Strategizing well locations in unconfined, heterogeneous hydrate reservoirs for maximizing gas production

Natural gas hydrates are a potential alternative to conventional energy due to their high energy density and low carbon with wide distribution across the globe. Producing methane from the gas hydrate reservoirs is technically challenging as they are present in complex geological environments which are highly heterogeneous. In this work, using numerical reservoir simulations of gas production from oceanic gas-hydrate reservoirs underlain with an aquifer we show that warm-water injection is necessary when the water layer below the hydrates is unconfined. Our simulations reveal that the aquifer characterization is essential to design the gas production strategy and estimating the gas recovery. We demonstrate that for a gas-hydrate reservoir attached to a moderately unconfined aquifer, warm-water injection in the hydrate-zone leads to more recovery. If the hydrate-zone is layered then the gas recovery improves by injecting the water into a more porous layer. However, for highly unconfined reservoirs water should be injected near the aquifer for efficient recovery of gas. Our findings will help in developing gas production plans from the hydrate reservoirs around the world

Spontaneous imbibition dynamics in two-dimensional porous media : a generalized interacting multi-capillary model

The capillary bundle model, wherein the flow dynamics of a porous-medium is predicted from that of a bundle of independent cylindrical tubes/capillaries whose radii are distributed according to the medium's pore size distribution, has been used extensively. The model lacks interaction between the flow channels, thus fails at predicting complex flow configuration, including those involving two-phase flow. We propose here to predict spontaneous imbibition in quasi-two-dimensional (quasi-2D) porous-media from a model based on a planar bundle of interacting capillaries. The imbibition flow dynamics, particularly, breakthrough time, global wetting fluid saturation at breakthrough, and capillary carrying the leading meniscus are governed by the distribution of the capillaries' radii and their spatial arrangement. For an 20 interacting capillary system, the breakthrough time can be 39% smaller than that predicted by the classic, non-interacting, capillary-bundle-model of identical capillary radii distribution. We propose a stochastic approach to use this model of interacting capillaries for quantitative predictions. Using the capillary diameter distribution as that of the pore sizes in the target porous medium, and computing the average behavior of a randomly-chosen samples of such interacting-capillary-bundles with different spatial arrangements, we obtain predictions of the position in time of the bulk saturating front, and of that of the visible leading front, that agree well with measurements taken from the literature. This semi-analytical model is quick to run and provides fast predictions on one-dimensional spontaneous imbibition in porous-media whose porosity structure can reasonably be considered two-dimensional, e.g., paper, thin porous-media in general, or layered aquifers

Can fluid-solid contact area quantify wettability during flow? – a parametric study

Wettability characterization in a porous medium is challenging owing to the heterogeneity and large-scale of the interacting surface. Measuring the liquid-solid contact area can be used as a real-time wettability quantification at the Darcy scale. However, flow, grain size, and saturation path can affect the liquid-solid contact area. In this work, we use the two-tracer experiments to quantify the liquid-solid contact area and relate it with different parameters affecting the liquid-solid contact area. We do experiments at different conditions, i.e. (a) when the organic phase is at residual saturation and (b) when both phases flow. When the organic phase is immobile, increasing the flow rate does not change the residual saturation significantly; however, the water-solid contact area increases because of the increased corner flow. When both organic and aqueous phases flow, the relationship between the water saturation and water-solid contact area is found to be dependent on the grain size

Deposition and removal studies of asphaltene from the glass surface

Asphaltene deposition in crude oil reservoirs and transportation lines affects the oil recovery and incurs additional operational costs. The current study discusses the removal of asphaltene from inorganic silica surfaces using hydrodynamic forces. The deposition of asphaltene was carried out on clean glass slides (proxy material for silica) from heptane-asphaltene dispersions via aging. For the removal of asphaltene, a parallel plate channel is fabricated with a pocket to place aged substrates under varying shear rates. The apparatus enables studying the surface morphology changes on a glass slide due to controlled flow conditions through physical contact techniques like atomic force microscopy (AFM). AFM characterizes the extent of both deposition and removal of asphaltene from the surface. The results show that large aggregates of asphaltene are removed from the surface with an increase in flow rates. The extent of removal of asphaltene from the substrate as a function of shear rate is determined. The study also discusses the possible mechanism of asphaltene removal from the surface using the hydrodynamic force calculations. The colloidal interactions calculated from hydrodynamic forces are reported to be Fadh/(d/2) = 1.29 mN/m. The presence of asphaltene tends to alter surface wettability. Interestingly, the contact angle measurements carried out on the asphaltene-deposited glass slides and after removal of asphaltene from the surface showed a negligible change, indicating incomplete removal of asphaltene from the surface

Tracking 3D seismic horizons with a new, hybrid tracking algorithm

We introduce a new algorithm for tracking 3D seismic horizons. The algorithm combines an inversion-based, seismic-dip flattening technique with conventional, similarity-based auto-tracking. The inversion part of the algorithm aims to minimize the error between horizon dips and computed seismic dips. After each cycle in the inversion loop, more seeds are added to the horizon by the similarity-based auto-tracker. In the example data set, the algorithm is first used to quickly track a set of framework horizons, each guided by a small set of user-picked seed positions. Next, the intervals bounded by the framework horizons are infilled to generate a dense set of horizons, a.k.a. HorizonCube. This is done under supervision of a human interpreter in a similar manner. The results show that the algorithm behaves better than unconstrained flattening techniques in intervals with trackable events. Inversion-based algorithms generate continuous horizons with no holes to be filled post-tracking with a gridding algorithm and no loop-skips (jumping to the wrong event) that need to be edited as is standard practice with auto-trackers. As editing is a time-consuming process, creating horizons with inversion-based algorithms tends to be faster than conventional auto-tracking. Horizons created with the proposed algorithm follow seismic events more closely than horizons generated with the inversion-only algorithm and fault crossings are sharper

