Gassmann's fluid substitution and shear modulus variability in carbonates at laboratory seismic and ultrasonic frequencies

Geophysics ◽  
2006 ◽  
Vol 71 (6) ◽  
pp. F173-F183 ◽  
Author(s):  
Ludmila Adam ◽  
Michael Batzle ◽  
Ivar Brevik
Keyword(s):  
Shear Modulus ◽  
Bulk Modulus ◽  
Oil Recovery ◽  
Laboratory Experiments ◽  
Oil And Gas ◽  
Pressure Effects ◽  
Gas Reservoirs ◽  
Reservoir Rocks ◽  
Fluid Saturation ◽  
Seismic Frequencies

Carbonates have become important targets for rock property research in recent years because they represent many of the major oil and gas reservoirs in the world. Some are undergoing enhanced oil recovery. Most laboratory studies to understand fluid and pressure effects on reservoir rocks have been performed on sandstones, but applying relations developed for sandstones to carbonates is problematic, at best. We measure in the laboratory nine carbonate samples from the same reservoir at seismic (3–3000 Hz) and ultrasonic [Formula: see text] frequencies. Samples are measured dry (humidified) and saturated with liquid butane and brine. Our carbonate samples showed typical changes in moduli as a function of porosity and fluid saturation. However, we explore the applicability of Gassmann’s theory on limestone and dolomite rocks in the context of shear- and bulk-modulus dispersion and Gassmann’s theory assumptions. For our carbonate set at high differential pressures and seismic frequencies, the bulk modulus of rocks with high-aspect-ratio pores and dolomite mineralogy is predicted by Gassmann’s relation. We also explore in detail some of the assumptions of Gassmann’s relation, especially rock-frame sensitivity to fluid saturation. Our carbonate samples show rock shear-modulus change from dry to brine saturation conditions, and we investigate several rock-fluid mechanisms responsible for this change. To our knowledge, these are the first controlled laboratory experiments on carbonates in the seismic frequency range.

Characterizing Pores and Pore-Scale Flow Properties in Middle Bakken Cores

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1343-1358 ◽  
Author(s):  
Somayeh Karimi ◽  
Hossein Kazemi
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Produced Water ◽  
Nitrogen Adsorption ◽  
Spontaneous Imbibition ◽  
Flow Properties ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Shale Reservoirs

Summary To understand the flow and transport mechanisms in shale reservoirs, we needed reliable core-measured data that were not available to us. Thus, in 2014, we conducted a series of diverse experiments to characterize pores and determine the flow properties of 12 Middle Bakken cores that served as representatives for unconventional low-permeability reservoirs. The experiments included centrifuge, mercury-intrusion capillary pressure (MICP), nitrogen adsorption, nuclear magnetic resonance (NMR), and resistivity. From the centrifuge measurements, we determined the mobile-fluid-saturation range for water displacing oil and gas displacing oil in addition to irreducible fluid saturations. From MICP and nitrogen adsorption, we determined pore-size distribution (PSD). Finally, from resistivity measurements, we determined tortuosity. In addition to flow characterization, these data provided key parameters that shed light on the mechanisms involved in primary production and the enhanced-oil-recovery (EOR) technique. The cores were in three conditions: clean, preserved, and uncleaned. The hydrocarbon included Bakken dead oil and decane, and the brine included Bakken produced water and synthetic brine. After saturating the cores with brine or oil, a set of drainage and imbibition experiments was performed. NMR measurements were conducted before and after each saturation/desaturation step. After cleaning, PSD was determined for four cores using MICP and nitrogen-adsorption tests. Finally, resistivity was measured for five of the brine-saturated cores. The most significant results include the following: Centrifuge capillary pressure in Bakken cores was on the order of hundreds of psi, both in positive and negative range. Mobile-oil-saturation range for water displacing oil was very narrow [approximately 12% pore volume (PV)] and much wider (approximately 40% PV) for gas displacing oil. In Bakken cores, oil production by spontaneous imbibition of high-salinity brine was small unless low-salinity brine was used for spontaneous imbibition. Resistivity measurements yielded unexpectedly large tortuosity values (12 to 19), indicating that molecules and bulk fluids have great difficulty to travel from one point to another in shale reservoirs.

scholarly journals Analysis of Petrophysical Studies of Deep Oil and Gas Reservoirs of Onshore and Offshore Fields in Azerbaijan

