Low-permeability Tight Reservoirs Research Articles

Developmental characteristics of fractures in deep tight sandstone reservoirs in the second Member of the Xujiahe Formation of Zhongjiang Gas Field

The development characteristics, scale and control factors of fractures are the core subjects of reservoir sweet spot prediction. The sandstone reservoir of the TX2 gas reservoir in the Zhongjiang Gas Field is a typical low porosity and low permeability tight reservoir with strong heterogeneity, but relatively high-quality reservoirs can be found in different well areas and well segments. In this paper, taking the second Member of the Xujiahe Formation (TX2) as an example, the control factors of fractures were systemically investigated via core observation, thin section, logging data, and fracture logging identifications. The results show that shear fractures are mainly developed in the cores, and they generally have high filling rate and poor effectiveness; microfractures can be found based on the vitrinite and cast thin section results. The intersection diagram (semi-quantitative) and the principal component and BP comprehensive identification (quantitative) methods can effectively identify different types of fractures. The combined application of principal component and BP comprehensive identification methods results in an 83.3 % fracture identification probability. Finally, we found that the development of fractures in TX2 is comprehensively affected by lithology, rock thickness, porosity, and faults.

Optimizing tight oil extraction from low permeability tight reservoirs: a study on stress sensitivity effects and applications in carbon capture, utilization, and storage

This paper takes into consideration the impact of stress sensitivity on bioenergy production from low permeability tight reservoirs, focusing on the post-fracturing phase. This paper established a trilinear flow model that effectively takes into account the dynamics of such reservoirs. This model incorporates stress sensitivity parameters and uses the perturbation transformation and Laplace transformation to solve the productivity prediction formula. The final productivity prediction curve post-fracturing is achieved through a numerical inversion method. This study shows that the stress sensitivity effect significantly diminishes the productivity of fractured horizontal wells used in bioenergy extraction. By introducing stress sensitivity effect parameters, this paper manages to uncover the influence law of mobility and artificial fracture parameters on productivity. Notably, as the reservoir mobility increases, the cumulative bioenergy production from fractured horizontal wells improves significantly. In addition to the above, this paper also scrutinizes the sensitivity of artificial fracture parameters and optimize both the quantity and length of these fractures. This plays a crucial role in enhancing the productivity and efficiency of bioenergy extraction from these tight reservoirs. The applicability and reliability of this method are extensively tested, thereby establishing its potential in guiding the development of low permeability reservoirs post-fracturing. Importantly, this research sets the groundwork for combining bioenergy production with Carbon Capture, Utilization, and Storage (CCUS) technologies. By focusing on optimization and stress management in tight reservoirs, this paper contributes to the sustainable production of bioenergy and reduce carbon emissions, moving a step closer to a cleaner and sustainable future.

Molecular dynamics simulation for quantitative characterization of wettability transition on silica surface

Surfactant controlling the wettability of reservoir rocks is one of the important ways to enhance oil recovery in low-permeability tight reservoirs. A large number of scholars have developed a series of excellent wettability control reagents through macro physical simulation experiments, but macro experiments are difficult to analyze the micro mechanism of liquid/liquid and liquid/solid interface action of reagents controlling rock wettability. In this paper, the wetting behavior of water molecules on silica surfaces modified with different hydroxylation, methylation and hydrophobic chain length was studied by molecular dynamics simulation, and the quantitative relationship between different modification degrees and wetting angle was established. The results show that the original wetting angle of silica is 58.5°, and the surface wettability can be changed from hydrophilic to hydrophobic through surface modification, with a wetting angle of 27.25°∼115.78°. With the increase of the coverage of hydrophobic methyl or hydrophilic hydroxyl modified groups, the wetting angle increases or decreases respectively. The quantitative relationship between modification degree and wetting angle was established by simulated data. With the increasing of the chain length of methyl group, the distance between water molecule and silica surface increases and the interaction decreases, which can improve the regulation effect of methyl group hydrophobicity. This paper provides a reference basis for the synthesis of rock wettability control reagent and the quantitative characterization of modification degree.

