The Fracture Network Inversion Based on Gas Production Profile

2019 ◽  
Author(s):  
Lidong Mi ◽  
Bicheng Yan ◽  
Qianjun Liu ◽  
Zongxiao Ren
Keyword(s):  
Fracture Network ◽  
Gas Production

scholarly journals Analysis of the Influence of Different Fracture Network Structures on the Production of Shale Gas Reservoirs

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
Ming Yue ◽  
Xiaohe Huang ◽  
Fanmin He ◽  
Lianzhi Yang ◽  
Weiyao Zhu ◽  
...  
Keyword(s):  
Finite Element ◽  
Shale Gas ◽  
Flow Direction ◽  
Fracture Network ◽  
Gas Production ◽  
Low Flow ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
Gas Seepage

Volume fracturing is a key technology in developing unconventional gas reservoirs that contain nano/micron pores. Different fracture structures exert significantly different effects on shale gas production, and a fracture structure can be learned only in a later part of detection. On the basis of a multiscale gas seepage model considering diffusion, slippage, and desorption effects, a three-dimensional finite element algorithm is developed. Two finite element models for different fracture structures for a shale gas reservoir in the Sichuan Basin are established and studied under the condition of equal fracture volumes. One is a tree-like fracture, and the other is a lattice-like fracture. Their effects on the production of a fracture network structure are studied. Numerical results show that under the same condition of equal volumes, the production of the tree-like fracture is higher than that of the lattice-like fracture in the early development period because the angle between fracture branches and the flow direction plays an important role in the seepage of shale gas. In the middle and later periods, owing to a low flow rate, the production of the two structures is nearly similar. Finally, the lattice-like fracture model is regarded as an example to analyze the factors of shale properties that influence shale gas production. The analysis shows that gas production increases along with the diffusion coefficient and matrix permeability. The increase in permeability leads to a larger increase in production, but the decrease in permeability leads to a smaller decrease in production, indicating that the contribution of shale gas production is mainly fracture. The findings of this study can help better understand the influence of different shapes of fractures on the production in a shale gas reservoir.

scholarly journals Experimental Investigation of Spontaneous Imbibition of Water into Hydrate Sediments Using Nuclear Magnetic Resonance Method

Energies ◽  
2020 ◽  
Vol 13 (2) ◽  
pp. 445 ◽  
Author(s):  
Liu Yang ◽  
Chuanqing Zhang ◽  
Jianchao Cai ◽  
Hongfeng Lu
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Research Work ◽  
Resonance Method ◽  
Fracture Network ◽  
Gas Production ◽  
Spontaneous Imbibition ◽  
Nuclear Magnetic Resonance Method ◽  
Water Imbibition ◽  
Nuclear Magnetic

Field observations show that less than one percent of dissociation water can be produced during gas hydrate production, resulting from spontaneous water imbibition into matrix pores. What’s more, the hydrate sediments are easily dispersed in water, and it is difficult to carry out spontaneous imbibition experiments. At present, there is little research work on the imbibition capacity of hydrate sediments. In this paper, a new method of water imbibition is proposed for hydrate sediments, and nuclear magnetic resonance (NMR) technique is used to monitor water migration. The results show that as the imbibition time increases, the water is gradually imbibed into matrix pores. Water imbibition can cause dramatic changes in pore structure, such as microfracture initiation, fracture network generation and skeleton dispersion. When the imbibition time exceeds a critical value, many secondary pores (new large pores and micro-fractures) start to appear. When imbibition time exceeds the dispersion time, fracture networks are generated, eventually leading to dispersion of the sediment skeleton. The imbibition curves of hydrate sediments can be divided into two linear stages, which corresponds, respectively, to water imbibition of primary pores and secondary pores. The imbibition rate of secondary pores is significantly larger than that of primary pores, indicating that the generation of new fractures can greatly accelerate the imbibition rate. Research on the characteristics of water imbibition in hydrate sediments is important for optimizing hydrate production regime and increasing natural gas production.

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 The Impacts of Bedding Strength Parameters on the Micro-Cracking Morphology in Laminated Shale under Uniaxial Compression

2020 ◽  
Vol 10 (16) ◽  
pp. 5496
Author(s):  
Fakai Dou ◽  
Jianguo Wang ◽  
Chunfai Leung
Keyword(s):  
Uniaxial Compression ◽  
Shear Failure ◽  
Critical Role ◽  
Fracture Morphology ◽  
Fracture Network ◽  
Gas Production ◽  
Strength Parameters ◽  
Matrix Cracks ◽  
Shale Formation ◽  
Dominant Matrix

The micro-cracking morphology in laminated shale formation plays a critical role in the enhancement of shale gas production, but the impacts of bedding strength parameters on micro-cracking morphology have not been well understood in laminated shale formation. This paper numerically investigated the initiation and evolution of micro-cracking morphology with bedding strength parameters in laminated shale under uniaxial compression. First, a two-dimensional particle flow model (PFC2D) was established for laminated shale. Then, the micro-mechanical parameters of this model were calibrated using stress-strain curves and final fracture morphology measured in the laboratory. Finally, the impacts of bedding strength parameters on the uniaxial compressive strength (UCS), crack type and the complexity of fracture network were analyzed quantitatively. Numerical simulation results indicate that the UCS of shale varies linearly with the bedding strength, especially when the shear failure of beddings is dominant. Matrix cracks mainly depend on bedding strength, while the generation of tensile cracks is determined by the shear-to-tensile strength ratio of beddings (STR). The shale with a higher STR is likely to produce a more complex fracture network. Therefore, the bedding strength parameters should be carefully evaluated when the initiation and evolution of micro-cracking morphology in laminated shale formation are simulated.

