Propped Fracture Conductivity Research Articles

Physical Simulation Experiment for Visualizing Pulverized Coal Transport in Propped Fractures

The issue of pulverized coal in coalbed methane wells during the discharge and mining process spans all stages, and it is a key factor constraining the continuous and stable discharge and production capacity of coalbed methane. Among these stages, the single-phase water flow stage features a high incidence of pulverized coal. Consequently, this paper presents a physical simulation experiment within the propped fractures during the single-phase water flow stage. The results of this study reveal the following: (1) Within the propped fracture channel, when pulverized coal is deposited along the flow line without causing blockage, the front end of the deposition exhibits a strip-like dispersion, evolving into “block deposition”, “flame-like accumulation”, “linear accumulation”, and “dispersed point-like accumulation”. (2) Agglomerated fracturing fluid can effectively mitigate the permeability damage caused by pulverized coal to the propped fractures. Both the driving speed and particle size of pulverized coal significantly influence pulverized coal transportation. The injury rate of propped fracture conductivity increases with increasing driving speeds, while the output of pulverized coal first increases and then decreases with increasing driving speed. Moreover, larger pulverized coal particle sizes result in notably greater damage to propped fracture conductivity than smaller particle sizes. Correspondingly, larger particles exhibit significantly lower output of pulverized coal compared to smaller particles, and transportation and output time are prolonged for larger particles. These findings underscore the importance of particle size and driving speed in the transportation dynamics of pulverized coal. The research results provide a theoretical basis for developing strategies for the prevention and control of pulverized coal during the single-phase water flow stage, thereby offering substantial scientific and practical value for the economic and efficient development of coalbed methane.

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

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

The influence of fracture surface morphology on propped fracture conductivity in tight sandstone reservoir

The investigation on the influence of fracture morphology on conductivity mainly focuses on the research of non-propped fracture conductivity. Few studies, however, have addressed the relationship between fracture surface characteristics and propped fracture conductivity. In this paper, by defining the maximum volume capacity of the fracture surface (VMF), according to the size relationship between the filling volume of proppants and VMF, the distribution state of proppants in propped fractures are divided into four modes, which can reflect the distribution state of proppant particle at different positions of the same fracture or different proppant concentrations in the rough surface fractures. Taking rough-surface rock samples and smooth-surface rock samples from tight sandstone reservoirs as experimental materials, a series of propped fracture conductivity tests in four modes are designed, supplemented by a various of methods such as refined characterization of three-dimensional roughness parameters of fracture surface and evaluation of proppant breakage rate. The influence of fracture morphology on the conductivity of propped fractures is systematically studied. The results show that the influence of fracture morphology on the conductivity of propped fractures varies with the distribution modes, which is closely correlated with the filling state and volume proppant filled in fractures. The influence of fracture morphology on the fracture conductivity in different distribution modes is revealed. Especially under the condition of multi-layer proppants, a new damage mechanism of fracture conductivity caused by fracture surface morphology is proposed, which is defined the “Retention Effect” of proppant particles caused by fracture surface morphology. The damage degree of this effect is characterized by defining “Damage Index of Fracture Conductivity on Rough Surface” (RFCI), which can quantitatively and accurately describe the damage degree of propped fracture conductivity caused by fracture surface morphology. The research results of this paper are helpful to understand the effect of fracture surface morphology on the conductivity of propped fractures, and also help to establish a laboratory model of the conductivity of rough fractures.

An Experimental Study on Propped Fracture Conductivity in Tight Reservoir

Propped fracture conductivity is a major element which will influence the stimulation effect after fracturing. To reveal the major factors affecting the propped fracture conductivity, the propped fracture conductivity with 20-40 mesh sand and ceramics of different sanding concentrations was experimentally studied. It can be concluded that, the propped fracture conductivity decreases as the closure pressure increases. For the silica sand proppant, when the closure pressure increased to 41.4 MPa, the downward trend of the conductivity became slower. For silica sand proppant, when the closure pressure is small, with the increase of sanding concentration, the fracture conductivity increases. When the closure pressure is greater than 41.4 MPa, the conductivity almost does not increase. Considering proppant costs, ceramic proppant can be used in low-closure pressure formations and silica sand proppant can be used in high-closure pressure formations.

