Petroleum Geoscience - Current Issue

The Lajas Formation (Middle Jurassic) of the Neuquén Basin in Argentina is a renowned unconventional tight gas sandstone reservoir. It has been studied widely from multidiscipline approaches; however, only a few petrophysical studies have been published. The objective of this study is to examine correlations between various porosity measurements obtained through petrographic optical and scanning electron microscopy (SEM), combined with quantitative X-ray diffraction (XRD) mineralogy, and petrophysical laboratory measurements, including nuclear magnetic resonance (NMR at 2 MHz) and gas-filled porosity (GFP). The analysed samples cover a wide compositional spectrum ranging from lithic feldsarenites to feldspathic litharenites, the clay fraction is dominated by chlorite or mixed illite/smectite (I/S) with less than 20% of expandable layers (I/S), and the total porosity ranges from 5 to 13%. Intercrystalline pores, which are associated with clay minerals, are a key component controlling the pore system of the unit. SEM images and a strong correlation between XRD data and the clay-bound water derived from NMR T 1–T 2 maps are clear evidence of this. The analysed reservoir shows a high variability and complexity in the pore structure related to other textural pores (e.g. non-clay intergranular and intragranular pores), thus reflecting the importance of multidisciplinary and multiscale studies that aim to understand the heterogeneous porosity network of tight sandstone reservoirs.

Due to the variability in depositional cycles and the active nature of the constituent minerals, carbonate rocks are commonly strongly modified by diagenetic processes that alter their original rock fabric and petrophysical properties. Conventional petrophysical models do not reliably assess these complexities, requiring extensive calibration efforts or pore-scale image analysis. We introduce a calibration-free method that enables the assessment of pore-network properties such as constriction factor, pore-body and pore-throat size distributions, as well as permeability and capillary pressure based on joint interpretation of nuclear magnetic resonance (NMR) transverse relaxation time (T 2) distribution and electrical conductivity measurements. We successfully applied the introduced method to pre-salt carbonates of the Barra Velha Formation in the Santos Basin of Brazil. The applications of the introduced method for assessing throat-size distribution in the core- and the well-log-scale domains have proven successful in 87 and 73% of the cases, respectively. The permeability estimates from the new method showed more than 42% improvement when compared against those obtained from NMR-based permeability assessment methods. The new method provides real-time and depth-by-depth assessments of the pore-throat size distribution and capillary pressure, minimizing the need for core-based calibration efforts and eliminating the need for detecting cutoff values in NMR-based permeability models.

The Junggar Basin, a major hydrocarbon province in China, contains more than 3 Bt of petroleum and 150 Bcm of natural gas. Within its Central Depression, the Shixi–Mobei Uplift is a key area for oil and gas exploration. This study examines the geological and depositional characteristics of the Sangonghe Formation using cores, microscopy, mineral analysis and seismic profiles. The Sangonghe Formation represents the peak of lacustrine transgression, transitioning to regression in the overlying Xishanyao and Toutunhe formations. It features diverse sedimentary facies, including braided river deltas and lacustrine fans, reflecting a progression from shallow- to deep-lake environments. Palaeogeomorphology, controlled by secondary structural slope-break zones, influenced facies distribution, with braided river deltas above and delta front/lacustrine fans below these zones. Provenance analysis has identified two main sediment sources: a northwestern source affecting the Shixi region's west and north, and a northeastern source impacting the Mobei region's east and NE. Reservoirs are characterized by residual, secondary and primary intergranular pores, with porosity positively correlated with permeability. The diagenetic stage of mesogenetic A2–B is observed, particularly in the Mobei region's east and SE. 2D seismic profiles and well-logging data estimate the areal extent of the lacustrine-fan reservoirs at 25–30 km2, with a gross rock volume of 15–20 km3 and hydrocarbon volumes of 50–100 MMbbl of oil equivalent. Exploration should focus on areas near wells QS and M171 with significant potential identified around wells QS1, QS404, QS403, QS204, QS9, M14, M20, M27, F003 and M171 as priority targets.

The Rovuma Basin, once overlooked for oil and gas exploration, emerged from 2020 as one of the world's most prolific hydrocarbon provinces following the discovery of c. 200 trillion cubic feet (Tcf) of gas in 5 years. Among the most significant discoveries were the supergiant Mamba Field and the giant Coral Field, discovered in 2011–12 by a joint venture led by Eni. Eni was one of the few companies to initiate exploration in the Rovuma Basin in 2006, when the area was regarded as non-attractive.

The Mamba and Coral prospects were initially identified in 2009 using 2D seismic data and were subsequently confirmed in 2010 using 3D seismic imaging. These discoveries are in structural–stratigraphic traps supported by direct hydrocarbon indicators (DHIs). Drilling revealed the presence of multiple high-permeability Paleogene sandstones gas pools, with six of these exceeding the 500 million barrels of oil equivalent (MMboe) threshold, classifying them as giants. Several of the Mamba Field reservoirs extend into the adjacent Area 1, where exploration has been conducted by an Anadarko-led joint venture.

Both fields exhibit exceptional reservoir quality, with reservoir units exceeding 100 m in gross thickness and with extremely high net-to-gross ratios (up to 80–90%). The superior reservoir quality is attributed to the synchronous interaction of turbidite gravity flows and sea-bottom currents, which have redistributed finer sediments and concentrated thick, clean sandstone deposits along the system's depositional axes.

The Coral project represents the first gas production from the Rovuma Basin's deep-water discoveries. Production commenced in November 2022 via the Coral Sul, a floating liquefied natural gas (FLNG) system.