Rock Physics Trends Research Articles

Applicability of 2D algorithms for 3D characterization in digital rocks physics: an example of a machine learning-based super resolution image generation

Digital rock physics is based on imaging, segmentation and numerical computations of rock samples. Due to challenges regarding the handling of a large 3-dimensional (3D) sample, 2D algorithms have always been attractive. However, in 2D algorithms, the efficiency of the pore structures in the third direction of the generated 3D sample is always questionable. We used four individually captured µCT-images of a given Berea sandstone with different resolutions (12.922, 9.499, 5.775, and 3.436 µm) to evaluate the super-resolution 3D images generated by multistep Super Resolution Double-U-Net (SRDUN), a 2D algorithm. Results show that unrealistic features form in the third direction due to section-wise reconstruction of 2D images. To overcome this issue, we suggest to generate three 3D samples using SRDUN in different directions and then to use one of two strategies: compute the average sample (reconstruction by averaging) or segment one-directional samples and combine them together (binary combination). We numerically compute rock physical properties (porosity, connected porosity, P- and S-wave velocity, permeability and formation factor) to evaluate these models. Results reveal that compared to one-directional samples, harmonic averaging leads to a sample with more similar properties to the original sample. On the other hand, rock physics trends can be calculated using a binary combination strategy by generating low, medium and high porosity samples. These trends are compatible with the properties obtained from one-directional and averaged samples as long as the scale difference between the input and output images of SRDUN is small enough (less than about 3 in our case). By increasing the scale difference, more dispersed results are obtained.

Using recursive inversion as input for gross-rock volume extraction from lithology prediction volumes: How bad can it be?

SummaryReserves and Resources can be directly estimated by using seismic lithology prediction volumes generated from AVO inversion, calibrated to wells, to estimate sand rock volumes within a stratigraphic interval. However, high quality AVO inversion data and studies are not always available. This case study utilises recursive inversion to generate prediction cubes for input to geobody based gross rock volume estimates.Here, relative recursive inversions of the near and far seismic stacks are generated. EEI rotation theory was applied to calculate relative AI and Vp/Vs volumes. These have then been converted to band-limited absolute inversion volumes by adding a low frequency model built using seismic horizons, well logs and rock physics trends. Finally, probability density functions calibrated to wells were estimated to calculate lithology prediction volumes. A sand probability volume is then calculated using these probability density functions. A relative approach has not been applied due to poor separability of different lithologies in cross-plot space.This method is applied to an area where a single multiazimuth PSDM seismic survey covers two gas fields and several deep exploration prospects. However, previous inversion studies were limited to the individual fields (each inverted separately), incorporated fluid contact information and did not cover the deeper exploration, so were therefore considered sub-optimal.Although there is potential for results from this method to be “bad”, this case study was successful. The inversion volumes generated as part of this study enabled a wholistic view of the fields and exploration prospectivity, which had not been previously possible with the available QI volumes. The seismic data used for input was exceptionally good, and there was abundant well control to provide control and for use in blind testing. The amount of validation and quality-control applied to this project cannot be under-stated. It is critically important to be mindful of the limitations and broad assumptions that are applied as part of this work-flow. These include the addition of the low-frequency model, wavelet affects not being taken into account and depth decay of the lithology predictions due to the application of a single PDF.

Rock-physics analysis of clay-rich source rocks on the Norwegian Shelf

Rock-physics trends and properties of clay-rich source rocks are investigated in selected wells in the North Sea and Norwegian Sea. Properties can vary significantly because of burial compaction, composition, diagenesis, organic richness, and maturation. The many competing effects can be difficult to disentangle in traditional rock-physics crossplots. However, nearly all the source-rock data in the study are bounded nicely by linear trends that are based on rock-physics models, in acoustic-impedance (AI) versus shear-impedance (SI) crossplots. These reference models serve as a nice screening tool for organic richness and/or maturation level (i.e., hydrocarbon generation and expulsion), regardless of burial depth. The use of rock-physics templates for the early mature to mature stage of clay-rich source rocks is demonstrated by combining a simple basin-modeling approach with a rock-physics model using Backus average in which the organic-rich shale is represented by a transverse isotropic mixture of clays, kerogen, and hydrocarbons. The resulting templates are bounded nicely by reference trends and explain some of the observed trends in the data. However, the local presence of carbonaceous material and diagenesis within the source rock, which have not been accounted for in the rock-physics modeling, might explain why some of the data points have higher impedances and lower VP/VS than the template models. Finally, source rocks with hydrocarbon saturation can cause AVO signatures similar to hydrocarbon-filled sands and therefore represent false positives in exploration.

