Integrated interpretation of gravity, magnetic, seismic, and well data to image volcanic units for oil-gas exploration in the eastern Junggar Basin, northwest China

2020 ◽  
Vol 8 (4) ◽  
pp. SS113-SS127
Author(s):  
Kaijun Xu ◽  
Yaoguo Li
Keyword(s):  
Seismic Data ◽  
Volcanic Rocks ◽  
Junggar Basin ◽  
Magnetic Data ◽  
Magnetic Method ◽  
Data Set ◽  
Amplitude Inversion ◽  
Gravity And Magnetic ◽  
Integrated Interpretation ◽  
Well Data

We carried out a multigeophysical data joint interpretation to image volcanic units in an area where seismic imaging is difficult due to complicated and variable volcanic lithology. The gravity and magnetic methods can be effective in imaging the volcanic units because volcanic rocks are often strongly magnetic and have large density contrasts. Gravity and magnetic data have good lateral resolution, but they are faced with challenges in defining the depth extent. Although seismic data make for poor imaging in volcanic rocks, they can provide a reliable stratigraphic structure above volcanic rocks to improve the vertical resolution of the gravity and magnetic method. We have developed an integrated interpretation method that combines the advantages of seismic, gravity, magnetic, and well data to generate a 3D quasigeology model to image volcanic units. We first use seismic data to obtain the stratigraphic boundaries, and then we apply an anomaly stripping method based on a seismic-derived structure to extract residual gravity and magnetic anomaly produced by volcanic rocks. We further perform the 3D gravity and magnetic amplitude inversion to recover the distribution of the density and effective susceptibility. We perform geology differentiation using the inverted density and effective magnetic susceptibility to identify the spatial distribution of four groups of volcanic units. The results show that the integrated interpretation of multigeophysical data can significantly decrease the uncertainty associated with any single data set and yield more reliable imaging of lateral and vertical distribution of volcanic rocks.

Concealed faults and intrusions identification based on multiscale edge detection and 3D inversion of gravity and magnetic data: A case study in Qiongheba area, Xinjiang, Northwest China

2019 ◽  
Vol 7 (2) ◽  
pp. T331-T345 ◽  
Author(s):  
Jiayong Yan ◽  
Xiangbin Chen ◽  
Guixiang Meng ◽  
Qingtian Lü ◽  
Zhen Deng ◽  
...  
Keyword(s):  
Edge Detection ◽  
Junggar Basin ◽  
Northwest China ◽  
Gold Deposits ◽  
Combination Method ◽  
Magnetic Data ◽  
3D Inversion ◽  
Data Set ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data

Qiongheba is a polymetallic ore concentration area located in the east margin of the Junggar Basin in Xinjiang, Northwest China. Because all three main types of metal deposits (porphyry-type copper, skarn-type iron-copper, and structural altered rock-type gold deposits) in this area are controlled strictly by fault structures and intrusions buried under the Quaternary sediments, the detection of concealed faults and intrusions is of great significance for mineral prospecting. We aim to make clear the faults and intrusions based on the high-precision gravity and magnetic data set. First, multiscale edge detection of gravity and magnetic data is used to distinguish and divide the faults system. Second, 3D recognition of concealed intrusions combining with 3D inversion and multiscale edge detection of gravity and magnetic is carried out to construct the 3D formation of concealed intrusions. Last, seven prospecting targets are proposed based on our research and existed regional geologic and geochemical information, and two of them have been confirmed to be rich in polymetal (Cu-Fe-Mo-Au in the Layikeleke deposit and Cu in the Baxi deposit) by drilling. Our research results not only proved the effectiveness of the combination method of 3D inversion and multiscale edge detection of gravity and magnetic data in the prospecting of concealed faults and intrusions, but they also provide abundant information for mineral exploration prediction in the Qiongheba area.

Oldest preserved sodium carbonate evaporite: Late Paleozoic Fengcheng Formation, Junggar Basin, NW China

2020 ◽  
Author(s):  
Tingting Wang ◽  
Jian Cao ◽  
Alan R. Carroll ◽  
Dongming Zhi ◽  
Yong Tang ◽  
...  
Keyword(s):  
Sodium Carbonate ◽  
Organic Geochemistry ◽  
Volcanic Rocks ◽  
Junggar Basin ◽  
Late Paleozoic ◽  
Hypersaline Lake ◽  
Data Set ◽  
Nw China ◽  
Petrographic Analyses ◽  
Geologic Setting

