scholarly journals Well Performance Simulation and Parametric Study for Different Refracturing Scenarios in Shale Reservoir

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-12 ◽  
Author(s):  
Jing Huang ◽  
Lan Ren ◽  
Jinzhou Zhao ◽  
Zhiqiang Li ◽  
Junli Wang
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Sichuan Basin ◽  
Gas Flow ◽  
Gas Production ◽  
Parameters Optimization ◽  
Well Performance ◽  
Fracture Permeability ◽  
Stimulated Reservoir Volume ◽  
Gas Recovery

Refracturing is an encouraging way to uplift gas flow rate and ultimate gas recovery from shale gas wells. A numerical model, considering the stimulated reservoir volume and multiscale gas transport, is applied to simulate the gas production from a refractured shale gas well. The model is verified against field data from a shale gas reservoir in Sichuan Basin. Two refracturing scenarios: refracturing through existing perforation clusters and refracturing through new perforation zones, are included in the simulation work. Three years after production is determined to be the optimum time for refracturing based on the evolution analysis of reservoir pressure, effective stress, fracture permeability, and gas recovery. The role that the hydraulic fracture conductivity and hydraulic fracture half-length play in gas production for different refracturing cases is explored. Pumping parameters of the refracturing job in Sichuan Basin are discussed combining with sensitivity analysis, and suggestions for pumping parameters optimization are proposed.

scholarly journals The Key Factors That Determine the Economically Viable, Horizontal Hydrofractured Gas Wells in Mudrocks

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2348 ◽  
Author(s):  
Syed Haider ◽  
Wardana Saputra ◽  
Tadeusz Patzek
Keyword(s):  
Gas Flow ◽  
Horizontal Well ◽  
Source Term ◽  
Organic Matrix ◽  
Fracture Network ◽  
Gas Production ◽  
Fracture Permeability ◽  
Gas Wells ◽  
Stimulated Reservoir Volume ◽  
Well Production

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity.

scholarly journals History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

scholarly journals Numerical simulation on the effect of fractures geometries for shale gas development with discrete fracture network model

2021 ◽  
Vol 11 (3) ◽  
pp. 1289-1301
Author(s):  
Songze Liu ◽  
Jianguang Wei ◽  
Yuanyuan Ma ◽  
Xuemei Liu ◽  
Bingxu Yan
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Gas Flow ◽  
Seepage Flow ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
Rock Matrix ◽  
Fracture Permeability ◽  
Cumulative Production

AbstractThe shale gas reservoir is regarded as a dual medium consisting of fracture (hydraulic fracture and discrete natural fracture network) and rock matrix, the seepage process in the fracture and rock matrix is fully considered and a mathematical model of seepage flow in accordance with Darcy's law was established. The results show the influence order of hydraulic fracture geometry on the cumulative production. Compared with the hydraulic fracture aperture of 10–4 m, when the aperture is 10–5 m and 10–6 m, the cumulative production is reduced by 88.0% and 99.7%, respectively. Compared with the hydraulic fracture length is 100 m, when the length is 200 m and 300 m, the cumulative production is increased by 38.2% and 62.4%, respectively. The increase in the natural fracture aperture increases the fracture permeability, which make it more conducive to gas flow into the fracture, thereby increasing the cumulative production. The increase in the number of natural fractures makes the connectivity of the shale reservoir becomes better and the cumulative production increases more.

Impact of the Cluster Spacing on Hydraulic Fracture Conductivity and Productivity of a Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Ameri Samuel
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Technical Information ◽  
Gas Production ◽  
Production Performance ◽  
Valuable Insight ◽  
Fracture Conductivity ◽  
Fracture Properties ◽  
Gas Recovery ◽  
The Impact

Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.

Lithology and sedimentary heterogeneity of the Longmaxi Shale in the southern Sichuan Basin, China

2021 ◽  
pp. 1-49
Author(s):  
Boling Pu ◽  
Dazhong Dong ◽  
Ning Xin-jun ◽  
Shufang Wang ◽  
Yuman Wang ◽  
...  
Keyword(s):  
Continental Shelf ◽  
Deep Water ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Sedimentary Environment ◽  
Gas Production ◽  
Carbonaceous Shale ◽  
Gas Wells ◽  
Longmaxi Shale ◽  
Siliceous Shale