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.

Numerical Simulation of Stimulated Volume in Low-Permeability Reservoir

2013 ◽  
Vol 734-737 ◽  
pp. 1415-1419
Author(s):  
Zhen Yu Liu ◽  
Tian Tian Cai ◽  
Hu Zhen Wang ◽  
Cheng Yu Zhang
Keyword(s):  
Numerical Simulation ◽  
Reference Value ◽  
Simulation Method ◽  
Fracture Network ◽  
Gas Production ◽  
Low Permeability ◽  
Flow State ◽  
Low Permeability Reservoir ◽  
Complex Fracture ◽  
Low Permeability Reservoirs

There is an increasing focus on the effective methods to develop low-permeability reservoirs, especially for ultra-low permeability reservoirs. It is hard to achieve the expected stimulation effect only on the traditional single fracturing, because of the poor supply ability from the matrix to fracture in low-permeability reservoirs. Volume stimulating to reservoir, achieving short distance from matrix to fracture because of producing fracture network. So the volume fracturing technology proposed for increasing oil or gas production, this technology is suitable for low porosity and low permeability reservoir. The conventional simulation method can't describe the complex fracture network accurately,but this paper established hydraulic fracturing complex fracture model based on the finite element numerical simulation method , making the simulated complex fracture more close to the real description,it can accurately describe the flow state in the reservoir and cracks.It has an important reference value to the low permeability reservoirs.

scholarly journals Well Screen and Optimal Time of Refracturing: A Barnett Shale Well

2013 ◽  
Vol 2013 ◽  
pp. 1-10 ◽  
Author(s):  
Shayan Tavassoli ◽  
Wei Yu ◽  
Farzam Javadpour ◽  
Kamy Sepehrnoori
Keyword(s):  
Numerical Simulation ◽  
Shale Gas ◽  
Fracture Network ◽  
Gas Production ◽  
Sensitivity Analyses ◽  
Optimal Time ◽  
Barnett Shale ◽  
Vast Number ◽  
Access To Data ◽  
The Right

Gas-production decline in hydraulically fractured wells in shale formations necessitates refracturing. However, the vast number of wells in a field makes selection of the right well challenging. Additionally, the success of a refracturing job depends on the time to refracture a shale-gas well during its production life. In this paper we present a numerical simulation approach to development of a methodology for screening a well and to determine the optimal time of refracturing. We implemented our methodology for a well in the Barnett Shale, where we had access to data. The success of a refracturing job depends on reservoir characteristics and the initial induced fracture network. Systematic sensitivity analyses were performed so that the characteristics of a shale-gas horizontal well could be specified as to the possibility of its candidacy for a successful refracturing job. Different refracturing scenarios must be studied in detail so that the optimal design might be determined. Given the studied trends and implications for a production indicator, the optimal time for refracturing can then be suggested for the studied well. Numerical-simulation results indicate significant improvement (on the order of 30%) in estimated ultimate recovery (EUR) after refracturing, given presented screen criteria and optimal-time selection.

The Fracture Network Inversion Based on Gas Production Profile

2019 ◽  
Author(s):  
Lidong Mi ◽  
Bicheng Yan ◽  
Qianjun Liu ◽  
Zongxiao Ren
Keyword(s):  
Fracture Network ◽  
Gas Production

Pseudo-probabilistic identification of fracture network in seismic clouds driven by source parameters

2020 ◽  
Vol 223 (3) ◽  
pp. 2066-2084
Author(s):  
Rike Koepke ◽  
Emmanuel Gaucher ◽  
Thomas Kohl
Keyword(s):  
Source Parameters ◽  
Synthetic Data ◽  
Fracture Network ◽  
Gas Production ◽  
Minimum Size ◽  
Seismic Events ◽  
Data Sets ◽  
Weighting Functions ◽  
Hydraulic Stimulation ◽  
Rupture Plane

SUMMARY Fracture networks in underground reservoirs are important pathways for fluid flow and can therefore be a deciding factor in the development of such reservoirs for geothermal energy, oil and gas production or underground storage. Yet, they are difficult to characterize since they usually cannot be directly accessed. We propose a new method to compute the likelihood of having a fracture at a given location from induced seismic events and their source parameters. The result takes the form of a so-called pseudo-probabilistic fracture network (PPFN). In addition to the hypocentres of the seismic events used to image the fracture network, their magnitudes and focal mechanisms are also taken into account, thus keeping a closer link with the geophysical properties of the rupture and therefore the geology of the reservoir. The basic principle of the PPFN is to estimate the connectivity between any spatial position in the cloud and the seismic events. This is done by applying weighting functions depending on the distance between a seismic event and any location, the minimum size of the rupture plane derived from the event magnitude, and the orientation of the rupture plane provided by the focal mechanism. The PPFN is first tested on a set of synthetic data sets to validate the approach. Then, it is applied to the seismic cloud induced by the deep hydraulic stimulation of the well GPK2 of the enhanced geothermal site of Soultz-sous-Forêts (France). The application on the synthetic data sets shows that the PPFN is able to reproduce fault planes placed in a cloud of randomly distributed events but is sensitive to the free parameters that define the shape of the weighting functions. When these parameters are chosen in accordance with the scale of investigation, that is, the typical size of the structures of interest, the PPFN is able to determine the position, size and orientation of the structure quite precisely. The application of the PPFN to the GPK2 seismic cloud reveals a large prominent fault in the deep-northern part of the seismic cloud, supporting conclusions from previous work, and a minor structure in the southern upper part, which could also be a branch of the main fault.

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