Tuesday July 28, 2026  Edition 120

Welcome to Core Elements #120. Looking back, I think that these 120 editions provide an encyclopedic cross-section of significant and latest research and development in subsurface geoscience and energy exploration. Thank you for your readership and your continued support.

Now, let’s dive into some interesting new geoscience stories.

Rasoul Sorkhabi

Editor, Core Elements

Cambrian Shale Gas

Sub-salt reservoir in The Netherlands (AAPG Bulletin, 2026)

Hydrocarbon resources of Cambrian sediments (541–485 Ma) are relatively underdeveloped. However, studies from China shed light on these old hydrocarbon resources. Let’s look at two recent studies published in AAPG Bulletin.

Where the studies researched:

• Both papers concern the Qiongzhusi Formation of the Sichuan Basin, one of China’s largest and most petroliferous basins.
• The Sichuan Basin is located in the Yangtze craton that lay along the western Gondwana coast during early Cambrian times.
• The Qiongzhusi Shale is a conventional source rock and an unconventional shale gas play.
• During the early Cambrian, deep-water depositional environments prevailed in the Yangtze craton, resulting in deposition of black shale ranging in thickness from 20 to 80 meters.

Study #1. Cambrian Shale Gas Accumulation

Haikuan Nie and colleagues studied the Qiongzhusi Formation as a self-sourced shale gas play.

What they did:

• The researchers analyzed more than 100 shale core samples from three wells and more than 200 outcrop samples.
• The analyses included total organic carbon (TOC), thermal maturity, kerogen isotope composition, mineral assemblages, porosity, permeability, scanning electron microscopy (SEM), isothermal adsorption, high-pressure mercury injection, and Canister desorption.

What they found:

• The integrated study identified two distinct facies in the shale formation:
  • Facies I is organic-rich shale with a TOC greater than 2 percent. This shale is deeply buried, over-pressured shale within the Deyang-Anyue intracratonic rift, which runs through the central Sichuan Basin.
  • Facies II is organic-poor silty shale (with a TOC of less than 0.5 percent) which is over-pressured and occurs along the rims and slopes of the Deyang-Anyue rift.
• The most productive shale gas reservoirs are located around the paleo-uplifts of the Yangtze craton and have equivalent vitrinite reflectance values less than 3.5 percent.
• A similar organic-rich shale, called the Niutitang Shale, also occurs outside the Sichuan Basin in the Yangtze craton, but it is normally pressured and lies at relatively shallower depths.

Study #2. Shale Gas in Carrier Bed Plays of Qiongzhusi Formation

Tonglou Guo and colleagues report on the Qiongzhusi Formation as a conventional source rock and examine how carrier beds within the formation can accumulate shale gas.

What they did:

• The researchers collected samples from six boreholes in the southwestern Sichuan Basin.
• They analyzed the samples by optical microscopy, field emission scanning electron microscopy, X-ray diffraction, helium porosity, TOC, and gas content measurement.

What they found:

• The researchers identified four lithofacies in the silty shale, with sedimentary textures driving differences in physical properties.
• Among these, the laminated siliceous silty shale with relatively low TOC content in the Middle Member of the Qiongzhusi Formation functions as a carrier bed.

Controlling factors:

Natural gas enrichment in the Middle Member is controlled by six factors:

1. Favorable physical properties
2. High feldspar content (averaged 20 percent) with well-developed laminations
3. A moderate TOC content (commonly 0.5 percent)
4. Sufficient natural gas charge
5. An effective seal-reservoir configuration
6. Absence of faults that connect with conventional reservoirs

An Improved Technique for Tying Seismic Images to Wells

An example of seismic image in depth (Interpretation)

Interpretation is a cross-disciplinary journal published jointly by AAPG and the Society of Exploration Geophysicists (SEG). You can subscribe to receive it here. 

A recent issue of Interpretation contains an interesting paper that suggests an improved procedure to tie seismic images to drilled wells.

From time domain to depth domain:

• Two-way travel time or time domain seismic images are usually converted to depth domain images as they are calibrated with well log data and used for structural and sequence stratigraphic interpretation.
• The success of pre-stack depth migration depends on the subsurface seismic velocity field.
• Scaling a depth-migrated image to actual depths can be a complicated and time-consuming process.

New workflow:

Afolabi Babalola and colleagues suggest a new workflow to improve the accuracy and efficiency of seismic-to-well calibration.

The procedure involves two steps:

1. An approximate velocity model is used to generate a geologically reasonable image through vertical depth conversion or depth migration.
2. An interval scaling field is defined and integrated in the depth domain to reposition the data, thereby achieving the desired fit to the well control.

Scaling field:

• The scaling field is derived for each 3D layer that is fully specified by two parameters: a scaling constant and a scaling gradient.
• The scaling field is subject to the same geologic constraints as velocity scaling; that is, it should have values close to one and follow the known stratigraphy and velocity boundaries.

Test results: The proposed workflow was applied to two examples:

1. Synthetic seismic dataset
2. Actual field data from offshore North Sea

Why it matters:

• The proposed procedure does not assume any specific velocity form.
• It provides a closed-form least-squares solution for aligning seismic data to well control in subsurface stratigraphy,
• It eliminates the need for iterative numerical optimization.

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