Journal of Unconventional Oil and Gas Resources最新文献

Tight carbonate reservoirs exhibiting thick transition zones usually contain a large quantity of oil. Therefore, significant reserves might be left after secondary recovery by waterflooding not only due to the being in transition zones but also more due to the rock quality, tightness, pore throat and geometry, mineralogy, and wettability etc. Proper characterization and modeling of oil reservoirs are the key factors to predict their production performances, improve oil recovery and optimize the reservoir management. The development of saturation functions for transition zones, especially, of carbonate reservoirs is vital and challenging to address the multiphase flow and initial water saturation distribution in both static and dynamic modes.

In this paper, a complete overview of the available experimental, modeling and simulation research works on transition zones in carbonate reservoirs is presented systematically. It is necessary to obtain a review of the past and present works so that the future researchers will get a clear idea of the approach on characterization and modeling of transition zones in carbonate reservoirs. Initial water saturation, hysteresis behaviors of relative permeability and capillary pressure, wettability alteration modeling and reserve estimation has been discussed in this paper. Petrographic and diagenesis study has also been discussed with the help of a few laboratory works from our research group. It is expected that this review will open new doors to the forthcoming researchers in this field. New thoughts and future works on transition zone characterization and modeling are also provided in this review as future developments and challenges.

In this study, a Computational Fluid Dynamics (CFD) solver able to simulate shale gas flow as fluid flow in a porous medium on the macro level is presented. The shale gas flow is described by means of a tailored governing equation with both fluid properties and permeability expressed as a function of the effective pore pressure (stress effect) and with Knudsen effects included through an apparent permeability. This CFD solver, developed in the OpenFoam framework, allows for the simulation of three-dimensional fractured geometries without limitations on the shape of the domain. The solver was assessed and validated against literature data showing good agreement in terms of both recovery rate and pressure field profiles. The solver was then used to explore two different phenomena affecting shale gas dynamics: the diffusion behaviour and the influence of fracture geometry. It was shown that shale gas flow, on the macro level, is a diffusion-dominated phenomenon, and its behaviour can also be qualitatively represented by a diffusion equation. It was also shown that the early behaviour of shale gas flow is dictated by the fracture geometry, and that the reservoir dimensions have no effect on the flow at early times. Finally, a newly developed “dual-zone” solver, where the shale matrix and the fracture network are modelled as two distinct domains interacting through the common boundaries, is presented and discussed.

In recent years, petroleum assessment incorporates the petroleum system concept method instead of the play concept method to estimate petroleum resources, because conventional-unconventional petroleum resources are more reliably estimated by the genetic similarities of petroleum fluids in the petroleum system. Conventional-unconventional oil resources co-exist in the Lucaogou-Permian petroleum system in the Jimusar sag of the Junggar basin, Northwest China. The mean in-place resources (IPR) of tight oil of the Lucaogou Formation (LF) were estimated at 2.0 billion tons by an integration method in the Jimusar sag. Based on the assessment of the technically recoverable coefficient by drill productivity, it is estimated that the mean technically recoverable resources (TTR) of tight oil are about 0.11 billion tons. The mean IPR and TTR of conventional oil of the Wutonggou Formation (WF) were evaluated at 0.36 billion tons and 0.06 billion tons by analogy methods, respectively. The ratio of mean IPR of unconventional oil to conventional oil in the Jimusar is about 5:1, but the ratio of mean TTR is only about 2:1. In addition, tight oil development is higher cost than conventional oil so far. Therefore, the development of tight oil in the Jimusar sag should be a careful consideration. Anyway, the integrated resource assessment of unconventional and conventional oil in the Jimusar sag could provide as a classic example for other lacustrine petroleum systems.

In this research, a numerical feasibility study of the thermal oil recovery using steam injection has been carried out for a heterogeneous heavy oil field located in southern Oman. There are several technical challenges for designing EOR operation system for oil reservoir with heterogeneous permeability. A numerical simulation of the steam injection has been developed to investigate the optimum heat transfer in the reservoir to reduce the oil viscosity with more efficiency. The CMG STARSTM model was used for the simulation of steam injection operation with the valve control of steam trap subcool in this field. The simulation results showed that the valve control can result in wider and faster temperature transmission and distribution in the reservoir after steam injection. It was also shown that steam trap operation can result in relatively higher oil production and lower required steam temperature. Finally, it was suggested that by setting subcool temperature on 20–30 °C using the valve control, steam injection efficiency can be increased and better SOR (steam oil ratio) and RF (recovery factor) can be achieved.

Condensate blockage is a serious problem in shale gas condensate reservoirs. As the pressure decreases lower than dew point pressure, condensate forms. This condensate reduces the relative permeability of gas and the productivity of shale gas condensate reservoirs.

Huff-n-puff gas injection is an EOR method in which a well alternates between injection, soaking, and production. Based on the laboratory study conducted by Meng et al. (2015), huff-n-puff gas injection was proven as an effective method to enhance condensate recovery for Eagle Ford shale cores. In this paper, a numerical reservoir simulation study is conducted to optimize the application of huff-n-puff gas injection in an Eagle Ford shale gas condensate reservoir. During the injection and soaking process, the pressure of the reservoirs built up, the condensate was revaporized to gas, and then was produced during the production process. Different parameters were investigated including injection time, soaking time, production time, and cycle numbers.

The results show that huff-n-puff gas injection is an effective method to enhance condensate recovery in the Eagle Ford shale gas condensate reservoir. It was found that the optimum injection time is the time during which the pressure of the main condensate region can be increased higher than dew point pressure. Also, shorter or even no soaking is more effective. The production time depends on the production decline rate. It is more profitable to start another cycle of huff-n-puff gas injection when the production rate is decreased to a low value.

