Constraints on melt content of off-axis magma lenses at the East Pacific Rise from analysis of 3-D seismic amplitude variation with angle of incidence

Author Posting. © American Geophysical Union, 2017. This article is posted here by permission of American Geophysical Union for personal use, not for redistribution. The definitive version was published in Journal of Geophysical Research: Solid Earth 122 (2017): 4123–4142, doi:10.1002/2016JB013785.We use 3-D multichannel seismic data to form partial angle P wave stacks and apply amplitude variation with angle (AVA) crossplotting to assess melt content and melt distribution within two large midcrustal off-axis magma lenses (OAMLs) found along the East Pacific Rise from 9°37.5′N to 9°57′N. The signal envelope of the partial angle stacks suggests that both OAMLs are partially molten with higher average melt content and more uniform melt distribution in the southern OAML than in the northern OAML. For AVA crossplotting, the OAMLs are subdivided into seven ~1 km2 analysis windows. The AVA crossplotting results indicate that the OAMLs contain a smaller amount of melt than the axial magma lens (AML). For both OAMLs, a higher melt fraction is detected within analysis windows located close to the ridge axis than within the most distant windows. The highest average melt concentration is interpreted for the central sections of the OAMLs. The overall low OAML melt content could be indicative of melt lost due to recent off-axis eruptions, drainage to the AML, or limited mantle melt supply. Based on the results of this and earlier bathymetric, morphological, geochemical, and geophysical investigations, we propose that the melt-poor OAML state is largely the result of limited melt supply from the underlying mantle source reservoir with smaller contribution attributed to melt leakage to the AML. We hypothesize that the investigated OAMLs have a longer period of melt replenishment, lower eruption recurrence rates, and lower eruption volumes than the AML, though some could be single intrusion events.National Science Foundation; CFI; CRC2017-12-2

Quantitative seismic interpretation in thin-bedded geology using full-wavefield elastic modelling

