Tight gas-bearing sandstone inversion using matrix modulus amplitude-variation-with-angle approximation

Hydraulic fracturing and drilling are commonly and widely used in many formations, particularly in unconventional reservoirs, such as tight sandstone reservoirs and so on. Whereas, during the fracturing or drilling process, large quantities of fluids are lost in the formation. Specially, many gas wells suffer a loss in productivity as a result of liquid invasion into the rock matrix. Liquid invasion is referred to as "water blocking", which is the primary damage that occurs in tight reservoirs and in low-permeability and ultra-low-permeability reservoirs. Some methods and materials, like methanol, are used to eliminate "water blocking", but only providing a temporary solution to the problem.This paper introduces a hydrophobic wettability function and mechanisem that effectively eliminates "water blocking" on the tight sandstone. The results from wettability experiments using tight sandstone show that hydrophobic wettability function on the sandstone surface, making a contact angle greater than 90°. The inner wall of capillary tube changes wettability and the capillary pressure becomes a positive driving force rather than a negative resistance. The experimental studies demonstrate that altering the wettability of tight sandstone to produce a hydrophobic surface is a viable method for recovering permeability and eliminating "water blocking".

ABSTRACT: Hydraulic fracturing is the key technique in the development of unconventional resources. Many optical experimental studies have been made to qualitatively study the hydraulic fracturing process. However, due to the time of fracture propagation being extremely short (ms), real-time quantitative description of the fracturing process is challenging. To clarify the process of fracture propagation, a novel triaxial optical hydraulic fracturing experimental apparatus is developed which mainly includes an ISCO displacement pump, triaxial servo control devices, high-intensity illumination devices, high-speed camera, and data acquisition systems. The fracturing process could be captured visually in real-time by using a high-resolution camera. This study also proposes an accurate and effective analysis method, Digital Image Correlation (DIC), for characterizing fracture and measuring the strain field. The results show that the pressure-time curve of hydraulic fracturing can be divided into three stages: pressure rise stage, the crack initiation and propagation stage, and the pressure plateau stage; the initiation pressures of water and CO2 fracturing in tight sandstone are 10.1 MPa and 5.2 MPa respectively; hydraulic fractures active the natural fractures, resulting in a complex fracture network structure; hydraulic fractures will turn and gradually become vertical to the minimum principal stress during the extension process. The results of this paper can provide guidance for the field application of hydraulic fracturing in tight sandstone resources. 1. INTRODUCTION With the rapid development of the economy, the energy demand has increased rapidly, and unconventional oil and gas resources such as tight gas, coalbed methane, and shale gas have become an important guarantee for the national energy strategy1. Hydraulic fracturing technology is an important technology for the exploitation of unconventional oil and gas resources2, among which the geometry of hydraulic fractures is the key to evaluating hydraulic fracturing operations, still needs further research3-7.

Large-scale tight sandstone gas reservoirs were developed in the Upper Paleozoic in the Linxing block on the eastern edge of the Ordos Basin. The Benxi, Taiyuan, Shanxi, Xiashihezi, Shangshihezi, and Shiqianfeng Formations were developed from the bottom to the upper Paleozoic. Tight sandstone reservoirs have the characteristics of low porosity, low permeability and strong heterogeneity, and the distribution of sand bodies varies greatly on the plane. In view of the domestic research on unconventional tight sandstone reservoirs is at the critical stage, the sharing of tight sandstone petrological data in Linxing block is particularly important. In order to better share these basic geological data, a total of 305 pieces of the Upper Paleozoic rocks collected from the Benxi, Taiyuan, Shanxi, Xiashihezi, Shangshihezi, and Shiqianfeng Formations were taken photos by polarized light micrograph. The main rock types are arkose quartz sandstone, followed by lithic quartz sandstone and quartz sandstone. This dataset involves 24 wells, which record the sample’s location, stratigraphic age, and rock characteristics in detail. These rock microscopic image datas can be widely used not only in basic geological research, but also in interdisciplinary research such as cooperative research with computer artificial intelligence, and can also provide basic data services for unconventional oil and gas exploration and development research.

