Bessa, Fadila (Occidental Petroleum Corporation) | Sahni, Vinay (Occidental Petroleum Corporation) | Liu, Shunhua (Occidental Petroleum Corporation) | Tan, Jiasen (Occidental Petroleum Corporation) | Frass, Manfred (Occidental Petroleum Corporation) | Kessler, James (Occidental Petroleum Corporation)
Understanding and modeling the interaction between hydraulic fractures and natural fractures is important to predict shale production performance. This paper presents a workflow that incorporates natural fractures, rock properties, and stress regimes to understand fracture behavior during stimulation treatment. The methodology also integrates the predefined discrete fracture network (DFN) and 3D reservoir properties to build a comprehensive hydraulic fracturing model. Heat maps are also generated to help evaluate completion design and well spacing strategies.
Applying the integrated fracture characterization workflow to the study area revealed that the vertical and lateral fracture growth is a function of structural context, stress conditions, and rock mechanical properties. Stimulation parameters, including proppant volume and injection pressures, for one horizontal and six vertical wells were utilized to build a comprehensive fracture network for the study area. The resulting model shows: (a) the stimulation of predefined natural fractures, and (b) the generation of induced fractures in the maximum stress direction associated with re-activation of pre-existing faults and fractures. The modeling results were validated by interwell interference data.
Fractures play an important role in hydrocarbon production from organic-rich shale reservoirs (Gale, et al., 2014). This is evident from the higher than expected production rates typically observed from low-porosity and ultra-low permeability shale rocks. Moreover, many shale outcrops, cores, and image logs show an abundance of natural fractures or fracture traces. This study integrates natural fracture characteristics, directional stresses, and hydraulic fractures to characterize and better comprehend Permian Wolfcamp production performance.
Several factors influence the stimulated rock volume (SRV) geometry during a hydraulic fracturing stimulation treatment. These factors include: structural context, natural fracture networks, rock mechanical properties, lithology, and stress changes associated with tectonic events (Gale et al., 2014; Maity, 2018). Furthermore, natural fracture systems in shales are heterogeneous; they can enhance or reduce formation productivity, augment or diminish rock strength, and may have a tendency to influence hydraulic fracture stimulation (Doe et al., 2013). The flow of stimulation fluid through natural fractures and the generation of hydraulic fractures were modeled in this study.
Objectives and Scope: Natural fractures were observed in core and image logs from the Hydraulic Fracture Test Site (HFTS) in Reagan Co., Texas. This paper provides an analysis of these fractures, including their orientation, size, spatial distribution, and openness.
Methods: We measured kinematic aperture sizes of two sets of sealed, opening-mode natural fractures in a slant core taken through a stimulated volume, and we analyzed the population distribution using cumulative frequency plots. For the spatial organization study, in addition to fractures identified in the slant core, we used data from image logs from three nearby horizontal producing wells. The spatial organization of fractures was investigated using our statistical method, Normalized Correlation Count (NCC), and by calculating the Coefficient of Variation, Cv, which is a measure of clustering.
Results: In the slant core 197 Set 1 (NE-SW) fractures are present (154 kinematic apertures measured), and there are 112 Set 2 (WNW-ESE) fractures (62 measured). The aperture-size distribution for Set 1 fractures follows a negative-exponential function, whereas Set 2 fractures follow a weak power-law. Only two fractures, both in Set 1 and ~ 1 mm wide, were open in the subsurface, although many more are now parted, mostly in Set 2. Linear intensity, P10, for measured fractures ≥1 mm wide is 0.01 frac/ft (Set 1) and 0.006 frac/ft (Set 2). Both natural fracture sets in an FMI image log from a nearby well have spatial arrangement patterns of regularly-spaced fractal clusters and Cv greater than 3 (3.22 to 4.05). Fracture cluster widths are 100–200 m, and cluster spacings range from 350–600 m. Fractures in COI image logs in two other wells have lower Cv (1.59 to 2.32). Both sets in the 6U well and Set 1 in the 6M well show elevated intensity along the middle section of the well and NCC indicates broad, but weak non-fractal clustering, likely related to lithological control of fracture growth. In the slant core Upper Wolfcamp Set 1 fractures are indistinguishable from random; Set 2 show a log-periodic clustering but with Cv less than 2.
