Low Proppant Concentrations Research Articles

Study on multi-cluster fracture propagation and quantitative evaluation method considering perforation erosion

This article pinpoints the problem of multiple clusters of crack extensions with perforation erosion, proposes a modified calculation formula for the variation of perforation diameter. Established a proposed three-dimensional numerical model to analyze the effect of different construction and completion parameters on fracture extension. The results show that: (1) With the pumping of sand-carrying fluid, the perforation erosion will lead to the increase of the flow coefficient and diameter of each cluster of perforation, which shows that the perforation erosion exacerbates the imbalance in flow distribution at the fracture inlet of each cluster as well as the non-uniform expansion of multi-cluster cracks. (2) The effect of perforation erosion increases with the enhancement of limited entry, and although the negative effect of perforation erosion is overall smaller than the positive effect of limited entry, it somewhat weakens the flow restriction ability of the perforation. (3) When the effect of limited entry is strengthened, considering the effect of perforation erosion the flow difference coefficient and the fracture length variation coefficient are significantly increased, and show a tendency to decrease (4) Use low proppant concentration to minimize damage to fractured pipe columns while meeting fracture inflow capacity.

Study The Effect of Proppant Concentration of Screen-Out Phenomena While Hydraulic Fracture Job

screen out is a blocking of the fracture path caused by bridging the path or accumulation of the proppant inside the fracture, clumping or lodging of the (solid particles) proppant across the hydraulic fracture width that causes to restrict formation fluid to flow into the hydraulically fractured formation. To avoid the screen out happening needing to save fracturing fluids, hydraulic horsepower. Conditions that leading to screen out during the hydraulic fracturing job in a well, such as, the ratio between the fracture widths to particle diameter that called (β), proppant concentration,  and wall roughness. The effects of these factors are investigated experimentally in the present work by building an apparatus that meet the shape of the real hydraulic fracture. The plugging time were measured and monitored through glass windows on both sides of the apparatus to follow the behavior of the proppant inside the fracture during the flow of the fracturing fluid or when the proppant plugs the fracture. To study the effect of the fracture wall roughness on the screen out phenomena, apparatus was build to get two different fracture shapes, to meet the real fracture wall in reality. Through the relation between the different proppant concentration and the plugging time, one can indicate on the graph the plugging region and non plugging region for different values of β, proppant concentration and fracture shape, in order to avoid the screen out. During designing the hydraulic fracture, the values of β were very important factor that can lead to screen out, through the results found that when β=1, the screen out happened very fast even at low proppant concentration, but for β=2, 3 and 4 the screen out depends on the proppant concentration and fracture shape. For β=5 it was found that, there is no screen out occurring for wide range of proppant concentration. The effect of hydraulic fracture wall roughness is important because it effect the speed of the suspension when passing through the fracture.

Effects of Altering Perforation Configurations on Proppant Transport and Distribution in Freshwater Fluid