<p indent="0mm">Large-scale tight sandstone gas reservoirs were developed from the Upper Paleozoic in the Linxing block on the eastern edge of the Ordos Basin, with Benxi, Taiyuan, Shanxi, Xiashihezi, Shangshihezi, and Shiqianfeng Formations from the bottom to the upper Paleozoic. Tight sandstone reservoirs have the characteristics of low porosity, low permeability and strong heterogeneity, and the distribution of sand bodies varies greatly on the plane. Considering domestic research on unconventional tight sandstone reservoirs has entered into a critical stage, the sharing of tight sandstone petrological data in Linxing block is particularly important. To this end, a total of 305 Upper Paleozoic rock thin sections were collected from the Benxi, Taiyuan, Shanxi, Xiashihezi, Shangshihezi, and Shiqianfeng Formations and were taken photos by polarized light microscope. The major rock type is arkose quartz sandstone, followed by lithic quartz sandstone and quartz sandstone. This dataset covers 24 wells in the Linxing block, which record in details the location, stratigraphic age, and rock characteristics of the samples. These rock microscopic image data can be widely used not only in basic geological research, but also in interdisciplinary research such as cooperative research integrating computer artificial intelligence. It also provides data support for unconventional oil and gas exploration, development and research.

ABSTRACTDeep tight sandstone oil and gas reservoirs are exerting an increasingly crucial role in the augmentation of fossil energy reserves and the provision of energy. On account of the intricate geological conditions and the deficiency of a comprehensive set of exploration and development engineering technologies as well as supporting processes, the present development of deep tight sandstone oil and gas reservoirs remains in its nascent stage. Through the analysis and generalization of the horizontal well development technology for deep tight sandstone oil and gas reservoirs, a series of technologies have been established, encompassing reservoir geological evaluation and modeling, horizontal well development reservoir engineering validation, horizontal well geological design, and enhanced oil recovery processes. By taking the C 6 reservoir in Ordos basin, China as the research subject, in light of the research outcomes regarding the damage mechanisms and potential damage factors of tight sandstone oil and gas reservoirs, a geological evaluation approach based on the well log response characteristics was constructed, clarifying the porosity and permeability features of the C 6 reservoir, establishing the numerical model of the oil reservoir, and further elaborating the methods for dividing the development layers, selecting the development well pattern, and determining the development well density. The design parameters of horizontal well‐segmented hydraulic fracturing were meticulously optimized, resulting in a minimum cluster spacing of 7 m and a maximum cluster spacing of 20 m. Given the influence of horizontal stress differences, the optimum fracturing density was ascertained to be 16 perforations per meter, and the optimal fracturing fluid volume was identified through simulation to range from 12 to 25 m3/m. The crucial technologies for the development of tight sandstone oil and gas reservoirs in horizontal wells have been clearly identified, offering theoretical direction for the efficient exploitation of deep tight sandstone oil and gas reservoirs.

Indonesia continues to experience a decline in oil and gas reserves, with oil reserves dropping from 7.25 MMSTB in 2016 to 4.17 MMSTB in 2022 and natural gas reserves falling from 144.06 TSCF to 54.83 TSCF (KESDM, 2022). In the midst of the depletion of national oil and gas reserves, unconventional hydrocarbon reserves show very promising amounts of reserves. The basin of interest area contributes 2% of national natural gas production and 5% of national oil production. A study of what parameters are suitable for unconventional oil and gas research in the offshore Indonesia basin, Area ENC especially in Miocene interval is needed. The parameters studied include shale volume, porosity, Total Organic Carbon (TOC), and Brittleness Index (BI), that’s analyzed in 6 wells of the interval. Facies analysis shows that in the study area there are six facies, namely shale, shale-interbedded siltstone, siltstone, siltstone-interbedded sandstone, sandstone, and coal. Some shale facies and tight sandstone in study area are meet the requirement as unconventional reservoirs. The petrophysical characteristics of the shale hydrocarbon reservoir interval are as follows: the average shale volume is 0.73 (the highest is Dahlia well: 0.87); the PHIE is 4.4% (the highest is Edelweiss well: 6.2%); the TOC is 2.57 (the highest is Dahlia well: 3.02); and the BI is 0.64 (the highest is Akasia well: 0.68). The petrophysical properties of the tight sand hydrocarbon reservoir interval are as follows: the average shale volume is 0.25 (the lowest is Edelweiss well: 0.24); the PHIE is 8.2% (the highest is Edelweiss well: 8.8%); and the BI is 0.72 (the highest is Edelweiss well: 0.84). Based on the analysis that has been carried out, it is concluded that Miocene interval in ENC area, are potential to be developed as unconventional hydrocarbon reservoirs.

