scholarly journals Fold-Related Fracture Distribution in Neogene, Triassic, and Jurassic Sandstone Outcrops, Northern Margin of the Tarim Basin, China: Guides to Deformation in Ultradeep Tight Sandstone Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Junpeng Wang ◽  
Lianbo Zeng ◽  
Xianzhang Yang ◽  
Chun Liu ◽  
Ke Wang ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Gas Production ◽  
Shear Mode ◽  
Fracture Density ◽  
Tight Sandstone ◽  
Supply Source ◽  
Northern Margin ◽  
Fracture Patterns ◽  
Fracture Development ◽  
Opening Mode

Abstract Ultradeep (6-8 km depth) low-porosity sandstone oil and gas reservoirs, in the Kuqa thrust belt of Tarim Basin, are an important natural gas supply source of China. Both opening and shear-mode fractures are extremely necessary reservoir elements for gas production in these rocks but are challenging to characterize with sparse core and well log observations. Here, we use outcrops of some of the same units from four exposed folds to describe fracture types and patterns. These four folds have a range of shapes that are representative of folds at depth. At the Dongq, Kuqa, Misib, and Tuger anticlines, we analyzed fracture type, cross-cutting and abutting relations, density, spatial arrangement, kinematic aperture, orientation, and mineral fill. One-dimensional inventories, field sketches, photographs, and LiDAR imagery documented fracture patterns. Most dips of all fractures shown everywhere on the fold are greater than 60 degrees (over 50%). Fracture kinematic apertures are 3 mm to ~6 mm, and fracture density is 0.5 traces/m to ~1.5 traces/m. All fractures are divided into shear mode (or small faults) and opening mode. Shear-mode fractures, with high dips that strike N-S, mutually crosswise arranged with intersection angles of 30-60 degrees, are found extensively on the flanks of these folds. In contrast, most opening-mode fractures strike E-W, are arranged parallel to each other, and are localized in fold hinges. Besides, exposed folds (reservoir analogues, figure 1) in a proximal (hinterland, Tuger and Misib) position have fracture abundance distributions and aperture size patterns compatible with fold-related fracture development whereas distal (basinward, Kuqa and Dongq) folds lack this correlation, but patterns in distal folds might be explained by overprinted effects of lithological heterogeneity on fracture abundance or the effects of nearby faults. The positive correlation between fold-related strain and fracture spatial distribution in the northern (proximal) folds permitted inference of fracture patterns in deep wells.

Deep structure at northern margin of Tarim Basin

2008 ◽  
Vol 53 (10) ◽  
pp. 1544-1554 ◽  
Author(s):  
JunMeng Zhao ◽  
HongGang Cheng ◽  
ShunPing Pei ◽  
HongBing Liu ◽  
JianShi Zhang ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Deep Structure ◽  
Northern Margin

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.

Controlled Frac Height Growth Technique to Avoid Contacting Water-Bearing Layer

2022 ◽  
Author(s):  
Hashem Al-Obaid ◽  
Sultan A. Asel ◽  
Jon Hansen ◽  
Rio Wijaya
Keyword(s):  
Hydraulic Fracturing ◽  
Height Growth ◽  
Gas Production ◽  
Stress Profile ◽  
Water Production ◽  
Tight Sandstone ◽  
Water Contact ◽  
Vertical Fracture ◽  
Vertical Growth ◽  
Water Zone

Abstract Many techniques have been used to model, diagnose and detect fracture dimension and propagation during hydraulic fracturing. Diagnosing fracture dimension growth vs time is of paramount importance to reach the desired geometry to maximize hydrocarbon production potential and prevent contacting undesired fluid zones. The study presented here describes a technique implemented to control vertical fracture growth in a tight sandstone formation being stimulated near a water zone. This gas well was completed vertically as openhole with Multi- Stage Fracturing (MSF). Pre-Fracturing diagnostic tests in combination with high-resolution temperature logs provided evidence of vertical fracture height growth downward toward water zone. Pre-fracturing flowback indicated water presence that was confirmed by lab test. Several actions were taken to mitigate fracture vertical growth during the placement of main treatment. An artificial barrier with proppant was placed in the lower zone of the reservoir before main fracturing execution. The rate and viscosity of fracturing fluids were also adjusted to control the net pressure aiming to enhance fracture length into the reservoir. The redesigned proppant fracturing job was placed into the formation as planned. Production results showed the effectiveness of the artificial lower barrier placed to prevent fracture vertical growth down into the water zone. Noise log consists of Sonic Noise Log (SNL) and High Precision Temperature (HPT) was performed. The log analysis indicated that two major fractures were initiated away from water-bearing zone with minimum water production. Additionally, in- situ minimum stress profile indicated no enough contrast between layers to help confine fracture into the targeted reservoir. Commercial gas production was achieved after applying this stimulation technique while keeping water production rate controlled within the desired range. The approach described in this paper to optimize gas production in tight formation with nearby water contact during hydraulic fracturing treatments has been applied with a significant improvement in well production. This will serve as reference for future intervention under same challenging completion conditions.

scholarly journals Indentation of the Pamirs with respect to the northern margin of Tibet: Constraints from the Tarim basin sedimentary record

Tectonics ◽  
2016 ◽  
Vol 35 (10) ◽  
pp. 2345-2369 ◽  
Author(s):  
Tamsin Blayney ◽  
Yani Najman ◽  
Guillaume Dupont‐Nivet ◽  
Andrew Carter ◽  
Ian Millar ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Sedimentary Record ◽  
Northern Margin

Factors influencing fractures networks within Permian shale intervals in the Cooper Basin, South Australia

