack was conducted. According to the experimental results, a new constitutive model for calculating the loading-path dependent proppant deformation and permeability was developed. In the proposed model, a simple yield equation and a non-associated potential equation were applied to derive the irreversible plastic deformation which is further used to calculate the material hardening parameter and the permeability damage. The model was validated by the experimental data and coupled into a reservoir simulator to investigate the impact of the stress shadow effects caused by the current stimulated fracture on the deformation and permeability of the placed proppant in the previous generated fracture. The modeled results revealed that the current fracturing operation damages the conductivity of the previous generated fracture, which must be taken into account for production prediction.

Summary The classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the “after fracturing” effective wellbore radius or from the “after fracturing” equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells. The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,h = 4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.

Acid fracturing is one of the applicable methods to stimulate oil and gas wells and increase the production rate in a carbonate reservoir. Acid fracture conductivity is an important parameter for the designing a fracture job. The amount of rock dissolved, fracture surface etching patterns, rock strength, and closure stress impact the resulting acid fracture conductivity. A model of acid fracture conductivity must accurately anticipate the fracture conductivity under closure stress. The rock strength affects substantially the fracture conductivity. A serious challenge of recent studies has been to predict the behaviour of different formations under various closure stresses. This study developed a robust intelligent model based on genetic algorithm to precisely predict the fracture conductivity by incorporating experimental data from various formations, whereby resulted in a good match between the model predictions and the experimental data. The effect of rock strength was investigated on the fracture conductivity under various closure stresses. The results show the rock strength plays a significant role when anticipating fracture conductivity, as various formations have behaved differently under different closure stresses. Furthermore, due to the complexity of rock behaviour at high closure stress, the results showed that as the closure stress increased the precision of all predictive correlations decreased considerably. Therefore, the fracture conductivity must be anticipated cautiously at high closure stresses by various predictive correlation particularly, in soft formation.

Summary In this paper, an integrated discrete-element-method (DEM)/computational-fluid-dynamics (CFD) numerical-modeling work flow is developed to model proppant embedment and fracture conductivity after hydraulic fracturing. Proppant with diameter from 0.15 to 0.83 mm was modeled as a frictional particle assembly, whereas shale formation was modeled as a bonded particle assembly by using the bonded-particle model in PFC3D (Itasca Consulting Group 2010). The mechanical interaction between proppant pack and shale formation during the process of fracture closing was first modeled with DEM. Then, fracture conductivity after the fracture closing was evaluated by modeling fluid flow through the proppant pack by use of DEM coupled with CFD. The numerical model was verified by laboratory fracture-conductivity experiment results and the Kozeny-Carman equation. The simulation results show that the fracture conductivity increases with the increase of proppant concentration or proppant size, and decreases with the increase of fracture-closing stress or degree of shale hydration; shale-hydration effect was confirmed to be the main reason for the large amount of proppant embedment.

A model capable of simulating proppant transport through hydraulic fracture network is developed and summarized in this paper. The proppant transport model (PTM) is able to capture multiple proppant transport patterns, including suspension, saltation and creeping. These patterns are first identified, and then quantified to establish proppant transport equations. The governing equations are programed into a three-dimensional, finite-difference model to simulate the proppant transport process. The PTM is coupled to a previously developed hydraulic fracture network propagation model, which updates essential input parameters such as fracture geometry, velocity distribution and pressure profile for each step. In every step, the proppant transport model extracts values for these parameters and solves the mass transport equations for all three patterns. Finally, the PTM generates proppant concentration, fracture conductivity and distribution throughout the created fracture network and predicts, at the end of the designed treatment the propped stimulated reservoir volume (PSRV) – a critical indicator of long-term stimulation effectiveness for hydraulically fractured oil/gas reservoirs. Parametric Studies of several important treatment, operational, reservoir, and geomechanical parameters are done in this paper to illustrate the impact of each factor on the PSRV.

