Single-phase permeability k has intensively been investigated over the past several decades by means of experiments, theories and simulations. Although the effect of surface roughness on fluid flow and permeability in single pores and fractures as well as networks of fractures was studied previously, its influence on permeability in a random mass fractal porous medium constructed of pores of different sizes remained as an open question. In this study, we, therefore, address the effect of pore–solid interface roughness on single-phase flow in random fractal porous media. For this purpose, we apply a mass fractal model to construct porous media with a priori known mass fractal dimensions 2.579≤Dm≤2.893 characterizing both solid matrix and pore space. The pore–solid interface of the media is accordingly roughened using the Weierstrass–Mandelbrot approach and two parameters, i.e., surface fractal dimension Ds and root-mean-square (rms) roughness height. A single-relaxation-time lattice Boltzmann method is applied to simulate single-phase permeability in the corresponding porous media. Results indicate that permeability decreases sharply with increasing Ds from 1 to 1.1 regardless of Dm value, while k may slightly increase or decrease, depending on Dm, as Ds increases from 1.1 to 1.6.
The detection of radioactive noble gases is a primary technology for verifying compliance with the pending Comprehensive Nuclear-Test-Ban Treaty. A fundamental challenge in applying this technology for detecting underground nuclear explosions is estimating the timing and magnitude of the radionuclide signatures. While the primary mechanism for transport is advective transport, either through barometric pumping or thermally driven advection, diffusive transport in the surrounding matrix also plays a secondary role. From the study of primordial noble gas signatures, it is known that xenon has a strong physical adsorption affinity in shale formations. Given the unselective nature of physical adsorption, isotherm measurements reported here show that non-trivial amounts of xenon adsorb on a variety of media, in addition to shale. A dual-porosity model is then discussed demonstrating that sorption amplifies the diffusive uptake of an adsorbing matrix from a fracture. This effect may reduce the radioxenon signature down to approximately one-tenth, similar to primordial xenon isotopic signatures.
Magnetic nanoparticles (MNPs) with surface coatings designed for water treatment, in particular for targeted removal of contaminants from produced water in oil fields, have drawn considerable attention due to their environmental merit. The goal of this study was to develop an efficient method of removing very stable, micron-scale oil droplets dispersed in oilfield produced water. We synthesized MNPs in the laboratory with a prescribed surface coating. The MNPs were superparamagnetic magnetite, and the hydrodynamic size of amine functionalized MNPs ranges from 21 to 255 nm with an average size of 66 nm. The initial oil content of 0.25 wt.% was reduced by as much as 99.9% in separated water. The electrostatic attraction between negatively charged oil-in-water emulsions and positively charged MNPs controls, the attachment of MNPs to the droplet surface, and the subsequent aggregation of the electrically neutral oil droplets with attached MNPs (MNPs-oils) play a critical role in accelerated and efficient magnetic separation. The total magnetic separation time was dramatically reduced to as short as 1 s after MNPs, and oil droplets were mixed, in contrast with the case of free, individual MNPs with which separation took about 36∼72 h, depending on the MNP concentrations. Model calculations of magnetic separation velocity, accounting for the MNP magnetization and viscous drag, show that the total magnetic separation time will be approximately 5 min or less, when the size of the MNPs-oils is greater than 360 nm, which can be used as an optimum operating condition.
Modeling the rate of penetration of the drill bit is essential for optimizing drilling operations. This paper evaluates two different approaches to ROP prediction: physics-based and data-driven modeling approach. Three physics-based models or traditional models have been compared to data-driven models. Data-driven models are built using machine learning algorithms, using surface measured input features - weight-on-bit, RPM, and flow rate – to predict ROP. Both models are used to predict ROP; models are compared with each other based on accuracy and goodness of fit (R2). Based on the results from these simulations, it was concluded that data-driven models are more accurate and provide a better fit than traditional models. Data-driven models performed better with a mean error of 12% and improve the R2 of ROP prediction from 0.12 to 0.84. The authors have formulated a method to calculate the uncertainty (confidence interval) of ROP predictions, which can be useful in engineering based drilling decisions.