2020 ◽  
Vol 20 (3) ◽  
pp. 204-213
Author(s):  
Vagif Sh. Gurbanov ◽  
◽  
Latif A. Sultanov ◽  
Nurlana I. Gulueva ◽  
◽  
...  
Keyword(s):  
Oil And Gas ◽  
Sedimentary Basin ◽  
Oil Industry ◽  
Gas Reservoirs ◽  
Reservoir Rocks ◽  
Deep Wells ◽  
Long Time ◽  
Enhance Efficiency ◽  
The Cost ◽  
Natural Hydrocarbon

The paper presents results of generalized laboratory studies from an array of petrophysical parameters of reservoir rocks (potential hydrocarbon reservoirs). The study is targeted at well-known horizons of productive strata of the Meso- Cenozoic sedimentary basin. The area under study includes oil and gas onshore and deep offshore fields in Azerbaijan that have been under active continuous developments. The development of these natural hydrocarbon accumulations has over a century-long history, which has shown that the major oil and gas deposits are associated with the South Caspian and Kura depressions subjected to an intensive submersion over the Meso-Cenozoic period. Although many of the fields in these depressions have been exploited for a long time, the commercial potential is high enough, especially in deep-seated areas. Nonetheless, problems associated with extracting oil and gas therefrom are pending final resolutions. Subsoil developments in the region are currently performed at an intensive rate at depths above 4-4.5 km, since most oil and gas deposits have already been explored at shallow and moderate depths (even in hard-to-reach areas). As known in oil industry, the wells with a depth of over 4 km are referred to deep wells, while those with a depth of over 6 km are referred to ultra-deep wells. Moreover, drilling of such wells is associated with serious costrelated challenges. For example, the cost of developing deep and even ultra-deep wells is high enough, ranging from $ 2-3 to $ 9-12 million. This fact emphasizes the need to enhance efficiency of such operations, which requires a highscale geological reasoning of a field’s potential and choice of a good location.

Geological and Field Feasibility Study of Field Development Management Using Marker-Based Production Profiling Surveillance in Horizontal Wells: The Case Study of the Yuzhno-Vyintoiskoye Field

2021 ◽  
Author(s):  
Marat Rafailevich Dulkarnaev ◽  
Yuri Alexeyevich Kotenev ◽  
Shamil Khanifovich Sultanov ◽  
Alexander Viacheslavovich Chibisov ◽  
Daria Yurievna Chudinova ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Water Saturation ◽  
Clay Content ◽  
Horizontal Wells ◽  
Integrated Approach ◽  
Geological Structure ◽  
Gas Field ◽  
Field Development ◽  
Reservoir Rocks

In pursuit of efficient oil and gas field development, including hard-to-recover reserves, the key objective is to develop and provide the rationale for oil recovery improvement recommendations. This paper presents the results of the use of the workflow process for optimized field development at two field clusters of the Yuzhno-Vyintoiskoye field using geological and reservoir modelling and dynamic marker-based flow production surveillance in producing horizontal wells. The target reservoir of the Yuzhno-Vyntoiskoye deposit is represented by a series of wedge-shaped Neocomian sandstones. Sand bodies typically have a complex geological structure, lateral continuity and a complex distribution of reservoir rocks. Reservoir beds are characterised by low thickness and permeability. The pay zone of the section is a highly heterogeneous formation, which is manifested through vertical variability of the lithological type of reservoir rocks, lithological substitutions, and the high clay content of reservoirs. The target reservoir of the Yuzhno-Vyintoiskoye field is marked by an extensive water-oil zone with highly variable water saturation. According to paleogeographic data, the reservoir was formed in shallow marine settings. Sand deposits are represented by regressive cyclites that are typical for the progressing coastal shallow water (Dulkarnaev et al., 2020). Currently, the reservoir is in production increase cycle. That is why an integrated approach is used in this work to provide a further rationale and creation of the starting points of the reservoir pressure maintenance system impact at new drilling fields to improve oil recovery and secure sustainable oil production and the reserve development rate under high uncertainty.

