Maximum Gas Saturation Research Articles

Impact of gas type on microfluidic drainage experiments and pore network modeling relevant for underground hydrogen storage

Underground hydrogen storage (UHS) in geological reservoirs is proposed as a technically feasible solution to balance mismatch between supply and demand in emerging markets. However, unique hydrogen properties and coupled flow mechanisms require new investigations to fully understand transport and storage of hydrogen in porous media across scales. Here we use microfluidics to investigate the effect of gas type and injection rate on flow patterns, saturation and connectivity of the gas phase. We visually observe that gas flow is characterized by capillary fingering, further confirmed by fractal dimension analysis. At lower injection rates, the gas saturation after drainage appears to increase with gas viscosity, with lower hydrogen saturation compared to methane and nitrogen. The maximum gas saturations (39–46 %) were achieved at higher injection rates, showing no clear correlation to gas type. However, the high-rate injections lead to undesired outcomes in terms of formation of disconnected gas ganglia, mostly pronounced for nitrogen. We identify an optimal injection rate to achieve maximum gas saturation with the least amount of disconnected gas. The experimental results are supported with pore network modeling to derive relative permeability and capillary pressure functions.

A three dimensional visualized physical simulation for natural gas charging in the micro-nano pore system

A micro-nano pore three-dimensional visualized real-time physical simulation of natural gas charging, in-situ pore-scale computation, pore network modelling, and apparent permeability evaluation theory were used to investigate laws of gas and water flow and their distribution, and controlling factors during the gas charging process in low-permeability (tight) sandstone reservoir. By describing features of gas-water flow and distribution and their variations in the micro-nano pore system, it is found that the gas charging in the low permeability (tight) sandstone can be divided into two stages, expansion stage and stable stage. In the expansion stage, the gas flows continuously first into large-sized pores then small-sized pores, and first into centers of the pores then edges of pores; pore-throats greater than 20 μm in radius make up the major pathway for gas charging. With the increase of charging pressure, movable water in the edges of large-sized pores and in the centers of small pores is displaced out successively. Pore-throats of 20–50 μm in radius and pore-throats less than 20 μm in radius dominate the expansion of gas charging channels at different stages of charging in turn, leading to reductions in pore-throat radius, throat length and coordination number of the pathway, which is the main increase stage of gas permeability and gas saturation. Among which, pore-throats 30–50 μm in radius control the increase pattern of gas saturation. In the stable stage, gas charging pathways have expanded to the maximum, so the pathways keep stable in pore-throat radius, throat length, and coordination number, and irreducible water remains in the pore system, the gas phase is in concentrated clusters, while the water phase is in the form of dispersed thin film, and the gas saturation and gas permeability tend stable. Connected pore-throats less than 20 μm in radius control the expansion limit of the charging pathways, the formation of stable gas-water distribution, and the maximum gas saturation. The heterogeneity of connected pore-throats affects the dynamic variations of gas phase charging and gas-water distribution. It can be concluded that the pore-throat configuration and heterogeneity of the micro-nanometer pore system control the dynamic variations of the low-permeability (tight) sandstone gas charging process and gas-water distribution features.

The influence of heat perturbation on natural gas hydrate sediment in deepwater drilling and cementing process

ABSTRACT The deepwater drilling and cementing techniques achieved significant development in recent years. However, the engineering response mechanism of natural gas hydrate sediment (NGHS) during drilling and cementing process is far from clear, which challenges the safe development of offshore petroleum resources. To reveal the influence of heat perturbation on NGHS of hydration exotherm of cement slurry and drilling fluid circular temperature increment in the process of subsequent drilling operation in shallow seabed, a mathematical model of hydrate dissociation is developed to simulate the influence by using the numerical simulation approach in this paper, and taking a natural gas hydrate reservoir at Liwan slope in the northern South China Sea as an example. The mathematical model comprehensively takes into account heat conduction, heat consumption of hydrate dissociation, hydrate dissociation dynamics, fluid seepage around the wellbore, and their coupling reaction. The analysis shows that the increase of heat transmitted from drilling and cementing process to NGHS facilitates the hydrate dissociation, leading to the growth of the sediment pore pressure in the near wellbore, the fluctuation range of pore pressure is rapidly diffused and significantly larger than the wellbore radius. The gas from the hydrate dissociation will permeate to the wellbore-distant area and reform hydrate with water. The gas will not to totally reformed hydrate in the short term, partially gathering around the wellbore, and the maximum gas saturation in the sediment is between 10% and 12%. The hydrate reformation area will be several times than the wellbore radius. But the maximum hydrate saturation will not exceed a certain value. The transition area of hydrate dissociation area to hydrate reformation area is quite narrow, and the range of high pore pressure is identical to that of the hydrate reformation. The hydrate dissociation will lead to NGHS instability, so the influence of heat perturbation on NGHS should be paid attention to in deepwater drilling and cementing process.