Experimental Study on Evaluation of Propped Fracture Conductivity of Conglomerate Reservoir in Baikouquan Formation of Ma-A Well Area of Xinjiang Oilfield

Experimental Study on Evaluation of Propped Fracture Conductivity of Conglomerate Reservoir in Baikouquan Formation of Ma-A Well Area of Xinjiang Oilfield

Generando ingresos a partir de objetivos económicamente no rentables. Implementación exitosa de técnicas de fractura HiWAY & TSO en el Campo Shushufindi

The giant Shushufindi field, discovered in 1968, is located in the North-East of the Orient basin in Ecuador, neighboring Maranon and Putumayo basins in Peru and Colombia, respectively. The field belongs to Block 57, it started production in 1972 and is sparsely developed with 165 active wells. The production comes from two of the main cretaceous reservoirs: Ti and Ui, with Ts, Us and BT as secondary targets. The challenge to obtain incremental production from the main reservoirs becomes a tough task. The emphasis on producing from the secondary reservoirs turns into a crucial target for meeting the production expectations in the low production or abandoned wells. The main challenges in the secondary reservoirs are intermediate petrophysical properties, stratigraphic variability, low pay, lateral discontinuity, and shale intercalations. However, there is an important volume of recoverable volumes associated in these sands that makes them an attractive target for production enhancement. Performing conventional operation in secondary reservoirs has a wide margin of risk in terms of incremental production, where the average oil production is ~120 BOPD. A strategy to improve conductivity in these marginal reservoirs is hydraulic fracturing. Induced fractures enhance permeability greatly by connecting pores together; with this, hydraulic fracturing becomes a critical technology to increase production. The effectiveness of hydraulic fracturing is determined by the propped conductivity and geometry,the fracture height, and half-length. Pad volume and proppant concentration also play an important role in the fracture-treatment design because they determine final propped fracture penetration and conductivity. A good understanding of the reservoir characteristics, together with a fit-to-purpose fracture design, led to a successful implementation of TSO and HiWAY fracture designs in the Shushufindi field, with outstanding results. During the 2018-2019 WO campaign, nine (9) well interventions involved hydraulic fracturing in secondary targets and two (2) in main targets. The execution of these jobs exceeded expectations generating oil production of 7000 BOPD (790 BOPD/well) after the jobs and revenue to the project, which translates to an estimated 6.9MM Bbls of recoverable reserves.

Coupled Numerical Method for Modeling Propped Fracture Behavior

Hydraulic fracturing is a well-known production intensification technique in the petroleum industry that aims to enhance the productivity of a well drilled mostly in less permeable reservoirs. The process’s effectiveness depends on the achieved fracture conductivity, the product of fracture width, and the permeability of the proppant pack placed within the fracture. This article presents an innovative method developed by our research activity that incorporates the benefit of the Discrete—and Finite Element Method to describe the in situ behavior of hydraulic fractures with a particular emphasis on fracture conductivity. DEM (Discrete Element Method) provided the application of random particle generation and non-uniform proppant placement. We also used FEM (Finite Element Method) Static Structural module to simulate the elastic behavior of solid materials: proppant and formation, while CFD (Computational Fluid Dynamics) module was applied to represent fluid dynamics within the propped fracture. The results of our numerical model were compared to data of API RP-19D and API RP-61 laboratory measurements and findings gained by publishers dealing with propped fracture conductivity. The match of the outcomes verified the method and encouraged us to describe proppant deformation and embedment and their effect as precisely as possible. Based on the results, we performed sensitivity analysis which pointed out the impact of several factors affecting proppant embedment, deformation, and fracture conductivity and let one be aware of a reasonable interpretation of propped hydraulic fracture operation. However, DEM–CFD coupled models were introduced regarding fracturing before, to the best of our knowledge, the developed workflow of coupling DEM–FEM–CFD for modeling proppant-supported fracture behavior has not been applied yet, thus arising new perspectives for explorers and engineers.