2012 ◽  
Vol 52 (1) ◽  
pp. 213 ◽  
Author(s):  
Hani Abul Khair ◽  
Guillaume Backé ◽  
Rosalind King ◽  
Simon Holford ◽  
Mark Tingay ◽  
...  
Keyword(s):  
Compressive Strength ◽  
Positive Curvature ◽  
Seismic Attributes ◽  
Gas Production ◽  
Natural Fracture ◽  
Seismic Survey ◽  
Critical Parameters ◽  
Fracture Density ◽  
High Fracture ◽  
Cooper Basin

The future success of both enhanced (engineered) geothermal systems and shale gas production is reliant on the development of reservoir stimulation strategies that suit the local geo-mechanical conditions of the prospects. The orientation and nature of the in-situ stress field and pre-existing natural fracture networks in the reservoir are among the critical parameters that will control the quality of the stimulation program. This study provides a detailed investigation into the nature and origin of natural fractures in the area covered by the Moomba–Big Lake 3D seismic survey, in the southwest termination of the Nappamerri Trough of the Cooper Basin. These fractures are imaged by both borehole image logs and complex multi-traces seismic attributes (e.g. dip-steered most positive curvature and dip-steered similarity), are pervasive throughout the cube, and exhibit a relatively consistent northwest–southeast orientation. Horizon extraction of the seismic attributes reveal a strong variation in the spatial distribution of the fractures. In the acreage of interest, fracture density is at its highest in the vicinity of faults and on top of tight antiforms. This study also suggests a good correlation between high fracture density and high gamma ray values. The correlation between high fracture density and shale content is somewhat counterintuitive, as shale is expected to have a higher tensile and compressive strengths at shallow depths and typically contain fewer fractures (Lin, 1983). At large depths, however—and due to sandstone diagenesis and cementation—shale has lower tensile and compressive strength than sandstone and is expected to be more fractured (Lin, 1983). A similar correlation has been noted in other Australian Basins (e.g. Northern Perth Basin). Diagenetic effects, pore pressure, stiffness, variations in tensile versus compressive strength of the shale and the sandstone may explain this disparity.

Depth-dependent analysis of fracture patterns inferred from image logs and cores in crystalline rocks

2020 ◽  
Author(s):  
Mohammad Javad Afshari Moein
Keyword(s):  
Spatial Distribution ◽  
Correlation Dimension ◽  
Numerical Models ◽  
Fracture Network ◽  
Crystalline Rocks ◽  
Geothermal System ◽  
Upper Rhine Graben ◽  
Enhanced Geothermal System ◽  
Fracture Density ◽  
Fracture Patterns

<p>Enhanced Geothermal System (EGS) development requires an accurate fracture network characterization. The knowledge on the fracture network is fundamental for setting up numerical models to simulate the activated processes in hydraulic stimulation experiments. However, direct measurement of fracture network properties at great depth is limited to the data from exploration wells. Geophysical logging techniques and continuous coring, if available, provide the location and orientation of fractures that intersect the wellbore. The statistical parameters derived from borehole datasets (either from image logs or cores) constrain stochastic realizations of the rock mass, known as Discrete Fracture Network (DFN) models. However, accurate parametrization of DFN models requires sufficient knowledge on the depth-dependent spatial distribution of fractures in the earth’s crust.</p><p>This analysis includes a unique collection of fracture datasets from six deep (i.e. 2-5 km depth) boreholes drilled into crystalline basement rocks at the same tectonic settings. All the wells were drilled in the Upper Rhine Graben in Soultz-sous-Forêts Enhanced Geothermal System, France, except the well that was drilled in Basel geothermal project, Switzerland. The datasets included both borehole image logs and core samples, which have a higher resolution. Two-point correlation function was selected to characterize the power-law scaling of fracture patterns. The correlation dimension of spatial patterns showed no systematic variations with depth at one standard deviation level of uncertainty in moving windows of sufficient number of fractures along any of the boreholes. This implies that a single correlation dimension is sufficient to address the global scaling properties of the fractures in crystalline rocks. One could also anticipate the spatial distribution of deeper reservoir conditions from shallower datasets. On the contrary, the fracture density showed some variations with depth that are sometimes consistent with changes in lithology and geological settings at the time of fracture formation.</p>

A Comprehensive Approach for Fracability Evaluation in Naturally Fractured Sandstone Reservoirs

2018 ◽  
Author(s):  
Zhaozhong Yang ◽  
Rui He ◽  
Xiaogang Li ◽  
Zhanling Li ◽  
Ziyuan Liu
Keyword(s):  
Large Scale ◽  
Evaluation Model ◽  
Gas Production ◽  
Natural Fracture ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Related Factors ◽  
Gas Field ◽  
Tight Gas Reservoir ◽  
Naturally Fractured

The tight sandstone gas reservoir in southern Songliao Basin is naturally fractured and is characterized by its low porosity and permeability. Large-scale hydraulic fracturing is the most effective way to develop this tight gas reservoir. Quantitative evaluation of fracability is essential for optimizing a fracturing reservoir. In this study, as many as ten fracability-related factors, particularly mechanical brittleness, mineral brittleness, cohesion, internal friction angle, unconfined compressive strength (UCS), natural fracture, Model-I toughness, Model-II toughness, horizontal stress difference, and fracture barrier were obtained from a series of petrophysical and geomechanical experiments are analyzed. Taking these influencing factors into consideration, a modified comprehensive evaluation model is proposed based on the analytic hierarchy process (AHP). Both a transfer matrix and a fuzzy matrix were introduced into this model. The fracability evaluation of four reservoir intervals in Jinshan gas field was analyzed. Field fracturing tests were conducted to verify the efficiency and accuracy of the proposed evaluation model. Results showed that gas production is higher and more stable in the reservoir interval with better fracability. The field test data coincides with the results of the proposed evaluation model.

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