Summary Proppant transport in horizontal wellbores has received significant industry focus over the past decade. One of the most challenging tasks in the hydraulic fracturing of a horizontal well is to predict the proppant concentration that enters each perforation cluster within the same stage. The main objective of this research is to investigate the effect of different perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. To simulate a fracturing stage in a horizontal wellbore, a laboratory-based 30-ft horizontal clear apparatus with three perforation clusters is used. Fresh water (~1 cp) is used as the carrier fluid to transport the proppant. This research incorporates the effect of testing three different injection rates each at four different proppant concentrations on proppant transport. Different perforation configurations are also used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations for the tested 100-mesh proppant. The proppant is mixed with fresh water in a 200-gallon tank for at least 10 minutes to ensure the consistency of the slurry mixture. The mixture is then injected into the transparent horizontal wellbore through a slurry pump. This laboratory apparatus also includes a variable frequency drive, a flowmeter, and two pressure transducers located right before the first two perforation clusters. Sieve analysis is conducted to understand the ability of fresh water to carry bigger particles of the mixture at different injection rates, proppant concentrations, and perforation configurations. The results show different fluid and proppant distributions occur when altering the perforation configurations, injection rates, and proppant concentrations. The effect of gravity is extreme when using a limited-entry configuration at each cluster [1 shots/ft (SPF)] located at the bottom of the pipe, especially at low injection rates, resulting in uneven proppant distribution with a heal-biased distribution. However, even proppant distribution is observed by changing the limited entry perforation configuration to the top of the horizontal pipe at similar injection rates and low proppant concentration. Increasing the proppant concentration reduces the void spaces between the particles and pushes them away toward the toe cluster. Even proppant distribution is also observed across the three perforation clusters when using higher flow rates and a 2 SPF perforation configuration located at both the top and the bottom of the pipe. The results show uneven fluid and proppant distributions between clusters with a toe-biased distribution when altering the perforation configurations to 3 and 4 SPF. The results of the sieve analyses show different size distributions of the settled and exited proppant through different perforations and clusters. This illustrates the ability of fresh water to transport different percentages of various proppant sizes to different perforations and clusters within a single stage. Frequently, the injected proppant is assumed to be distributed evenly across the perforation clusters and the distribution of fluid and proppant is assumed to be identical. This research provides a better understanding of the proppant transport inside the multiclusters in a horizontal wellbore by using fresh water as the carrier fluid. This research is unique in that it experimentally studies the effect of changing the perforation configurations and orientation on the proppant transport and distribution. This study comprehensively investigates the effect of injection parameters that influence the proppant transport behavior such as injection rate and proppant concentrations. The work shows that the distribution of the transported proppant is different across individual clusters and varies between different perforations within each cluster. Such information is beneficial to understanding transport in horizontal, multistage completions and how such impacts the overall treatment efficiency, especially when employing limited-entry perforation techniques.

Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China

With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m 3 /t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500–800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.47-1.71 MPa/100 m). Overall, the stress release zone at depths of 500–800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production. • In-situ stress distribution characteristics of coals in the Western Guizhou. • Permeability and resource distribution show similar belting as with stress regimes. • Stress release zone at 500–800 m depths are favorable for CBM extraction. • Low proppant concentration and high fluid volume are suggested for hydrofracturing. • Individual-seam fracturing is the most effective productivity enhancement method.

Brazilian tensile failure characteristics of marine shale under the hydration effect of different fluids

In this paper, shale gas cores from the Lower Silurian Longmaxi Formation in the Zhaotong National Shale Gas Demonstration Area were selected to study the hydration effect of different fluids on the fracture morphology inside the shale, the rock tensile strength and the Brazilian tensile failure mode. Fresh water and slick water were adopted for hydration pretreatments and the CT technique was used to compare the changes of the fabric in the shale. Then, Brazilian tensile tests were carried out to study the tensile strength and tensile failure modes of the shale specimen after hydration pretreatment. Finally, two horizontal wells in the study area were selected to perform pilot tests of hydration pretreatment in their fracturing operation sites. And the following research results were obtained. First, in the process of spontaneous imbibition, the hydration effect of fresh water is superior to that of slick water in promoting the fracture complexity of marine shale in the same hydration duration. Second, fresh water has greater surface tension and lower viscosity and its hydration effect can not only promote the propagation of original fractures but induce new micro-fractures or branches, while the hydration effect of slick water mainly promotes the propagation of original fractures. Third, due to hydration effect, marine shale is damaged and its tensile strength is reduced. After the hydration pretreatment by fresh water and slick water, the tensile strength of the shale specimens are reduced by 35.6% and 18.1%, respectively. Fourth, according to the propagation paths of main fractures, the Brazilian tensile failure modes of hydrated shale can be divided into four types (i.e., step shaped, dog-leg shaped, branching shaped and arc shaped) or their combinations, while the tensile failure mode of unhydrated shale is only a straight line. Fifth, hydration effect can effectively increase the complexity of the hydraulic fractures in marine shale, so if the conditions permit, it is recommended to inject a certain amount of fresh water at a high pumping rate within the limited pressure after perforation and to shut in the well until the hydraulic fracturing operation. And in order to reduce the difficulties of pumping the proppant during the hydraulic fracturing operation, a pumping strategy of “low proppant concentration, large volume of slurries” can be adopted to reach the expected proppant volume.