Silvereye 1 Case Study – the False Positive

The objective of the recent Silvereye 1 exploration well in Bass Basin was to test Paleocene and Cretaceous sandstone reservoirs of the Eastern View Coal Measures (EVCM). The well was designed to test a faulted four-way dip closure and stratigraphic trap interpreted as a sand filled channel. Pre-drill analysis relied on a recent 3D marine seismic survey with well control provided by 2D seismic ties to wells located in adjacent exploration permits. The pre-drill interpretation of a gas-bearing sandstone-filled channel was based on a brightening of seismic amplitude (a predominantly class 3 AVO anomaly) associated with the channel feature. The AVO behaviour was consistent with the response at the same gas-bearing stratigraphic level in the nearby White Ibis 1 well, hence the presence of hydrocarbons (gas) was considered likely. The well intersected the predicted stratigraphy but failed to encounter hydrocarbons at any of the reservoir intervals. A channel sand was intersected within a thick claystone interval at the pre-drill proposed stratigraphic trap. The claystone is characterised by low-velocity and high density, while the sandstone has slightly higher porosity than sand typically encountered in this section. It was the contrasting characteristics of these lithologies that determined the class 3 AVO response and the misinterpretation of the anomaly. We show that a close examination of the rock physics trends of reservoir and non-reservoir rocks in surrounding wells could have allowed this scenario to be recognised pre-drill. Failure to recognise all possible lithological characteristics in the pre-drill AVO model meant that not all outcomes were analysed, and hence were not included in the risking of the prospect . The post drill evaluation has recognised that rock physics studies are an important tool for recognising all possible scenarios to aid in prospect evaluation. Had a more comprehensive rock physics evaluation been conducted, the actual outcome would likely have been recognised as one of several possibilities, but would not necessarily have prevented drilling of the well.

Statistical classification of seismic amplitude for saturation and net-to-gross estimates

Inverting geophysical data for reservoir properties of interest requires linking the underlying geology to the observed data. In order to do so, the geologic heterogeneity needs to be modeled to examine how it controls the reservoir properties and affects any geophysical measurements. This task becomes exceedingly complex because of the infinite number of possible geologic models that could be constructed even though most of them are unreasonable from a geologic standpoint. If seismic data are used to constrain that modeling process, then the ambiguity in the problem may be reduced. Two reservoir parameters of interest for both fluid-flow and geologic modeling are saturation (Sw) and net-to-gross (N/G). Rock-physics trends indicate that the elastic and seismic responses of these two properties typically overlap one another. In seismic applications, therefore, a change in one property can be easily misinterpreted as a variation in the other. Within a reservoir-modeling scenario, how can these two parameter...

Scale of experiment and rock physics trends

Because rock is heterogeneous at all scales, it is often invalid to assign a single porosity, permeability, resistivity, or velocity to a volume in the subsurface. Well data demonstrate that these properties can vary appreciably between two points just a foot apart. The same happens at the pore scale. Consider, for example, a CT scan of a 1.3-mm Berea sandstone cube (Figure 1). The porosity of this sample, as calculated by counting the blue (pore space) pixels, is 0.164.

Paleocene exploration in the Faroe–Shetland Channel: disappointments and discoveries

While the early drilling in the UK West of Shetlands area was concentrated on structural highs, the 1992 discovery of oil in the deep-water Paleocene sands of the Foinaven Field re-invigorated exploration interest in hydrocarbon traps with a stratigraphic element and encouraged a high level of participation in the UK 16th Licensing Round (1995) west of Britain. Many of the main exploration targets in these rounds were mapped as sand pinchouts onto either the basin margin or onto intra-basinal structural highs, for example, updip to the southeast of the 1989 well, 205/9-1. Few of the initial wells drilled to test this type of pinchout play were commercially successful but, as part of the exploration effort, a large area of the basin was blanketed with 3D seismic data on which more subtle features could be recognized. Seismic anomalies similar to those of the successful discoveries were sought on the new 3D data, as this type of play relied heavily on seismic attributes to help define risks and reserve size. The Foinaven and Schiehallion fields have a suite of attractive seismic characteristics and exploration effort was driven by the search for similar seismic anomaly features throughout the Atlantic Margin. As wells were drilled on 16th Round acreage, some of the targeted seismic reflection anomalies, originally seen as direct hydrocarbon indicators, turned out to have different causes. Representative examples are shown from the central part of Quadrant 205 in which tuning, seismic artefacts, porosity effects and unexpected igneous lithologies contributed to the drilling of unsuccessful exploration wells. The variation with depth of rock physics trends in the area are shown, the characteristics of some direct hydrocarbon seismic indicators are modelled and comments are made on the sensitivity of the modelled seismic response to shear velocity estimation. The former ‘White Zone’ or undesignated area, the previously unlicensed acreage between the UK and Faroe Islands, was opened through the Faroes 1st and the UK 19th Licensing Rounds in 2000 and 2001. By 2003 the first 8 of 15 commitment exploration wells were drilled in these licenses. Together with an assessment of the seismic anomalies and the risks of stratigraphical traps in the area, analysis of the petroleum system led to the siting of the 6004/16-1z well on the structural high of a Cenozoic inversion anticline. The resulting ‘Marjun’ discovery, the first in the Faroes, consisted of a gross 170 m hydrocarbon column in the T10 Early Paleocene interval, thus opening a new fairway in the area. The challenge has evolved in the last five years from finding an effective reservoir in the basinal areas to the search for a robust trap with an intact sealing lithology.

AVO classification of lithology and pore fluids constrained by rock physics depth trends

Elastic properties of rocks are strongly influenced by local geological trends and can change markedly even within a sedimentary basin. Critical geologic factors that control elastic properties are either related to depositional environment or burial history. Knowledge about the expected change in seismic response, as a function of depositional or compactional trends, will increase the ability to predict hydrocarbons, especially in areas with little or no well log information. In other words, by understanding the geologic constraints in an area of exploration, one can reduce the range of expected variability in rock properties and hence reduce the uncertainties in seismic reservoir prediction. Figure 1 depicts this problem, where we assume there is well log control only in the shallow interval on the shelf edge. Before extending the exploration into more deeply buried zones, or to more distal deepwater environments, it is important to understand the rock physics trends in the area.