We present a time-depth relationship for Integrated Ocean Drilling Program (IODP) Expedition 341 Southern Alaska Margin Sites U1420 and U1421 using high-resolution multichannel seismic, core, and logging data. Calibrating and combining core and logging data at each site minimizes data gaps in physical properties information. Remaining data gaps were interpolated using spline fitting in order to provide continuous estimates of bulk density and compressional wave velocity for the full drilled interval. We use the interpolated physical property curves for bulk density and compressional wave velocity at each site to generate synthetic seismic traces. At Site U1421, vertical seismic profiling further constrained the time-depth relationship and was used to calibrate the velocity curve and provide input for the initial velocity model during the tie. Finally, we matched simulated reflectors in the synthetic trace with events in the nearby seismic traces and established a time-depth relationship at each site.
Any efficient exploitation of new petroleum reservoirs necessitates developing methods to mobilize the crude oils from such reservoirs. Here silicon dioxide nanoparticles (SiO2 NPs) were used to improve the efficiency of the chemical-enhanced oil recovery process that uses surfactant flooding. Specifically, SiO2 NPs (i.e., 0, 0.001, 0.005, 0.01, 0.05, and 0.1 wt%) and Tween®20, a nonionic surfactant, at 0, 0.5, and 2 critical micelle concentration (CMC) were varied to determine their effect on the stability of nanofluids and the interfacial tension (IFT) at the oil–aqueous interface for 5 wt% brine-surfactant-SiO2 nanofluid-oil systems for West Texas Intermediate light crude oil, Prudhoe Bay medium crude oil, and Lloydminster heavy crude oil. Our study demonstrates that SiO2 NPs may either decrease, increase the IFT of the brine-surfactant-oil systems, or exhibit no effects at all. For the brine-surfactant-oil systems, the constituents of the oil and aqueous substances affected the IFT behavior, with the nanoparticles causing a contrast in IFT trends according to the type of crude oil. For the light oil system (0.5 and 2 CMC Tween®20), the IFT increased as a function of SiO2 NP concentration, while a threshold concentration of SiO2 NPs was observed for the medium (0.5 and 2 CMC Tween®20) and heavy (2 CMC Tween®20) oil systems in terms of IFT trends. Concentrations below the SiO2 NP threshold concentration resulted in a decrease in IFT, and concentrations above this threshold resulted in an increase in IFT. The IFT decreased until the NP concentration reached a threshold concentration where synergetic effects between nonionic surfactants and SiO2 NPs are the opposite and result in antagonistic effects. Adsorption of both SiO2 NPs and surfactants at an interface caused a synergistic effect and an increased reduction in IFT. The effectiveness of the brine-surfactant-SiO2 nanofluids in decreasing the IFT between the oil-aqueous phase for the three tested crude oils were ranked as follows: (1) Prudhoe Bay > (2) Lloydminster > and (3) West Texas Intermediate. The level of asphaltenes and resins in these crude oil samples reflected these rankings. A decrease in the IFT also indicated the potential of the SiO2 NPs to decrease capillary pressure and induce the movement and recovery of oil in original water-wet reservoirs. Conversely, an increase in IFT indicated the potential of SiO2 NPs to increase capillary pressure and oil recovery in reservoirs subject to wettability reversal under water-wet conditions. Raspberry-like morphology particles were discovered in 5 wt% brine-surfactant-SiO2 nanofluid-oil systems. The development of raspberry-like particles material with high surface area, high salt stability, and high capability of interfaces alteration and therefore wettability changes offers a wide range of applications in the fields of applied nanoscience, environmental engineering, and petroleum engineering.
The interactions of microbial methane generation in fine-grained clay-rich sediments, methane migration, and gas hydrate accumulation in coarse-grained, sand-rich sediments are not yet fully understood. The Terrebonne Basin in the northern Gulf of Mexico provides an ideal setting to investigate the migration of methane resulting in the formation of hydrate in thin sand units interbedded with fractured muds.