Viscoelasticity of Ells River bitumen sand and 4D monitoring of thermal enhanced oil recovery processes

Geophysics ◽  
2013 ◽  
Vol 78 (6) ◽  
pp. D419-D428 ◽  
Author(s):  
James W. Spencer
Keyword(s):  
Bulk Modulus ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Pore Space ◽  
Rock Physics ◽  
Steam Injection ◽  
P Wave ◽  
Low Frequencies ◽  
Recovery Processes ◽  
Seismic Frequencies

Samples of Ells River bitumen sand from Alberta, Canada were measured at low frequencies (0.2–205 Hz) to determine the temperature and frequency dependence of velocities and attenuations. The samples were first measured “as received” where the pore space is mostly filled with bitumen but also contains small amounts of air and water. With residual air in the pores, at 5°C, there is strong dispersion in the P-wave modulus and a peak in attenuation at seismic frequencies. The frequency-dependent moduli and attenuations shift by three orders of magnitude in frequency as temperature is increased from 5°C to 48°C, consistent with the bitumen viscosity. Samples were then saturated so any empty pore space is filled with water. After saturation, at 1 Hz, increasing temperature from 5°C to 49°C causes a 30% reduction in the saturated P-wave modulus, a 34% reduction in the saturated bulk modulus, and a 6% reduction in the shear modulus. This behavior can only be explained by the temperature-dependent bulk modulus of bitumen. The results enable predictions regarding the P-velocities that can be expected during seismic monitoring of thermal enhanced oil recovery processes. Velocities for cold bitumen sand are near [Formula: see text] at reservoir pressure and temperature. Following steam injection, velocities should be very low (near [Formula: see text]) in heated zones more than 50°C with a free gas phase, which could be steam or gas. There will be a progressive reduction in velocities, i.e., [Formula: see text] at 25°C and [Formula: see text] at 49°C, in areas of formation heating, but without steam or gas in the pores. Albeit smaller than the effect of steam, the effect of formation heating alone is large enough to be easily detected by today’s 4D surveys. With local rock physics calibration, it should be possible to map the areal extent of formation heating using 4D seismic data.

scholarly journals Convective Mixing Driven by Non-monotonic Density

2021 ◽  
Author(s):  
M. T. Elenius ◽  
S. E. Gasda
Keyword(s):  
Fluid Flow ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Convective System ◽  
Late Time ◽  
Field Scale ◽  
Gas Reservoirs ◽  
Mixture Density ◽  
Convective Mixing ◽  
Gravity Effects

AbstractCO$$_\text {2}$$ 2 injection for enhanced oil recovery (CO$$_\text {2}$$ 2 -EOR) or for storage in depleted oil and gas reservoirs can be a means for disposing of anthropogenic CO$$_\text {2}$$ 2 emissions to mitigate climate change. Fluid flow and mixing of CO$$_\text {2}$$ 2 and hydrocarbons in such systems are governed by the underlying physics and thermodynamics. Gravity effects such as gravity override and convection are mechanisms that can alter fluid flow dynamics, impacting CO$$_\text {2}$$ 2 migration, oil production and eventual CO$$_\text {2}$$ 2 storage at the field scale. This study focuses on convection in a miscible setting caused by non-monotonicity in oil density when mixed with CO$$_\text {2}$$ 2 , i.e., a maximum mixture density occurs at an intermediate CO$$_\text {2}$$ 2 concentration. We perform high-resolution simulations to quantify the convective behavior in a simple box system where gravity effects are isolated. We show that convection of CO$$_\text {2}$$ 2 in oil is dependent on whether CO$$_\text {2}$$ 2 originates from above or below the oil zone. From above, convection follows classic convective mixing but is accelerated by viscosity decrease with increasing CO$$_\text {2}$$ 2 . From below, convection flows upward due to CO$$_\text {2}$$ 2 buoyancy, but is countered by downward convection due to the heavier mixture density. This convective system is significantly more complex and efficient than from above. We characterize the instabilities in both early- and late-time regimes and quantify mixing rates. For a 100 mD reservoir, convective fingers would be on the order of centimeters in width and mix over a meter length scale within days to a month, depending on the placement of CO$$_\text {2}$$ 2 . The simulations are performed in non-dimensional form and thus can be rescaled to a different reservoir parameters. Our results give important insights into field-scale impacts of convective mixing and can guide future work in development of upscaled models and experimental design.

scholarly journals Application of Magnetic and Dielectric Nanofluids for Electromagnetic-Assistance Enhanced Oil Recovery: A Review

