Well-connected Fracture Network Research Articles

An Improved Fracture Seismic Method for identifying the drilling targets of medium-deep geothermal resources: A case study on heishan geothermal area

The Heishan geothermal area is located at southern area of the gigantic rock body of the Lincang Granite in western Yunnan, where the groundwater system and geothermal fluids are mainly distributed along the Heishan-Hejian fault with exposed temperatures ranging from 85 °C to 99 °C and an average geothermal gradient exceeding 49 km/ °C, showing a high potentiality for power generation. In order to understand its origin and distribution characteristics and to identify favorable drilling targets for further exploration and development, this study conducted analyses and characterizations of the ground water system, thermal structures, and heat storage fracture network through using the improved fracture seismic method. The results indicate that the distribution of vertical fracture network of Heishan geothermal area is mainly controlled by a set of secondary northeast trending faults, which govern the hydraulic circulation in the geothermal area together with the northwest-southeast trending main structures. Horizontally, the well-connected fracture network is predominantly distributed at depths ranging from 1500 to 2000 m, exhibiting a trend of thermal convergence from northwest to southeast. Therefore, the southern part of the Heishan geothermal area, particularly the high energy intensity zone at depths of 2000 to 2500 m, represents a favorable drilling targets. Furthermore, this underground fracture characterization method can be also applied to improve the success rate of directional reservoir transformation of enhanced geothermal system (EGS) and effectively monitor it.

Imbricated structure and hydraulic path induced by strike slip reactivation of a normal fault

In carbonates, fault zones strongly influence local reservoir properties and act as drains or barriers to flows. In the case of reactivated faults, newly developed fracture and fault systems rework and cross-cut pre-existing fault structures. The modifications of initial damage zone and fault core properties alter the fault zone properties and potentially created new fluid pathways. This study of the polyphase Castellas fault zone, developed as normal and later reactivated as strike slip, characterizes the structural pattern related to tectonic reactivation, and estimates the hydraulic behaviour of the fault zone through time. This fault affects carbonates located on La Fare anticlinal (SE France). High resolution mapping, 848 measurements and cross-sections allowed to discriminate the fault structures and the lateral heterogeneity of its architecture. Along the 850m-long studied damage zone we identify 8 principal fault planes, 2 relay zones, 19 secondary fault planes, and fault lenses. The study shows that the fault zone developed as isolated fault segments during the normal activity and acted as a drain to fluid flows during its nucleation. Later strike-slip reactivation led to the main structures visible presently as a well-connected fracture network and un-cemented breccia allowing the fault to be a drain to fluid flows.

Anderson localisation and reentrant delocalisation of tensorial elastic waves in two-dimensional fractured media

We study tensorial elastic wave transport in two-dimensional densely fractured media using numerical simulations and document transitions from propagation to diffusion and to localisation/delocalisation. For large fracture stiffness, waves are propagative at the scale of the system. For small stiffness, multiple scattering prevails, such that waves are diffusive in disconnected fracture networks, and localised in connected ones with a strong multifractality of the intensity field. A re-entrant delocalisation is found in well-connected fracture networks due to energy leakage via evanescent waves and cascades of mode conversion.

Are Visible Fractures Accurate Predictors of Flow and Mass Transport in Fractured Till?

Tracer experiments conducted in the laboratory on undisturbed core samples (<7.3-cm-diameter) have been a standard method for estimating hydraulic and transport properties of fractured till since the 1980s. This study assesses the relationship between visible fractures on the top and bottom of core samples and the resulting hydraulic and mass transport properties of the core. We hypothesized that more visible fractures would indicate the presence of a well-connected fracture network, leading to greater hydraulic conductivity (K) values and earlier chemical breakthrough times. To test this hypothesis, water flow and bromide (Br-) tracer experiments were performed on 10, 16-cm diameter, 16-cm-tall samples of fractured Dows Formation till from central Iowa. Visually identifiable fractures were present on the top and bottom of every sample. Results indicate that the visual identification of fractures does not predict a connected fracture network, as some samples produced breakthrough curves showing rapid first arrival times and shapes characteristic of solute transport in a fractured medium, while others appeared similar to an unfractured medium. No correlation was found between the number of visible fractures and K (Pearson's r=0.25), or Br- first arrival time (r=-0.33), but a strong negative correlation between K and first arrival time (r=-0.92). Results indicate that the sample volume was not large enough to reliably contain a connected fracture network. Thus, testing large volumes of till at the field scale coupled with fracture-flow modeling likely represents the best approach for estimating hydraulic and mass transport properties for fractured till.