Because of continuing demand for energy from fossil fuels, low-permeability hydrocarbon-bearing rocks such as stiff shales and tight sandstones are regularly stimulated using hydraulic fracturing technology (Curtis 2002). In a similar vein, development of intermediate-grade geothermal resources in low-permeability igneous and sedimentary rocks also requires hydraulic fracture stimulation. Most stiff rocks are naturally fractured, which affects hydraulically induced fracture direction locally, but the global orientation of induced fracture growth remains normal to the minimum principal stress. The key factor for economic success is to maximize the stimulated volume and the surface area across which heat, oil or gas can diffuse.

Micro/nanoscale pore structure and fractal characteristics of tight gas sandstone: A case study from the Yuanba area, northeast Sichuan Basin, China

This paper describes the development and implementation of a multi-frac completion strategy that improved the well performance by more than 500% in the first successful hydraulic fracture treatment pumped in deep Pre-Khuff targets. The primary target reservoir is a deep tight gas sandstone that can be found at depths exciding 16,000 ft with temperatures above 350°F. Given the reservoir characteristics, primarily its low permeability, hydraulic fracturing is required to achieve commercial production rates. The design of the fracture stimulation treatment presented several challenging conditions including high formation temperature, closure stress, and fracture pressure with the potential for post treatment proppant flowback in an offshore environment. The learning curve was collapsed by interdisciplinary evaluation of diverse data sets from legacy and newly drilled wells. Mechanistic models were employed in a grid-oriented planar 3D hydraulic fracture simulator to optimize treatments and to understand changes in production performance related to specific multi-fractured completion strategies, guiding the optimization process. This work led to the successful implementation nano-proppants, pseudo-stable fracturing fluids and, among other technologies, specialized perforation guns designed for low stress anisotropy conditions. This paper will provide insights on the results and lessons learned from the implementation of cutting-edge hydraulic fracturing technology that provided the means to overcome challenges to unlock hard to recover reserves.

The recovery of natural gas from low permeability sandstones in the US has been made commercially possible due, to a large degree, to advanced technologies. The US currently produces 2 TCF annually from tight gas sandstone reservoirs. Large efforts have been directed towards identifying and developing the more productive basinal areas, or 'sweet spots9 of tight gas reservoirs. The identification of natural fractures prior to drilling, through the use of remote imagery in combination with established methods such as magnetic and gravity mapping, is currently being pioneered. Reduction in well-bore stimulation costs through development and application of advanced hydraulic fracture technology has improved the economics of tight gas production. The use of 3D fracture models in combination with realistic insitu stress profiles, appropriate proppants and effective quality controls have greatly increased well productivities through smaller, more efficient fracture treatments. Treatments have been successfully designed to avoid damage to natural fractures.Large tight gas sandstone resources similarly exist in the Cooper and Perth Basins of Australia and in the Taranaki Basin of New Zealand, although these resources remain largely untapped. To date, less than 50 BCF has been produced from Australian and New Zealand tight sandstones, largely from the Tirrawarra Sandstone and Patchawarra Formation of the Cooper Basin and the Ngatoro/McKee Formations of the Taranaki Basin. These formations compare well however, in terms of depositional environments with prolific US tight gas producing formations. They appear to be well placed to take advantage of the experiences and technologies gained by their US counterparts as well as through site specific adaptation of such technologies and the development of new technologies.

The use of 3D time‐lapse shear wave seismic data is being tested to monitor the production from a tight gas sandstone reservoir in western Colorado. The focus of this study is to monitor the production of gas using dedicated time‐lapse surveys collected in 2003 and 2004. Observable changes between the two surveys illustrate the ability of highly repeatable shear wave seismic data to monitor production of gas in a complex and unconventional reservoir. These observable changes allow for a more complete understanding of drainage patterns and reservoir connectivity. This increased reservoir understanding can provide insight to help guide drilling, completion, and recompletion programs, and to increase gas recovery efficiency by avoiding depleted zones.

