Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.
As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.
It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.
For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.
The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.
CO2 exchange method is one of the extraction techniques that is under development for the production of methane from gas hydrate resources, and the mechanisms and kinetics of the CO2-CH4 exchange process still remain unclear. We model this process with molecular dynamics (MD) simulation to reveal the reaction mechanism, find the optimal operating condition and enhance the conversion rate. The simulations are carried out at three different temperatures to study the impact of temperature on the exchange rate and the kinetics. The production runs are carried out at microsecond level in the NPT ensemble with pressure held at 5 MPa. The simulation results and the associated analysis show that at the investigated conditions, the CO2-CH4 exchange process involves a direct swap of the guest molecules without complete breakage of the water cages. Also, temperature has a significant impact on the kinetics of the process that the increase of temperature from 250K to 270K accelerates the procedure by at least 1.5 times. The reactions mainly occur at the hydrate surface, so that it is critical to enhance the penetration of CO2 into hydrate structures for large scale application of the CO2-CH4 exchange method.
It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models.
We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation.
This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each reservoir.
An XFEM-EDFM scheme and associated monolithic solution method are proposed to model time-dependent poromechanics and two-phase flow. Fractures are modeled as interfaces with displacement discontinuities. The contact forces are treated using Lagrange Multipliers. A number of numerical tests are performed to investigate the Newmark scheme's accuracy and cases for wave propagation in poroelastic and natural fracture media are implemented to evaluate computational efficiency. We apply the method to model seismic data from hydraulic fracture network. Empirical results validate the Newmark scheme accuracy as well as computational efficiency and localization of newton update in seismic field is necessary for the further application. The synthetic model of multiple hydraulic stages illustrates the effect of flow coupling and newly generated fractures on the microseismic field. The model is applied to simultaneously assimilate well performance and microseismic observations, thereby informing about the causal event dynamics.
An extension of the novel fully coupled thermo-hydro-mechanical Open-System Geomechanics (OSG) model is developed for the analysis of coupled flow and oil-shale geomechanics. The model is cast within the framework of Biot's elasticity and classical thermoelasticity. A new term in the equations due to pyrolysis is included in the present model to capture the removal of mass from the reactive solid phase due to the kerogen conversion process modeled through a simplified chemical reaction model. The proposed novel formulation approach and its numerical implementation differs from traditional methods and offers a step improvement in the geomechanical modeling of thermally-reactive porous media, such as, oil shales. The numerical implementation of the OSG model, a first in the literature, is developed within the framework of a proprietary coupled thermal-reactive flow and geomechanics simulator, which was extensively validated in a previous publication. In this paper, we compare the thermal-reactive OSG model against experimental measurements. Numerical results from the validation test shows that the model captures the fundamental physical behavior of oil-shale geomechanics realistically and correctly. Parametric analyses of the OSG model indicate that the chemical conversion term is the critical term that dictates the magnitude of the compaction in the solid equation and a further investigation illustrates the importance of the mobility term in the pore pressure buildup. It is also noticed that the initiation and rate of compaction of the oil-shale sample are governed by the chemical activation energy and reaction-rate constant.
Acidizing in un-fractured carbonate reservoirs has been well studied through modeling and simulation. Since carbonate reservoirs are often naturally fractured, fractures should be modeled for realistic acidizing operations. We present adaptive enriched Galerkin (EG) methods to simulate acidizing in fractured carbonate reservoirs. We adopt a two-scale continuum model for the acid transport. The coupled flow and reactive transport systems are spatially discretized by EG methods. Fractures are introduced using local grid refinement (LGR) technique. Adaptive mesh refinement (AMR) is implemented around wormhole interfaces. Simulation results show that acidizing in fractured carbonate reservoirs is largely dependent on the fracture system while acidizing in unfractured carbonate reservoirs is mainly determined by operation parameters such as acid injection rate. Computationally, the proposed EG scheme has less numerical dispersion and grid orientation effects than standard cell center finite difference/volume methods. AMR is very efficient to track the wormhole growth and speed up acidizing simulations.
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
The innovations of marine LNG terminal concepts are a hot area of research for several years. In order to study the towing and sinking hydrodynamic properties of the large-scale concrete LNG terminals, the basin test and numerical simulation was carried out to simulate the dynamic motion of the concrete LNG terminals towed to the site and sinking on the seabed.
When the caission is placed, the caission generates motion under the action of the waves, and the caission is restrained by the control cable during the movement. Based on the stability and safety considerations of caission sinking construction under the marine environment conditions, it is necessary to know the motion state of the entire sinking process of caission. Therefore, it is necessary to numerically predict the motion response of caission.