Refleksjonsseismikk brukes til å lage seismiske «bilder» av den øverste delen av jordskorpen, blant annet med tanke på leting etter reservoarer for olje, gass, karbonlagring og geotermisk energi. I tillegg til å gi grunnlag for en strukturell tolkning, kan de seismiske dataene brukes til å kvantifisere egenskapene til det faste materialet og væskeinnholdet i bergartene. Et viktig verktøy i slik kvantitativ seismisk tolkning er analyse av såkalt AVO: amplitudenes variasjon med avstanden mellom kilde og mottaker (offset). Tynne geologiske lag gir utfordringer for AVO-modellering og tolkning, fordi lagtykkelsen vil kunne være mindre enn oppløsningen i de seismiske dataene. En problemstilling som tas opp i denne avhandlingen er nettopp hvordan man kan gjøre nøyaktig seismisk (forover) modellering i medier med tynne lag. En konvensjonell tilnærming innen AVO- modellering og inversjon er å bruke såkalt konvolusjonsmodellering. Denne metoden tar imidlertid bare hensyn til de primære seismiske refleksjonene og er derfor unøyaktig når modellene har tynne lag. To bedre alternativer er endelig-differanse-modellering og reflektivitetsmetoden. Reflektivitetsmetoden er en delvis analytisk modelleringsmetode for horisontalt lagdelte medier og er beregningsmessig billigere enn endelig-differansemodellering, der beregningene er basert på et tett samplet rutenett (grid). Jeg viser i avhandlingen at reflektivitetsmetoden er godt egnet for AVO-modellering i lagdelte medier. Seismiske data har en båndbegrenset karakter. En konsekvens er at beregning av reservoaregenskaper fra seismiske data generelt ikke er entydig, noe som særlig kommer til uttrykk for lagdelt geologi med tynne lag. Probabilistiske inversjonsmetoder, som for eksempel bayesianske metoder, tar hensyn til denne flertydigheten ved å forutsi sannsynligheter, noe som gjør det mulig a kvantisere usikkerheten. I avhandlingen kombinerer jeg seismisk modellering med bayesiansk klassifisering og inversjon. Modelleringen er utført med reflektivitetsmetoden og er basert på det komplette elastiske bølgefeltet. Formålet er å adressere to konkrete kvantitative seismiske tolkningsproblemer: 1) kvantifisering av usikkerhet i bayesiansk porevæske-klassifisering i nærvær av tynne lag med høy impedans, forårsaket av kalsittsementering i sandstein, og 2) estimering av reservoaregenskapene til turbiditt-reservoarer karakterisert ved alternerende lag av sandstein og skifer. I den første anvendelsen viser jeg i en modelleringsstudie at kalsitt-sementerte lag kan gi en detekterbar refleksjonsrespons, noe som kan påvirke amplituden målt ved reservoartoppen og dermed forstyrre AVO-målingen. Den observerte effekten øker usikkerheten ved porevæske-klassifisering basert på AVO-attributter, som jeg har demonstrert i en case-studie. Følgelig øker sannsynligheten for en falsk hydrokarbon-indikasjon betydelig i nærvær av kalsittsementerte lag. I den andre anvendelsen presenterer jeg en bayesiansk inversjon som tar AVO-skjæringspunktet og gradienten målt på toppen av et reservoar som inngangsdata og estimerer sannsynlighetstetthetsfunksjonen til forholdstallene «net-to-gross» og «net-pay-to-net». Metoden ble anvendt på syntetiske data og AVO-attributtkart fra Jotunfeltet på norsk kontinentalsokkel. Det ble funnet at AVO-gradienten korrelerer med reservoarets net-togross forhold, mens AVO-skjæringspunktet er mest følsomt for typen porevæske. Etter inversjon genererte jeg kart over de mest sannsynlige verdiene av forholdene net-to-gross og net-pay-to-net, samt kart over net pay og usikkerhetene. Disse kartene kan bidra til å identifisere potensielle soner med høy reservoarkvalitet og hydrokarbonmetning.Reflection seismics is used to image the subsurface for the exploration of oil and gas, geothermal or carbon storage reservoirs, among others. In addition to the structural interpretation of the resulting seismic images, the seismic data can be interpreted quantitatively with the goal to obtain rock and fluid properties. An essential tool in quantitative seismic interpretation is the analysis of the amplitude variation with offset (AVO). Thin-bedded geology below the seismic resolution poses challenges for AVO modelling and interpretation. One problem addressed in this thesis is accurate seismic forward modelling in thin-bedded media. Primaries-only convolutional modelling, commonly used in conventional AVO modelling and inversion, is prone to failure in the presence of thin beds. Better alternatives are finite-difference modelling or the reflectivity method. The reflectivity method is a semi-analytic modelling method for horizontally layered media and is computationally cheaper than finite-difference modelling on densely sampled grids. I show in this thesis that the reflectivity method is well-suited for the AVO modelling of layered media. The band-limited nature of seismic data is one reason for the non-unique estimation of reservoir properties from seismic data, especially in thin-bedded geology. Probabilistic inversion methods, such as Bayesian methods, honour this non-uniqueness by predicting probabilities that allow the uncertainty to be quantified. In this thesis, I integrate full-wavefield elastic seismic modelling by the reflectivity method with Bayesian classification and inversion. The objective is to address two concrete quantitative seismic interpretation problems: 1) the uncertainty quantification of Bayesian pore-fluid classification in the presence of thin high-impedance layers caused by calcite cementation in sandstone, and 2) the estimation of reservoir properties of turbidite reservoirs characterised by sand-shale interbedding. In the first application, I show through a modelling study that calcite-cemented beds lead to detectable reflection responses that can interfere with the target reflection at the reservoir top and thereby perturb the AVO behaviour. The observed effect increases the uncertainty of pore-fluid classification based on AVO attributes, as demonstrated by a case study. Consequently, the probability of a false hydrocarbon indication is significantly increased in the presence of calcite-cemented beds. In the second application, I present a Bayesian inversion that takes the AVO intercept and gradient measured at the top of a reservoir as input and estimates the probability density function of the net-to-gross ratio and the net-pay-to-net ratio. The method was applied to synthetic data and AVO attribute maps from the Jotun field on the Norwegian Continental Shelf. It was found that the AVO gradient correlates with the net-to-gross ratio of the reservoir, while the AVO intercept is most sensitive to the type of pore fluid. After inversion, maps of the most-likely values of the net-to-gross ratio, net-pay-to-net ratio, net pay and the uncertainty could be generated. These maps help to identify potential zones of high reservoir quality and hydrocarbon saturation.Doktorgradsavhandlin