Using 3D seismic and well log data, we have identified several previously unidentified hydrate bearing units in the Terrebonne Basin. Two units are >100 m-thick fine-grained clay-rich units where gas hydrate occurs in near-vertical fractures. In some locations, these fine-grained units lack fracture features, and they contain 1–4-m thick hydrate bearing-sands. In addition, several other thin sand units were identified that contain gas hydrate, including one sand that was intersected by a well at the location of a discontinuous bottom-simulating reflector. Using correlation of well log data to seismic data, we have mapped and described these new units in detail across the extent of the available data, allowing us to determine the variation of seismic amplitudes and investigate the distribution of free gas and/or hydrate.
We present several potential source-reservoir scenarios between the thick fractured mud units and thin hydrate bearing sands. We observe that hydrate preferentially forms within thin sand layers rather than fractures when sands are present in larger marine mud units. Based on regional mapping showing the patchy lateral extent of the thin sand layers, we propose that diffusive methane migration or short-migration of microbially generated methane from the marine mud units led to the formation of hydrate in these thin sands, as discontinuous sands would not be conducive to long-range migration of methane from deeper reservoirs.
The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part due to lack of consistent evidence for - and clarification of - NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research has emphasized that NPs bring about "pore plugging" that reduces pressure transmission, and in turn fluid inflow, into the shale pore matrix which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any considerable filtration in shales considering the very low permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: "how, when, why do nanoparticles plug up shale pore throats?"
Zeta Potential (ZP) measurements were carried out on the aqueous dispersions (NPs) and on intact shale thin sections exposed to the nanofluid in order to determine the degree of interaction behavior between NPs and shales. The experimental data was then used to calculate DLVO curves (describes the force between charged surfaces interacting through a liquid medium) in order to determine if the total potential energy was sufficient for NP's to diffuse through the repulsive barrier and attract (or overcome repulsion) to the shale surface. Estimated DLVO curves are used to demonstrate the NP's ability to contribute to borehole stability but are not directly correlated, and therefore, NP effects on shale stability were studied in detail using pore pressure transmission tests (PTT), which measure fluid pressure penetration in shales, and modified Thick Wall Collapse (TWC) tests, which explore the influence of NPs on the collapse pressure of shale samples.
Our investigation shows that NPs can reduce fluid pressure penetration and delay borehole collapse in shales, but only under certain conditions. Electrostatic and electrodynamic interaction between NP's and shale surfaces, governed by DLVO forces, is the main mechanism that will lead to pore throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective stress reduction. For Mancos shale, it was shown that 20 nm nanosilica (anionic) are effective in partially plugging the pore throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, the positively charged nanosilica (cationic) showed better results for pore-plugging capabilities than the anionic nanosilica.
The findings lead to some interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy will depend on the specific type of shale, the specific type, size and concentration of NP, the interaction between NP-shale, and external factors such as pH, salinity, temperature etc. NP use for practical shale stabilization therefore requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be "one size fits all".
We studied methane migration mechanisms and associated hydrate accumulation rates in coarse-grained sands of the Terrebonne Basin, located in Walker Ridge Block 313, northern Gulf of Mexico. Hydrate in this area is distributed heterogeneously within ~900 m of methane hydrate stability zone, in both thick (10-25 m) and thin (< 3 m) sand layers, and in units of subvertical hydrate-filled fractures. We investigated hydrate formation from diffusively and advectively supplied methane using one-, two-, and three-dimensional basin modeling. We found that different migration mechanisms result in characteristic hydrate accumulation signatures that can link field observations to methane sources.
We performed a series of laboratory and image analysis on organic shale samples before and confined compressive strength tests. Following failure, we often observe an increase in pore volume in the sub-micron range, which appears to be related to the formation of microcracks that in some cases cross or terminate in organic matter, intersecting the organic-hosted pores. Samples with higher clay content tended not to display this behavior. The microcrack networks allow the hydrocarbons to migrate to the main induced tensile fractures. The disconnected nature of the microcracks causes only a slight increase in permeability, consistent with other observations.
