Quantitative analysis of seismic response to total organic content and thermal maturity in shale gas plays

2011 ◽  
Vol 51 (2) ◽  
pp. 704
Author(s):  
Ebrahim Hassan Zadeh ◽  
Reza Rezaee ◽  
Michel Kemper
Keyword(s):  
Seismic Response ◽  
Shale Gas ◽  
Effective Medium Theory ◽  
Rock Physics ◽  
Sedimentary Basins ◽  
Organic Content ◽  
Effective Porosity ◽  
Forward Modelling ◽  
Gas Field ◽  
Simultaneous Inversion

Although shales constitute about 75% of most sedimentary basins, the studies dealing with their seismic response are relatively few, particularly for the organic rich shale gas. Mapping distribution of shale gas and identifying their maturation level and organic carbon richness is critically important for unconventional gas field exploration and development. This study analyses the sensitivity of acoustic and elastic parameters of shales to variations in pore fluid content. Based on the effective medium theory a rock physics model has been made by inversion of the shale stiffness tensor from sonic, density, porosity and clay content logs. Due to the lack of a generally agreed upon fluid substitution model for shale, a statistical approach to Gassmann’s Model using effective porosity in the near boundary conditions, has been developed to account for shale. Fluid substituted logs—for a variety of maturation levels—and gas saturations were generated and used to make the layered earth models. AVO and seismic forward modelling were performed using the rock physics modelled and the fluid substituted logs on layered models. As part of seismic forward modelling, simultaneous inversion is performed for each model to generate P-impedance, S-impedance and density volumes. The sensitivity of the models were analysed by histogram, cross plotting, cross section highlighting, and body checking techniques. This study showed a dramatic hydrocarbon content effect—specifically gas—in the seismic response of shales.

Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China

2021 ◽  
Author(s):  
Yaowen Liu ◽  
Wei Pang ◽  
Jincai Shen ◽  
Ying Mi
Keyword(s):  
Shale Gas ◽  
Mineral Content ◽  
Horizontal Wells ◽  
Organic Content ◽  
Gas Production ◽  
Liquid Loading ◽  
Comprehensive Overview ◽  
Gas Field ◽  
Well Trajectory ◽  
Positive Effect

Abstract Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed. Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral. The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.

Time-lapse seismic monitoring methodologies applied to the Pyrenees Field, offshore Western Australia

2015 ◽  
Vol 55 (2) ◽  
pp. 412 ◽  
Author(s):  
Ramses Meza ◽  
Guy Duncan ◽  
Konstantinos Kostas ◽  
Stanislav Kuzmin ◽  
Mauricio Florez ◽  
...  
Keyword(s):  
Seismic Response ◽  
Coming Out ◽  
Rock Physics ◽  
Time Lapse ◽  
Reservoir Rock ◽  
Gas Field ◽  
Field Development ◽  
Fluid Saturation ◽  
Band Limited ◽  
4D Seismic

Time-lapse dedicated 3D seismic surveys were acquired across the Pyrenees oil and gas field, Exmouth Sub-basin to map production-induced changes in the reservoir. Rock-physics 4D modelling showed that changes in pore pressure and fluid saturation would produce a time-lapse seismic response of sufficient magnitude, in both amplitude and velocity, to overcome time-lapse noise. The dominant observed effect is associated with gas coming out of solution. The reservoir simulation model forecasted that reservoir depletion would cause gas breakout that would impact the elastic properties of the reservoir. The effect of gas breakout can be clearly observed on the 4D seismic data as a change in both amplitude and velocity. The analysis of the seismic datasets was proven to be enhanced significantly by using inversion methodologies. These included a band-limited extended-elastic impedance (EEI) approach, as well as simultaneous 4D elastic inversion. These datasets, combined with rock physics modelling, enabled quantitative interpretation of the change in 4D seismic response which was a key tool for assisting with the infill well placement and field development strategy.

Geophysical pore type inversion in carbonate reservoir: integration of cores, well-logs, and seismic data (Yadana field, offshore Myanmar)

Geophysics ◽  
2021 ◽  
pp. 1-69
Author(s):  
Thomas Teillet ◽  
François Fournier ◽  
Luanxiao Zhao ◽  
Jean Borgomano ◽  
Fei Hong
Keyword(s):  
Seismic Data ◽  
Effective Medium Theory ◽  
Rock Physics ◽  
Carbonate Reservoir ◽  
Well Logs ◽  
Inversion Method ◽  
Gas Field ◽  
Medium Theory ◽  
Scale Thickness ◽  
Pore Types

