scholarly journals Numerical Investigation of Fracture Compressibility and Uncertainty on Water-Loss and Production Performance in Tight Oil Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (7) ◽  
pp. 1189 ◽  
Author(s):  
Kai Liao ◽  
Shicheng Zhang ◽  
Xinfang Ma ◽  
Yushi Zou
Keyword(s):  
Water Loss ◽  
Fracture Network ◽  
Production Performance ◽  
Oil Reservoirs ◽  
Natural Fracture ◽  
Tight Oil ◽  
Fracture Density ◽  
Breakthrough Time ◽  
Complex Fracture ◽  
Fracture Closure

Multi-stage hydraulic fracturing along with horizontal wells are widely used to create complex fracture networks in tight oil reservoirs. Analysis of field flowback data shows that most of the fracturing fluids are contained in a complex fracture network, and fracture-closure is the main driving mechanism during early clean up. At present, the related fracture parameters cannot be accurately obtained, so it is necessary to study the impacts of fracture compressibility and uncertainty on water-loss and the subsequent production performance. A series of mechanistic models are established by considering stress-dependent porosity and permeability. The impacts of fracture uncertainties, such as natural fracture density, proppant distribution, and natural fracture heterogeneity on flowback and productivity are quantitatively assessed. Results indicate that considering fracture closure during flowback can promote water imbibition into the matrix and delay the oil breakthrough time compared with ignoring fracture closure. With the increase of natural fracture density, oil breakthrough time is advanced, and more water is retained underground. When natural fractures connected with hydraulic fractures are propped, well productivity will be enhanced, but proppant embedment can cause a loss of oil production. Additionally, the fracture network with more heterogeneity will lead to the lower flowback rate, which presents an insight in the role of fractures in water-loss.

scholarly journals Study on Deliverability Evaluation of Staged Fractured Horizontal Wells in Tight Oil Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5857
Author(s):  
Siyu Liu ◽  
Shengchun Xiong ◽  
Dingwei Weng ◽  
Peng Song ◽  
Rou Chen ◽  
...  
Keyword(s):  
Network Structure ◽  
Horizontal Wells ◽  
Fracture Network ◽  
Stress Sensitivity ◽  
Oil Reservoirs ◽  
Tight Oil ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Tight Oil Reservoirs ◽  
Fractured Horizontal Wells

At present, the existing deliverability evaluation models mainly consider the impact of specific factors on production, and the description of the complex fracture network structure primarily remains at the stage of an ideal dual-pore medium with uniform distribution. However, this cannot reflect the actual fracture network structure and fluid flow law of fractured horizontal wells. Thus, in this paper, a non-uniform fracture network structure is proposed considering the influence of the threshold pressure gradient and stress sensitivity characteristics on the production performance of horizontal wells. The stress sensitivity and the fractal theory are combined to characterize the permeability of the complex fracture network, and a three-zone compound unsteady deliverability model for staged fractured horizontal wells in tight oil reservoirs is successfully developed. Laplace transformation, perturbation theory, and numerical inversion are applied to obtain the semi-analytical solution of the proposed deliverability model. The reliability and accuracy of the analytical solution are verified by the classical tri-linear flow model and an oil field example. The effects of related influential parameters on the production of horizontal wells are analyzed. The deliverability evaluation method proposed in this paper can provide a theoretical basis for formulating rational development technology policies for tight oil reservoirs.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

The Stratigraphy of Pre-Tertiary Economic Basement in South Jambi B Block, South Sumatra Basin

2021 ◽  
Keyword(s):  
Significant Contribution ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Density ◽  
The South ◽  
The North ◽  
Fracture Intensity ◽  
Parent Rocks ◽  
Major Fault ◽  
Essential Function

As one of the most promising plays, the Pre-Tertiary basement play holds a significant contribution to the latest success of exploration efforts in the South Sumatra Basin, which then includes the South Jambi B Block. Yet, the natures of the Pre-Tertiary unit in this block remains unsolved. Lithology variability, spatial irregularity, genetic ambiguity, and different reservoir characteristic are indeterminate subjects in the block are the main focus here. The ultimate goals of this study are to better characterize the unit and gain more understanding in calibrating the remaining potential. Based on this study, The Pre-Tertiary units are mainly originated from layered marine-deltaic sedimentary parent rocks with carbonate, intruded by spotty granite where the concentration of each parent rocks varies at the north, the middle, and southern part. Secondly, both lithology heterogeneity and natural fracture density create distinctive reservoir deliverability at each structure. The storage concept is an essential function of natural fracture intensity and diversity, supported by matrix porosity that varies across a different succession of lithology. Lastly, this study observes that major fault orientation is essential in constructing the fracture network. Evidence from several image logs across the study area concludes that most of the interpreted fractures are oriented subparallel to the major faults. The northern belt area is relatively affected by NW-SE Neogene structure, where the southern area is recognized to be affected by both Neogene compression and pre-existing Paleogene structure.

Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

2015 ◽  
Vol 3 (3) ◽  
pp. SU17-SU31 ◽  
Author(s):  
Jian Huang ◽  
Reza Safari ◽  
Uno Mutlu ◽  
Kevin Burns ◽  
Ingo Geldmacher ◽  
...  
Keyword(s):  
Sensitivity Analysis ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Natural Fracture ◽  
Design Parameters ◽  
Reservoir Area ◽  
Complex Fracture ◽  
Model Complex ◽  
Fracture Interaction ◽  
The Impact

Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.

scholarly journals Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries

2016 ◽  
Vol 6 (1) ◽  
Author(s):  
Pavel Zuloaga-Molero ◽  
Wei Yu ◽  
Yifei Xu ◽  
Kamy Sepehrnoori ◽  
Baozhen Li
Keyword(s):  
Simulation Study ◽  
Oil Reservoirs ◽  
Tight Oil ◽  
Complex Fracture ◽  
Co2 Eor ◽  
Tight Oil Reservoirs

scholarly journals Performance Optimization of CO2 Huff-n-Puff for Multifractured Horizontal Wells in Tight Oil Reservoirs

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-13
Author(s):  
Mingqiang Hao ◽  
Songlin Liao ◽  
Guangming Yu ◽  
Xinhui Lei ◽  
Yong Tang
Keyword(s):  
Crude Oil ◽  
Horizontal Wells ◽  
Production Performance ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Tight Oil ◽  
Production Parameters ◽  
Sensitivity Factors ◽  
Tight Oil Reservoirs ◽  
The Impact

In this paper, the sensitivity factors of CO2 huff-n-puff for multifractured horizontal wells (MFHWs) in tight oil reservoirs were investigated through an experimental test and numerical simulation. The pressure-volume-temperature (PVT) experiment and the slim tube experiment are used to understand the interaction mechanism between CO2 and crude oil, and the minimum miscibility pressure (MMP) of the CO2-crude oil system is 17 MPa. The single-well model was firstly established to analyze the sensitivity factors on production performance of MFHWs by using CO2 huff-n-puff. The controlling factors of CO2 huff-n-puff for MFHWs in tight oil reservoirs were divided into three categories (i.e., reservoir parameters, well parameters, and injection-production parameters), and the impact of individual parameter on well performance was discussed in detail. The range of reservoir parameters suitable for CO2 huff-n-puff of MFHWs is obtained. The reservoir permeability is from 0.1 mD to 1 mD, the reservoir thickness changes from 10 m to 30 m, and the reservoir porosity is from 7% to 12%. Based on the reservoir parameters of the target reservoir, the reasonable well and fracture parameters are obtained. The sensitivity intensity was followed by the horizontal well length, fracture conductivity, fracture spacing, and fracture half-length. CO2 injection-production parameters are further optimized, and the sensitivity intensity was followed by the single-cycle cumulative CO2 injection rate, the soaking time, the injection rates, and the production rates. It provides a reference for parameter optimization of CO2 huff-n-puff for MFHWs in tight oil reservoirs.

scholarly journals Experimental study on fracture propagation of hydraulic fracturing for tight sandstone outcrop

2020 ◽  
pp. 014459872097251
Author(s):  
Wenguang Duan ◽  
Baojiang Sun ◽  
Deng Pan ◽  
Tao Wang ◽  
Tiankui Guo ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Variable Rate ◽  
Tight Sandstone ◽  
Complex Fracture ◽  
Hf Propagation ◽  
Complex Fracture Network

The tight sandstone oil reservoirs characterized by the low porosity and permeability must be hydraulically fractured to obtain the commercial production. Nevertheless, the post-fracturing production of tight oil reservoirs is not always satisfactory. The influence mechanism of various factors on the fracture propagation in the tight oil reservoirs needs further investigation to provide an optimized fracturing plan, obtain an expected fracture morphology and increase the oil productivity. Thus, the horizontal well fracturing simulations were carried out in a large-scale true tri-axial test system with the samples from the Upper Triassic Yanchang Fm tight sandstone outcrops in Yanchang County, Shaanxi, China, and the results were compared with those of fracturing simulations of the shale outcrop in the 5th member of Xujiahe Fm (abbreviated as the Xu 5th Member) in the Sichuan Basin. The effects of the natural fracture (NF) development degree, horizontal in-situ stress conditions, fracturing treatment parameters, etc. on the hydraulic fracture (HF) propagation morphology were investigated. The results show that conventional hydraulic fracturing of the tight sandstone without NFs only produces a single double-wing primary fracture. The fracture propagation path in the shale or the tight sandstone with developed NFs is controlled by the high horizontal differential stress. The higher stress difference (<12MPa) facilitates forming the complex fracture network. It is recommended to fracture the reservoir with developed NFs by injecting the high-viscosity guar gum firstly and the low-viscosity slick water then to increase the SRV. The low-to-high variable rate fracturing method is recommended as the low injection rate facilitates the fracturing fluid filtration into the NF system, and the high injection rate increases the net pressure within the fracture. The dual-horizontal well simultaneous fracturing increases the HF density and enhances the HF complexity in the reservoir, and significantly increases the possibility of forming the complex fracture network. The fracturing pressure curves reflect the fracture propagation status. According to statistical analysis, the fracturing curves are divided into types corresponding to multi-bedding plane (BP) opening, single fracture generation, multi-fracture propagation under variable rate fracturing, and forming of the fracture network through communicating the HF with NFs. The results provide a reference for the study of the HF propagation mechanism and the fracturing design in the tight sandstone reservoirs.

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