Proppant distribution patterns play a significant role in the improvement of stimulated well performance. Multiple studies indicate that an uneven proppant distribution within fractures can considerably reduce well productivity. However, fluid flow is not necessarily restricted by a non-uniform proppant distribution. A novel technique called channel fracturing greatly increases fracture conductivity by creating open channels inside fractures that are caused by heterogeneous proppant placement. In this study, an effective experimental model was established to measure the flow capacity with heterogeneous proppant placement. A series of experiments on a discontinuous proppant distribution and conductivity was conducted by considering the formation temperature. The fracture conductivities of a heterogeneous proppant placement and uniform proppant distribution were compared. The effects of the fibre concentration, proppant properties, rock properties, proppant mass placement patterns, and fluid damage on the fracture conductivity and proppant embedment were also investigated to quantify the key factors affecting the effectiveness effectivity of the propped fracture. In addition, new analytical models were derived to calculate the proppant embedment and fracture conductivity with a discontinuous proppant distribution. The creeping deformation model was adopted to predict the changes in the proppant embedment and fracture conductivity over time. This study contributes to the optimization of channel fracturing treatments and elucidates the effect of a heterogeneous proppant placement on fracture conductivity.

The shear slip of the rough fracture surface is the main conductivity mechanism for the fractured network formed by unconventional reservoir fracturing, which has a large number of self-supporting fractures. However, the current research on influent space and conductivity capacity for shear slip fractures still remains qualitative, and there are few reports on quantitative studies. In this paper, the three-dimensional digitization method is used to obtain the fractal dimension D of the fracture space under different slips. Based on the laboratory experiments, this paper establishes the evolution law of conductivity of the shear fracture under different slip amounts. It also proposes a new method of shear fracture analysis, which helps to predict accurately the conductivity of shear fractures under different in-situ stress conditions and to carry out the laboratory evaluation and analysis of shear fractures. The investigation shows that the fractal dimension D of the shear fracture space increases with the increase in slip distance, but the changes become insignificant when the slip distance exceeds 0.3 mm. The conductivity is greatly increased (usually by orders of magnitude) in the presence of the slip distance. When the slip distance approximates 0.3 mm, the conductivity reach a maximum value; the shear fracture conductivity has a power exponential relation with the fractal dimension D of the equivalent plane of the fracture space, but the correlation decreases as the stress increases.

At present, many influenced factors were not taken into consideration during optimum design for multistage fractures optimum design for cluster horizontal wells, which leads to lower accuracy, even error decision. In this paper, taking pressure sensitive effect, high-velocity non-Darcy effect, fracture conductivity decreasing along with time, and fracturing fluid leak off into consideration, four kinds of cluster horizontal wells pattern were studied including line pattern with two wells, parallel pattern, K pattern, and X pattern with four wells. The greatest innovation was that the optimal fracture parameters could be obtained according to the quantitative parameters plate without time-consuming simulation. The interference between different well branches in line-shaped dual-well cluster mainly appears between the toe ends. The fractures distributed like W shape could reduce investment, and the long fractures at both ends are best. For parallel four-well cluster wells, the fractures should be staggered distributed and W shape distributed, long fractures are distributed at toe ends, and the fracture length/well interval ratio should be between 0.3 and 0.4. Furthermore, the most optimal fracture length increases with permeability decreasing. The “K type” and “X type” cluster wells need longer fracture length, so the out end fracture length needs to be longer.

The purpose of hydraulic fracturing is to establish a highway for oil and gas transportation, and the fracture conductivity reflects the highway’s transport capacity. Scholars have proposed several methods for calculating the conductivity, including both numerical and analytical methods. The analytical methods have received widespread attention as their calculation processes are simple and easy to use. However, the differences between the analytical models and between the models and experimental results are not clear, which prevents the selection of the optimal model. Therefore, this study compared these differences. In this study, comparative analysis was conducted for four analytical models from four aspects, including the factors considered by the models, input parameters, model calculation results, and the differences between the models and the experimental results. By conducting this comparison, there are some differences between the factors, input parameters, and calculation results of the four models. There are also some differences between the predicted values of the models and the experimental results. For practical application, the model must be corrected by fitting the test data. The current model does not fully reflect the interaction mechanism between a proppant and a rock. It is recommended that further research on analytical modeling is conducted.

The effectiveness of hydraulic fracturing in tight reservoirs is considered to be influenced by three main factors, namely, stimulated reservoir volume (SRV), fracture density, and fracture conductivity. No conclusive method is available to predict the effectiveness of hydraulic fracturing; there is often a failure to determine whether production differences among wells are caused by the effectiveness of the hydraulic fracturing or by the geological conditions, fluid properties, and other factors. Based on the principles of energy conservation and material balance, a mathematical model for calculating the average length of fractures and hypothetical number of fractures was established by the calculus of variations to obtain the key parameters for describing fracture density and conductivity. The degree of influence of the individual parameters on the effectiveness of hydraulic fracturing is obtained from Grey correlation analysis, and two calculation models for the comprehensive evaluation parameter are proposed. The comprehensive evaluation parameters produced from the two models have a preferable correlation with the well production. This paper presents a rigorous method for evaluating the effectiveness of hydraulic fracturing, which can explain the reasons for the production differences between wells.