Improving heat extraction performance of an enhanced geothermal system utilizing cryogenic fracturing

Engineered fractures play an important role in improving heat extraction performance of Enhanced Geothermal Systems (EGS). It is possible to create these engineered fractures with cryogenic fracturing technology. Cryogenic liquid nitrogen could be used as a stimulation fluid - causing severe thermal shock. This thermal shock would lead to a well-connected fracture network in a hot, low permeability reservoir. Based on local thermal equilibrium theory, a coupled thermal-hydraulic model has been developed to simulate the heat extraction process in an EGS as a function of different fracture configurations. The proposed model is validated against analytical solutions. Using this validated model, EGS heat extraction is simulated for different stimulation scenarios. The characteristics of the temperature distribution and heat extraction are analyzed and compared for the different stimulation scenarios. The production well temperature and flow rate, as well as the potential power output over a 30 year period are calculated and compared for four scenarios. The results indicate that fracture networks created by cryogenic fracturing could significantly improve the heat extraction performance of an EGS.

Multiple lines of field evidence to inform fracture network connectivity at a shale site contaminated with dense non-aqueous phase liquids

AbstractConceptual models of the fracture networks in shale were evaluated at a site contaminated with chlorinated solvents. Prior borehole testing in eight holes under open hole ambient and pumping conditions identified 14 flow zones (140 m bedrock interval) with zero to five zones per hole. Cross-hole testing showed only a few cross-connections between transmissive fractures. The initial conceptual model thus featured a sparse fracture network with few dominant fractures. Detailed profiles (hydraulic head, rock core volatile organic compounds, groundwater volatile organic compounds from packer and multi-level sampling, cross-hole multi-level monitoring of permanganate injections) were collected from several holes and indicated a well-connected fracture network with many hydraulically active fractures not influenced by open hole cross-connection. This contrasting conceptual model contained numerous well-connected horizontal and vertical fractures that allowed chlorinated solvents to penetrate the upper 50–60 m of bedrock as dense non-aqueous phase liquids, followed by diffusion-driven mass transfer from fractures into the porous rock matrix, such that nearly all the contaminant mass resided as dissolved and sorbed phases, measurable in rock core without cross-contamination during drilling. The difference in the two conceptual models has important implications for source zone and plume attenuation.

Upscaling permeability for three-dimensional fractured porous rocks with the multiple boundary method

Upscaling permeability of grid blocks is crucial for groundwater models. A novel upscaling method for three-dimensional fractured porous rocks is presented. The objective of the study was to compare this method with the commonly used Oda upscaling method and the volume averaging method. First, the multiple boundary method and its computational framework were defined for three-dimensional stochastic fracture networks. Then, the different upscaling methods were compared for a set of rotated fractures, for tortuous fractures, and for two discrete fracture networks. The results computed by the multiple boundary method are comparable with those of the other two methods and fit best the analytical solution for a set of rotated fractures. The errors in flow rate of the equivalent fracture model decrease when using the multiple boundary method. Furthermore, the errors of the equivalent fracture models increase from well-connected fracture networks to poorly connected ones. Finally, the diagonal components of the equivalent permeability tensors tend to follow a normal or log-normal distribution for the well-connected fracture network model with infinite fracture size. By contrast, they exhibit a power-law distribution for the poorly connected fracture network with multiple scale fractures. The study demonstrates the accuracy and the flexibility of the multiple boundary upscaling concept. This makes it attractive for being incorporated into any existing flow-based upscaling procedures, which helps in reducing the uncertainty of groundwater models.

Overview of naturally permeable fractured reservoirs in the central and southern Upper Rhine Graben: Insights from geothermal wells

Since the 1980′s, more than 15 geothermal wells have been drilled in the Upper Rhine Graben (URG), representing more than 60 km of drill length. Although some early concepts were related to purely matrix-porosity reservoirs or Hot Dry Rock systems, most projects in the URG are currently exploiting the geothermal resources that are trapped in fracture networks at the base of the sedimentary cover and in the granitic basement. Lessons-learnt from the European EGS reference site at Soultz-sous-Forêts reveal highest natural permeability in the uppermost altered crystalline basement.Here, we present a compilation of related information to examine a more general validity of this hypothesis for the central URG. In this respect, 15 geothermal wells were analyzed concerning their lithologies, temperature distribution with depth, and their hydraulic yields. Among others, permeable fractures in Triassic sediments were observed among others during drilling operations at Soultz-sous-Forêts, Rittershoffen, Cronenbourg (France), Landau, Insheim, Bruchsal and Brühl (Germany). The geothermal wells at Soultz-sous-Forêts, Rittershoffen (France), Landau and Insheim (Germany) also intersect well-connected fracture networks in the uppermost altered granitic basement. Permeable fractures are intersected to a depth of 5 km at Soultz-sous-Forêts (France) and Basel (Switzerland).The compilation of geologic, hydraulic and thermal data of 15 geothermal wells shows permeability variation among the lithologies with the maximum observed at the top of the hydrothermally altered granite. This higher permeability is likely due to the intense fracture density in the fault core of the fracture zone and the large porous and altered damage zone which allow connection with the reservoir.

