**1. Introduction**

Worldwide, oil reserves estimated in traditional reservoirs are in a consistent decline, while triggering complications and enhancements of technologies of hydrocarbon exploration and characterization. One of the promising solutions to maintain production at current levels is the development of hard-to-recover reserves, including low-permeable (tight) carbonate reservoirs [1,2].

The correct determination of reservoir properties for the case remains challenging for oil and gas companies despite an increase in their interest in developing such formations and deposits [3–5]. Both porosity and permeability contribute significantly to resource assessment and reserves' estimation of a target asset.

Tight carbonate rocks feature low porosity and permeability, the absence of structural, and stratigraphic control of the distribution of oil-containing intervals, which do not allow distinguishing them from well-logging data. All mentioned factors lead to a low oil recovery factor (<10–20%). Therefore, one critical task is the development of methods for estimating the reservoir properties of tight rocks.

Conventional methods for petrophysical core analysis were established during the 1970–1980s, when the development of conventional reserves had reached its peak [3]. Notably, the measured porosity varied in the range of 10–30% and permeability 10–200 mD.

The main obstacles to the proper determination of the reservoir properties (porosity and permeability) of tight reservoir rocks are their low porosity (<3–5%), and low permeability (<1 mD), as well as a high degree of heterogeneity of void space structure (VSS). However, conventional laboratory methods were developed for the characterization of conventional highly porous and permeable reservoir rocks, such as well-sorted sandstones. Complex reservoirs reside at the edge of their operating envelope in terms of porosity and permeability [6]. For example, conventional Dean–Stark extraction tends to overestimate water saturation in tight reservoirs, and reliable results require new approaches [7]. Indeed, conventional porosity techniques may overestimate and implicitly add uncertainty to the results of both geological and hydrodynamic modeling of field-scale processes [8].

In other words, the target formations fall out of the operational domain for conventional methods. Therefore, companies (operators and oilfield service divisions) tend to develop or adopt new techniques and equipment for such measurements.

At the current stage, laboratory petrophysical methods targeting tight reservoirs fall into two groups. The first group includes bulk methods, delivering a single integral property value (the result of determination) for a target rock sample. The second group improves the understanding of bulk values by direct (explicit) imaging of the void space structure, as well as mineral and organic matrix.

The petrophysical properties of the target rocks sugges<sup>t</sup> a complicated inhomogeneous microstructure. The dimensions of voids fall below the micrometer scale. They require novel methods for evaluating the reservoir properties and high-resolution imaging, which obtains three-dimensional (3D) images of the void space structure with resolution up to 50 nm [9,10].

Multiple publications characterize the porosity [11,12], the porous structure, and permeability of tight sands, shales, and carbonates [13–15]. Based on published papers, we summarized conventional methods (basic in core analysis) and unconventional methods (widely applied for tight rock characterization) (Table 1).


**Table 1.** Methods applied for reservoir properties' laboratory assessment.

Multiscale research studies on tight reservoirs sugges<sup>t</sup> utilizing novel laboratory methods for characterizing the reservoir properties and the void space structure [16–20]. Nuclear magnetic resonance (NMR) and mercury injection capillary pressure (MICP) methods have been introduced as primary tools for defining the porosity and pore size, whereas the X-ray computed tomography (CT) and SEM (or FIB-SEM) often visualize the void space of tight sands and carbonates.

First of all, the use of NMR relaxometry in the study of low-porous sand and clay rocks falls into a separate group [21,22]. In the presence of clays or at low porosity, the most commonly used T2 cuto ff values ultimately give inaccurate estimates of permeability due to reservoir heterogeneity. X-ray tomography (CT) in a modern petrophysical laboratory is becoming an increasingly popular method in the study of rocks, complementing routine, and special core analysis [23]. X-ray microtomography often joins mercury porosimetry to study shale and tight rocks [24,25]. Di fferent industries have implemented scanning electron microscopy (SEM) for more than 55 years. One of the key aims has been to characterize various industrial materials at micro- and nanoscales [26]. Today's increased interest from petroleum engineers to detailed characterization of tight reservoirs has raised interest in the application of SEM for shale investigations at very high magnifications [27]. Various microstructural techniques, including X-ray CT, petrographical microscopy, and SEM, identify and characterize macroto nanoscale voids in tight carbonate rocks.

However, the application of the listed unconventional methods is complicated. Firstly, published case studies mainly cover only a few methods for characterizing the reservoir properties. The majority of publications present success stories with excellent and reliable results, even in cases of low- and ultra-low permeable reservoir rocks [8,16,17,19]. Therefore, recommended workflows often do not include failure scenarios and do not highlight the limitations of conventional methods. Secondly, all existing workflows present case studies for a particular type of reservoir (tight sands and tight shales) and rarely provide the application of the same procedure to di fferent rock types. Therefore, it remains a challenge for us to construct an experimental workflow, which would combine the most mentioned methods in the publications and obtain real-time data for the ultra-low-permeable rock.

In this work, we applied a number of advanced laboratory methods for the characterization of an ultra-low-permeable carbonate Tlaynchy-Tamakian Formation. We employed an integrated analysis to investigate the advantages and limitations of the methods for estimating porosity and permeability. The study eventually discusses an optimal suite of methods for gathering quality datasets.

#### **2. Materials and Methods**