Fracture conductivity decline is a concern in the Tuscaloosa Marine Shale (TMS) wells due to the high content of clay in the shale. An analytical well productivity model was developed in this study considering the pressure-dependent conductivity of hydraulic fractures. The log-log diagnostic approach was used to identify the boundary-dominated flow regime rather than the linear flow regime. Case studies of seven TMS wells indicated that the proposed model allows approximation of the field data with good accuracy. Production data analyses with the model revealed that the pressure-dependent fracture conductivity in the TMS in the Mississippi section declines following a logarithmic mode, with dimensionless coefficient χ varying between 0.116 and 0.130. The pressure-dependent decline of fracture conductivity in the transient flow period is more significant than that in the boundary-dominated flow period.

The recent development of unconventional oil and gas reservoirs has been accompanied by a rapid expansion in hydraulic fracturing technology. A successful stimulation treatment relies heavily on the performance of the proppant used. Proppant performance has been quantified thoroughly in a laboratory setting for over 30 years through the procedures outlined in API RP61 and later API RP19D, referred to as the short-term test and long-term test, respectively. These procedures produce variable results from test to test, person to person, and lab to lab. As a result, a gross variance of ±20% about a mean is considered within laboratory accuracy for the long-term test, although variances of more than 80% have been recorded. This variability is thought to be a consequence of the inconsistent packing structure generated by the cell loading process, which creates a loose, incompact arrangement of proppant grains. The focus of this research was the development of a new cell loading process that creates a more repeatable grain packing structure. Applying vibration to the proppant pack prior to testing was evaluated as a means of rearranging the grains into a denser, more compact structure and in turn decreasing the level of variability. A modification of the procedure defined by API RP19D was used to compare the different cell loading techniques in a timely manner. Five methods of applying vibrational energy were investigated, with successively more refined technologies used as research progressed. Preliminary results were encouraging and led to the development of two vibrational methods that substantially decreased gross variance of conductivity measurements. The cell loading technique outlined in API RP19D produced a variance ranging from 13% to 51%, with an average variance of 31% for the entirety of the stress ramp. Both vibrational methods produced variances below the threshold of 20% throughout the stress ramp, with an average variance of 6% for one vibrational method and 11% for the other. These results demonstrate the potential for a vibration modification to the cell loading process to improve the science of conductivity testing.

As the most commonly used technology to exploit tight dolomite reservoirs, acid fracturing usually begins with injecting pad fluid to create rough-surface fractures, followed by pumping acid to form non-uniform etching on fracture surfaces. Thus, the etching pattern and acid fracture conductivity depend largely on initial character of rough-surface fractures. In this work, experiments were conducted to examine the effects of initial roughness and mechanical property of fracture surface on acid fracture conductivity. Eight artificially split core samples were collected from tight dolomite outcrops and classified into three categories based on the surface topography and splitting force curve. Rough fracture surfaces were scanned utilizing the 3D laser scanner. Then, dynamic acid etching tests were conducted, varying the acid flow rate and acid-rock contact time. Besides, the roughness of fracture surfaces were measured utilizing the 3D laser scanner again. After that, acid fracture conductivity was determined. The effects of acid flow rate, acid-rock contact time, fracture surface topography and mechanical property on acid etching and acid fracture conductivity were discussed. The experimental results demonstrated that the initial fracture surface topography and acid flow rate jointly controlled the acid etching pattern and the resulting acid fracture surface topography. The orientation of the fractures distributed on the fracture surface had significant effects on the acid fracture conductivity. Dissolved mass increased with longer acid-rock contact time. Longer acid-rock contact time brought higher acid fracture conductivity under low closure stress, while shorter contact time sustained higher acid fracture conductivity under high closure stress. Higher maximum splitting force referred to higher mechanical property, and more breaking stages referred to more microfractures developed. Rock samples with higher maximum splitting force and only one breaking stage exhibited higher acid fracture conductivity. This paper provides a systematic method to study the effects of initial roughness and mechanical property of fracture surfaces on acid fracture conductivity. Compared with the results based on smooth-surface fracture, the experimental results based on rough-surface fracture can guide acid fracturing design and optimization in a more accurate way. Accordingly, a cost-effective stimulation outcome can be expected.

