scholarly journals Fracture networks in Rotliegend gas reservoirs of the Dutch offshore: implications for reservoir behaviour

2000 ◽  
Vol 79 (1) ◽  
pp. 45-57 ◽  
Author(s):  
B.D.M. Gauthier ◽  
R.C.W.M. Franssen ◽  
S. Drei
Keyword(s):  
Fracture Network ◽  
Development Planning ◽  
Small Scale ◽  
List Type ◽  
Gas Reservoirs ◽  
Positive Role ◽  
Field Development ◽  
Fracture Systems ◽  
Reservoir Flow ◽  
Gas Fields

AbstractFracture systems of Rotliegend gas fields in and at the margins of the northern Broad Fourteens Basin in the Dutch offshore are described in terms of orientation, frequency, origin and type, and in relation to larger-scale structures. First, fracture data collected from core and image logs have been corrected to account for the bias related to the 1-D sampling. Second, these results were integrated with data on fracture cements and diagenesis in order to assess the timing of the fracture network development.On the basis of their regional extent three phases of fracturing and four orientation trends can be distinguished in the basin: (1)at Triassic times and related to early diagenesis and burial, NW-SE to NNW-SSE and NE-SW to ESE-WNW particulate-shear fractures developed;(2)during the Mid-Kimmerian and related to the main burial stage, shear-related and dilational-shear-fault-related fracturing occurred parallel with larger-scale faults;(3)during the Cretaceous and related to uplift, NW-SE and NE-SW joints propagated; a regional joint system developed outside the Jurassic rift basin, preferentially oriented E-W to ESE-WNW; these joints have not been dated accurately.The fault-related shear fractures tend to compartmentalise the reservoirs, whereas the regional joints tend to enhance reservoir flow properties. These fracture systems are thought to play a negative or positive role, respectively, but only in fields with poor reservoir quality. Consequently, in such cases small-scale fractures should be taken into account in field development planning.

scholarly journals Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

2021 ◽  
Author(s):  
Atheer Dheyauldeen ◽  
Omar Al-Fatlawi ◽  
Md Mofazzal Hossain
Keyword(s):  
Transient Flow ◽  
Development Planning ◽  
Main Role ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Field Development ◽  
Drilling Performance ◽  
Well Location ◽  
Infill Drilling ◽  
Tight Formations

AbstractThe main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

scholarly journals Application of Unconventional Seismic Attributes and Unsupervised Machine Learning for the Identification of Fault and Fracture Network

2020 ◽  
Vol 10 (11) ◽  
pp. 3864 ◽  
Author(s):  
Umar Ashraf ◽  
Hucai Zhang ◽  
Aqsa Anees ◽  
Hassan Nasir Mangi ◽  
Muhammad Ali ◽  
...  
Keyword(s):  
Neural Networks ◽  
Median Filter ◽  
Fracture Network ◽  
Structural Features ◽  
Small Scale ◽  
Fracture Density ◽  
Fracture Characterization ◽  
Field Development ◽  
Fracture Length ◽  
Dip Angle

The identification of small scale faults (SSFs) and fractures provides an improved understanding of geologic structural features and can be exploited for future drilling prospects. Conventional SSF and fracture characterization are challenging and time-consuming. Thus, the current study was conducted with the following aims: (a) to provide an effective way of utilizing the seismic data in the absence of image logs and cores for characterizing SSFs and fractures; (b) to present an unconventional way of data conditioning using geostatistical and structural filtering; (c) to provide an advanced workflow through multi-attributes, neural networks, and ant-colony optimization (ACO) for the recognition of fracture networks; and (d) to identify the fault and fracture orientation parameters within the study area. Initially, a steering cube was generated, and a dip-steered median filter (DSMF), a dip-steered diffusion filter (DSDF), and a fault enhancement filter (FEF) were applied to sharpen the discontinuities. Multiple structural attributes were applied and shortlisted, including dip and curvature attributes, filtered and unfiltered similarity attributes, thinned fault likelihood (TFL), fracture density, and fracture proximity. These shortlisted attributes were computed through unsupervised vector quantization (UVQ) neural networks. The results of the UVQ revealed the orientations, locations, and extensions of fractures in the study area. The ACO proved helpful in identifying the fracture parameters such as fracture length, dip angle, azimuth, and surface area. The adopted workflow also revealed a small scale fault which had an NNW–SSE orientation with minor heave and throw. The implemented workflow of structural interpretation is helpful for the field development of the study area and can be applied worldwide in carbonate, sand, coal, and shale gas fields.