The force anlysis of the caission structure in water is a viscous wave-making problem a bluff body in a restricted area. In the viscous medium with infinite domain, the flow around the object can only be solved satisfactorily when the Reynolds number is small. The caisson involves not only the blunt body but also the large Reynolds number of the medium and the influence of restricted boundary and free surface. Therefore, it is generally believed that the most reliable method is experimental research. As the caisson section is square and blunt, the flow separation point is stable, which creates conditions for self-similarity in experimental study. Therefore, in theory, the experimental study can obtain quite satisfactory results. The main purpose of the towing tests is to investigate the dynamic behavior and characteristics of the caisson and the line tensions during towing out from the dry dock to the sea area in waves and currents.
Related work on towing of Large-scale structure. Kyozuka, Y.
The commom occurrence of massive methane hydrate in numerous gas chimney structures, located in Joetsu basin, Sea of Japan, stimulates great interest from by academia, industry and national institutes in developing technologies to produce the potential energy resource. Unlike other deep methane hydrate deposited in formations a few hundred meters below seafloor, the hydrate chimney structures are located at the seafloor or up to 100 m below the seafloor; therefore, previously field-tested production methods such as depressurization are not applicable. The newer production method of jetting from the openhole section of a wellbore to excavate the hydrate bearing formation was proposed as a possible production method. However, jetting will create large empty chambers below the seafloor and could possibly jeopardize the stability and safety of well-heads and the production facility on the seafloor.
This paper presents a 3D geomechanical simulation study to evaluate the feasibility of the jetting method to produce methane from the hydrate chimneys in the Sea of Japan. In this study, to honor lateral and vertical variation of hydrate saturation as well as mechanical properties, different 3D geomechanical models were constructed to represent three shallow methane hydrate inhabitation types (chunk, laminated, and dispersed) by using data from various sources. Dynamic numerical simulation by using a 3D finite element simulator was conducted to simulate the jetting process to excavate 16-m diameter chamber from bottom of the borehole (about 100 m below seafloor) progressively up to the bottom of the conductor of the wellbore, about 10-m below the seafloor.
The numerical simulation shows that jetting is likely to be feasible as all simulation cases resulted in tolerable vertical displacement and equivalent plastic strain under ideal conditions, e.g., lateral homogeneous formation, constant chamber pressure (equal to formation pore pressure) and blowout preventer (BOP) weight of 20 t. In these cases, the plastic zone only extends to limited area from the sidewall. Additional complexities were considered in the numerical simulation to evaluate the operational risks during actual jetting operations, such as faulting, fluctuation of chamber pressure, and change of BOP weights.
This numerical simulation evaluated potential risks related to jetting operations of hydrate chimneys in the Sea of Japan and provided critical information for the engineering design of the proposed field test of jetting operations to produce this valuable resource in the Sea of Japan.
Wan, Liming (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Mian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhang, Fengshou (Department of Geotechnical Engineering, Tongji University) | Wang, Li (China United Coalbed Methane Co., Ltd.) | Chen, Wangang (China United Coalbed Methane Co., Ltd.)
With the development of unconventional oil and gas resources, the technology of commingling production in coal measure has been studied, which requires us to have a better understanding of the fracture near the wellbore in multi-layers. Previous studies mainly focused on the fracture morphology in a single layer and lack of 3D evolution role of microfracture propagation, so the fracture geometry in multi-layers of the coal seam and microfracture initiation near wellbore were studied in this paper.
In this study, the 3D-lattice model was used to simulate the 3D dynamic hydraulic fracture morphology near the wellbore in multi-layered coal based on XSite simulator, and the spiral perforation position was mainly studied. To verify the numerical simulation, the true tri-axial test system was implied for fracturing simulation experiments on the combination of coal, sandstone and limestone outcrops. The perforation position was changed to analyze the fracture morphology near the wellbore. Besides, the 3D scanning technology and the fracturing curve were used to study the fracture characters. As a result, the fracture morphologies near the wellbore in different perforation positions were studied.
The numerical simulation results showed that the microfracture evolution process in spiral perforation can be divided into three stages, (a) Stage 1: the vertical microfracture bands develop along the perforation hole; (b) stage 2: micro-annulus fracture forms around the wellbore; (c) stage 3: fractures break through along the perforation holes perpendicular to the minimum in-situ stress. The cleats and the natural fractures dominated the fracture initiation geometry when perforating in coal. The secondary branch fractures and the stepped fractures were the main characters in coal. Sandstone was a good barrier layer for the coal seam in fracturing, and the fracture in coal was easy to break through the limestone layer. When fracture initiated in coal layer, the fracture near the wellbore was complex with many secondary fractures, and the fracture surface was rough with poor continuity; when initiated in both sandstone and coal layers simultaneously, the main fracture developed quickly in coal and the smooth fracture surface formed near the wellbore.
The results of laboratory experiments were in good agreement with numerical simulation. The 3D evolution role of microfracture near wellbore could give a deep understanding of fracture complexity in near-wellbore area in coal. The experiments considered the actual formation combination, and the results of multi-layer fracturing could give a good guidance for field perforation optimization in the commingling of coal measure strata.