The pulse fracturing is widely used in unconventional reservoirs. It alternately pulse pumping the proppant slurry and clean fluid to form discontinuous placement proppant pillars in the artificial fractures and the pulse fracture conductivity is several orders of magnitude higher than conventional hydraulic fracture conductivity. However, the understanding of the deformation law of proppant pillar under the action of closure pressure and proppant normal stress is unclear, resulting in difficult to calculate the fracture conductivity and prefer proppant. Firstly, replacement construction and experimental displacement by Renault Similarity Criteria, three typical proppant pillars placement structures are extracted through the large-scale visualized flat plate device. The Young's modulus of the proppant pillars are calculated in modified API conductivity cell. Secondly, proppant pillars are dispersed into particles by the Smooth Particle Method (SPH). Using the parameters obtain from the above experiments, fracture-proppant pillar contact models are established to simulate the deformation process of proppant pillar and get normal stress of proppant particles. Thirdly, extracting the shape of stabilized proppant pillars, establish the fracture-proppant pillar flow model, calculate the fracture conductivity in different closure pressure. The simulation results show that as the closure pressure increases from 14MPa to 41MPa, the fracture width present an accelerated downward trend, The fracture width under the support of the initial radius of 9 mm proppant pillars are the largest, decreasing from 2.52mm to 1.72mm, the larger the radius of the proppant pillar, the greater the fracture width, the normal stress of three types of proppant pillar particles are both changed from 73MPa to 110MPa. The elliptical cylinder proppant pillar has the largest fracture conductivity. Its fracture conductivity is reduced from 12500D•cm to 3630D•cm. The larger the construction displacement and the pulse time of proppant slurry, the greater the fracture conductivity. The model in this article can calculate the normal stress of proppant particle and fracture conductivity in different closure pressure, which can significantly guide the choice of construction parameters and the type of proppant.

Proppant transport adequately during hydraulic fracturing treatment assumes same perforation contribution through multi-perforation system. Proppant transport performance into the different ordination fracture system using multi-entry perforation technique is still not fully understood. This experimental study was aimed to deeply investigate five factors that affect proppant transport performance: number of perforations, perforation opening size, shear rate, fracture orientation, and proppant size distribution. The impact of these factors on proppant transport performance from different perspective was studied. Fracture slot model was designed and built to observe easily the effects of perforation density and fracture orientation. The results of this experimental work show that limited-entry perforation technique has significant impact on proppant transport within fractures where single top perforation had better proppant placement than multi-perforation system. Fracture area was approximately propped with 66% and 48% using top perforation and multi-perforation system, respectively. Slurry with high shear rate has a negative effect on the proppant equilibrium dune level (EDL) and fracture propped area (FPA). Fracturing treatment using high shear rate causes high pressure drop in the fracture that leads to decreasing EDL by 17% and fracture propped area by 23% comparing to using low shear rate. Using large proppant size (20/40) leads to form high EDL and FPA compared to 100 mesh size. Proppant transport dominated by four mechanisms and the vertexes near wellbore plays main mechanism to carry proppant farther inside the fracture.

Post hydraulic fracture diagnostics often leads to an estimation of effective fracture lengths that are substantially shorter that the created length. (Ibrahim et al. 2017, Barree et al. 2003) This gives rise to questioning validity of the diagnostics or concerns regarding execution of the fracture stimulation itself. The objective of the paper is to show that short effective lengths are understood and predictable in the context of the physics of flow in propped fractures. Extensive laboratory testing of a broad range of proppants under a wide range of conditions has led to a databased and detailed understanding of pressure drop in a propped fracture as a function of fluid flow. The pressure drop in turn will dictate inflow from the reservoir at any point along the fracture. This interaction of pressure drop in the fracture and reservoir inflow will in turn dictate the flowing length of the fracture. Testing has demonstrated and it is well understood that the conductivity of a proppant under downhole conditions in a propped fracture is significantly less than that measured in the lab under ideal conditions of single phase Darcy flow at 2 lbm/ft2 loading. (Duenckel et al. 2017) This results from the combined effects of low proppant concentrations, frac fluid damage, multiphase flow and non-Darcy flow as well as other damage mechanisms. The paper will demonstrate that the pressure loss in the fracture resulting from the combined effects of these damage mechanisms quickly consumes the available energy to the point that the viscous forces are less than the capillary and gravity forces in the fracture, limiting further flowing length. In very low permeability reservoirs inflow from the reservoir quickly becomes insufficient to overcome gravity and capillary forces. The paper will also address the following question: if effective lengths are very short of what benefit is pumping large volumes of proppant? Further, how does one explain apparent field evidence for long fracture lengths (e.g. pressure communication) if indeed the effective length is much shorter? The paper will show how effective fracture lengths are not dependent on propped fracture properties alone. Given the limited effective conductivity resulting from a combination of damage mechanisms, the interaction of the propped fracture conductivity and reservoir inflow dictate effective fracture lengths. The resulting effective lengths are expected to be much shorter than the created lengths.