Machine Learning-Based Propped Fracture Conductivity Correlations of Several Shale Formations.

In hydraulic fracturing operations, small rounded particles called proppants are mixed and injected with fracture fluids into the targeted formation. The proppant particles hold the fracture open against formation closure stresses, providing a conduit for the reservoir fluid flow. The fracture’s capacity to transport fluids is called fracture conductivity and is the product of proppant permeability and fracture width. Prediction of the propped fracture conductivity is essential for fracture design optimization. Several theoretical and few empirical models have been developed in the literature to estimate fracture conductivity, but these models either suffer from complexity, making them impractical, or accuracy due to data limitations. In this research, and for the first time, a machine learning approach was used to generate simple and accurate propped fracture conductivity correlations in unconventional gas shale formations. Around 350 consistent data points were collected from experiments on several important shale formations, namely, Marcellus, Barnett, Fayetteville, and Eagle Ford. Several machine learning models were utilized in this research, such as artificial neural network (ANN), fuzzy logic, and functional network. The ANN model provided the highest accuracy in fracture conductivity estimation with R2 of 0.89 and 0.93 for training and testing data sets, respectively. We observed that a higher accuracy could be achieved by creating a correlation specific for each shale formation individually. Easily obtained input parameters were used to predict the fracture conductivity, namely, fracture orientation, closure stress, proppant mesh size, proppant load, static Young’s modulus, static Poisson’s ratio, and brittleness index. Exploratory data analysis showed that the features above are important where the closure stress is the most significant.

Mechanical behavior of hollow proppants based on finite element model

AbstractProppants are being increasingly used in hydraulic fracturing, which keep the fractures open. Progress has been made in developing hollow proppants that can be transported to the far end of the fractures to improve propped fracture conductivity. Two primary mechanisms by which proppants are damaged under closure stress are embedment and crushing, leading to a remarkable reduction in fracture conductivity. In this study, finite element model (FEM), considering rock plasticity, was used to study the embedment and crushing of a hollow proppant. After comparison with the existing model and experimental data, the proposed FEM was employed to conduct sensitivity studies. The effects of the following parameters on embedment and crushing were analyzed: closure stress, distance coefficient, Young's modulus of rock and proppant, proppant size, and hollow structure. The results show that the most sensitive environmental factor is the distance coefficient, followed by closure stress and Young's modulus of rock. The embedment depth increases approximately linearly with the proppant size, and proppants with different sizes have similar crushing rates. The hollow structure has little effect on proppant embedment but significantly affects proppant crushing. Based on the data normalization method, the optimal ratio of hollow radius to proppant radius was designed to be 0.7. These results can guide the preparation of hollow proppants.

Impact of Proppant Pumping Schedule on Well Production for Slickwater Fracturing

Summary Slickwater fracturing has become one of the most leveraging completion technologies in unlocking hydrocarbon in unconventional reservoirs. In slickwater treatments, proppant transport becomes a big concern because of the inefficiency of low-viscosity fluids to suspend the particles. Many studies have been devoted to proppant transport experimentally and numerically. However, only a few focused on the proppant pumping schedules in slickwater fracturing. The impact of proppant schedules on well production remains unclear. The goal of our work is to simulate the proppant transport under real pumping schedules (multisize proppants and varying concentration) at the field scale and quantitatively evaluate the effects of proppant schedules on well production for slickwater fracturing. The workflow consists of three steps. First, a validated 3D multiphase particle-in-cell (MP-PIC) model has been used to simulate the proppant transport at real pumping schedules in a field-scale fracture (180-m length, 30-m height). Second, we applied a propped fracture conductivity model to calculate the distribution of propped fracture width, permeability, and fracture conductivity. In the last step, we incorporated the fracture geometry, propped fracture conductivity, and the estimated unpropped fracture conductivity into a reservoir simulation model to predict gas production. Based on the field designs of pumping schedules in slickwater treatments, we have generated four proppant schedules, in which 100-mesh and 40/70-mesh proppants were loaded successively with stair-stepped and incremental stages. The first three were used to study the effects of the mass percentages of the multisize proppants. From Schedules 1 through 3, the mass percentage of 100-mesh proppants is 30, 50, and 70%, respectively. Schedule 4 has the same proppant percentage as Schedule 2 but has a flush stage after slurry injection. The comparison between Schedules 2 and 4 enables us to evaluate the effect of the flush stage on well production. The results indicate that the proppant schedule has a significant influence on treatment performance. The schedule with a higher percentage of 100-mesh proppants has a longer proppant transport distance, a larger propped fracture area, but a lower propped fracture conductivity. Then, the reservoir simulation results show that both the small and large percentages of 100-mesh proppants cannot maximize well production because of the corresponding small propped area and low propped fracture conductivity. Schedule 2, with a median percentage (50%) of 100-mesh proppants, has the highest 1,000-day cumulative gas production. For Schedule 4, the flush stage significantly benefits the gas production by 8.2% because of a longer and more uniform proppant bed along the fracture. In this paper, for the first time, we provide both the qualitative explanation and quantitative evaluation for the impact of proppant pumping schedules on the performance of slickwater treatments at the field scale by using an integrated numerical simulation workflow, providing crucial insights for the design of proppant schedules in the field slickwater treatments.