Distribution of melt along the East Pacific Rise from 9°30′ to 10°N from an amplitude variation with angle of incidence (AVA) technique

Author Posting. © The Author(s), 2015. This article is posted here by permission of The Royal Astronomical Society for personal use, not for redistribution. The definitive version was published in Geophysical Journal International 203 (2015): 1-21, doi:10.1093/gji/ggv251.We examine along-axis variations in melt content of the axial magma lens (AML) beneath the fast-spreading East Pacific Rise (EPR) using an amplitude variation with angle of incidence (AVA) crossplotting method applied to multichannel seismic data acquired in 2008. The AVA crossplotting method, which has been developed for and, so far, applied for hydrocarbon prospection in sediments, is for the first time applied to a hardrock environment. We focus our analysis on 2-D data collected along the EPR axis from 9°29.8′N to 9°58.4′N, a region which encompasses the sites of two well-documented submarine volcanic eruptions (1991–1992 and 2005–2006). AVA crossplotting is performed for a ∼53 km length of the EPR spanning nine individual AML segments (ranging in length from ∼3.2 to 8.5 km) previously identified from the geometry of the AML and disruptions in continuity. Our detailed analyses conducted at 62.5 m interval show that within most of the analysed segments melt content varies at spatial scales much smaller (a few hundred of metres) than the length of the fine-scale AML segments, suggesting high heterogeneity in melt concentration. At the time of our survey, about 2 yr after the eruption, our results indicate that the three AML segments that directly underlie the 2005–2006 lava flow are on average mostly molten. However, detailed analysis at finer-scale intervals for these three segments reveals AML pockets (from >62.5 to 812.5 m long) with a low melt fraction. The longest such mushy section is centred beneath the main eruption site at ∼9°50.4′N, possibly reflecting a region of primary melt drainage during the 2005–2006 event. The complex geometry of fluid flow pathways within the crust above the AML and the different response times of fluid flow and venting to eruption and magma reservoir replenishment may contribute to the poor spatial correlation between incidence of hydrothermal vents and presence of highly molten AML. The presented results are an important step forward in our ability to resolve small-scale characteristics of the AML and recommend the AVA crossplotting as a tool for examining mid-ocean ridge magma-systems elsewhere.This research was supported by NSF awards OCE0327872 to J.C.M. and S.M.C., OCE-0327885 to J.P.C., and OCE0624401 to M.R.N

Fault imaging enhancement in Taranaki Basin, New Zealand and rock physics and inversion based reservoir characterization in the Central Gulf Coast region of Texas

Fault imaging technique and reservoir characterization based on rock physics analysis and pre-stack inversion has been widely used hydrocarbon exploration. For the fault imaging technique, the ant tracking has been widely used in fault interpretation. However, the reliability of the results is highly dependent on appropriately choosing a signal processing method and volume attributes. In our study area, which lies in the southern Taranaki Basin, we applied Graphic Equalizer as the processing tool and the Chaos attribute before running the ant tracking algorithm. Results show that the procedure provides a better result and can map both the major and minor faults more efficiently than the conventional fault interpretation procedure. For the reservoir characterization study, we use the Lower Wilcox strata which has been proven to be a good quality reservoir along the Central Gulf Coast of Texas. While the complexity of its sedimentary environment makes it hard to locate the isolated productive sand accurately. We carry out the rock physics analyses to provide a better understanding of the reservoir properties. Bulk density, P-wave velocity, and elastic moduli are extracted from four wells for analyzing the depth and temperature effects on compaction. A combination of three effective medium models is used for cement volume diagnostics. For the further reservoir characterization, we conduct the pre-stack seismic inversion with seven wells constrained. Our inversion results show a successful delineation of the reservoir using the Vp/Vs and S-Impedance values --Abstract, page iv