Sodium carbonate evaporites can provide important paleoclimatic constraints and economic resources but are relatively rare; most known examples are limited to the Cenozoic. The first known late Paleozoic occurrence was recently reported from the Fengcheng Formation in the northwestern Junggar Basin, NW China. However, its mineralogy, age, and geologic setting have been sparsely documented. To help establish a broader understanding of the formation of these important deposits, this paper presents a comprehensive new data set that includes drill core, well logs, petrographic analyses, X-ray diffraction data, organic geochemistry (biomarkers), and U-Pb zircon age data. Evaporite deposition is estimated to have occurred between ca. 305 Ma and 296 Ma in a series of extensional grabens that hosted a stratified, hypersaline lake (or lakes). The lake deposits are closely associated with coeval volcanic rocks, suggesting that subsurface interaction of these with CO2-enriched hydrothermal fluids may have contributed to the excess alkalinity required to precipitate Na-carbonate. Trona (NaHCO3 · Na2CO3 · 2H2O) in the Fengcheng Formation was likely formed syndepositionally and then partly replaced by wegscheiderite (Na2CO3 · 3NaHCO3). Other evaporite minerals most likely formed during diagenesis. The Fengcheng Formation also contains nahcolite (NaHCO3), which requires pCO2 >680 ppm to form, although no textural evidence was found to demonstrate a primary origin. The presence of extensive lacustrine evaporites nonetheless reflects a relatively warm and arid climate at ∼40−50°N that apparently coincided with the late Paleozoic icehouse.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

Bright spots, milligals, and gammas

Geophysics ◽  
1982 ◽  
Vol 47 (12) ◽  
pp. 1693-1705
Author(s):  
Alan O. Ramo ◽  
James W. Bradley
Keyword(s):  
Seismic Data ◽  
Magnetic Data ◽  
Amplitude Analysis ◽  
Seismic Amplitude ◽  
The North ◽  
Gravity And Magnetic ◽  
Amplitude Anomaly ◽  
North Edge ◽  
Gravity And Magnetic Data ◽  
Seismic Anomaly

Spatially discontinuous high‐amplitude seismic reflections were encountered in seismic data acquired in the early 1970s in northeast Louisiana and southwest Arkansas. Large acoustic impedance contrasts are known to result from gaseous hydrocarbon accumulations. However, amplitude anomalies may also result from large density and velocity contrasts which are geologically unrelated to hydrocarbon entrapment. A well drilled on the northeast Louisiana amplitude anomaly encountered 300 ft of rhyolite at a depth of 6170 ft. Subsequent gravity and total field magnetic profiles across the feature revealed the presence of 0.2 mgal and 17 gamma anomalies, respectively. The measured magnetic susceptibility of the rhyolite was 0.0035 emu and the measured density contrast was [Formula: see text]. Model studies based on the seismically determined areal extent of the anomaly and the measured thickness of rhyolite accounted for the observed gravity and magnetic anomalies. The southwest Arkansas amplitude anomaly was a sheet‐like reflection which terminated to the north and west within the survey area. Two north‐south gravity profiles exhibited a negative character over the sheet‐like reflector but did not exhibit a clear spatial correlation with the north limit of the seismic anomaly. Two north‐south magnetic profiles exhibited tenuous 4 gamma anomalies which appeared to be spatially correlated with the interpreted north edge of the seismic anomaly. A subsequent wildcat well encountered no igneous material but did penetrate 200 ft of salt at about 7500 ft. Reassessment of the gravity and magnetic data indicated that this seismic amplitude anomaly is not attributable to an intrasedimentary igneous source; it suggested a salt‐related 0.2 to 0.3 mgal minimum coextensive with the observed seismic amplitude anomaly. Present amplitude analysis technology would treat these seismic data with suspicion. However, gravity and magnetic data acquisition can provide a relatively inexpensive means for evaluation and verification of amplitude anomalies and thus should be an adjunct for land seismic exploration utilizing amplitude analysis.

Fracture detection via correlating P-wave amplitude variation with offset and azimuth analysis and well data in eastern central Saudi Arabia

2017 ◽  
Vol 5 (4) ◽  
pp. T531-T544
Author(s):  
Ali H. Al-Gawas ◽  
Abdullatif A. Al-Shuhail
Keyword(s):  
Saudi Arabia ◽  
Seismic Data ◽  
Production Data ◽  
Fracture Zones ◽  
Fracture Detection ◽  
Amplitude Variation ◽  
Data Set ◽  
Amplitude Variation With Offset ◽  
Well Data ◽  
Patch Geometry

The late Carboniferous clastic Unayzah-C in eastern central Saudi Arabia is a low-porosity, possibly fractured reservoir. Mapping the Unayzah-C is a challenge due to the low signal-to-noise ratio (S/N) and limited bandwidth in the conventional 3D seismic data. A related challenge is delineating and characterizing fracture zones within the Unayzah-C. Full-azimuth 3D broadband seismic data were acquired using point receivers, low-frequency sweeps down to 2 Hz, and 6 km patch geometry. The data indicate significant enhancement in continuity and resolution of the reflection data, leading to improved mapping of the Unayzah-C. Because the data set has a rectangular patch geometry with full inline offsets to 6000 m, using amplitude variation with offset and azimuth (AVOA) may be effective to delineate and characterize fracture zones within Unayzah-A and Unayzah-C. The study was undertaken to determine the improvement of wide-azimuth seismic data in fracture detection in clastic reservoirs. The results were validated with available well data including borehole images, well tests, and production data in the Unayzah-A. There are no production data or borehole images within the Unayzah-C. For validation, we had to refer to a comparison of alternative seismic fracture detection methods, mainly curvature and coherence. Anisotropy was found to be weak, which may be due to noise, clastic lithology, and heterogeneity of the reservoirs, in both reservoirs except for along the western steep flank of the study area. These may correspond to some north–south-trending faults suggested by circulation loss and borehole image data in a few wells. The orientation of the long axis of the anisotropy ellipses is northwest–southeast, and it is not in agreement with the north–south structural trend. No correlation was found among the curvature, coherence, and AVOA in Unayzah-A or Unayzah-C. Some possible explanations for the low correlation between the AVOA ellipticity and the natural fractures are a noisy data set, overburden anisotropy, heterogeneity, granulation seams, and deformation.