Numerical study of the effect of propped surface area and fracture conductivity on shale gas production: Application for multi-size proppant pumping schedule design

Hydraulic fracturing is a technique extensively used in the oil and gas industry, where water, proppant (sand) and additives are injected into unconventional reservoirs to enhance the recovery of shale hydrocarbon. Although some previous studies have developed pumping schedules that maximize gas production for a single-size proppant, there are very few studies that consider the effect of varying proppant diameters across pumping stages on shale gas production. Motivated by this, we carried out an extensive sensitivity analysis to determine the effect of different proppant diameters on the average fracture conductivity (FC), average propped surface area (PSA) and cumulative shale gas production volume. We found out that the cumulative shale gas production volume depends on both the average PSA and average FC. We also found out that small-diameter proppant resulted in higher average PSA and lower average FC, whereas large-diameter proppant resulted in lower average PSA and higher average FC. Hence, we designed a multi-size proppant pumping schedule considering both of these parameters into account for simultaneously propagating multiple fractures to maximize shale gas production from unconventional reservoirs. Since the size of injected proppant particles determines the average PSA and average FC for the propped hydraulic fractures, we developed a novel framework called Sequentially Interlinked Modeling Structure (SIMS) to predict the average PSA, average FC and cumulative shale gas production volume at the end of 10 years for a given pumping schedule. Then, we used this SIMS framework to obtain a multi-size proppant pumping schedule that maximizes shale gas production. Finally, we demonstrated that the obtained pumping schedule gives a cumulative shale gas production volume greater than the values obtained from the existing pumping schedules.

Meta-analysis of propped fracture conductivity data—fixed effects regression modeling

Previous empirical models of propped fracture conductivity are based either on data sourced from single investigations or on data not in the public domain. In this work, statistically rigorous models of propped fracture conductivity are developed using a database of fracture conductivity experiments reported in technical literature over the last 40 years.The database contains about 2700 data points. Propped fracture conductivity is the dependent variable and proppant type, mesh size, proppant concentration, formation hardness, closure stress, formation temperature, and polymer concentration are the independent variables. The full, original database was pared down to various subsets, each having complete information in relation to some subset of the independent variables. The number of independent variables included in each of the resulting databases varied from three to six. Seventy percent of the data was used to develop the models while thirty percent of the data was used to validate them.Fixed effect models were selected using all subsets regression analysis in three, four, and five experimental factors for each of two types of proppant. The five factor model appeared to be the most useful model for both proppant types from a predictive point of view. Five-factor model predictions also compared favorably with an existing propped fracture conductivity model and different case histories published in literature.This project provides engineers with access to a propped fracture conductivity database based on experiments reported over the past 40 years in technical literature. The models developed based on this database can be used to generate predictions of propped fracture conductivity for a variety of proppant characteristics and formation conditions. Also, the models presented here are based on data from experimental investigations in different laboratories, potentially reducing biases that may be present in single laboratory investigations.