Development of new testing procedures to measure propped fracture conductivity considering water damage in clay-rich shale reservoirs: An example of the Barnett Shale

Multi-stage hydraulic fracturing is the key to the success of many shale gas and shale oil reservoirs. The main objective of hydraulic fracturing in shale is to create fracture networks with sufficient fracture conductivity. Due to the variation in shale mineralogical and mechanical properties, fracture conductivity damage mechanisms in shale formations are complex. Standard fracture conductivity measurement procedures developed for fractures with high proppant concentration had to be modified to measure the conductivity in fractures with low proppant concentration. Water-based fracturing fluids can interact with the clay minerals in shale and eventually impact shale fracture conductivity. All these challenges require more experimental studies to improve our understanding of realistic fracture conductivity in shale formations. The aims of this work were to design an experimental framework to measure fracture conductivity created by low concentration proppants and to investigate the mechanisms of conductivity damage by water. We first presented the laboratory procedures and experimental design that can accurately measure fracture conductivity of shale fractures at low concentrations of proppants. Then we measured the undamaged shale fracture conductivity by dry nitrogen. Water with similar flowback water compositions was injected to simulate the damage process followed by secondary gas flow to measure the recovered fracture conductivity after the water damage. This study shows that the developed laboratory procedures can be utilized to reproducibly measure shale fracture conductivity by both gas and liquid. The conductivity measurement of propped fractures by small size proppants at low concentrations requires strict control on gas flow bypassing the fracture both parallel and perpendicular to the fracture length direction. Shale fracture surface softening is identified as the dominant cause for the significant conductivity reduction after water flow.

Measurement of realistic fracture conductivity in the Barnett shale

The Mississippian Barnett shale of the Fort Worth Basin is one of the most successfully developed shale gas plays in North America by applying multistage hydraulic fracturing stimulation techniques. The fracturing design involves pumping low viscosity fluid with low proppant concentrations at high pump rate, commonly known as “slick water fracturing”. Direct laboratory measurement of natural and induced fracture conductivity under realistic conditions is needed for reliable well performance analysis and fracturing design optimization.During the course of this study a series of conductivity experiments was completed. The cementing material present on the surface of natural fractures was preserved during the initial unpropped conductivity tests. The induced fractures were artificially created by breaking the shale rock along the bedding plane to account for the effect of irregular fracture surfaces on conductivity. Proppants of various sizes were manually placed between rough fracture surfaces at realistic concentrations. The two sides of the induced fractures were cut in a way to represent either an aligned or a displaced fracture face with a 0.1inch offset. The effect of proppant partial monolayer was also studied by placing proppants at ultra-low concentrations.Results from the experiments show that unpropped induced fractures can provide a conductive path after removal of free particles and debris generated when cracking the rock. Poorly cemented natural fractures are effective flow paths. Unpropped fracture conductivity depends strongly on the degree of shear displacement, the presence of shale flakes and particles, and the amount of cementing material removed. The propped fracture conductivity is weakly dependent on fracture surface roughness at higher proppant concentrations. Moreover, propped fracture conductivity increases with larger proppant size and higher concentration in the testing range of this study. Results also show that proppant partial monolayers cannot survive higher closure stresses.

Effect of foam quality on effectiveness of hydraulic fracturing in shales

The goal of this work is to study the effect of foam quality on the gas productivity of fractured wells in shales. A numerical model of fracture propagation is developed which incorporates a 2D fracture model, proppant transport, and foam rheology. The fracture conductivity distribution is computed from the local proppant concentration, which is incorporated in a reservoir simulation model to predict the gas production by depressurization. Given the rock mechanical properties, the fracturing fluid, proppants, and rock permeability control the shape and conductivity of the fractures created during hydraulic fracturing. The shape and conductivity of the fracture, in turn, control the gas productivity of such a well. Foam quality, proppant size, proppant concentration, and rock permeability are varied. The results show that, in most cases, the gas production is optimum at an intermediate foam quality (of about 65%) because it creates the largest propped fracture area and minimizes leak-off. Only for the case of 0.1 micro-Darcy rock, low proppant concentration and large proppant size, the gas production increases monotonically with foam quality because high quality foam can place a partial monolayer of proppants. Fracturing with water as the initial pad and a high quality (65–85%) foam as the proppant carrier is more effective than using the same foam for both pad and slurry.