Full-Scale Fracture System Analysis of Shale Reservoir and its Petroleum Significance

2021 ◽  
Author(s):  
Xuewen Shi ◽  
Yanming Tong ◽  
Wenping Liu ◽  
Chunduan Zhao ◽  
Jia Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
System Analysis ◽  
Principal Component ◽  
Fracture Network ◽  
Fracture System ◽  
Thrust Faults ◽  
Gas Reservoirs ◽  
Tectonic Event ◽  
Field Development ◽  
Regional Tectonic

Abstract Ascertaining the characteristics of fracture system at different scales integratedly is very important for performing efficient exploration and development activities of specific shale gas reservoirs. In this paper, an area around 250 square kilometers in Changning Block of Sichuan Basin is taken as an example, which belongs to Chinese Shale Gas Development Demonstration Plot. Seismic structural interpretation was performed detailedly based on original seismic amplitude cube and derived edge-detection cubes, and then the technologies of finite element horizon flattening, orthogonal decomposition principal component analysis, seismic discontinuity patch auto-extraction and paleo-stress field inversion were applied, together with the existing regional geological understanding and fracture information in wells, to figure out the staging and grouping of fracture system at seismic scale (i.e., at large and middle scales), at the same time to clarify the regional tectonic evolution and its genetic relationship with fractures at different scales such as the ones revealed by seismic data and cores or image logs. The following conclusions were reached. (a) The tectonic movements affecting the development of fracture system in study interval mainly happened during Yanshanian-Himalayan periods, i.e., 3 compressional tectonic episodes which were nearly in S-N direction in Late Yanshanian period, in NNE-SSW direction in Early Himalayan period, and in NWW-SEE direction in Middle Himalayan period respectively. (b) The Late Yanshanian tectonic event primarily formed long-axis anticlines and synclines, thrust faults and fault-related fractures, all of which were nearly in E-W trending, and fold-related fractures in different directions. (c) The Early Himalayan tectonic event mainly formed genetically related conjugate fracture sets including strike-slip faults and shear fractures both in NNW and NE directions, and transverse extensional fractures. (d) The Middle Himalayan tectonic event chiefly formed thrust faults, and related fractures and folds in NNE~NE direction, and transverse extensional fractures. (e) Furtherly our work demonstrated that such kind of fracture system analysis was of great significance in building discrete fracture network, providing precautionary advice for drilling engineering, and optimizing completion program and field development plan, etc. Hence, integrated fracture system analysis at full scales to reach more meaningful and robust conclusions is essential work for unconventional resources evaluation and characterization.

Dual-Permeability Modeling of Capillary Diversion and Drift Shadow Effects in Unsaturated Fractured Rock

2009 ◽  
Vol 131 (10) ◽  
Author(s):  
Clifford K. Ho ◽  
Bill W. Arnold ◽  
Susan J. Altman
Keyword(s):  
Fractured Rock ◽  
Constitutive Relations ◽  
Water Flux ◽  
Fracture Network ◽  
Small Scale ◽  
Grid Refinement ◽  
Capillary Pressures ◽  
And Behavior ◽  
Capillary Pressure Curves ◽  
The Impact