A new method to improve long-term fracture conductivity in acid fracturing under high closure stress

Acid propped fracturing is one of the most effective methods to enhance the stimulation effect, especially in the high-temperature deep carbonate formation. However, the short-term conductivity experimental data used in existing acid fracturing optimal designs may not be directly applicable to the real case. Aiming at this problem, this paper conducted a research on long-term acid conductivity behavior and proposed a new method to raise acid fracture conductivity under high closure stress. Frist, a series of experiments with carbonate core samples were conducted to investigate long-term acid conductivity behavior of carbonate reservoirs with closure stress up to 100 MPa. Gelled and cross-linked acids with different acid-rock contact times were tested to analyze the effects of acid type and acid-rock contact time on the conductivity. Next, acid fracture conductivity by adding proppant was tested to investigate the feasibility of increasing acid fracture conductivity under high closure stress. Long-term conductivity was measured up to 168 h to analyze the impact of deformation and embedment of proppant on conductivity. Finally, proppant size and concentration on conductivity were optimized for maximizing conductivity. The study shows that the conductivity with gelled acid is higher than the case with cross-linked acid for the same contact time. When the contact time is 60 min, gelled acid fracture conductivity has already reached its upper limit. The ideal combination of proppant size and concentration are optimized at different stress level. When the closure pressure is below 50 MPa, the conductivity is the highest at the proppant concentration of 0.75 kg/m2 using 20/40 mesh proppant. While the closure pressure exceeds 50 MPa, the conductivity is the highest at the proppant concentration of 3 kg/m2 using 40/70 mesh proppant. The acid propped fracture conductivity decreases rapidly in 48 h and undergoes the gradual drop, remaining steady after 120 h. An analytical model of acid propped fracture conductivity was also developed. This study provided an insight into optimizing acid propped fracturing design and predicting well performance.

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.

An experimental study on screening of dispersants for the coalbed methane stimulation

As coal is characterised by low mechanical strength, it generates lots of coal fines caused by erosion of the hydraulic fluids and scratch of the proppants in the fracturing process. The coal fines will settle out and accumulate in the fractures and result in a sharp increase of the injection pressure. Therefore it is more difficulty to fill sand. The propped fracture conductivity will be reduced significantly in the process of dewatering and gas production because of the accumulation of coal fines. The function of dispersant is to suspend the coal fines in the fracturing fluids or other waterbased fluids to prevent the coal fines from aggregation. In this paper, an experimental method is presented to study the effect of the dispersants and the influence of the coal fines on the propped fracture conductivity. With this methods, two anionic dispersants, lignin sulfonic acid and sodium lignosulfonate, were evaluated. Results show that sodium lignosulfonate performs better in dispersing coal fines. It can effectively delay aggregation of coal fines and significantly reduce conductivity damage of the propped fracture. With addition of this dispersant to the hydraulic fluids, coal fines can flow readily together with water-based fluid during hydro-fracturing and gas production. [Received: June 27, 2012; Accepted: July 9, 2013]