Effect of well configuration, well placement and reservoir characteristics on the performance of marine gas hydrate reservoir

Reservoir simulations are used to forecast the long-term gas production from gas hydrate reservoirs. In the present work, we explore different well placements and well configurations to analyze the gas production strategy for an oceanic, unconfined, class-2, gas hydrate reservoir using an in-house three-dimensional finite volume simulator. In the past, for depressurization in an unconfined class-2 reservoirs, isolation of the aquifer zone by well placement is suggested. We show that for high pressure conditions in marine gas hydrate reservoirs, depressurization is ineffective even with horizontal producer placed far away from the aquifer. Therefore, Warm water injection is necessary along with depressurization. We demonstrate that, the injector placement and configuration determines the gas production behavior and producer conditions do not significantly impact the production potential. We also find that the unconfined aquifer below the hydrate zone helps in the warm water convection and proximity of the injector to the aquifer improves gas production behavior. However, for unconfined class-2 gas hydrate reservoirs with low initial pressure, depressurization is effective and leads to a very high recovery (80%) of the gas. The reservoir porosity governs the warm water injection which affects the available dissociation energy to the gas hydrates and hence the gas recovery. In a layered reservoir, the porosity of the hydrate layer adjacent to the overburden has significant impact on the gas production due to the available dissociation energy from the overburden

Super-resolution reconstruction of reservoir saturation map with physical constraints using generative adversarial network

Complete physics-based numerical simulations currently provide the most accurate approach for predicting fluid flow behavior in geological reservoirs. However, the amount of computational resources required to perform these simulations increase exponentially with the increase in resolution to the point that they are infeasible. Therefore, a common practice is to upscale the reservoir model to reduce the resolution such that numerous simulations, as required, can be performed within a reasonable time. The problem we are trying to solve here is that the simulation results from these upscaled models, although they provide a zoomed-out and global view of the reservoir dynamics, however, they lack a detailed zoomed-in view of a local region in the reservoir, which is required to take actionable decisions. This work proposes using super-resolution techniques, recently developed using machine learning methods, to obtain fine-scale flow behavior given flow behavior from a low-resolution simulation of an upscaled-reservoir model. We demonstrate our model on a two-phase, deal-oil, and heterogenous oil reservoir, and we reconstruct the oil saturation map of the reservoir. We also demonstrate how the network can be trained using dynamic coarse geological properties at various resolutions. The findings imply that even when coarse geological features and with limited resolution, the super-resolution reconstructions are able to recreate missing information that is close to the ground facts

A novel approach for wettability estimation in geological systems by fluid-solid interfacial area measurement using tracers

Wettability plays a vital role in many applications of flow in porous media and affects Darcy scale flow parameters by influencing the fluid-solid interfacial area. Therefore, quantifying the fluid-solid interfacial area can provide a way to measure wettability at the Darcy scale. Here, we experimentally explore a dual-tracer method, which can also be scaled to large geological reservoirs to quantify the fluid-solid interfacial area during the multiphase flow through a porous medium for different wetting conditions. Using our experiments, we demonstrate the influence of different saturations, wettability and flow conditions on the solid–liquid interfacial area. When oil is in the residual phase, we observe that the solid-water interfacial area increases with the increase in water saturation for the water-wet and mixed-wet cases. However, the water-solid interfacial area decreases with an increase in water saturation for the oil-wet case. We increase the water saturation by increasing the water flow rate; therefore, the anomalous behaviour seen in the oil-wet case can be attributed to the rearrangement of oil and water at higher water flow rates. When both oil and water are flowing, the solid-water interfacial area increases with water saturation for all the wettability cases and increases in water wettability as anticipated. Synopsis: Wettability measurements at Darcy-scale give a broad idea of overall subsurface wetting conditions for application in CO2 sequestration, ground-water remediation or oil recovery

Effect of pH and surfactants on shear induced asphaltene removal

Asphaltene removal from sediments is essential for enhanced oil recovery from heavier crude oil reservoirs and tar sands and bitumen recovery from bottom products in downstream processes. Water injection or water flooding at high pressures exert shear forces that can overcome the adhesive forces between asphaltene and mineral surfaces. The adhesive forces are also affected by ions in the aqueous medium. In the current work we study asphaltene removal from silica surface using shear forces of aqueous media in a parallel plate channel. We demonstrate the effect of varying pH and surfactant conditions in aqueous media on asphaltene removal efficiency. We relate the removal efficiency with fractional asphaltene volume on the surface estimated from atomic force microscopy. The fractional asphaltene volume reduces to 0.12 at pH 10, which is approximately 50% lower than water at neutral pH at the same shear rate. We show that the water-soluble anionic surfactants are inefficient in asphaltene removal, whereas cationic surfactant reduces the asphaltene fraction to 0.30. We conclude that the removal efficiency is affected by the zeta potential of the asphaltene and the surface, where electrostatic repulsion between the asphaltene and the surface and increased wettability in the presence of cationic surfactant improves asphaltene removal