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Selected effects of VTI anisotropy on downhole microseismic data

Święch E., Pasternacki A., Maćkowski T.

Geology, Geophysics and Environment

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2016

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Vol. 42, no. 1

131--132

EN

Shale gas is one of the well-known unconventional resources of natural gas all over the world. This term refers to natural gas that is trapped within shale formations. Shales are fine – grained sedimentary rocks which can be reach resources of both petroleum and natural gas. This sedimentary rocks are heavily layered and in their nature exhibit VTI velocity anisotropy behavior (Van Dok et al. 2011). This statement indicates that the world among us is not isotropic and we should not neglect this fact in our geophysical research. Anisotropy, in general is the property of the material. It can be described as the attribute of a material’s property with respect to the direction in which it is measured (Pereira & Jones 2010). There are two essential types of anisotropy: VTI and HTI. Vertical velocity layering gives rise to VTI (vertical transverse isotropy) velocity in which seismic wave velocity is faster in the horizontal direction than in the vertical one. The second type of isotropy is horizontal transverse isotropy (HTI) which causes azimuthal traveltime variations. The common mechanism for this type of anisotropy is vertical aligned fractures in an isotropic background medium (Jenner 2011.) Authors of this study focused mostly on VTI as this type of anisotropy is present in shale formations, as a result of small scaled heterogeneities from fine layering (Thomsen 1986). The VTI anisotropy can be mathematically described by using three Thomsen parameters: epsilon, delta and gamma. Epsilon is a measure of the difference between the horizontal and vertical propagation velocities for compressional waves. Gamma parameter is a measure of the difference in the horizontal and vertical propagation velocities for horizontally polarized shear waves (SH waves). Delta parameter is not easily described either mathematically or qualitatively (Pereira & Jones 2010), but it influences the anisotropy velocities in medium incidence angles. These parameters can be mathematically expressed by equations proposed by Leon Thomsen (Thomsen 1986). In this study, authors present influence of VTI anisotropy on microseismic data recorded during hydraulic fracturing of shale intervals in one of the well located in Northern Poland. Authors points out how the anisotropy affects on microseismic events location, locating them in isotropic and anisotropic velocity models with usage of TGS algorithm. Furthermore, authors indicate possible solution to estimate VTI parameters based on microseismic data. VTI anisotropy parameters plays critical role not only in case of microseismic data analysis but also in processing of active seismic data. Authors proved that VTI anisotropy present in the investigated area has strong influence on microseismic events location especially in depth. Moreover estimation of VTI anisotropy parameters based on microseismic data with usage of Thomsen equations is possible.

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Seismic modelling as a tool for optimization of downhole microseismic monitoring array

Pasternacki A., Święch E., Maćkowski T.

Geology, Geophysics and Environment

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2016

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Vol. 42, no. 1

112--113

EN

Hydraulic fracturing processes employed to release natural gas accumulations trapped in shale formation causes cracks in fractured media occurred as microseismic events. Those events can be detected with either surface or downhole monitoring technique. One of the advantages of downhole microseismic monitoring technique is the relative high detection moment magnitude threshold, compared to surface and quasi surface arrays (Maxwell 2014). The epicenters of detected microseismic events are located with certain accuracies (Eisner et al. 2010). The uncertainties in location are mainly caused by simplification of a very complex geological structure, geometry of the monitoring network, arrival time pick uncertainty and naturally selected processing method. The correct assessment of macroseismic events locations with their uncertainties is the key to proper interpretation of the results. In this study, authors present an analysis of optimizing geometry of the downhole microseismic monitoring array minimalizing location error and taking into account level of detectability. To achieve this goal, several different downhole array geometries were tested. The study is located in Northern Poland where active exploration of shale gas deposits takes place. In the investigated area three wells are located, one vertical (W-1) and two horizontal, which have been drilled in the same azimuths but different direction and slightly different depths (W3H – deeper and W2Hbis – shallower). As there is possibility that these wells will be stimulated in close period of time, the chosen array placed in the monitoring well should be optimal for depths. As Eisner stated in his work, best downhole array should have to consist of 3C sensors placed below and above of the planed depths of stimulation to reduce uncertainty of the event locations (Eisner et al. 2009). Both treatment wells have relatively high horizontal distance, which results with high distance between receivers and possible events (in ranges between 500 m to 1700 m), which is quite high compared to literature examples (Warpiński & Natl 1994). To perform this analysis, GeoTomo MiVu TM Microseismic Processing System was used, which includes a Vecon modeling engine. This software has been granted to AGH UST for research and educational purposes. The passive seismic modelling was done with GRTM method (generalized reflection transmission coefficients) (Kennet 1980). This kind of mixed procedure is relatively fast to perform and allows checking many different configurations of downhole array. Based on the 3D seismic survey provided by PGNiG in the investigated area authors have decided to use simple layered velocity model which sufficiently describes the local geological conditions. The synthetic microseismic events were located using TGS (Traveltime Grid Search) algorithm available in MiVu software. Based on presented analysis authors were able to choose optimal geometry of downhole micro seismic array for both prospective intervals which fulfill condition of being good compromise between costs and location accuracy of possible events.

