Natural fractures in the Spraberry Formation, Midland basin, Texas: The effects of mechanical stratigraphy on fracture variability and reservoir behavior

We characterize relationships between stratigraphy and natural fractures in outcrops of Mesozoic strata that rim the San Juan Basin in New Mexico and Colorado. These outcrops expose fluvial and shallow-marine siliciclastic deposits and calcareous mudstones deposited in a distal marine setting. We focus primarily on a regionally extensive fracture set formed during the Eocene to minimize localized tectonic effects on fracture development. Where possible, we supplement our observations with wireline log- or laboratory-derived measurements of rock properties. Our goals are twofold: 1) to illustrate how direct integration of data and concepts from stratigraphy and structural geology can lead to better fracture characterization, and 2) to develop thought processes that will stimulate new exploration and development strategies. Genetic beds form one scale of stratification in the outcrops we describe. For example, sandstone beds can be arranged into coarsening and thickening upward successions that are the depositional record of shoreline progradation. In fluvial settings, cm- to dm-scale sandstone beds can also be part of m-scale single-storey channel complexes that, themselves, can be arranged into amalgamated channel complexes 10s of m thick. In these and other settings, it is important to distinguish between beds and features that can be defined via wireline logs because it is the former (cm- to dm-scale) that are usually the primary control the distribution of natural fractures. The extension fractures we describe are typically bed-bound, with bedding being defined by lithology contrasts and the associated changes in elastic properties. Fracture spacing distributions are typically lognormal with average spacing being less than bed thickness. Although mechanical bedding and depositional bedding are commonly the same, diagenesis can cut across bed boundaries and complicate this relationship, especially where lithologic contrasts are small. Deposits from similar depositional environments which undergo different diagenetic histories can have substantially different mechanical properties and therefore deform differently in response to similar imposed stresses.

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Quantitative Prediction of Natural Fractures in Shale Oil Reservoirs

Geofluids ◽

10.1155/2021/5571855 ◽

2021 ◽

Vol 2021 ◽

pp. 1-15

Author(s):

Lei Gong ◽

Shuai Gao ◽

Bo Liu ◽

Jianguo Yang ◽

Xiaofei Fu ◽

...

Keyword(s):

Oil Reservoirs ◽

Quantitative Prediction ◽

Shale Oil ◽

Natural Fractures ◽

Power Law Distribution ◽

Key Factors ◽

Factors Affecting ◽

Mechanical Stratigraphy ◽

Fracture Distribution ◽

Shale Oil Reservoirs

Natural fractures are the key factors controlling the enrichment of shale oil. It is of great significance to clarify the distribution of natural fractures to guide the selection of sweet spots for shale oil. Taking the Qing-1 Member shale oil reservoir in the northern Songliao Basin, China as an example, a new method considering the factors affecting fracture distribution was proposed to quantitatively predict the structural fractures. And the effect of natural fractures on shale oil enrichment was discussed. Firstly, the types and characteristics of fractures in shale oil reservoirs are characterized by using core and outcrop data. Combined with the experimental analysis, the influences of fault, mechanical stratigraphy, mineral composition and content, TOC, and overpressure on fracture intensity were clarified. Then, the number and density of fractures are quantitatively predicted according to the power-law distribution of fault length. Next, geomechanical simulation and fracture prediction were carried out on the model which was established with comprehensive consideration of the influencing factors of fracture distribution. Finally, the fracture distribution is evaluated comprehensively based on above prediction. The prediction results in this work are consistent with the core measurements.

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Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Energies ◽

10.3390/en12203852 ◽

2019 ◽

Vol 12 (20) ◽

pp. 3852 ◽

Cited By ~ 4

Author(s):

Kiran Nandlal ◽

Ruud Weijermars

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Fractured Reservoirs ◽

Test Site ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Natural Fractures ◽

Midland Basin ◽

Drained Rock Volume ◽

The Impact

Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates.

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Natural Fractures, Fracture Facies, and Their Applications in the Well Completion – Case Studies from the Permian Wolfcamp Formation, Midland Basin, West Texas, USA

Proceedings of the 6th Unconventional Resources Technology Conference ◽

10.15530/urtec-2018-2902102 ◽

2018 ◽

Author(s):

Bingjian Li ◽

Lauren Robinson

Keyword(s):

Case Studies ◽

Natural Fractures ◽

Midland Basin ◽

Well Completion ◽

West Texas

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Natural Fractures in Carbonate Basement Reservoirs of the Jizhong Sub-Basin, Bohai Bay Basin, China: Key Aspects Favoring Oil Production

Energies ◽

10.3390/en13184635 ◽

2020 ◽

Vol 13 (18) ◽

pp. 4635

Author(s):

Guoping Liu ◽

Lianbo Zeng ◽

Chunyuan Han ◽

Mehdi Ostadhassan ◽

Wenya Lyu ◽

...

Keyword(s):

Oil Production ◽

Bohai Bay ◽

Well Testing ◽

Natural Fractures ◽

Lower Paleozoic ◽

Thin Sections ◽

Mechanical Stratigraphy ◽

Porosity And Permeability ◽

Basement Reservoirs ◽

Dip Angle

Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections from the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin, natural fractures are found to be abundant in genetic types (tectonic, pressure-solution, and dissolution) in these reservoirs. Tectonic fractures are dominant in such reservoirs, and lithology, mechanical stratigraphy, and faults are major influencing factors for the development of fractures. Dolostones with higher dolomite content are more likely to have tectonic fractures than limestones with higher calcite content. Most tectonic fractures are developed inside mechanical units and terminate at the unit interface at nearly perpendicular or high angles. Also, where a thinner mechanical unit is observed, tectonic fractures are more frequent with a small height. Furthermore, the dominant direction of tectonic fractures is sub-parallel to the fault direction or oblique at a small angle. In addition, integrating diverse characteristics of opening-mode fractures and well-testing data with oil production shows that, in perforated intervals where dolostone and limestone are interstratified or dolostone is the main lithologic composition, fractures are developed well, and the oil production is higher. Moreover, fractures with a larger dip angle have bigger apertures and contribute more to oil production. Collectively, this investigation provides a future reference for understanding the importance of natural fractures and their impact on oil production in the carbonate basement reservoirs.

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