Significance: Incorporation of Discrete Fracture Networks (DFN's) into hydraulic fracture modeling and reservoir simulation requires high-quality natural fracture data from image logs and core. This paper provides such data and provides information on natural-hydraulic fracture interaction at the HFTS site.
Jiang, Li-Wei (PetroChina Zhejiang Oilfield Company) | He, Yong (PetroChina Zhejiang Oilfield Company) | Shu, Dong-Chu (PetroChina Zhejiang Oilfield Company) | Niu, Wei (PetroChina Zhejiang Oilfield Company) | Pan, Feng (Schlumberger) | Wang, Yue (Schlumberger) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger) | Tang, Yu (PetroChina Southwest Oil and Gas Company)
Most bedding-parallel fractures in the WuFengLongMaxi Formation, SiChuan basin, are calcite filled and commonly show slickensides, which features characterize bedding-parallel shear fractures. Such fractures can serve as flow channels and storage spaces in gas shale reservoirs. However, little is known about their size and spatial distribution, the relationship of their permeability to the confining stress, and any relationship with porosity. Knowing these relationships may contribute to understanding the role of bedding-parallel shear fractures in shale gas enrichment.
Bedding-parallel shear fractures were measured from core and image logs from the WuFeng-LongMaxi Formation, southern SiChuan basin, supplemented with stress-dependent permeability experimental data and nuclear magnetic resonance (NMR) logs from the same wells. Core and image logs were used to characterize the spatial organization of the fractures. A stress-dependent permeability experiment was proposed to investigate the fracture permeability response to changes in confining stress. The effect of the fractures on porosity was examined in terms of the macroporous component reflected by the NMR T2 relaxation; macropores are more likely to be preserved in gas-rich shale. Study of 27 wells spanning 100 km west-east across the southern SiChuan basin revealed the aperture size of bedding-parallel shear fractures ranges from 1 cm to 50 cm. In most wells, the fractures are much more intense in organic-rich intervals, which have low elastic modulus compared to the overlying nonorganic shale and underlying stiff limestone. The stress-dependent permeability experiment suggests that permeability in samples with the fractures is two to three orders of magnitude larger than in samples without fractures under the same confining stress. Fracture permeability decreases exponentially until the confining stress reaches 25 MPa. NMR analysis indicates that the macroporous component has an inverse relationship with the intensity of bedding-parallel shear fractures.
This paper is a companion to URTeC 2670034, “Sampling a Stimulated Rock Volume: An Eagle Ford Example.” That paper detailed the nature of the stimulated rock volume adjacent to a hydraulically fractured horizontal well. It demonstrated that hydraulic fractures are far reaching and abundant but quite variably distributed spatially; the presence of well propped fractures beyond 100 feet of the stimulated well appeared negligible.
The present paper reconciles the production performance of the central pilot well with far-field pressure monitor data to characterize the drained rock volume (DRV). Central to the stimulated reservoir description is the integration of data from core, image logs, proppant tracer, distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and pressure which shows that not all hydraulic fractures are created equal. Principal and secondary hydraulic fractures are identified based on the correlation between image log interpreted fracture aperture and the far-field pressure data. Analysis of distributed temperature data during the completion and warm back period is furthermore used to infer fracture connectivity to the well. A highly fractured near well region between clusters is concluded. A novel data-driven reservoir model is constructed wherein the key interpretations are consistently integrated. Production, bottom hole pressure, and far-field pressure data from 14 pressure monitoring stations are history matched. A heterogeneous drained rock volume is predicted. The integrated model is compared to common production history matched planar fracture models to assess the potential impacts on cluster spacing, well spacing, and well stacking decisions.
In 2017 ConocoPhillips reported (Raterman, et al., 2018) on a pilot conducted in the Eagle Ford (EF) shale that was internally referred to as the “SRV pilot”. The original paper dealt primarily with the execution of the pilot and the attendant description of hydraulic and natural fractures within the