Pore pressure depletion from hydrocarbon production causes an increase in effective stress in the reservoir and can result in significant compaction. The change in stress state with depletion induces a change in permeability both in the far-field and the near wellbore region. Modeling the depletion induced permeability alteration is crucial in forecasting hydrocarbon production and designing a drilling strategy. Porosity-based permeability models are typically used in which the permeability changes are assumed to be isotropic. However, most rocks are anisotropic, and the stress changes due to depletion and drilling a well are also anisotropic. As an example, we compared isotropic and anisotropic permeability predictions around a hypothetical well drilled in the Tor formation in Valhall field in the North Sea. The results show that isotropic permeability models tend to underestimate the degree of permeability reduction in the near-wellbore region, but even when anisotropy is considered, the permeability in the radial direction still only decreases by about 10%. These results may still need to be considered when designing a development strategy in depleted reservoirs.
Nuclear magnetic resonance (NMR) relaxometry is an excellent tool for probing the interactions between solid pore surface and pore fluids in porous media. Surface relaxation is a key component of NMR relaxation. It is well-known that in conventional rocks, paramagnetic centers contribute most to the surface relaxation phenomenon. However, the interactions between organic pore surfaces and pore fluids, and the mechanism of surface relaxation in organic shale pores, are not well-understood. We tackle the issue using deuterated compounds to adjust the proton density in the liquid phase and monitoring the transverse relaxation rate changes of kerogen-fluid mixtures. With the Barnett and Eagle Ford kerogen isolates, we found that for alkanes, it is intramolecular dipolar coupling that dominates among the magnetic interactions. As a result, the transverse relaxation rate of alkane proton spins is more likely to be dependent on the concentration of active adsorption sites on the kerogen surface, rather than the kerogen proton density. For water inside organic pores, surface relaxation most likely originates from hydrogen bonding and intermolecular dipolar coupling. We also examined the temperature effect on kerogen surface relaxation and found temperature-dependent behavior that is consistent with surface relaxation by hydrogen bonding and homonuclear dipolar coupling interactions.
One of NMR’s major advantages is its ability to differentiate various fluids inside porous media. However, the logging speed of the NMR tools is usually slow due to the long wait time needed for this application, and it is not always a trivial task to discern the fluid types, especially when there are multiple fluid components present. Water-soluble contrast agents, such as MnCl2 or Gd- EDTA, have been proposed for use during the logging process to accelerate the relaxation of protons in water molecules. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doping of the water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to the water-soluble contrast agents that are compatible with OBM.
In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated.
The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is needed, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from claybound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring.
The evaluation of Nuclear Magnetic Resonance (NMR) measurements can be challenging in organic-rich mudrocks because of their heterogeneity, tight pores, presence of kerogen, and lack of understanding of relaxation mechanism on kerogen surface. Conventional NMR simulation methods do not account for any dipolar coupling in kerogen pores. Reliable pore-scale modeling of NMR response in organic-rich mudrocks enables better understanding of the influence of the aforementioned parameters on NMR measurements. In this paper, we introduce a pore-scale simulation method for reliable modeling of NMR response in kerogen isolates and organic-rich mudrocks for different pulse sequences. We use the developed simulator to quantify the effects of homonuclear dipolar coupling on NMR response in organic pores in simple pore geometries and actual mudrock samples.
We simulated the NMR response in isolated ellipsoidal pores, kerogen isolates and organic-rich mudrocks using a pore-scale finite volume simulation technique. The inputs to the simulator were isolated ellipsoidal pores, pore-scale images of kerogen isolates, and 3D pore-scale FIB-SEM (Focused Ion Beam Scanning Electron Microscope) images of organic-rich mudrock samples, including the topology of different matrix components such as kerogen, inorganic minerals, and bulk and surface properties of different pore fluids present in the pore space. The outputs from the simulator were transverse (T2) and longitudinal (T1) decay constants in the aforementioned pore geometries. We used Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence and Inversion Recovery combined with CPMG pulse sequence (IR-CPMG) to simulate T2 distribution and T1- T2 maps, respectively.