Detection of pore types and diagenetic features from seismic data is a major challenge for the evaluation of carbonate reservoirs in the subsurface. Based on a detailed petrographical and petrophysical analysis of carbonate rock using optical and scanning electron microscopy, mercury-injection measurements, digital image analysis, and well logs, we have determined the potential of the geophysical pore type (αP) inversion a rock physics inversion scheme based on the differential effective medium theory – to quantitatively and qualitatively characterize the pore type distribution from acoustic data in the Yadana carbonate gas field (Early Miocene, offshore Myanmar). The geophysical pore type (αP) is revealed to be an upscalable parameter, whose depositional/diagenetic interpretation may be performed at well log and at seismic scales. We apply the inversion method on a 3D seismic data to map the reservoir-scale distribution and highlight the occurrence of laterally extended (100–1000 m) subseismic- to seismic-scale (thickness >5 m) geologic bodies. From this approach, two main reservoir geobodies are discriminated and interpreted in terms of depositional and diagenetic fabrics: (1) highly microporous, decameter-scale reservoir units (approximately 80% of the reservoir), mainly consisting of foraminiferal, red algae floatstone to rudstone with vuggy, moldic porosity, and characterized by moderate to high αP (0.11–0.20) and (2) thin, stratiform, cemented scleractinian floatstone/brecciated units (5–10 m; approximately 20% of the reservoir) with low microporosity and macroporosity and exhibiting low αP values (<0.11).

Quantitative prediction of total organic carbon content in shale-gas reservoirs using seismic data: A case study from the Lower Silurian Longmaxi Formation in the Chang Ning gas field of the Sichuan Basin, China

2018 ◽  
Vol 6 (4) ◽  
pp. SN153-SN168 ◽  
Author(s):  
Sheng Chen ◽  
Wenzhi Zhao ◽  
Qingcai Zeng ◽  
Qing Yang ◽  
Pei He ◽  
...  
Keyword(s):  
Wave Velocity ◽  
Shale Gas ◽  
Rock Physics ◽  
Elastic Parameter ◽  
P Wave ◽  
Quantitative Prediction ◽  
S Wave ◽  
Gas Field ◽  
Lower Silurian ◽  
Data Volume

We present a quantitative prediction of total organic carbon (TOC) content for shale-gas development in the Chang Ning gas field of the Sichuan Basin (China). We have used the rock-physics analysis method to define the geophysical characteristics of the reservoir and the most sensitive elastic parameter to TOC content. We established a quantitative prediction template of the TOC content by rock-physics modeling. Well data and 3D seismic data were combined for prestack simultaneous inversion to obtain the most sensitive elastic parameter data volume. According to the prediction template, we transformed the sensitive elastic parameter data volume to the TOC content volume. The rock-physics analysis indicates that the reservoir with a high TOC content in the Lower Silurian Longmaxi Formation (Fm) of the Chang Ning (CN) gas field is characterized by low density, low P-wave velocity ([Formula: see text]), low S-wave velocity ([Formula: see text]), low Poisson’s ratio (PR), and low ratio of P-wave velocity to S-wave velocity ([Formula: see text]). Density is the most sensitive elastic parameter to TOC content. The rock-physics model suggests that density is negatively correlated with TOC content, and the relationship between them changes under different porosities. The reservoir with high TOC content is mainly distributed at the bottom of the Longmaxi Fm and in the central and east central area of the study field. The quantitative prediction results are in good agreement with the log interpretation and production test. Therefore, it has important implications for the efficient development of the shale-gas reservoir in the basin.

scholarly journals Prestack inversion and multiattribute analysis for porosity, shale volume, and sand probability in the Havert Formation of the Goliat field, southwest Barents Sea

2017 ◽  
Vol 5 (3) ◽  
pp. SL69-SL87 ◽  
Author(s):  
Honore Dzekamelive Yenwongfai ◽  
Nazmul Haque Mondol ◽  
Jan Inge Faleide ◽  
Isabelle Lecomte ◽  
Johan Leutscher
Keyword(s):  
Barents Sea ◽  
A Priori ◽  
Rock Physics ◽  
Lower Triassic ◽  
Effective Porosity ◽  
Distribution Functions ◽  
Simultaneous Inversion ◽  
Shale Volume ◽  
Prestack Inversion ◽  
Shaly Sand

An integrated innovative multidisciplinary approach has been used to estimate effective porosity (PHIE), shale volume ([Formula: see text]), and sand probability from prestack angle gathers and petrophysical well logs within the Lower Triassic Havert Formation in the Goliat field, Southwest Barents Sea. A rock-physics feasibility study revealed the optimum petrofacies discriminating ability of extended elastic impedance (EEI) tuned for PHIE and [Formula: see text]. We then combined model-based prestack inversion outputs from a simultaneous inversion and an EEI inversion into a multilinear attribute regression analysis to estimate absolute [Formula: see text] and PHIE seismic attributes. The quality of the [Formula: see text] and PHIE prediction is shown to increase by integrating the EEI inversion in the workflow. Probability distribution functions and a priori petrofacies proportions extracted from the well data are then applied to the [Formula: see text] and PHIE volumes to obtain clean and shaly sand probabilities. A tectonic-controlled point-source depositional model for the Havert Formation sands is then inferred from the extracted sand bodies and the seismic geomorphological character of the different attributes.

Sign in / Sign up

Export Citation Format

Share Document