Permeability upscaling in carbonate rocks is challenging due to the heterogeneity at multiple scales. Although there are several computational methods for permeability upscaling, the applicability, ...computational time, and the associated accuracy of these methods may vary significantly. This article modified an established Karim and Krabbenhoft renormalization method (KRM) and proposed a regression-based renormalization for permeability upscaling in carbonate rocks, and the results are compared with the classical KRM. To this end, permeability at the small-scale samples (size = 5003 and 6003 voxels, from 405 to 7944 μm3) and the whole core plug scale are computed from three carbonate samples of varying heterogeneity and composition using pore network models extracted from 3D micro-CT images. Subsequently, the modified regression-based renormalization method is applied to calculate the regression (upscaled) permeability. Our results indicate that the regression permeability is in good agreement with experimental permeability for full-size core plug estimations (maximum error = 11.07%) using the proposed RKRM approachsuggesting the accuracy of this method. Furthermore, the relative error of the permeability estimation from small-scale samples using KRM was much higher than those of the RKRMsuggesting the superiority of the proposed approach over the classical one. The observed errors in permeability using the RKRM approach, despite being lower than the classical KRM approach, are attributed to the heterogeneity of carbonate samples at the sub-core and core scales. The results of this study thus add to the general understanding of permeability upscaling in carbonates and the associated impact of heterogeneity.
The National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey are leading an effort to conduct an extended gas hydrate production test ...in northern Alaska. The proposed production test required the drilling of an initial stratigraphic test well (STW) to confirm the geologic conditions of the proposed test site. This well was completed in January 2019 in cooperation with the Prudhoe Bay Unit Working Interest Owners. The Prudhoe Bay Unit Hydrate-01 STW was spudded on 10-December-2018. Downhole data acquisition was completed on 25-December-2018, and the rig was released on 01-January-2019. The Hydrate-01 STW was drilled in two sections, including the surface hole that was drilled to a depth of 2248 ft measured depth (MD) (685 m MD) and cased, and the production hole section that was drilled to a depth of 3558 ft MD (1084 m MD) and also cased. A thermally chilled mineral-oil-based mud was used in the main (production) hole section of the well to maintain wellbore stability and quality of the wellbore acquired data. The primary wellbore data were acquired using logging-while-drilling tools. A sidewall pressure core system was also deployed to gather grain size and other data needed for the design of the future production test wells. In addition to confirming the geologic conditions at the test site, the Hydrate-01 STW was designed to serve as a monitoring well during future field operations. Therefore, two sets of fiber-optic cables, each including a bundled distributed acoustic sensor (DAS) and a distributed temperature sensor (DTS), were clamped to the outside of the production casing and cemented in place. In March 2019, the project team acquired three-dimensional (3D) DAS vertical seismic profiling data in the Hydrate-01 STW. Temperature surveys were also acquired with the DTS as deployed in the Hydrate-01 STW during the completion of the well and nearly continuously since March-2019.
The interfacial behavior of surfactants exerts a considerable impact on the chemical flooding-produced liquid treatment project. For circumventing the limitations of model simplification and ...single-factor simulation of previous molecular dynamics (MD) studies, this paper based on the experimental results of crude oil-phase and water-phase composition constructed different simulation systems of “crude oil/SDBS/mineral water” considering the concentration of sodium dodecyl benzene sulfonate (SDBS). The impact of SDBS concentration on the stability of the crude oil–mineral water interfacial film was explored, and the simulation results were verified by comparing with the simulation system of “crude oil/SDBS/pure water” and interfacial tension experiments. The simulated results showed that the SDBS molecules in the system exist in the form of a monolayer film after dynamic relaxation equilibrium, and with the increase in concentration, the number of SDBS molecules per unit area of the film increases, and the molecular chain bending characteristics are weakened. The order of the effect of inorganic cations on the aggregation degree of SDBS is Ca2+ > Na+ > K+ > Mg2+. When the concentration of SDBS increased from 0.15 to 0.70 mol/L, the total oil water interfacial film thickness increased from 1.433 nm in the crude oil/SDBS/mineral water system and 1.272 nm in the crude oil/SDBS/pure water system to 2.125 nm in the crude oil/SDBS/mineral water system and 2.398 nm in the crude oil/SDBS/pure water system. The absolute value of interface formation energy increased from 1223.59 and 1236.32 to 2739.19 and 3033.64, respectively, which are also basically consistent with the experimental results of interface tension. Furthermore, inorganic ions will weaken the performance of the surfactant SDBS and detrimentally affect the structural strength and stability of interfacial films. These results offer useful insights into the stabilization mechanism of oil–water emulsions. In particular, they provide a basis for the design and optimization of new pathways for oil–water emulsion instability in oilfield development.