Building tilted transversely isotropic depth models using localized anisotropic tomography with well information

Geophysics ◽  
2010 ◽  
Vol 75 (4) ◽  
pp. D27-D36 ◽  
Author(s):  
Andrey Bakulin ◽  
Marta Woodward ◽  
Dave Nichols ◽  
Konstantin Osypov ◽  
Olga Zdraveva
Keyword(s):  
Seismic Data ◽  
Model Building ◽  
Symmetry Axis ◽  
Transverse Isotropy ◽  
Synthetic Data ◽  
Rock Physics ◽  
Transversely Isotropic ◽  
Data Set ◽  
Anisotropic Models ◽  
Well Data

Tilted transverse isotropy (TTI) is increasingly recognized as a more geologically plausible description of anisotropy in sedimentary formations than vertical transverse isotropy (VTI). Although model-building approaches for VTI media are well understood, similar approaches for TTI media are in their infancy, even when the symmetry-axis direction is assumed known. We describe a tomographic approach that builds localized anisotropic models by jointly inverting surface-seismic and well data. We present a synthetic data example of anisotropic tomography applied to a layered TTI model with a symmetry-axis tilt of 45 degrees. We demonstrate three scenarios for constraining the solution. In the first scenario, velocity along the symmetry axis is known and tomography inverts for Thomsen’s [Formula: see text] and [Formula: see text] parame-ters. In the second scenario, tomography inverts for [Formula: see text], [Formula: see text], and velocity, using surface-seismic data and vertical check-shot traveltimes. In contrast to the VTI case, both these inversions are nonunique. To combat nonuniqueness, in the third scenario, we supplement check-shot and seismic data with the [Formula: see text] profile from an offset well. This allows recovery of the correct profiles for velocity along the symmetry axis and [Formula: see text]. We conclude that TTI is more ambiguous than VTI for model building. Additional well data or rock-physics assumptions may be required to constrain the tomography and arrive at geologically plausible TTI models. Furthermore, we demonstrate that VTI models with atypical Thomsen parameters can also fit the same joint seismic and check-shot data set. In this case, although imaging with VTI models can focus the TTI data and match vertical event depths, it leads to substantial lateral mispositioning of the reflections.

A seismic to simulation unconventional workflow using automated fault-detection attributes

2017 ◽  
Vol 5 (3) ◽  
pp. SJ41-SJ48 ◽  
Author(s):  
Jesse Lomask ◽  
Luisalic Hernandez ◽  
Veronica Liceras ◽  
Amit Kumar ◽  
Anna Khadeeva
Keyword(s):  
Seismic Data ◽  
Spatial Information ◽  
Spatial Location ◽  
Statistical Information ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Data Set ◽  
Fault Indicator ◽  
Well Data ◽  
Additional Constraints

Natural fracture networks (NFNs) are used in unconventional reservoir simulators to model pressure and saturation changes in fractured rocks. These fracture networks are often derived from well data or well data combined with a variety of seismic-derived attributes to provide spatial information away from the wells. In cases in which there is a correlation between faults and fractures, the use of a fault indicator can provide additional constraints on the spatial location of the natural fractures. We use a fault attribute based on fault-oriented semblance as a secondary conditioner for the generation of NFNs. In addition, the distribution of automatically extracted faults from the fault-oriented semblance is used to augment the well-derived statistics for natural fracture generation. Without the benefit of this automated fault-extraction solution, to manually extract the fault-statistical information from the seismic data would be prohibitively tedious and time consuming. Finally, we determine, on a 3D field unconventional data set, that the use of fault-oriented semblance results in simulations that are significantly more geologically reasonable.

scholarly journals MODERN OPPORTUNITIES FOR BUILDINGCONCEPTUAL GEOLOGICAL MODELS

Neft i gaz ◽  
2020 ◽  
Vol 5 (119) ◽  
pp. 41-54
Author(s):  
N.G. MATLOSHINSKIY ◽  
◽  
R.N. MATLOSHINSKIY ◽  
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
The Other ◽  
Total Correlation ◽  
Wide Range ◽  
Geological Models ◽  
Integrated Interpretation ◽  
Well Data ◽  
The One ◽  
Gas Potential

Modern integrated interpretation of borehole and seismic data allows solving a wide range of problems based on the construction of reliable conceptual geological models of the studied areas. The total correlation of seismic horizons allows us to consider the studied section in all its details with the maximum use of seismic information and to ensure its objective comparison with well data. This approach is especially important for the purposeful study of the prospects for oil and gas potential, both in structural traps and non-structural traps, on the one hand, and the construction of objective geostatic models, on the other

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