Study on the Imbibition Characteristics of Different Types of Pore-Throat Based on Nuclear Magnetic Resonance Technology

“Fracturing network+imbibition oil production” is a new attempt to effectively develop low-permeability tight reservoirs. Fracturing fluid is not only a carrier for sand carrying but also a tool in the process of imbibition. On the basis of imbibition experiments, combined with nuclear magnetic resonance and pseudo-color processing technology, this paper clarified the dominant forces of different types of pore-throat and quantitatively characterized the contribution of different levels of pore-throat to imbibition oil recovery. The results show that gravity is the main controlling force of imbibition for reservoirs with higher permeability. Fluid replacement mainly occurs in the early period of imbibition. Macropores contribute most of the imbibition recovery, mesopores have a weak contribution, and the contribution of micropores and pinholes can be ignored. For the reservoirs with low permeability, capillary force is the main controlling force of imbibition. Fluid replacement mainly occurs in the later period of imbibition. Macropores contribute most of the imbibition recovery rate, mesopores contribute a small part of the imbibition recovery factor, and the contribution of micropores and pinholes can be ignored. This paper clarified that macropores and mesopores are the main sources of the contribution of imbibition recovery efficiency, and oil content and connectivity are key factors for the imbibition recovery efficiency.

Analysis of Test Method for Oil and Water Relative Permeability Curve in Tight Reservoirs

With the development of the international economy, the global demand for oil and gas resources has continued to increase in recent years. The development of high-permeability reservoirs has reached the middle and late stages, and resources are depleting. With the large-scale successful exploitation of tight oils in North America, low-permeability tight reservoirs have gradually become the main object of development. Compared with conventional reservoirs, tight reservoirs mainly develop nano- scale pore systems. It causes poor reservoir properties, high interlayer heterogeneity, low porosity and permeability, and generally no natural productivity in reservoirs. In tight reservoirs, the flow of oil-water phases is not affected by the scale, but also the wettability, they make the oil and water phases seepage more complicated. In this paper, the natural core of a tight reservoir in Daqing was selected. Experiments were carried out using two experimental methods: steady-state method and non-steady-state method. The characteristics of oil and water phases percolation in tight reservoirs were analyzed. The results by comparing the two experimental methods showed the steady state method is suitable for measuring the oil and water relative permeability curve of tight reservoirs.

The tight reservoir microscopic classification of southern part of Qijia area in Songliao Basin

With the decreasing of the conventional oil and gas reserves, the unconventional tight oil and gas are gradually becoming the focus of the study. The casting thin section, conventional mercury injection, constant velocity and pressure mercury and other experimental methods, tight reservoir microscopic characteristics in southern part of Qijia area were studied in this paper. Based on the above conditions, combined with the parameters of pore type, pore throat radius, the reservoir is divided into two types, conventional reservoir and low permeability tight reservoir. Reservoir conventional reservoir permeability values are greater than 1mD, low permeability tight reservoirs are classified into IIa type and IIb type, which provides some reference value for the actual exploration and development.

Characteristics and geological significance of fluorescence for sandstone grains and hydrocarbon extracts from low permeability reservoirs in the Ordos Basin, China

The Triassic Chang-3 and Jurassic Yanan low-permeability reservoirs in the southern part of the Tianhuan Depression of the Ordos Basin, north-central China, were investigated using the quantitative fluorescence of reservoir sandstone grains and their hydrocarbon extracts. Values of quantitative grain fluorescence on extract intensity (QGF-E) are generally higher than 150 pc, indicating that oil and gas migration has taken place in the low-permeability tight sand bodies in the study area, so these sandstone strata were the main transport system of oil and gas migration. The values of QGF index and QGF-E in the Chang-3 subsection profile above 2168 m are higher than those below 2168 m; similarly, the two values in the Yanan formation profile above 1849 m are higher than those below 1849 m, indicating that the oil–water contacts of the Chang-3 subsection and Yanan Formation in the study area are 2168.0 and 1849.0 m, respectively. The results of total scanning fluorescence for hydrocarbon extracts from the Chang-3 subsection and Yanan Formation show that the extracts contain low aromatic hydrocarbon and are mature. Our results demonstrate that QGF and QGF-E methods are very effective in understanding the properties and accumulation process of hydrocarbon in low-permeability tight reservoir.