Signatures of present and past melt distribution along fast and intermediate spreading centers

The work presented in this dissertation depicts past and present signatures of melt distribution at fast and intermediate spreading centers. The primary goal of the studies included in this thesis is to provide better understanding of melt distribution and variation in melt physical properties within and at the base of oceanic crust formed at these spreading centers. Furthermore, this work examines effects that melt presence might have on formation and structural characteristics of oceanic crust. To explore the above we use geophysical data collected during two expeditions conducted along the Juan de Fuca Ridge (intermediate) and the East Pacific Rise (fast). The major part of the thesis is based on the work conducted on high resolution reflection seismic data that investigate present day intracrustal melt distribution along the East Pacific Rise (EPR) axis extending between 8º20’ and 10º10’N. Here, the character of the melt reservoir is examined from different aspects and by using different seismic data analysis methods. By systematic analysis of the seismic reflection data, we show that the axial melt lens (AML) is segmented at different segment scales. Locations of the mapped disruptions in the AML correspond to previously identified tectonic discontinuities well expressed in the seafloor bathymetry. The above result corroborates genetic relationship between tectonic and magmatic segmentation. To examine melt distribution along the EPR, here for the first time we use amplitude variation with angle of incidence (AVA) crossplotting technique that was developed by oil and gas industry experts to look for presence of hydrocarbons. Further data examination for the first time for the mid-ocean ridges show presence of deeper lenses (lenses that are present below the AML). Presence of gaps in these sub-events and their collocation with what is believed to be the location of origin of the last documented eruption occurred in 2005-06, may shed light on the mechanisms behind the mid-ocean ridges volcanic processes. To explore variation in crustal structure and melt distribution at present day along the Juan de Fuca Ridge and relicts of past melt presence near ridge propagators wakes, a combination of gravity and multi-channel seismic data was used. Gravity modeling, constrained by seismic data, showed that robust topography (shallow axial depth and wide axial high) and thicker crust observed for the southern portion of this ridge system originate from enhanced melt supply at the base of the crust. In addition, prominent crustal thickening on the younger crust side of the inner propagators wakes (now on the ridge flanks) is brought into relationship with collocated frozen magma lenses imaged at the base of the crust. Spatial relationship of the two argues for their causal relationship at the time of the crustal formation on the axis. Our study suggests that these frozen lenses represent the record of once molten reservoir that most probably actively participated in the formation of the thicker crust