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Effect of the near surface layer for the microseismic monitoring – 2D modelling

Pasternacki A., Wandycz P., Maćkowski T.

Geology, Geophysics and Environment

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2016

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Vol. 42, no. 1

111

EN

Microseismic monitoring is usually used to map hydraulic fracture or stress changes in the reservoir, which is stimulated (Maxwell et al. 2010, Duncan & Eisner 2010). Examining the wave traveling through the reservoir can provide many important information on medium properties (Grechka et al. 2011) and can be used either to assess the stimulated reservoir or improve microseismic imagining. Microseismic monitoring network can be deployed either on surface or in borehole. Noise level observed on the surface network is usually 10 times higher than one observed in the receivers placed in borehole but still the detection the microseismic events by the surface array is possible (Eisner et al. 2010). In this study, we present the results of the synthetic modeling to show qualitatively and quantitatively the influence of the near-surface layer and the effect of the attenuation in this layer for the assessment of the strength of the signal recorded by receivers placed on the surface or just below it. For the purpose of this research, authors performed 2D seismic modeling using Tesseral software. We performed several different models, each of them in two variants. First variant included the impact of the impedance contrast of the near surface layer; in the second variant we suppressed that effect. Layer composition in models differed both in number and their properties (velocity and quality factor). In each model, we used one type of source located in 3 different places. Monitoring array was vertical and constrained with 100 geophones. First receiver was placed on the surface, and the spacing between phones was 1m. Data obtained with this procedure were then analyzed using Matlab software. For each model, we compered the relative amplitudes of the different events in both variants, and then assessed the impact of the impedance contrast in the near surface layer. Performed modeling proved that the influence of the near surface layer is significant. We observe that the amplitude ratio between the first receivers in two variants of each model ranges from 1.5 to almost 2, regardless of the depth of the source. Signal enhancement is the function of the impedance contrast, and does not depend on the attenuation in the near surface layer. However, attenuation does not influence the enhancement of the signal, very low quality factor in the shallow layers highly influences the strength of the arriving waves.

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Comparison of solutions for microseismic focal mechanism estimation

Wandycz P., Święch E., Pasternacki A.

Geology, Geophysics and Environment

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2016

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Vol. 42, no. 1

137--138

EN

One of the major advantages of microseismic data, recorded during hydraulic fracturing of prospective shale intervals is ability to use both P and S wave in the analysis, not only to determine epicentral locations of events but also to describe source itself. The information about the mechanisms of located microseismic events allows better understanding of in situ stress and strain conditions and the local subsurface geomechanical properties and forces (Kamei et al. 2015). As Duncan stated in his work, a proper characterization of the observed events mechanisms is the key to understand radiation pattern of the signals in the investigated area (Duncan & Eisner 2010). Moreover, an understanding of the nature of the rock failure supports reservoir simulation models and stimulated reservoir volume estimates (Kratz & Thorton 2016). Proper assessment of event strike, dip and rake provides the geometry of the fracture plane assuming double couple focal mechanism, while full moment tensor inversion provides information about shear and tensile nature of the calculated mechanisms. The common method to obtain reliable focal mechanisms of observed microseismic events is decomposing of the full moment tensor. Seismic moment tensor is powerful tool which provides a general mathematical solution of sources that can be used to distinguish between various types of microseismic events. The method comes to reliably estimation of the six independent components of a full moment tensor by lestsquares inversion (Eaton & Forouhideh 2010). The motivation for this analysis was to determine microseismic focal mechanisms based on P – wave peak amplitude, P and S – waves peak amplitudes and S – wave peak amplitude only to estimate the differences and uncertainties between these three different solutions. Furthermore authors decided to check how the mechanisms changes with different geometries of downhole monitoring array. In this study only synthetic data computed in MiVu GeoTomo software using raytracing method and simple layered velocity model were used. The mentioned velocity model was constructed based on well logs data delivered by PGNiG from measurements done in Northern Poland where active exploration of shale gas takes place. In this analysis authors focused only on double couple (DC) and compensated linear vector dipole (CLVD) mechanisms which are two most common types of microseismic focal mechanisms occur during hydraulic fracturing of shale deposits. Performed analysis proved that the best and most consistent results with the lowest uncertainties reflected in the condition number parameter can be obtained by using both P and S peak amplitudes.