Pressure Transient Analysis for Wells With Variable Sandface Flow Rate

Abstract In the last two decades, with the availability of new state-of-the- art production logging devices that are capable of providing accurate downhole rate and pressure measurements, variable rate testing has been given special concern. This is mainly because it is sometimes impractical and often impossible to hold a constant flow rate long enough to perform a drawdown test. Furthermore, the use of sand face flow rate and pressure data in well test analysis has a few major advantages over conventional methods. Variable-rate tests minimize the wellbore storage effects, reduce the test duration, and provide better description of the area in the vicinity of the wellbore. This paper presents a new technique that does not require a constant flow rate for the entire duration of the test. The technique consists of two flowing periods: a short constant flow rate period followed by a variable flow rate period. In deriving the final working equation, the variable flow rate period is approximated by a polynomial. The new method can be also used to analyze pressure drawdown data dominated by wellbore storage and pressure buildup data pertaining to early time afterflow. Two simulated cases and two field examples are presented to illustrate the applicability of the new technique. Introduction The pressure drawdown test has long been recognized in the oil industry to be an excellent technique to determine reservoir characteristics. However, one of the major drawbacks in analyzing pressure draw downs is the theoretical requirement of these techniques that requires the flow rate to be held strictly constant during the entire test duration. Moreover, in most wells, the wellbore storage effects dominate the early test data and force the operator to run the test for a long period of time. This is especially true in low-productivity pumping wells and low-permeability tight reservoirs. Furthermore, in the case of small reservoirs, the boundary effects may disturb the test data even before the appearance of the semi log straight line on the test plot. Sometimes, even when the plot displays a straight line, the data analysis may not reflect the near wellbore conditions. In all of these cases, the well test fails to achieve its goals. In addition, for both oil and gas wells, the long constant-rate production condition is hard to fulfill in the field, especially during the early life of the reservoir. For all of these reasons, well test researchers tried to come up with new testing techniques that do not require a constant rate, minimize the wellbore storage effects, reflect the actual conditions in the vicinity of the wellbore, and reduce the test duration. Variable-rate tests are designed to solve most of these problems. The idea of using afterflow data to analyze well tests is not new. As early as 1955, Gladfelter et al.(1) presented the first attempt to use approximated afterflow rate and pressure data to estimate the reservoir parameters.

Estimates of Undiscovered Recoverable Conventional Oil and Gas Resources of United States: ABSTRACT

In 1987, the US Geological Survey and Minerals Management Service completed the assessment of the undiscovered conventional resources of crude oil and natural gas in the US. The assessed resources were defined as (1) those considered recoverable under current technology and (2) those that could be recovered economically under specified price-cost relationships. Not included in the study were resources from tar deposits, heavy oil deposits, oil shales, gas in low-permeability tight reservoirs, coal-bed methane, gas in geopressured shales and brines, and gas in natural gas hydrates. The assessments were based upon the analysis of oil and gas plays and prospects supported by studies and analysis of the petroleum geology, exploration history, finding rates, and field-size distributions. Probability procedures were used in their derivation. The estimates of undiscovered recoverable conventional oil resources for the US range from 33 to 70 billion bbl, with a mean estimated of 49 billion bbl. The estimates of undiscovered gas range from 307 to 507 trillion ft/sup 3/, with a mean of 399 trillion ft/sup 3/. The undiscovered economically recoverable oil and gas resources for the US are estimated to range from 21 to 54 billion bbl of oil and 208 to 326 trillion ft/sup 3/ more » of gas. The mean value for oil is 35 billion bbl and for gas is 263 trillion ft/sup 3/. « less