Assessment of Trapping Mechanisms of CO2 Sequestration and Optimization of Key Process Parameters in a Deep Saline Aquifer Using Reservoir Simulation and Response Surface Methodology

Deep saline aquifers are perhaps one of the most ubiquitous sites available for CO2 sequestration. In this study, a compositional reservoir simulator was used to evaluate the effects of various CO2 trapping mechanisms in a saline aquifer which includes structural, solubility and mineral trapping. CO2 was injected at a rate of 4000 m3/day at the bottom of the aquifer for 50 years. The results indicate that structural trapping dominated for initial 3 years, after which the maximum gas saturation and pressure was reached. During solubility trapping, the gas saturation decreased by more than 70% of the maximum saturation. Mineral trapping decreased saturation further by another 10%. In another approach, the effect of wastewater injection following injection of CO2 was evaluated. The numerical simulations show reduction in both the amount of mobile CO2 and its upward migration. Among the different trapping mechanisms, solubility trapping is found to be the most vital one. Multivariate analysis and optimization of the responses, viz. average gas saturation and average pressure rise, were carried out using response surface methodology. Optimized results were obtained for efficient CO2 sequestration with lesser mobile CO2 and pressure rise at lower values of injection rate (1000 m3/day), injection time (50 years), vertical-to-horizontal permeability ratio, Kv/Kh (0.016), and residual gas saturation (0.4).

Impact of formation slope and fault on CO2 storage efficiency and containment at the Shenhua CO2 geological storage site in the Ordos Basin, China

Carbon dioxide (CO2) storage security is a key issue in CO2 geological storage (CGS). A three-dimensional (3D) conceptual reservoir model of the Shenhua CO2 geological storage site in the Ordos Basin has been used to investigate the impact of reservoir formation dip and the influence of enhanced permeability fault zones on CO2 storage and migration security. A total of 8 simulations were carried out using the TOUGH2 integral finite difference modelling code with the ECO2N fluid property module. The simulation results showed that the dip of the reservoir formation and fault had a significant impact on CO2 migration and storage security. Increasing the dip of the reservoir increased CO2 migration distance, decreased the total volume of CO2 safely stored in the formation and resulted in increased maximum gas saturation and liquid mass fraction of dissolved CO2. The presence of fault provided a channel for CO2 leakage and caused an irregular distribution of formation pressure. The onset time of leakage through the fault proved to be a function of formation dip, occurring at 465, 230, and 160 years following commencement of CO2 injection for dips of 5°, 10°, and 15° respectively. The lateral extent of both the high saturation CO2 plume and the plume of dissolved CO2 was greater in the steeply dipping faulted reservoir model, suggesting that gently dipping un-faulted reservoir formations should be selected for future CGS projects in the Ordos Basin.