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Prognostic accumulation zones for oil and natural gas in the criteria for the distribution of petrophysical parameters in the main dolomite in Gorzow-Pniewy area

Semyrka R., Maruta M., Pasternacki A.

Archives of Mining Sciences

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2013

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Vol. 58, no. 4

1111--1132

EN

W ocenie ilościowej i jakościowej przestrzeni porowej środowiskiem anizotropowym są węglanowe skały zbiornikowe. Zróżnicowany litologiczno-facjalnie oraz miąższościowo, ropo-gazonośny poziom dolomitu głównego charakteryzuje się złożonym układem pojemnościowo-filtracyjnym. Tym regułom podporządkowana jest ocena i perspektywy poszukiwawcze w cechsztyńskim poziomie dolomitu głównego (Ca2) w Polsce w rejonie Gorzów-Pniewy.W celu uprządkowania tego zagadnienia i prognozy perspektyw złożowych, w oparciu o wyniki badań porozymetrycznych, przeprowadzono analizę parametrów petrofizycznych dolomitu głównego w przedstawionym obszarze, o stwierdzonej ropo-gazonośności tego poziomu. Wyniki badań porozymetrycznych wyraźnie wskazują na heteregoniczność utworów dolomitu głównego w zakresie zmienności parametrów petrofizycznych, odniesionych do zróżnicowanych litologicznie stref paleogeograficznych w analizowanym obszarze. Analiza ta, w odniesieniu do pojemności magazynowej dolomitu głównego, rozwiniętego w zróżnicowanych facjach poszczególnych stref paleogeograficznych, pozwala na ocenę możliwej akumulacji węglowodorowej, w stosunku do potencjału generacyjnego tego poziomu.

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Wstępne wyniki modelowań przestrzennych (3D) parametrów petrofizycznych skał podczas poszukiwań stref występowania gazu zamkniętego w polskim basenie czerwonego spągowca

Papiernik B., Górecki W., Pasternacki A.

Przegląd Geologiczny

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2010

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Vol. 58, nr 4

352-364

EN

The Rotliegend Basin is filled with terrigenic complex over 1200 m in thickness. The complex comprises sediments of eolian, fluvial and playa depositional systems (Fig. 1). Reservoir volume of the pore space accessible for the reservoir media is ca. 830-990 km3. Gas exploration in this stratigraphic unit is now focused at depths of around 3000-3800 m b.s.l., in the near-top zone. Poor reservoir properties, especially permeabilities, are here the limiting factor for conventional exploration. A change in the prospecting strategy to comprise tight gas targets moves research into the deeper zone covering the whole profile of the Rotliegend. The paper presents preliminary results of 3D modeling of lithofacies and related petrophysical parameters variability. The static model was created with the use of Petrel 2009.2. Structural framework was built using regional structural, isopach and facies maps. It was relatively detailed, comprising 9 576 000 cells organized in 3 zones and 60 layers. To estimate facies model, the authors used results of integrated environmental analysis of core data and logs from 117 wells (Fig. 2 ). Models of clay content (Vsh) and porosity (PHI) were based on logs from 75 wells. The obtained results show that the northern margin of the Eastern Erg is characterized by presence of numerous eolian strata with porosity ranging from 5 to 15%. Their quality, quantity and thickness decrease toward the north, along with increase in depth. Modeling results indicate that the dominating porous layers of eolian sandstones and fluvial inserts are often intercalated with "non-reservoir" layers revealing porosity below 5%. In this zone, a deeper part of the Rotliegend section should be investigated more thoroughly (Fig. 5, 6, 9). The Pomeranian sector of the Central Basin is dominated by playa and fluvial sediments (Fig. 7, 8, 10). Slightly clayey eolian strata make a few, laterally discontinuous intercalations. Gas accumulations could be expected within local, laterally confined interlayers of eolian and fluvial sandstones with porosity of around 5-12%. Due to the location in the near-base part of the Rotliegend section, close to Carboniferous source rocks, they may be filled with gas, forming so-called sweet spots. Probability of gas occurrence in Pomerania is high as indicated by the Międzyzdroje gas field or small accumulation found in Piaski-PIG2 well. The presented preliminary study allowed to test usability of 3D modeling in tight gas prospecting. Fully reliable results will be obtained after increasing precision of the models comprising detailed seismic interpretation, the use of seismic attributes, and inclusion of quantitative data in diagenetic processes and sedimentology of layers in the modeling process.