When liquid nitrogen (LN2) comes in contact with the coal seam, the mechanical properties of the coal body will be changed, which can fracture the coal seam and improve the efficiency of coalbed ...methane extraction. To explore the influence of liquid nitrogen on the mechanical properties of dry and saturated coal, this paper adopts different LN2 treatment methods (freezing 0, 50 min, F-T 10 cycles) to determine the mechanical strength of the coal sample and the ultrasonic longitudinal wave velocity. After a single freezing of LN2 for 50 min, the mechanical properties of the dry and saturated frozen coal samples have been improved. The mechanical strength of the saturated frozen coal samples has increased more than that of the dry state; the freeze–thaw cycle reduces the mechanical strength. The compressive strength has the largest decrease, which is reduced by 45.2%; the wave velocity of the dry coal sample shows a trend of first increasing and then decreasing after different LN2 treatments, but the overall change is small. The water-saturated coal sample increases during a single freezing and decreases during the freeze–thaw cycles, and the lowest wave speed is only 0.821 km/s. By analyzing the changes in mechanical properties, it is concluded that water-saturation treatment can damage its own strength. Short-term freezing can help increase the mechanical strength of coal. Freeze–thaw cycles cause serious deterioration and damage to coal. The increase in the pore volume of coal in the freezing stage is much greater than that in the melting stage.
The application of JP-10 (exo-tetrahydrodicyclopentadiene) in regenerative cooling channels is restrained by the severe coke deposition during its supercritical pyrolysis, while using hydrogen donors ...is one of the coke deposition suppression methods. To get new insights into the possible coke inhibition effect of the hydrogen donor under supercritical conditions, the pyrolysis and coke deposition of JP-10 in the presence of decalin at different concentrations (10–30 wt %) were experimentally examined in an electrically heated tube reactor at 4.0 MPa and 550–730 °C. The addition of decalin promotes the pyrolysis of JP-10, and the heat sink is maximumly improved from 2.87 to 3.21 MJ/kg (11.6%) at 730 °C, attributed to the higher conversion and mole yield of light alkenes. Meanwhile, the coke on the surface and in the bulk flow was maximumly reduced 43.0 and 31.8% with the addition of decalin, respectively. The coke deposition suppression is in agreement with the increased selectivity of stable precursors and the reduced content of polycyclic aromatic hydrocarbons (PAHs). On the basis of product distributions, decalin provides more free radicals to enhance the bimolecular reaction, then promotes the conversion of JP-10, and also provides active hydrogen radicals to restrain the formation of PAHs in the bulk flow and the radical growth of surface coke.
Gas hydrates are found in significant quantities on the North Slope of Alaska in subpermafrost sand units and intermixed in lower portions of permafrost within the hydrate stability window. While ...conventional surface seismic data and established imaging methods can indicate the presence of gas hydrate reservoirs, producing high-resolution images of (seismically) thin layers remains challenging due to the preferential attenuation of the higher-frequency data components. An alternative strategy is to use distributed acoustic sensing (DAS) involving cementing optical fibers into boreholes to measure seismic wavefield energy closer to the strata of interest using vertical seismic profiling (VSP). DAS VSP imaging takes advantage of the shorter travel paths and reduced attenuation to generate higher-resolution near-well images. We illustrate these benefits on a DAS VSP data set acquired at the Hydrate-01 stratigraphic test well located in the Prudhoe Bay Unit of Alaska where significant gas hydrate deposits have been detected in two subpermafrost sand layers that are intended for long-duration production testing. Our DAS data preprocessing workflow effectively isolates the upgoing compressional-wave (P-wave) reflections required for subsurface acoustic imaging. After applying three-dimensional (3-D) tomography to improve the quality of the 3-D migration velocity model, we use 3-D reverse-time migration (RTM) to develop high-quality images of the two target sands and minor near-well faulting. We validate our RTM images through highly accurate well-ties with previously acquired petrophysical log data. This study demonstrates that combining 3-D RTM imaging with DAS VSP data provides significant value to gas hydrate and similar projects, and it suggests that more advanced inversion approaches such as (elastic) least-squares RTM could recover higher-resolution and more quantitative estimates of subsurface reflectivity, which would be valuable for refining the understanding of gas hydrate systems.
Kinetic hydrate inhibitors (KHIs) have been used for over 25 years to prevent gas hydrate formation in oil and gas production flow lines, but they are some of the most expensive oilfield production ...chemicals. The main component in KHI formulations is a water-soluble polymer with many amphiphilic groups. Usually, in commercial KHI polymers, the hydrophilic part of these groups is the amide group. In addition, KHI polymers are often incompatible with film-forming corrosion inhibitors. Therefore, we sought to find cheaper but effective KHIs that could also act as a flow line corrosion inhibitor. Continuing earlier work from our group with maleic-based polymers, we have now explored maleic acid/N-vinyl caprolactam (MAcid/VCap) copolymers to introduce VCap, a well-known KHI monomer, together with the cheaper MA monomer. KHI performance screening tests were conducted under high pressure with a structure II-forming natural gas mixture in steel rocking cells using the slow (1 °C/h) constant-cooling test method. Surprisingly, the MAcid/VCap copolymer showed very poor KHI efficacy. GFN2-xTB molecular dynamics simulations revealed that MAcid/VCap exhibits intra-hydrogen bond networks that trap the polymer morphology in the globular form. In this scenario, the caprolactam ring is encapsulated inside the polymer structure due to the intra-hydrogen bonds and the hydrophobic interactions that minimize its ability to interact with the hydrate surfaces, which significantly reduces the MAcid/VCap kinetic inhibition performance. However, the polymer in such globular forms still displays an important amount of its carboxylic groups exposed to water, which explains the water solubility. In contrast to MAcid/VCap copolymers, maleimide derivatives with dibutylamino end groups were effective KHIs and even better with dibutylamine oxide end groups. A terpolymer of MA/VCap reacted with N,N-dibutylaminopropylamine followed by subsequent oxidation of the end groups to dibutylamine oxide and gave the best performance of any maleic-based polymer reported to date. The combination of caprolactam and dibutylamine oxide groups can be thought of as synergism within the same polymer, akin to the excellent synergy of the separate molecules, tributylamine oxide and PVCap.