The experimental modeling of gas percolation mechanisms in a coal-measure tight sandstone reservoir: A case study on the coal-measure tight sandstone gas in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Tight sandstone gas from coal-measure source rock is widespread in China, and it is represented by the Xujiahe Formation of the Sichuan Basin and the Upper Paleozoic of the Ordos Basin. It is affected by planar evaporative hydrocarbon expulsion of coal-measure source rock and the gentle structural background; hydrodynamics and buoyancy play a limited role in the gas migration-accumulation in tight sandstone. Under the conditions of low permeability and speed, non-Darcy flow is quite apparent, it gives rise to gas-water mixed gas zone. In the gas displacing water experiment, the shape of percolation flow curve is mainly influenced by core permeability. The lower the permeability, the higher the starting pressure gradient as well as the more evident the non-Darcy phenomenon will be. In the gas displacing water experiment of tight sandstone, the maximum gas saturation of the core is generally less than 50% (ranging from 30% to 40% and averaging at 38%); it is similar to the actual gas saturation of the gas zone in the subsurface core. The gas saturation and permeability of the core have a logarithm correlation with a correlation coefficient of 0.8915. In the single-phase flow of tight sandstone gas, low-velocity non-Darcy percolation is apparent; the initial flow velocity (Vd) exists due to the slippage effect of gas flow. The shape of percolation flow curve of a single-phase gas is primarily controlled by core permeability and confining pressure; the lower the permeability or the higher the confining pressure, the higher the starting pressure (0.02–0.08 MPa/cm), whereas, the higher the quasi-initial flow speed, the longer the nonlinear section and the more obvious the non-Darcy flow will be. The tight sandstone gas seepage mechanism study shows that the lower the reservoir permeability, the higher the starting pressure and the slower the flow velocity will be, this results in the low efficiency of natural gas migration and accumulation as well as low gas saturation. The laboratory modeling on gas migration accumulation mechanism in coal-measure tight sandstone can provide a theoretic foundation to reveal the tight sandstone gas enrichment regularity, evaluation of prospecting area, and the study of development mechanism.

The interpretation of amplitude changes in 4D seismic data arising from gas exsolution and dissolution

This study examines the four-dimensional (4D) seismic signatures from multiple seismic surveys shot during gas exsolution and dissolution in a producing hydrocarbon reservoir, and focuses in particular on what reservoir information may be extracted from their analysis. To aid in this process, hydrocarbon gas properties and behaviour are studied, and their relationship to the fluid-flow physics is understood using numerical simulation. This knowledge is then applied to interpret the seismic response of a turbidite field in the UK Continental Shelf (UKCS). It is concluded that for a repeat seismic survey shot 6 months or more after a pressure change above or below bubble point (as in our field case), the gas-saturation distribution during either exsolution or dissolution exists in two fixed saturation conditions defined by the critical and the maximum possible gas saturation. Awareness of this condition facilitates an interpretation of the data from our field example, which has surveys repeated at intervals of 12–24 months, to obtain an estimate of the critical gas saturation of between 0.6 and 4.0%. These low values are consistent with a range of measurements from laboratory and numerical studies in the open literature. Our critical gas-saturation estimate is also in qualitative agreement with the solution gas–oil ratios estimated in a material balance exercise using our data. It is not found possible to quantify the maximum gas saturation using the 4D seismic data alone, despite the advantage of having multiple surveys, owing to the insensitivity of the seismic amplitudes to the magnitude of this gas saturation. Assessment of the residual gas saturation left behind after secondary gas-cap contraction during the dissolution phase suggests that small values of less than a few per cent may be appropriate. The results are masked to some extent by an underlying water flood. It is believed that the methodology and approach used in this study may be readily generalized to other moderate- to high-permeability oil reservoirs, and used as input in simulation model updating.

Experimental study of gas and water transport processes in the inter-cleat (matrix) system of coal: Anthracite from Qinshui Basin, China