There are several formulas used in this area in determination of important parameters including but not limited to elasticity, Young’ modulus, fracture conductivity, stress, and strain as well as the characteristics of rock system This chapter provides a comprehensive list of commonly used formulas in geomechanics and fracturing, comprising very simple to relatively-more complex formulas that will serve engineers in oil and gas industry as a useful reference. Inputs, outputs, and formulas are outlined clearly along with their units. References are listed for the reader to investigate the subject further where necessary. This chapter features more than 75 formulas in gecomechanics, fracturing, and fracture-related calculations.

During hydraulic fracturing treatments, proppants – usually sand – are placed inside fractures to improve fracture conductivity. However, a large portion of the generated hydraulic fractures often remain unpropped after fracturing treatments. There are two primary reasons for this poor proppant placement. First, proppants settle quickly in common fracturing fluids (e.g., slickwater), which results in unpropped sections at the tip or top of the fracture. Second, a large number of the microfractures are too narrow to accommodate any common commercial proppant. Such unpropped fractures hold a large potential flow capacity as they exhibit a large contact area with the reservoir. However, their potential flow capacity is diminished during production due to closing of unpropped fractures because of closure stress. In this study, fractures are categorized as wider fractures, which are accessible to proppant, and narrower fractures, which are inaccessible to proppant. For wider fractures, proppant transport is important as proppant is needed for keeping them open. For narrower fractures, a chemical formulation is proposed as there is less physical restriction for fluids to flow inside across them. The chemical formulation is expected to improve fracture conductivity by generating roughness on fracture surfaces. This dissertation uses experiments and simulations to investigate proppant transport in a complex fracture network with laboratory-scale transparent fracture slots. Proppant size, injection flow rate and bypass fracture angle are varied and their effects are systematically evaluated. Based on experimental results, a straight-line relationship can be used to quantify the fraction of proppant that flows into bypass fractures with the total amount of proppant injected. A Computational Fluid Dynamics (CFD) model is developed to simulate the experiments; both qualitative and quantitative matches are achieved with this model. It is concluded that the fraction of proppant which flows into bypass fractures could be small unless a significant amount of proppant is injected, which indicates the inefficiency of slickwater in transporting proppant. An alternative fracturing fluid – foam – has been proposed to improve proppant placement because of its proppant carrying capacity. Foam is not a single-phase fluid, and it suffers liquid drainage with time due to gravity. Additionally, the existence of foam bubbles and lamellae could alter the movement of proppants. Experiments and simulations are performed to evaluate proppant placement in field-scale foam fracturing application. A liquid drainage model and a proppant settling correlation are developed and incorporated into an in-housing fracturing simulator. Results indicate that liquid drainage could negatively affect proppant placement, while dry foams could lead to negligible proppant settling and consequently uniform proppant placement. For narrower fractures, two chemical stimulation techniques are proposed to improve fracture conductivity by increasing fracture surface roughness. The first is a nanoparticle-microencapsulated acid (MEA) system for shale acidizing applications, and the second is a new technology which can generate mineral crystals on the shale surface to act as in-situ proppants. The MEA could be released as the fracture closes and the released acid could etch the surface of the rock locally, in a non-uniform way, to improve fracture conductivity (up to 40 times). Furthermore, the in-situ proppant generation technology can lead to crystal growth in both fracking water and formation brine conditions, and it also improves fracture conductivity (up to 10 times) based on core flooding experiments