The drift-shadow effect describes capillary diversion of water flow around a drift or cavity in porous or fractured rock, resulting in lower water flux directly beneath the cavity. This paper presents computational simulations of drift-shadow experiments using dual-permeability models, similar to the models used for performance assessment analyses of flow and seepage in unsaturated fractured tuff at Yucca Mountain. Comparisons were made between the simulations and experimental data from small-scale drift-shadow tests. Results showed that the dual-permeability models captured the salient trends and behavior observed in the experiments, but constitutive relations (e.g., fracture capillary-pressure curves) can significantly affect the simulated results. Lower water flux beneath the drift was observed in both the simulations and tests, and fingerlike flow patterns were seen to exist with lower simulated capillary pressures. The dual-permeability models used in this analysis were capable of simulating these processes. However, features such as irregularities along the top of the drift (e.g., from roof collapse) and heterogeneities in the fracture network may reduce the impact of capillary diversion and drift shadow. An evaluation of different meshes showed that at the grid refinement used, a comparison between orthogonal and unstructured meshes did not result in large differences.

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.

New method for Handling of Infrastructural Constraints for Integrated Modeling in Steady Case

2021 ◽  
Author(s):  
Dmitry Moiseevich Olenchikov
Keyword(s):  
Optimal Solution ◽  
Field Development ◽  
Flow Models ◽  
Second Stage ◽  
Operation Modes ◽  
Reservoir Flow ◽  
Terminal Constraints ◽  
Surface Network ◽  
Two Stages ◽  
And Control

Abstract Recently, more and more reservoir flow models are being extended to integrated ones to consider the influence of the surface network on the field development. A serious numerical problem is the handling of constraints in the form of inequalities. It is especially difficult in combination with optimization and automatic control of well and surface equipment. Traditional numerical methods solve the problem iteratively, choosing the operation modes for network elements. Sometimes solution may violate constraints or not be an optimal. The paper proposes a new flexible and relatively efficient method that allows to reliably handle constraints. The idea is to work with entire set of all possible operation modes according to constraints and control capabilities. Let's call this set an operation modes domain (OMD). The problem is solved in two stages. On the first stage (direct course) the OMD are calculated for all network elements from wells to terminal. Constraints are handled by narrowing the OMD. On the second stage (backward course) the optimal solution is chosen from OMD.

Geomechanical and Fracture Network Interpretation of a Devonian Outcrop

2021 ◽  
pp. 1-16
Author(s):  
Scott McKean ◽  
Simon Poirier ◽  
Henry Galvis-Portilla ◽  
Marco Venieri ◽  
Jeffrey A. Priest ◽  
...  
Keyword(s):  
Large Scale ◽  
Multiple Scales ◽  
Fracture Network ◽  
Natural Fracture ◽  
Small Scale ◽  
Nugget Effect ◽  
Schmidt Hammer ◽  
Unconventional Reservoir ◽  
Fracture Anisotropy ◽  
Fracture Intensity

Summary The Duvernay Formation is an unconventional reservoir characterized by induced seismicity and fluid migration, with natural fractures likely contributing to both cases. An alpine outcrop of the Perdrix and Flume formations, correlative with the subsurface Duvernay and Waterways formations, was investigated to characterize natural fracture networks. A semiautomated image-segmentation and fracture analysis was applied to orthomosaics generated from a photogrammetric survey to assess small- and large-scale fracture intensity and rock mass heterogeneity. The study also included manual scanlines, fracture windows, and Schmidt hammer measurements. The Perdrix section transitions from brittle fractures to en echelon fractures and shear-damage zones. Multiple scales of fractures were observed, including unconfined, bedbound fractures, and fold-relatedbed-parallel partings (BPPs). Variograms indicate a significant nugget effect along with fracture anisotropy. Schmidt hammer results lack correlation with fracture intensity. The Flume pavements exhibit a regionally extensive perpendicular joint set, tectonically driven fracturing, and multiple fault-damage zones with subvertical fractures dominating. Similar to the Perdrix, variograms show a significant nugget effect, highlighting fracture anisotropy. The results from this study suggest that small-scale fractures are inherently stochastic and that fractures observed at core scale should not be extrapolated to represent large-scale fracture systems; instead, the effects of small-scale fractures are best represented using an effective continuum approach. In contrast, large-scale fractures are more predictable according to structural setting and should be characterized robustly using geological principles. This study is especially applicable for operators and regulators in the Duvernay and similar formations where unconventional reservoir units abut carbonate formations.

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