Gas-hydrates saturation estimation in Krishna-Godavari basin, India

Gas hydrates are an unconventional energy resource. They may become an important source of energy for India in the future. They occur offshore along the continental margin. They are currently in exploratory and evaluation stages and their quantification is an important task. The goal of this thesis is to demonstrate a new technique for the estimation of gas hydrates volumes. The region of study is the Krishna-Godavari basin. It is located on the eastern offshore areas of India. The presence of gas hydrates has been proven by drilling into marine sediments as a part of the Indian National Gas Hydrates Program. Borehole subsurface and surface seismic data were collected during this expedition. I use a 2D seismic reflection line and borehole log data for my study. The method I use for estimation of gas hydrates saturation uses a combination of inversion of seismic reflection data and development of seismic attributes. My approach can be broadly described by following steps: 1. Process the seismic data to remove noise. Use stacked and migrated data along with well logs to perform poststack seismic inversion to obtain impedance information in volumetric portions of the subsurface. 2. Use NMO corrected CDP gather records of the seismic reflection data along with subsurface well logs to perform prestack seismic inversion to obtain impedance volumes. 3. Compare the results from step1 and step 2 and use the best results to perform multi-attribute analysis using a neural network method to predict resistivity and porosity logs at the well location. Use the transform equations obtained at the well location to predict the well logs throughout the seismic section in the desired zone of interest. 4. Use an anisotropic equivalent of Archie’s law that relates resistivity and porosity to saturation to predict saturation throughout the seismic reflection section. The majority of the previous work done in the region is limited to gas hydrates quantification only at the well location. By using neural networks for multi-attribute analysis, I have demonstrated a statistical based method for the prediction of log properties away from well location. My results suggest gas hydrates saturation in the range of 50-80% in the zone of interest. The estimated saturation of gas hydrates matches up very closely with the saturation estimates obtained from the cores recovered during coring of the boreholes. Hence my method provides a reliable method of quantification of gas hydrates by making best possible use of seismic and well log data. The unique combination of impedance derived attributes and neural-network includes the non-linear behavior in the predictive transform relationships. The use of an anisotropic formulation of Archie’s law to estimate saturation also produces accurate results confirmed with the observed gas-hydrates saturation.Geological Science

Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs

During this last period of the ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342), we finalized integration of rock physics, well log analysis, seismic processing, and forward modeling techniques. Most of the last quarter was spent combining the results from the principal investigators and come to some final conclusions about the project. Also much of the effort was directed towards technology transfer through the Direct Hydrocarbon Indicators mini-symposium at UH and through publications. As a result we have: (1) Tested a new method to directly invert reservoir properties, water saturation, Sw, and porosity from seismic AVO attributes; (2) Constrained the seismic response based on fluid and rock property correlations; (3) Reprocessed seismic data from Ursa field; (4) Compared thin layer property distributions and averaging on AVO response; (5) Related pressures and sorting effects on porosity and their influence on DHI's; (6) Examined and compared gas saturation effects for deep and shallow reservoirs; (7) Performed forward modeling using geobodies from deepwater outcrops; (8) Documented velocities for deepwater sediments; (9) Continued incorporating outcrop descriptive models in seismic forward models; (10) Held an open DHI symposium to present the final results of the project; (11) Relations between Sw, porosity, and AVO attributes; (12) Models of Complex, Layered Reservoirs; and (14) Technology transfer Several factors can contribute to limit our ability to extract accurate hydrocarbon saturations in deep water environments. Rock and fluid properties are one factor, since, for example, hydrocarbon properties will be considerably different with great depths (high pressure) when compared to shallow properties. Significant over pressure, on the other hand will make the rocks behave as if they were shallower. In addition to the physical properties, the scale and tuning will alter our hydrocarbon indicators. Gas saturated reservoirs change reflection amplitudes significantly. The goal for the final project period was to systematically combine and document these various effects for use in deep water exploration and transfer this knowledge as clearly and effectively as possible