Temperature changes in and around the wellbore could lead to significant well performance and flow assurance issues. Despite its importance, near wellbore temperature change due to gas production and its importance on well performance is not well understood. Reduction of temperature in the near well bore section, could potentially lead to hydrate formation and as a result reduction of well performance.

This work is aimed at evaluating the thermal behaviour in the near wellbore region of a low to tight permeability gas reservoir (ranging between 0.02 and 10 mD) during its natural depletion. The study is conducted by using a thermal-compositional simulator. The process required to simulate such thermal behaviour in a numerical simulator is outlined in this paper. This study is focused on analysing the impacts of different parameters such as reservoir and fluid properties, well trajectories and draw down magnitudes have been studied. Such parameters have an impact on JTE or conductive/convective heat transfer and therefore will affect the reservoir temperature. In addition the near wellbore temperature responses to varying production and well configurations are reviewed to identify the contributing parameter and their impact on reservoir temperature.

The results of a grid sensitivity analysis showed that the choice of grid size will have a significant impact on calculated temperatures. In addition, the results reveal that significant temperature reduction could occur around the wellbore due to Joule-Thomson expansion and heat transfer in form of conduction and convention. It is also shown that size of the affected area depends on the magnitude of cooling due to Joule-Thomson expansion as well as reservoir properties such as skin and permeability. This study showed that the most influential parameter is the wellbore inflow rate due to draw down. In addition, parameters such as pressure profile along the well trajectory, inflow area along the well and reservoir quality along the wellbore will play a vital role in cooling process as well as radius of the impacted zone. The results also showed that absolute initial reservoir temperature have no significant impact on the magnitude of temperature change.

Fluid flow through the reservoir is defined on the basis of the relative permeability which essentially captures the preferential flow of any specific fluid. Utilization of steam assisted gravity drainage (SAGD) presents challenges to the conventional understanding of relative permeability due to the introduction of heat to the reservoir. The presence of three distinct fluid phases (steam, water, and oil) in conjunction with a temperature dependency has many implications for the modelling of complex fluid dynamics. However, effective characterization of relative permeability curves is integral to successful simulation and so a model capable of representing three-phase flow is required. By implementing a simplified fractional flow analysis, this study is able to regress three-phase flow in the laboratory to a pseudo two-phase relative permeability. Modifications of conventional fractional flow theory allow for the extension of the analysis to the SAGD and solvent aided-SAGD (S-SAGD) process. Overall displacement is defined on the basis of both a microscopic component represented by modified capillary number and a macroscopic component represented by mobility ratio. Negation of the liquid-gas interaction through the assumption of waterflooding enables the generation of pseudo two-phase relative permeability curves that result in comparable performance to lab scale experiments. Because the experimentally obtained SAGD and S-SAGD results are used to construct the pseudo-relative permeability curves, our model includes the many complex fundamental changes occur in viscosity and relative permeability during SAGD and S-SAGD in the newly constructed relative permeability curves. Thus, our results offer a simplistic way to ease the compositional simulation of SAGD and S-SAGD through waterflooding approach.

The gradual depletion of the conventional energy reserves and ever growing energy demand has been the matter of global concern over the last few decades. Shrinking coal and petroleum resources have posed researchers to look for exploration and exploitation of unconventional gas resources. In this scenario, natural gas is not only a promising alternative solution towards mitigation of energy crisis but also a potential candidate to reduce the environmental impact through restraining the greenhouse gas effect. In this context, methane extraction from coalbeds has gained its commercial viability in different parts of the world viz. USA, China, Australia, India etc.

The review highlights global scenario of coalbed methane (CBM), transport of methane through coalbed, the sorption behavior of methane within the unconventional gas reservoirs, thermodynamic activities of gas adsorption into reservoir bed in terms of thermodynamics parameters viz. Gibbs free energy, temperature, enthalpy and entropy and the kinetic study of the contrivance of methane discharge for indicating the type of gas adsorbed onto the surface of coal matrix and time lapsed for saturation of coalbed. Maturity, geology and geochemical characteristics of coal have been reviewed for differential methane sorption in coal reservoirs. Diffusion and sorption isotherm model which fits the experimental data related to gas retention and release mechanism has also been discussed. Finally, different physicochemical characteristics of coal responsible for the methane gas storage and recovery have been discussed.

Production of unconventional oil and gas resources has played a significant role on the global energy supply, of which tight oil and gas reservoirs are drawing greater focus. The key enabler behind tight oil and gas production has been multi-stage hydraulic fracturing along extended reach horizontal wells. Despite many advances in multistage fracturing, it still remains unclear how to model the hydraulic fracturing process to provide the basis to optimize and predict the properties of fracture networks and associated enhancement of fluid production. In typical reservoir simulation practice, the conventional way to represent the hydraulic fracture is to place high permeability planes around the horizontal well – this means that the user has prescribed the orientation and length scale of the fracture before the simulation has started. In the research documented here, we explore a dynamic fracturing approach that uses a dilation-recompaction model in a reservoir simulator to model hydraulic fracturing. The key strength of the approach is that the geometry and length scale of the fracture is not prescribed a priori. The results of the simulation show that dilation-recompaction model is capable of modeling the hydraulic fracturing process prior to the flow-back and production. The oil, gas, and water rates of the model are well matched to the field data and the extent of the fractured zone predicted by the model is reasonable.