Characterising the present-day stress regime of the Georgina Basin

ABSTRACTThe onshore Georgina Basin in northern Australia is prospective for unconventional hydrocarbons; however, like many frontier basins, it is underexplored. A well-connected hydraulic fracture network has been shown to be essential for the extraction of resources from the tight reservoirs that categorise unconventional plays, as they allow for economic flows of fluid from the reservoir to the well. One of the fundamental scientific questions regarding hydraulic stimulation within the sub-surface of sedimentary basins is the degree to which local and regional tectonic stresses act as a primary control on fracture propagation. As such, an understanding of present-day stresses has become increasingly important to modern petroleum exploration and production, particularly when considering unconventional hydrocarbon reservoirs. This study characterises the regional stress regime in the Georgina Basin using existing well data. Wellbore geophysical logs, including electrical resistivity image logs, and well tests from 31 petroleum and stratigraphic wells have been used to derive stress magnitudes and constrain horizontal stress orientations. Borehole failure features interpreted from wellbore image and caliper logs yield a maximum horizontal stress orientation of 044°N. Integration of density log data results in a vertical stress gradient of 24.6 MPa km–1. Leak-off and mini-fracture tests suggest that this is the minimum principal stress, as leak-off values are generally shown to be at or above the magnitude of vertical stress. The maximum horizontal stress gradient is calculated to be in the range of 31.3–53.9 MPa km–1. As such, a compressional stress regime favouring reverse/reverse–strike-slip faulting is interpreted for the Georgina Basin.

Modeling flow in naturally fractured reservoirs: effect of fracture aperture distribution on dominant sub-network for flow

Fracture network connectivity and aperture (or conductivity) distribution are two crucial features controlling flow behavior of naturally fractured reservoirs. The effect of connectivity on flow properties is well documented. In this paper, however, we focus here on the influence of fracture aperture distribution. We model a two-dimensional fractured reservoir in which the matrix is impermeable and the fractures are well connected. The fractures obey a power-law length distribution, as observed in natural fracture networks. For the aperture distribution, since the information from subsurface fracture networks is limited, we test a number of cases: log-normal distributions (from narrow to broad), power-law distributions (from narrow to broad), and one case where the aperture is proportional to the fracture length. We find that even a well-connected fracture network can behave like a much sparser network when the aperture distribution is broad enough (α ≤ 2 for power-law aperture distributions and σ ≥ 0.4 for log-normal aperture distributions). Specifically, most fractures can be eliminated leaving the remaining dominant sub-network with 90% of the permeability of the original fracture network. We determine how broad the aperture distribution must be to approach this behavior and the dependence of the dominant sub-network on the parameters of the aperture distribution. We also explore whether one can identify the dominant sub-network without doing flow calculations.

Shape factor for dual-permeability fractured reservoir simulation: Effect of non-uniform flow in 2D fracture network

The flow properties of naturally fractured reservoirs are dominated by flow through the fractures. In a previous study we showed that even a well-connected fracture network behaves like a much sparser network when the aperture distribution is broad enough: i.e., most fractures can be eliminated while leaving a sub-network with virtually the same permeability as the original fracture network. In this study, we focus on the influence of eliminating unimportant fractures which carry little flow on the inferred characteristic matrix-block size. We model a two-dimensional fractured reservoir in which the fractures are well-connected. The fractures obey a power-law length distribution, as observed in natural fracture networks. For the aperture distribution, because information from the subsurface is limited, we test a number of cases: log-normal distributions (from narrow to broad), and power-law distributions (from narrow to broad). The matrix blocks in fractured reservoirs are of varying sizes and shapes; we adopt the characteristic radius and the characteristic length to represent the characteristic matrix-block size. We show how the characteristic matrix-block sizes increase from the original fracture network to the dominant sub-network. This suggests that the matrix-block size, or shape factor, used in dual-porosity/dual-permeability waterflood or enhanced oil recovery (EOR) simulations or in homogenization should be based not on the entire fracture population but on the sub-network that carries almost all of the injected fluid (water or EOR agent).