Crystals ◽  
2021 ◽  
Vol 11 (2) ◽  
pp. 106
Author(s):  
Yarima Mudassir Hassan ◽  
Beh Hoe Guan ◽  
Hasnah Mohd Zaid ◽  
Mohammed Falalu Hamza ◽  
Muhammad Adil ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Experiments ◽  
Oil And Gas ◽  
Field Application ◽  
Wettability Alteration ◽  
Effective Performance ◽  
Global Concern ◽  
Incremental Oil Recovery ◽  
First Time

Crude oil has been one of the most important natural resources since 1856, which was the first time a world refinery was constructed. However, the problem associated with trapped oil in the reservoir is a global concern. Consequently, Enhanced Oil Recovery (EOR) is a modern technique used to improve oil productivity that is being intensively studied. Nanoparticles (NPs) exhibited exceptional outcomes when applied in various sectors including oil and gas industries. The harshness of the reservoir situations disturbs the effective transformations of the NPs in which the particles tend to agglomerate and consequently leads to the discrimination of the NPs and their being trapped in the rock pores of the reservoir. Hence, Electromagnetic-Assisted nanofluids are very consequential in supporting the effective performance of the nanoflooding process. Several studies have shown considerable incremental oil recovery factors by employing magnetic and dielectric NPs assisted by electromagnetic radiation. This is attributed to the fact that the injected nanofluids absorb energy disaffected from the EM source, which changes the fluid mobility by creating disruptions within the fluid’s interface and allowing trapped oil to be released. This paper attempts to review the experimental work conducted via electromagnetic activation of magnetic and dielectric nanofluids for EOR and to analyze the effect of EM-assisted nanofluids on parameters such as sweeping efficiency, Interfacial tension, and wettability alteration. The current study is very significant in providing a comprehensive analysis and review of the role played by EM-assisted nanofluids to improve laboratory experiments as one of the substantial prerequisites in optimizing the process of the field application for EOR in the future.

scholarly journals Experimental Study on Enhanced Condensate Recovery by Gas Injection in Yaha Condensate Gas Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Yiming Wu ◽  
Kun Yao ◽  
Yan Liu ◽  
Xiangyun Li ◽  
Mimi Wu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Recovery Rate ◽  
Oil And Gas ◽  
Gas Injection ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Injection Method ◽  
Production Ratio

A condensate gas reservoir is an important special oil and gas reservoir between oil reservoir and natural gas reservoir. Gas injection production is the most commonly used development method for this type of gas reservoir, but serious retrograde condensation usually occurs in the later stages of development. To improve the recovery efficiency of condensate oil in the middle and late stages of production of a condensate gas reservoir, a gas injection parameter optimization test study was carried out, taking the Yaha gas condensate reservoir in China as an example. On the premise that the physical experimental model and key parameters met the actual conditions of the formation, the injection method, injection medium, injection-production ratio, and other parameters of the condensate gas reservoir were studied. Research on the injection method showed that the top injection method had a lower gas-oil ratio and higher condensate oil recovery. The study of injection medium showed that the production effect of carbon dioxide (CO2) injection was the best injection medium, and the maximum recovery rate of condensate oil was 95.11%. The injection-production ratio study showed that the injection-production ratio was approximately inversely proportional to the recovery factor of condensate gas and approximately proportional to the recovery factor of condensate oil. When the injection-production ratio was 1 : 1, the maximum recovery rate of condensate oil was 83.31%. In summary, in the later stage of gas injection development of the Yaha condensate gas reservoir, it was recommended to choose the development plan of CO2 injection at the top position with an injection-production ratio of 1 : 1. This research can not only provide guidance for the later formulation of gas injection plans for Yaha condensate gas reservoirs but also lay a foundation for the research of gas injection migration characteristics of other condensate gas reservoirs.

scholarly journals Influence of CO2 retention mechanism storage in Alberta tight oil and gas reservoirs at Western Canadian Sedimentary Basin, Canada: hysteresis modeling and appraisal

2020 ◽  
Author(s):  
Perumal Rajkumar ◽  
Venkat Pranesh ◽  
Ramadoss Kesavakumar
Keyword(s):  
Oil Recovery ◽  
Fossil Fuels ◽  
Oil And Gas ◽  
Injection Pressure ◽  
Retention Mechanism ◽  
Gas Production ◽  
Tight Oil ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs ◽  
Tight Oil And Gas

AbstractRapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.

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