Abstract The operation and numerical simulation of CO2-ECBM processes requires a thorough understanding of the fluid conductivity properties of the coal matrix. Therefore, single phase (water) and two-phase (water and gas) fluid flow tests on a cylindrical anthracite coal matrix plug of 28.5 mm in diameter and about 20 mm in length were conducted in a triaxial flow cell at a confining pressure and axial load of 20 MPa. The absolute permeability coefficient, determined by single phase steady-state water flow tests, was about 2.0 ∙ 10− 20 m2 (20 nDarcy). Two-phase flow tests (gas breakthrough tests) were performed by imposing high differential gas pressures (up to 7 MPa) on the water-saturated sample and monitoring the pressure changes over time in closed upstream and downstream reservoirs. Argon (Ar), methane (CH4) and carbon dioxide (CO2) showed significant differences in their pressure transient curves during gas breakthrough tests, which indicated different controlling processes. The inert gas Ar exhibited capillary pressure-controlled breakthrough behavior. The maximum effective permeability, measured after gas breakthrough at maximum gas saturation, was 1.8 ∙ 10− 21 m2 (1.8 nDarcy); a residual pressure difference referred to as the “capillary threshold pressure” was 0.9 MPa for the Ar–water–coal system. The sorbing gas CH4 exhibited solely diffusion-controlled transport behavior, and no indications of capillary pressure effects. The reactive and sorbing gas CO2 showed initially capillary pressure-controlled and subsequently diffusion-controlled breakthrough behavior. The mass balance of the gas breakthrough tests indicated that the bulk of CO2 and CH4 were taken up by the coal sample. Sorption accounted for the strong uptake of CH4 by the coal sample, whereas both sorption and, to a lesser extent, CO2–water–mineral reactions were inferred for CO2.

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

AbstractThe capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N2, CO2 and CH4 breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (kabs), determined by steady‐state fluid flow tests, ranged between 10−22 and 10−15 m2. Maximum effective permeabilities to the gas phase keff(max), measured after gas breakthrough at maximum gas saturation, extended from 10−26 to 10−18 m2. Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (Pd), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N2, CO2 and CH4, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.

Flooding for Tertiary Recovery After Successful Gas Injection for Secondary Recovery-Brookhaven, Mississippi

Gas injection processes in Brookhaven field have increased oil recovery from 36 million barrels to 64 million barrels. Water injection after the gas injection has already increased recovery by 3 1/2 million barrels and is expected to account eventually for more than 5 million barrels. Thanks largely to monitoring programs, the tertiary recovery has been profitable. Introduction The description, analysis, and performance of the Brookhaven, Miss., oil field under gas injection have been well and accurately documented in the literature. As a result, the success of the gas displacement processes in this reservoir with large permeability variation is generally well known in the permeability variation is generally well known in the industry.This paper describes the successful recovery of additional oil by supplementing and then replacing gas displacement with water displacement. Success in recovering the waterflood oil was assured by the monitoring programs, which eliminated or delayed expenditures until oil production was reasonably well assured. Reservoir History and Description The Brookhaven field, located in South Central Mississippi, was discovered in June 1943. Active development on 40-acre spacing began in 1945. Production is from the Basal Tuscaloosa, in the Upper Production is from the Basal Tuscaloosa, in the Upper Cretaceous, at an average producing depth of approximately 10,300 ft subsurface, or 9,800 ft subsea. The proved closure is approximately 400 ft. The Tuscaloosa is a sandstone reservoir of erratic deposition. A large permeability variation exists, but the zones of high permeability do not normally appear to be continuous between wells. Several north-south trending faults have combined with sand pinchouts to subdivide the field into isolated producing areas. Fig. 1 is a structure map on the top of the Basal Tuscaloosa. The area farthest west, defined as Block H, was discovered in 1968, fault separated from the remainder of the field. Block H production has been involved in neither the gas injection program nor the waterflood program, and consequently, has been omitted from the field totals given here.The Brookhaven reservoir fluid was a highly undersaturated oil, and the need for pressure maintenance was soon apparent. By June 1948, the field was unitized and gas injection was begun. The reservoir pressure initially was 4,537 psi at a subsea datum of pressure initially was 4,537 psi at a subsea datum of 9,800 ft, but the pressure in much of the field bad dropped below 2,500 psi when gas injection began. By 1961, sufficient gas had been injected to raise the reservoir pressure above 3,300 psi. Fig. 2 is a map indicating the maximum gas saturation reached in the gas-swept zone. The gas saturation was estimated through the use of Buckley-Leverett displacement calculations.In 1957 a program of alternately injecting slugs of produced water with the injected gas (WAG) was produced water with the injected gas (WAG) was instituted. Later, the program was revised in an attempt to return all of the produced water to the reservoir through certain previous gas injection wells.In 1965 a pilot waterflood program was begun in an economically depleted gas-swept portion of the field. Waterflooding has since been expanded to include most of the major areas of the field. JPT P. 783