Characterization of Hydraulic-Fracture Geometry in Shale-Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16896, ’Characterization of Hydraulic-Fracture Geometry in Shale-Gas Reservoirs by Use of Early Production Data,’ by Chunlou Li, Randy LaFollette, Andy Sookprasong, and Sharon Wang, Baker Hughes, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Drilling long horizontal wellbores and completing wells with multistage fracturing are common practices in shaleplay development. One of the keys to enhancing production of these ultratight reservoirs is the creation of a complex_fracture system with very high surface area. Results of the current study show that post-treatment production data exhibit distinct features associated with various fracture systems and should be able to aid in describing the complex fracture system. The primary objective of this work was to find correlations between early-time production signatures and the fracture network. Introduction Hydraulic fracturing has long been an effective technique for stimulating low-permeability reservoirs. To simplify fracture modeling, biwing single-plane fracture geometry was often assumed from prefracture design through post-fracturing evaluation. However, fractures in the real world have been documented to be much more complex. Especially for economic shale plays, hydraulic-fracture interaction with natural fractures may result in complex fracture-network development. The biwing-fracture parameters—length, height, width, and conductivity—are not sufficiently detailed to describe complex fractures. Instead, another set of parameters—fracture density, unpropped- and propped-fracture conductivity, and stimulated-reservoir volume (SRV)—may be more-appropriate parameters to consider in both fracture design and production modeling. After fracturing treatments, characterization of created fracture profiles helps engineers to understand the reservoir better and thereby to optimize subsequent well completions. Various fracture-diagnostic technologies were developed to describe the fracture parameters involved: orientation, length, height, width, and conductivity. These fracture-diagnostic techniques have been applied mainly to estimate biwing-fracture geometry. When applied to shale-gas wells, some of them fail to provide helpful information because of the complexity of the created fracture network. Microseismic mapping is a technique that is widely accepted to characterize complex fracture networks. However, it is difficult to estimate the effectiveness of stimulation treatments directly from microseismic mapping because the location of proppant and the distribution of conductivity in the fracture network cannot be determined from microseismic data. Direct fracture-diagnostic methods and production-analysis techniques are beyond the scope of this work. But, informed by the ideas underlying those techniques, this paper attempts to identify possible correlations between early-time production signatures and complex-fracture-system parameters.

Improved Conductivity and Proppant Applications in the Bakken Formation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163849, ’Investigation of Improved Conductivity and Proppant Applications in the Bakken Formation,’ by Bethany Kurz, SPE, Energy and Environmental Research Center, Darren Schmidt, SPE, and Phil Cortese, SPE, Weatherford, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. Production from the Bakken and Three Forks formations within the Williston basin is continuing to climb as a result of applied horizontal drilling and hydraulic fracturing. Key to increased oil production is the evolution of reservoir-stimulation techniques, such as fracturing-fluid systems and proppant types. This study evaluated the key factors that may result in conductivity loss within the Bakken and Three Forks reservoirs. The results of this work suggest that certain fluids may affect both rock and proppant strength and, therefore, require consideration. Introduction This work was conducted in an effort to answer questions regarding reservoir stimulation in the Bakken petroleum system, specifically with respect to conductivity loss in hydraulic fractures over time. The key questions that were evaluated include Can conductivity loss be attributed to proppant degradation, rock strength, or both? What role do fluids have in affecting propped-fracture conductivity? To what extent does fluid exposure affect the degradation of rock strength and proppant performance? How do various proppants perform relative to one another under stress using actual core samples from the Bakken petroleum system? Laboratory tests were conducted to evaluate the sensitivity of Bakken and Three Forks formation cores to various fluids; to evaluate the strength of Ottawa sand, an unspecified premium precured resin-coated sand (RCS), and a lightweight ceramic proppant (Econoprop) with respect to various fluids; and to measure the relative laboratory conductivity performance of propped fractures using actual rock core. Fluids used in experiments to examine potential strength degradation for both rock and proppant included the following: Slickwater—a mixture of polyacrylamide and fresh water Crosslinked gel—guar-polymer thickening agent, borate crosslinker, and fresh water Gelled diesel—diesel fuel and phosphate ester Bakken-formation crude—crude oil Bakken-formation brine—highly concentrated saltwater The fluids were selected on the basis of the most common fluids expected to be encountered in the Bakken formation. Embedment Brinell-hardness-index testing is a measure of rock strength that is determined by embedding a metal ball into formation rock at a given applied load. This type of index testing was used to gauge the relative strength of Bakken and Three Forks samples before and after exposure to formation and hydraulic-fracturing fluids. Core samples used to study rock strength originated from the North Dakota Industrial Commission (NDIC) #16771 well, located in the Manitou field of Mountrail County. Rock strength was measured with a Brinell-hardness-test apparatus. Publicly available hardness data were available from two wells in proximity, including NDIC #15986, Robinson Lake field, Mountrail County, approximately 10 miles to the southeast NDIC #16083, Capa field, Williams County, approximately 10 miles to the southwest