Predicting the effects of the fracture penetration ratio and fracture conductivity in hydraulically- fractured vertical wells in dry-gas and wet-gas reservoirs is important in determining the well performance in a given formation. A fracture length and conductivity which provide the highest ultimate gas recovery factor at the earliest time to reach abandonment conditions is the proper fracture type which has to be selected for developing the reservoir. A three dimensional reservoir simulation model is used to evaluate the performance of hydraulic fractured vertical wells as a function of fracture penetration ratio and fracture conductivity. Accurate determination of initial gas reserves, average reservoir pressure at abandonment time, and the time to reach abandonment conditions is very important to the petroleum industry. Material balance technique and volumetric method, currently used in the petroleum industry to determine the reserves, which do not consider well performance and, as a result, predict a very high recovery factor at abandonment pressure for hydraulic fractured vertical wells in volumetric dry-gas and wet-gas reservoirs. Well performance in hydraulic fractured vertical wells depends on fracture penetration ratio and fracture conductivity. A comparison with horizontal wells of same penetration ratio is also provided in this paper as an alternative to hydraulic fracturing. A number of simulation runs were performed on a square shape reservoir of horizontal permeability 0.01 md, 0.1 md and 1 md with a penetration ratio of 0.2, 0.4 and 0.8. Our results quantify and show that the ultimate recovery factor and abandonment time are function of fracture penetration ratio regardless of fracture conductivity. In addition, our results shows that in low permeability reservoirs a hydraulic fractured vertical well of similar penetration ratio to a horizontal well perform twice in terms of recovery factor and abandonment time. The effects of formation thickness, well parameters and reservoir rock properties on the average reservoir pressure at abandonment time and on the time to reach the economic limit are also presented in this paper. Based on the results of fracture penetration ratio and fracture conductivity in volumetric dry-gas and wet-gas reservoirs, this paper presents recommendations regarding the proper well type with which the reservoir should be developed.

Proppant embedment mainly accounts for diminishing fracture aperture and conductivity. The conductivity decrease could greatly restrict fluid flow, thereby affecting the well performance. In this paper, new mathematical models are derived to calculate the proppant embedment and fracture conductivity after hydraulic fracturing. These models take three crucial factors into consideration, including proppant instantaneous elastic deformation, the conductivity change over time, and effective fracture geometry and corresponding proppants amount. Fitting correction is performed for the new theoretical model based on the experimental data. The results show that the theoretical model proposed matches well with the experimental data. The fracture conductivity is in proportion to proppant viscosity, elastic modulus of proppant and in inverse proportion to closure pressure, while elastic modulus of rock and large value of formation rock viscosity have slight impact on fracture conductivity. Moreover, with the increase of proppant viscosity, it takes longer for the conductivity to come to the steady state. These new mathematical models can provide some insights for proppant size selection and sand ratio optimization of fracturing treatment, and it is also a good method to predict the proppant embedment and the fracture conductivity.

Coupled liquid CO2 fracturing-huff and puff (CCFHP) treatment is combination of CO2 stimulation and CO2 EOR, aiming to maximise the productivity of tight oil reservoirs. In this work, we develop analytical procedures and methods to analyse technological parameters during CCHFP treatment. Several parameters, such as fracture length, fracture conductivity, fracture spacing, CO2 injection volume, soaking time, bottom hole flowing pressure (BHFP) are studied. Compositional numerical model is employed to simulate the flow process and interaction between CO2 and oil in reservoir. Orthogonal analysis method is then utilised to analyse the sensitivity of technological parameters and optimisation is implemented accordingly. The results show that the production rate of coupled liquid CO2 fracturing-huff and puff treatment is better than both CO2 fracturing treatment and CO2 huff and puff treatment. The research has valuable guiding significance for design and optimisation of field operation.

Acid etched fracture length and conductivity affect the carbonate stimulation effect. In this paper, acid-etched experiments with large-scale rock plate (1000 mm × 100 mm × 15 mm) were performed to investigate the acid etched fracture length, pattern, and conductivity. The relayed rock plates were etched with spent acid, collected from the outlet of previous plates, to simulate acid flow and reaction in a long artificial fracture. The rock plates were scanned with laser profilometer before and after acid etching to study etch behavior. The acid-etched fracture conductivity was measured under different closure stresses. The effective acid-etched fracture length is the fracture position with residual acid concentration. The results showed that the effective acid-etched fracture lengths with retarded acid were much higher than conventional acid, and most of the acid is consumed near the fracture heel. The acid-etched fracture pattern of self-diverting acid shows stronger non-uniformity with higher acid concentration, and more uniformly with lower acid concentration. The acid-etched fracture conductivity distribution along the whole artificial fracture is obtained with several relayed large-scale rock plates. And the acid-etched fracture conductivity obtained from large-scale rock plate is much lower than that from an API (American Petroleum Institute) rock plate. This study provided an experimental measure for acid-etched fracture length and global fracture conductivity evaluation.