During the late stage of water flooding, most reservoirs will enter the high water cut stage. The remaining oil is mainly concentrated in the high structural part. At this time, the water flooding ...effect is no longer ideal. Based on this problem, nitrogen foam-enhanced EOR research is carried out. Through two-dimensional visualization experiments, we observed the migration and diffusion of nitrogen foam and summarized the mechanism of nitrogen foam flooding system in enhancing oil recovery in heavy oil reservoirs with bottom water. The physical displacement experiment of core tube is carried out under simulated reservoir conditions, the gas–liquid ratio parameters of nitrogen foam are optimized, and the influence of injection and production methods on recovery factor is studied. The results show that nitrogen foam flooding has certain washing ability and can increase the sweep efficiency. The plugging effect of foam can effectively improve the oil displacement effect. Foam foaming is used to form frothing solution with emulsifying and viscosity-reducing function. The crude oil is produced in the form of foam oil and emulsion under the action of emulsification and viscosity reduction, and the recovery factor is increased. In visual experiments and core tube experiments, the recovery rates of foam flooding stage are 22.4 and 34.9%, respectively. The gas–liquid ratio of 3:1 is the best proportion, and the injection method is the best effect of nitrogen foam flooding and foam huff and puff. The recovery rate of nitrogen foam flooding-foam injection method is 40.7%, which is 5.8% higher than that of nitrogen foam flooding injection mode.
It is of great significance to study the mechanical properties of hydrate-bearing sediments for safe and efficient exploitation of hydrate resources. Considering the lack of studies on clay-bearing ...fine-grained reservoirs, submarine clay taken from the Shenhu Sea in the South China Sea and quartz sand were used to synthesize hydrate-bearing clayey-silty sediments (HBCS). A series of consolidated-drained tests were carried out to investigate the effects of hydrate saturation, effective confining pressure, and their coupling on the mechanical properties of HBCS. The results show that with the increase in hydrate saturation and the decrease in effective confining pressure, the stress–strain curve of the HBCS shows a trend from strain hardening to strain softening. The peak strength and residual strength increase with the increase in effective confining pressure and hydrate saturation. The secant modulus E 50 increases with the increase in hydrate saturation and shows an irregular change trend with the increase in effective confining pressure. The contact area between particles determines the change rule of Secant modulus E 50. With the increase in hydrate saturation, the cohesion first increased rapidly and then increased slowly. The internal friction angle increases with the increase in hydrate saturation, but the increase is small. This indicates that hydrate has a great influence on the cohesion of sediments, but a small influence on the internal friction angle.
Estimating shale oil resources is critical in shale oil exploration, and the pyrolysis parameter S 1 is a frequently used parameter to assess the oil amount in shale. However, S 1 loses some light ...and heavy hydrocarbons due to core storage conditions and experimental technology, resulting in underestimating shale oil resources. In this paper, a set of models were developed to correct the light and heavy hydrocarbon losses for S 1 based on conventional and multistage Rock-Eval experiments on liquefrozen and room-temperature shales collected from the Funing Formation, Subei Basin. Two types of correction models of heavy hydrocarbon loss for liquefrozen and room-temperature shales were determined by comparing the conventional and multistage Rock-Eval experiments, respectively. The light hydrocarbon loss correction model was obtained according to conventional Rock-Eval experiments on liquefrozen and room-temperature shales. Moreover, the estimation models of adsorbed, free, and movable amounts of oil were determined and validated by the oil saturation index (OSI) method. The results show that the total, adsorbed, free, and movable oil contents can be estimated well by these correction models. A case study from the Funing Formation, Subei Basin, indicates that the higher the content of total oil, the higher the amounts of free and movable oil, indicating that shale with more oil also has a more excellent mobile and developable potential. Organic matter is the main adsorbent for shale oil. Shales with TOC greater than 1.5% generally have greater free (movable) oil amounts, which may be the optimal target for shale oil exploration and exploitation. This study provides an innovative approach to correct the key parameters of shale oil resources, and thus, is crucial for the exploration and development of shale oil in the Funing Formation, Subei Basin.
PDF