Structural and statistical characterization of joints and multi-scale faults in an alternating sandstone and shale turbidite sequence at the Santa Susana Field Laboratory: Implications for their effects on groundwater flow and contaminant transport

This paper describes the properties of faults and fractures in the Upper Cretaceous Chatsworth Formation exposed at Santa Susana Field Laboratory and its surroundings (Simi Hills, California), where groundwater flow and contamination have been studied for over three decades.The complex depositional architecture of this turbidite consisting of alternating sandstones and shales, interacting with formative stress conditions are responsible for multi-scale fault hierarchies and permeable fractures in which nearly all groundwater flow occurs.Intensity and distribution of background fractures and their relation to bedding thickness are established for sandstones, the dominant lithology. The architecture of faults with increasing displacement is described, and relationships among fault dimensional parameters captured.Data from ∼400 boreholes and piezometers reveal the effect of faults and fractures on groundwater flow. Large hydraulic head differences, observed across fault zones with shale-rich cores, indicate these structures as cross-flow barriers. Moreover, hydraulic head profiles under ambient conditions, and pumping tests suggest strong hydraulic connectivity in all directions to depth of hundreds of meters.This outcrop-based structural characterization relates the horizontal hydraulic conductivity to the observed well-connected fracture network, and explains the strong vertical connectivity across low-hydraulic conductivity shales as faults and sheared fractures provide flow pathways.

Integration of Pressure-Transient Data in Modeling Tengiz Field, Kazakhstan—A New Way To Characterize Fractured Reservoirs

Summary A systematic work-flow to integrate pressure-transient data collected from single-well buildup tests in numerical reservoir-simulation models for a fracture/matrix system is presented. The results of its application in a sector model in the southeast region of Tengiz field in Kazakhstan are also discussed. The procedure starts with a selected numerical-simulation model, either a discrete fracture/matrix (DFM) model or a dual-porosity dual-permeability (DPDK) model, and follows with the analysis of a numerically generated buildup test to calculate the fracture spacing and shape factor of the model. Then, following the correlations between pressure-transient-analysis results and the average or representative values of the model-input parameters near the well, which contain the previously obtained fracture spacing and shape factor, the numerical-model parameters are adjusted in each iteration to match the pressure-transient behavior observed in the buildup test including the interporosity flow between matrix and fracture and the radial flow in the total system. Before field application, the numerical-simulation results from both DFM and DPDK models were validated against analytical pressure-transient solutions for a dual-porosity system. The gridding and time-steps were calibrated to reproduce the analytical transient behavior. Finally, the new work-flow was applied to a sector model of Tengiz field in the southeast region focusing on two wells. Following the developed work-flow, a DFM model was constructed, and its fracture and matrix properties were adjusted to honor buildup-test data at both wells and the transient data collected during a pulse test conducted between them. The study results show that the key factors of a DFM model on buildup transient response are the fracture permeability, fracture aperture, and matrix permeability in the well-drainage area, and the dominant parameters on pulse-test response are the fracture permeability and matrix porosity in the influence area between the two wells. Using the correlations quantitatively for each simulation step could reduce the total number of iterations needed to converge to the numerical solution. The modified model also generated flow distribution along the wellbore, consistent with production-logging data at one well. The resulting sector map of pressure change during buildup test indicates the area with well-connected fracture network. Dynamic transient data contain rich information about reservoirs, and the effective integration of dynamic and static data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production, and optimizing recovery. The novelty of this study is the quantitative use of the correlations between pressure-transient-analysis results and the representative values of the input parameters in a numerical model to reduce the number of simulation iterations. Its application in Tengiz is also one of the rare examples in which single-well and multiple-well transient data, production logging, and image-log data are all available.

Fracture imaging within a granitic rock aquifer using multiple-offset single-hole and cross-hole GPR reflection data

The sparsely spaced highly permeable fractures of the granitic rock aquifer at Stang-er-Brune (Brittany, France) form a well-connected fracture network of high permeability but unknown geometry. Previous work based on optical and acoustic logging together with single-hole and cross-hole flowmeter data acquired in 3 neighboring boreholes (70-100 m deep) have identified the most important permeable fractures crossing the boreholes and their hydraulic connections. To constrain possible flow paths by estimating the geometries of known and previously unknown fractures, we have acquired, processed and interpreted multifold, single- and cross-hole GPR data using 100 and 250 MHz antennas. The GPR data processing scheme consisting of time-zero corrections, scaling, bandpass filtering and F-X deconvolution, eigenvector filtering, muting, pre-stack Kirchhoff depth migration and stacking was used to differentiate fluid-filled fracture reflections from source-generated noise. The final stacked and pre-stack depth-migrated GPR sections provide high-resolution images of individual fractures (dipping 30-90{\deg}) in the surroundings (2-20 m for the 100 MHz antennas; 2-12 m for the 250 MHz antennas) of each borehole in a 2D plane projection that are of superior quality to those obtained from single-offset sections. Most fractures previously identified from hydraulic testing can be correlated to reflections in the single-hole data. Several previously unknown major near vertical fractures have also been identified away from the boreholes.