X-ray CT scanning is one of the main methods to study the pore structure of the rocks. However, low resolution is currently one of the major challenges of this method, which does not allow for the identification of microscopic pores. Even though adopting images of higher resolutions could reflect the microscopic pores of the rocks, due to the small size of the scanned rock sample in the x-ray CT scanning method, the rock parameters cannot be effectively obtained, especially for the rocks with strong heterogeneity. This would cause the loss of important pore information, such as fractures’ information. Focusing on this problem, the current research tries to propose a method for constructing high-precision digital rocks of complexly porous rocks. This method is based on the simultaneous application of x-ray CT scanning images, nuclear magnetic resonance measurements, as well as mercury injection experimental data and fractal discrete fracture network. These methods effectively compensate for the shortcomings of the scanning method where it cannot capture pores smaller than the scanning resolution and for the lack of fracture information due to rock sampling. The research results showed that compared with the digital rock models constructed by single-resolution scanning, the high-precision complex pore digital rock constructed by this method can effectively improve the accuracy of the results of porosity and permeability calculations. These results were closer to the results of rock physics experiments. This approach provides a solid foundation for the numerical simulation of rock parameters in unconventional reservoirs with complex pore structures, such as carbonate, tight sandstone and shale reservoirs.

Effect of rock mineralogy on Hot-CO2 injection for enhanced gas recovery

Laboratory visualization of supercritical CO2 fracturing in tight sandstone using digital image correlation method

Permo-Triassic formations in Mandapetta field from eastern onshore, India possesses historical drilling challenges in terms of wellbore instability, non-productive time and poor hole condition in deep higher stressed formations. Lack of acquiring reliable log data and problems in recovering good quality cores present difficulties in proper formation evaluation and zone selection for testing. Historical well test results in target K-Formation has been not encouraging despite good gas shows during drilling. Estimated formation pressure gradient ranges 1.45sg-1.52sg. Layered shale with coal and tight sandstone in same open hole section pose risks of mud losses and poor cement job. Present study highlights the workflow adopted to improve drilling and completion in open hole section of more than 1000 m with varying lithology being drilled successfully. Advanced 3D anisotropic acoustic measurements acquired are used to estimate anisotropic elastic properties (vertical and horizontal Young's modulus and Poisson's ratio) in the overlying shales. Horizontal tectonics has been determined across stress induced anisotropic layers. This approach provides better understanding of formations and stress distribution. Thomsen Gamma values range 0.1 to 0.4 in shale layers of overburden formations. In order to minimize uncertainty in 8.5inch section while drilling, advanced logs were acquired in 12.25inch hole section to estimate tectonics at well location while constraining ratio of horizontal to vertical Young's modulus and Poisson Ratio in shale layers based on Thomsen Gamma and clay volume. Analysis suggested typical VTI anisotropy of 15%-20% in shale layers. Inverted direct horizontal strain parameters at well location suggested the ratio of maximum to minimum horizontal stress to vary 1.15-1.23. Mud weight used while drilling 8.5inch section ranged 1.49sg1.52sg against the recommended mud weight of 1.50sg-1.52sg while pumping sealing agents to prevent mud losses in coal layers. Flow rate was maintained on lower values to minimize ECD values. Hole condition improved significantly with no issues in logging. Post-drill anisotropic rock mechanics model suggested good quality sandstone in target source formation with usual conventional reservoir in shallower formation. Zone was selected based on permeability, breakdown and completion quality for perforations. Analysis of high-quality sonic slowness helped to identify possible gas reservoir in laminated source rock. There was stress contrast of 2000psi-2500psi among reservoir layers and shale stress barriers. Implemented workflow and successful execution helped to drill the well 5 days earlier than plan with no major drilling incidents. Successful core recovery for Shale Gas evaluation was also possible due to better wellbore quality. Initial testing of K-Formation produced gas with significant improved flow rate by 150% without any stimulation for the 1st time in the history of the field.