Results of numerical modeling demonstrated the measurable sensitivity of the NMR response in organic-rich mudrocks to surface relaxation anisotropy and correlation time. We showed that the dominant peak of T2 distribution relatively varied by 29%, 11%, and 10%, due to surface relaxation anisotropy in ellipsoidal pores, kerogen isolates, and an actual organic-rich mudrock sample, respectively. The dominant T2 peak decreased by 92%, 89%, and 89% with increase in correlation time in ellipsoidal pores, kerogen isolates, and the actual organic-rich mudrock sample, respectively. The T1/T2 ratio increased from 1.1 to 17.7 for ellipsoidal pores, from 1.1 to 15.9 for kerogen isolates, and 1.1 to 10.8 for the actual organic-rich mudrock sample when correlation time increased from 1.5e-07 to 5.5e-06. The outcome of this paper is a new finite volume based simulation method for modeling NMR response, which accounts for homonuclear dipolar coupling in organic pores and can reliably model magnetization decay in kerogen nano-pores. Reliable pore-scale modeling can improve the assessment of petrophysical properties in complex organic-rich mudrocks and help in better understanding of their productivity.
Pore pressures in sediments at convergent margins play an important role in driving chemical fluxes and controlling deformation styles and localization. In the Bering Trough offshore Southern Alaska, extreme sedimentation rates over the last 140 kyr as a result of glacial advance/retreats on the continental shelf have resulted in elevated pore fluid pressures in slope sediments overlying the Pamplona Zone fold and thrust belt, the accretionary wedge resulting from subduction of the Yakutat microplate beneath the North American Plate. Based on laboratory experiments and downhole logs acquired at Integrated Ocean Drilling Program Site U1421, we predict that the overpressure in the slope sediments may be as high as 92% of the lithostatic stress. Results of one‐dimensional numerical modeling accounting for changes in sedimentation rate over the last 130 kyr predicted overpressures that are consistent with our estimates, suggesting that the overpressure is a direct result of the rapid sedimentation experienced on the Bering shelf and slope. Comparisons with other convergent margins indicate that such rapid sedimentation and high overpressure are anomalous in sediments overlying accretionary wedges. We hypothesize that the shallow overpressure on the Bering shelf/slope has fundamentally altered the deformation style within the Pamplona Zone by suppressing development of faults and may inhibit seismicity by focusing faulting elsewhere or causing deformation on existing faults to be aseismic. These consequences are probably long‐lived as it may take several million years for the excess pressure to dissipate.
This paper reports on the dispersion stability of 150 nm polyvinyl alcohol coated biochar nanoparticles in brine water. Biochar is a renewable, carbon based material that is of significant interest for enhanced oil recovery operations primarily due to its wide ranging surface properties, low cost of synthesis, and low environmental toxicity. Nanoparticles used as stabilizing agents for foams (and emulsions) or in nanofluids have emerged as potential alternatives to surfactants for subsurface applications due to their improved stability at reservoir conditions. If, however, the particles are not properly designed, they are susceptible to aggregation because of the high salinity brines typical of oil and gas reservoirs. Attachment of polymers to the nanoparticle surface, through covalent bonds, provides steric stabilization, and is a necessary step. Our results show that as the graft density of polyvinyl alcohol increases, so too does the stability of nanoparticles in brine solutions. A maximum of 34 wt% of 50,000 Da polyvinyl alcohol was grafted to the particle surface, and the size of the particles was reduced from ~3500 nm (no coating) to 350 nm in brine. After 24 h, the particles had a size of ~500 nm, and after 48 h completely aggregated. 100,000 Da PVA coated at 24 wt% on the biochar particles were stable in brine for over 1 month with no change in mean particle size of ~330 nm.