Pressure-Transient Testing of Low-Permeability Multiple-Fracture Horizontal Wells

This article, written by Dennis Denney, contains highlights of paper SPE 163983, ’An Approach to Practical Pressure-Transient Testing of Multiple-Fracture-Completed Horizontal Wells in Low-Permeability Reservoirs,’ by Richard Volz, Elvia Pinto, and Omar Soto, SPE, BP America, and J.R. Jones, SPE, NSI Fracturing, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed. A common well-completion configuration for shale-gas wells is a horizontal well with multiple transverse hydraulic fractures. This configuration is becoming common for tight gas reservoirs. Pressure-transient testing of this completion configuration has not been considered practical or useful because extracting completion parameters (e.g., fracture conductivity and fracture half-length) from the recorded response requires estimating the effective formation permeability. Estimating permeability directly from a buildup or drawdown test can be performed only if data from the radial-flow period, which reflects this parameter, are recorded. Unfortunately, for this completion configuration in a low-permeability reservoir, this flow period occurs only after extremely long shut-in or flowing times. Introduction The usual shale-gas completion is a cased-and-cemented horizontal well, perforated with multiple perforation clusters. Each perforation cluster is treated with an independent fracture stimulation with a large volume of fluid and relatively low proppant concentration. The goal is to create an induced-hydraulic-fracture system, spaced along and covering the length of the horizontal well to provide a large, effective surface flow area in the reservoir. Interpreted microseismic images of these multistage-stimulation treatments indicate that, in some reservoirs, the fractures created at each perforation cluster have dominant transverse components. These dominant transverse components may or may not be interpreted to be overlain with or coupled to a more-complex system of secondary fractures. Even if the secondary system of more-complex fracturing occurs, the relative importance of this secondary fracture system and its relative contribution to the deliverability of the overall induced fracture system remain subjects of debate. It is equally difficult to establish or deny the importance of the overprint of a natural-fracture system to the flow response and performance of multiple-fracture horizontal wells (MFHWs) in unconventional reservoirs. Therefore, the natural starting point for developing a useful pressure- transient- analysis method for horizontal-shale- well data would be on responses from horizontal wells affected by induced transverse fractures alone. Building viable pressure-transient-data interpretation methods for this simple base-case problem was the goal of this work. This interpretation must be accomplished before considering how to solve the more general cases that include induced- and natural-fracture complexity. The main issues in analyzing the pressure-transient response from an MFHW are the same as those with a vertically fractured well.

Experimental Study of Fracture Conductivity for Water-Fracturing and Conventional Fracturing Applications

Summary Hydraulic fracturing treatments that use treated water and very low proppant concentrations (commonly referred to as water-fracturing treatments or "waterfracs") have been successful in stimulating low-permeability reservoirs. However, the mechanism by which these treatments provide sufficient conductivity is not well understood. To understand the effects of fracture properties on conductivity, a series of laboratory conductivity experiments was performed with fractured cores from the east Texas Cotton Valley sandstone formation. The results of this study demonstrate that fracture displacement is required for surface asperities to provide residual fracture width and sufficient conductivity in the absence of proppants. However, the conductivity may vary by at least two orders of magnitude, depending on formation properties such as the degree of fracture displacement, the size and distribution of asperities, and rock mechanical properties. In the presence of proppants, the conductivity can be proppant- or asperity-dominated, depending on the proppant concentration, proppant strength, and formation properties. Under asperity-dominated conditions, the conductivity varies significantly and is difficult to predict. Low concentrations of high-strength proppant overcome the uncertainty associated with formation properties and provide proppant-dominated conductivity. The implication of these results is that the success of a water-fracturing treatment is difficult to predict because it will depend significantly on formation properties. This dependence can be overcome by using high-strength proppants or proppants at conventional field concentrations.