Fracture detection with azimuthal seismic data, rock physics, and geomechanics

Significant progress has been made for fracture detection in unconventional plays using advanced geophysical techniques such as the use of P-wave AVO algorithms in multi-azimuth data. In the past decade, it has been recognised that major amplitude distortions in anisotropic media occur, for wide-azimuth data, and that these might potentially be related to fracture distribution in the layered media. However, inversion of the azimuthally varying P-wave AVO gradient for the crack density is non-unique without additional information. Aims This research work aims to better understand the seismic anisotropy of shale rocks to improve future exploration by using fracture modelling and azimuthal AVO/AVA for fracture detection, and rock physics to develop a thorough understanding of the reservoir and quantify fracture anisotropy quantitatively and qualitatively. This is a potentially important unconventional oil and gas reservoir of the Late Jurassic age. Specifically, the project aims to improve future oil exploration by using AVAz variations for fracture detection and fracture models in effective media. Scope The scope of this research is to model fractures of the effective medium to see the impact on seismic amplitudes distortions in different azimuthal directions and determine the type of AVO present in the models to compare them with real data in shale-type rocks. Implementation is presented of a new methodology to estimate anisotropic brittleness, the azimuthal TOC and stress field and its comparison with hydraulic treatment pressure data, calculated from inverted volumes with good quality azimuthal seismic data. Rock physics and fluid replacement in fracture models in shale rocks approaches will be tested for (brine/oil/gas) to better understand the fluid substitution in azimuthal synthetic models and the AVAz curves. Motivation The motivation for this work is to develop a better understanding of the anisotropy within the Pimienta Formation, which will help understand the shale-type rock fabric through fracture modelling, azimuthal data for better reservoir characterization in unconventional reservoirs. Methods Based on the effective media theory of fracture models addressed by other researchers, codes were developed and tested to obtain an azimuthal seismic image depending on the type of fracture arrangement (e.g., Hudson, and Linear slip). Within the methodology, in the substitution of fluids, the Linear slip model was tested to verify the synthetic azimuthal response with three cases (Brine/Oil/dry). Azimuthal seismic information provided by PEMEX was used to perform AVO Azimuthal analysis within the Pimienta Formation in order to identify possible fracture swarms and be able to determine the direction of the fast velocity (V_fast) that is related to the direction of fractures and possible current stress. Then rock physics modelling of elastic moduli in an anisotropic way was estimated by developing codes to obtain brittleness, these elastic moduli (e.g., Young´s Modulus and Poisson's Ratio) were used to estimate the stresses in a sub-area in the study area using inverted volumes. Differential Effective Medium (DEM) and Effective Field Method (EFM) have been tested in the study area to estimate the elastic moduli. Results The Pimienta Formation in rock physics template analysis fit much better using friable-sand model instead of friable shale model, different values in anisotropy within Pimienta Formation were found according to the significant amplitude distortions seen in each fracture model which may explain the intrinsic anisotropy of the Pimienta Formation. The azimuthal AVO demonstrated the possible existence of fractures within the Pimienta Formation in the study area according to the differences in the fast velocity (V_fast) and slow velocity (V_slow) and the Thomsen’s parameters, the fluid-filled fracture models through fluid substitution analysis in shale rocks demonstrated amplitude changes depending on the azimuth direction. The elastic properties (e.g., Young´s Modulus and Poisson´s Ratio) were estimated in VTI/HTI modes using the inverted data and finally the stress field using hydraulic treatment pressure information. Conclusions In this research work, two main contributions can be addressed that may help other geoscientists for a better understanding of the anisotropy in shale rock type and can be widely applied for reservoir characterization on unconventional resources in other projects around the world and maybe applied naturally fractured carbonates. 1. A new equation for estimation of the TOC in different azimuths named “upscaled azimuthal TOC “using inverted data from azimuthal seismic data contributed to the novel implementation of the calculation of this attribute which had been experimentally tested on core analysis in different azimuths. 2. A novel approach for the estimation of anisotropic brittleness has contributed to the field of anisotropy on shale rock types by using vertical transverse isotropy (VTI) and horizontal transverse isotropy (HTI) using azimuthal sectors of inverted seismic information. 3. For this research project, applications were developed in the field of geophysics that addressed fractured models (e.g., Hudson, and Linear slip), anisotropic rock physics for the calculation of elastic properties in two main directions 0° (VTI) and 90° (HTI) for the calculation of anisotropic brittleness compared with other researchers in this field. Such applications can help the geoscientific community to model fractures in effective media in a versatile and easy to use way since most software does not handle this type of modelling. 4. These new contributions in geophysics applied to the oil industry were focused on the study of the Pimienta Formation; however, these contributions can be widely used in the development, understanding and characterization of unconventional and carbonate reservoirs around the world. Finally, these contributions and all the analysis carried out in this research work will contribute to more efficient stages design for hydraulic treatment in horizontal wells in unconventional reservoirs, in order to reduce operating costs and the number of wells with the objective of obtaining the highest possible commercial production of hydrocarbon without ignoring the environmental impact and concerns