Experimental Method to Simulate Coal Fines Migration and Coal Fines Aggregation Prevention in the Hydraulic Fracture

A simple and effective experimental method is proposed to simulate coal fines migration through the proppant pack; such migration inevitably occurs during the process of fracturing fluid flowback or dewatering and gas production in coalbed methane (CBM) reservoirs. The damage to conductivity caused by coal fines migration in the pack and the factors affecting such migration are analyzed. A dispersion agent of coal fines applicable to hydraulic fracturing in CBM is optimized, consequently solving the problem of coal fines aggregation and retention in the proppant pack. Discharging coal fines with water or water-based fracturing fluid from the proppant pack can be difficult because of the adsorption and hydrophobicity of coal fines. Thus, coal fines are likely to aggregate and be retained in the proppant pack, thereby resulting in pore throat plugging, which causes serious damage to fracture conductivity. Two percent coal fines can reduce propped fracture conductivity by 24.4 %. The mobility and retention of coal fines in the proppant pack are affected by proppant size, proppant type, flowback rate, and coal fines property. When flowback rate exceeds the critical value, coal fines can be discharged from the pack, consequently reducing damage to propped fracture conductivity. More importantly, the steady discharging of coal fines requires steady dewatering and gas production to avoid flow shock, which causes pressure disturbance to drive coal fines in a remote formation. The optimized dispersant FSJ-02 employed in this paper can effectively change the wettability and surface potential of coal fines to improve their suspension and dispersion in water-based fracturing fluid. The recovery rate of coal fines increased by 31.5 %, whereas conductivity increased by 13.3 %.

Realistic Proppant Conductivity Data Improves Hydraulic Fracturing Treatment Design

Abstract Successful application of hydraulic fracturing is dependent on obtaining the desired propped fracture length and conductivity. Post-frac pressure analysis methods are often used to calculate the apparent length and conductivity that were achieved by a fracturing treatment. Many times, the calculated conductivity values are a factor of two to five lower than had been predicted by the pre-frac design calculation. Occasionally values an order of magnitude lower than those predicted are found. Recent laboratory tests on proppants held at stress for long time periods at various reservoir temperatures resulted in much lower conductivity values than when generated with very short test times. The result of this testing program has been the development of a large base of conductivity data that are much more realistic than the data which have been in use for many years. This may help explain discrepancies in pre-frac predictions and post-frac calculations. In many cases, the treatment design will be altered appreciably by the use of more realistic conductivity data. In this paper, we will present comparisons of the old data and the more realistic values. We will also illustrate the significant effect that use of the new data can have on fracturing treatment design. In many applications the recommended proppant addition schedule will be much more ambitious. Some well conditions may result in the need for a stronger propping agent than had been predicted using less realistic conductivity data. Introduction In recent years, advances in the field of transient pressure analysis on hydraulically fractured wells will often allow an operator to make post-frac estimates of effective fracture length and fracture conductivity(1,2). No longer are the analyses based on "infinite conductivity" fractures where the calculated fracture length was typically less than 30 m. When these new "finite conductivity" analysis methods were first introduced, the fracture length and fracture conductivity values were often in significant disagreement with pre-frac predictions of computer design simulator models. More recently, refinements in analysis techniques, coupled with further experience in applying these methods, have resulted in improved calculations which yield a calculated fracture length that is usually in reasonable agreement with design simulators(3.4). This has not been the case with post-frac calculations of fracture conductivity, however, where pre-frac predictions continue to be much higher in many cases(3–6). In 1973, Cooke(7) published data indicating that brine and temperature will have a significant effect on fracture conductivity with time. Corrosion of test equipment and other problems interfered with later attempts to extend this work. The net result was that essentially all the conductivity data published by the industry has been at ambient test temperatures with short test times at each stress level(8,11). A few authors have tested at higher temperatures, but again using only short time durations at each closure stress(12,13). In 1986, McDaniel(14) published work that described how these experimental problems can be overcome. The paper also presented data that indicated "time at stress" may be a very important factor at any temperature, although the primary emphasis was at relatively high reservoir temperature (135 °C).