Producers have always been eager to know the reasons for the difference in the production of different shale gas wells. The Southern Sichuan Basin in China is one of the main production zones of Longmaxi shale gas, while the shale gas production is quite different in different shale gas wells. The Longmaxi formation was deposited in a deep water shelf that had poor circulation with the open ocean, and is composed of a variety of facies that are dominated by fine-grained (clay- to silt-size) particles with a varied organic matter distribution, causing heterogeneity of the shale gas concentration. According to the different mother debris and sedimentary environment, we recognized three general sedimentary subfacies and seven lithofacies on the basis of mineralogy, sedimentary texture and structures, biota and the logging response: (1) there are graptolite-rich shale facies, siliceous shale facies, calcareous shale facies, and a small amount of argillaceous limestone facies in the deep - water shelf in the Weiyuan area and graptolite-rich shale facies and carbonaceous shale facies in the Changning area; (2) there are argillaceous shale facies and argillaceous limestone facies in the semi - deep - water continental shelf of the Weiyuan area and silty shale facies in the Changning area; (3) argillaceous shale facies are mainly developed in the shallow muddy continental shelf in the Weiyuan area, while silty shale facies mainly developed in the shallow shelf in the Changning area. Judging from the biostratigraphy of graptolite, the sedimentary environment was different in different stages.

Application Investigation of Light Proppant in Hydraulic Fracturing of Marcellus Shale

2021 ◽  
Author(s):  
Aymen Alhemdi ◽  
Ming Gu
Keyword(s):  
History Matching ◽  
Marcellus Shale ◽  
In Situ Stress ◽  
Production Performance ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Conductivity ◽  
Stimulated Reservoir Volume ◽  
Conductivity Distribution ◽  
Cumulative Production

Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.

scholarly journals Numerical Simulation of Shale Gas Multiscale Seepage Mechanism-Coupled Stress Sensitivity

2019 ◽  
Vol 2019 ◽  
pp. 1-13 ◽  
Author(s):  
Xun Yan ◽  
Jing Sun ◽  
Dehua Liu
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Gas Transport ◽  
Sensitivity Coefficient ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Molecular Flow ◽  
Adsorption Phenomenon ◽  
Gas Seepage ◽  
The Impact

The complexity of the gas transport mechanism in microfractures and nanopores is caused by the feature of multiscale and multiphysics. Figuring out the flow mechanism is of great significance for the efficient development of shale gas. In this paper, an apparent permeability model which covers continue, slip, transition, and molecular flow and geomechanical effect was presented. Additionally, a mathematical model comprising multiscale, geomechanics, and adsorption phenomenon was proposed to characterize gas flow in the shale reservoir. The aim of this paper is to investigate some important impacts in the process of gas transportation, which includes the shale stress sensitivity, adsorption phenomenon, and reservoir porosity. The results reveal that the performance of the multistage fractured horizontal well is strongly influenced by stress sensitivity coefficient. The cumulative gas production will decrease sharply when the shale gas reservoir stress sensitivity coefficient increases. In addition, the adsorption phenomenon has an influence on shale gas seepage and sorption capacity; however, the effect of adsorption is very weak in the early gas transport period, and the impact of later will increase. Moreover, shale porosity also greatly affects the shale gas transportation.

scholarly journals Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Energies ◽  
2020 ◽  
Vol 14 (1) ◽  
pp. 2
Author(s):  
Liang Gong ◽  
Yuan Zhang ◽  
Na Li ◽  
Ze-Kai Gu ◽  
Bin Ding ◽  
...  
Keyword(s):  
Energy Consumption ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Production ◽  
Formation Temperature ◽  
Displacement Efficiency ◽  
Gas Recovery ◽  
Displacement Capacity ◽  
Molecular Investigation ◽  
Shale Reservoirs

The rapid growth in energy consumption and environmental pollution have greatly stimulated the exploration and utilization of shale gas. The injection of gases such as CO2, N2, and their mixture is currently regarded as one of the most effective ways to enhance gas recovery from shale reservoirs. In this study, molecular simulations were conducted on a kaolinite–kerogen IID composite shale matrix to explore the displacement characteristics of CH4 using different injection gases, including CO2, N2, and their mixture. The results show that when the injection pressure was lower than 10 MPa, increasing the injection pressure improved the displacement capacity of CH4 by CO2. Correspondingly, an increase of formation temperature also increased the displacement efficiency of CH4, but an increase of pore size slightly increased this displacement efficiency. Moreover, it was found that when the proportion of CO2 and N2 was 1:1, the displacement efficiency of CH4 was the highest, which proved that the simultaneous injection of CO2 and N2 had a synergistic effect on shale gas production. The results of this paper will provide guidance and reference for the displacement exploitation of shale gas by injection gases.

Numerical Simulation of Shale Gas Production

2011 ◽  
Vol 402 ◽  
pp. 804-807 ◽  
Author(s):  
Song Ru Mu ◽  
Shi Cheng Zhang
Keyword(s):  
Shale Gas ◽  
Simulation Models ◽  
Fracture Network ◽  
Gas Production ◽  
Wire Mesh ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Fracture Mapping

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

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