Browsing by Subject "Tight oil"
Now showing 1 - 3 of 3
Results Per Page
Sort Options
Item Developments in modeling and optimization of production in unconventional oil and gas reservoirs(2015-05) Yu, Wei; Sepehrnoori, Kamy, 1951-; Chin, Lee; Delshad , Mojdeh; Mohanty, Kishore K; Patzek, Tadeusz WThe development of unconventional resources such as shale gas and tight oil exploded in recent years due to two key enabling technologies of horizontal drilling and multi-stage fracturing. In reality, complex hydraulic fracture geometry is often generated. However, an efficient model to simulate shale gas or tight oil production from complex non-planar fractures with varying fracture width along fracture length is still lacking in the petroleum industry. In addition, the pore size distributions for shale gas reservoirs and conventional gas reservoirs are quite different. The diffusivity equation of conventional gas reservoirs is not adequate to describe gas flow in shale reservoirs. Hence, a new diffusivity equation including the important transport mechanisms such as gas slippage, gas diffusion, and gas desorption is required to model gas flow in shale reservoirs. Furthermore, there are high cost and large uncertainty in the development of shale gas and tight oil reservoirs because of many uncertain reservoir properties and fracture parameters. Therefore, an efficient and practical approach to perform sensitivity studies, history matching, and economic optimization for the development of shale gas and tight oil reservoirs is clearly desirable. For tight oil reservoirs, the primary oil recovery factor is very low and substantial volumes of oil still remain in place. Hence, it is important to investigate the potential of CO₂ injection for enhanced oil recovery, which is a new subject and not well understood in tight oil reservoirs. In this research, an efficient semi-analytical model was developed by dividing fractures into several segments to approximately represent the complex non-planar fractures. It combines an analytical solution for the diffusivity equation about fluid flow in shale and a numerical solution for fluid flow in fractures. For shale gas reservoirs, the diffusivity equation of conventional gas reservoirs was modified to consider the important flow mechanisms such as gas slippage, gas diffusion, and gas desorption. The key effects of non-Darcy flow and stress-dependent fracture conductivity were included in the model. We verified this model against a numerical reservoir simulator for both rectangular fractures and planar fracture with varying width. The well performance and transient flow regime analysis between single rectangular fracture, single planar fracture with varying width, and single curving non-planar fracture were compared and investigated. A well from Marcellus shale was analyzed by combining non-planar fractures, which were generated from a three-dimensional fracture propagation model developed by Wu and Olson (2014a), and the semi-analytical model. Contributions to gas recovery from each gas flow mechanism were analyzed. The key finding is that modeling gas flow from non-planar fractures as well as modeling the important flow mechanisms in shale gas reservoirs is significant. This work, for the first time, combines the complex non-planar fracture geometry with varying width and all the important gas flow mechanisms to efficiently analyze field production data from Marcellus shale. We analyzed several core measurements for methane adsorption from some area in Marcellus shale and found that the gas desorption behaviors of this case study deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, such behavior has not been presented in the literature for shale gas reservoirs to behave like multilayer adsorption. The effect of different gas desorption models on calculation of original gas in place and gas recovery prediction was compared and analyzed. We developed an integrated reservoir simulation framework to perform sensitivity analysis, history matching, and economic optimization for shale gas and tight oil reservoirs by integrating several numerical reservoir simulators, the semi-analytical model, an economic model, two statistical methods, namely, Design of Experiment and Response Surface Methodology. Furthermore, an integrated simulation platform for unconventional reservoirs (ISPUR) was developed to generate multiple input files and choose a simulator to run the files more easily and more efficiently. The fracture cost was analyzed based on four different fracture designs in Marcellus shale. The applications of this framework to optimize fracture treatment design in Marcellus shale and optimize multiple well placement in Bakken tight oil reservoir were performed. This framework is effective and efficient for hydraulic fracture treatment design and production scheme optimization for single well and multiple wells in shale gas and tight oil reservoirs. We built a numerical reservoir model to simulate CO₂ injection using a huff-n-puff process with typical reservoir and fluid properties from the Bakken formation by considering the effect of CO₂ molecular diffusion. The simulation results show that the CO₂ molecular diffusion is an important physical mechanism for improving oil recovery in tight oil reservoirs. In addition, the tight oil reservoirs with lower permeability, longer fracture half-length, and more heterogeneity are more favorable for the CO₂ huff-n-puff process. This work can provide a better understanding of the key parameters affecting the effectiveness of CO₂ huff-n-puff in the tight oil reservoirs.Item Performance evaluation of CO2 EOR in tight oil formation with complex fracture geometries(2016-05) Zuloaga Molero, Pável; Sepehrnoori, Kamy, 1951-; Yu, WeiThe recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the oil recovery factor expected is still very low even after the wells have been fractured and therefore, tight formations are considered good candidates for enhanced oil recovery (EOR). One of the most suitable solutions to improve the oil recovery is the carbon dioxide (CO2)-based EOR. Although the injection of CO2 is not new for conventional oil reservoirs, its practice in tight oil formations is still a relatively novel idea. Two injection-production strategies are often employed: continuous CO2 injection or flooding and CO2 Huff-n-Puff. However, it is not clear which scenario is the best strategy to achieve an optimal recovery, which highly depends on many uncertain reservoir and fracture parameters and it is not clearly understood until recently. Another challenge of the estimation of the incremental recovery of these injection approaches is to properly model the hydraulic fractures and CO2 transport mechanism. The actual hydraulic fracturing process often creates complex fracture networks, especially when the fracture propagates in a formation with a large amount of pre-existing natural fractures. In this study, the CO2-EOR effectiveness is simulated and analyzed by comparing the Huff-n-Puff and the continuous injection scenarios. The effect of matrix permeability on the comparison of well performance of these two scenarios was investigated. Subsequently, Design of Experiment and Response Surface Methodology is used to perform sensitivity studies with four uncertain parameters including matrix permeability, number of wells, well pattern, and fracture half-length to determine the best injection approach. In addition, an efficient methodology of embedded discrete fracture model (EDFM) is introduced to explicitly model complex fracture geometries. The effects of complex fracture geometries on well performance of CO2 Huff-n-Puff and CO2 continuous injection were also investigated as well as the effect of natural fractures. The analysis of the CO2-EOR effectiveness confirms that the appropriate modelling of the complex fractures geometry plays a critical role in estimation of the incremental oil recovery. This study provides new insights into a better understanding of the impacts of reservoir permeability, complex hydraulic fractures and natural fractures on well performance during CO2-EOR process in tight oil reservoirs and in the determination and design of the optimal injection-production scheme to maximize the oil recovery factor for multi-fractured horizontal wells.Item Using simple models to describe oil production from unconventional reservoirs(2014-05) Song, Dong Hee; Lake, Larry W.Shale oil (tight oil) is oil trapped in low permeability shale or sandstone. Shale oil is a resource with great potential as it is heavily supplementing oil production in the United States (U.S. Energy Information Administration, 2013). The shale rock must be stimulated using hydraulic fracturing before the production of shale oil. When the hydrocarbons are produced from fractured systems, the resulting flow is influenced by the fracture, the stimulated rock, and the matrix rock. The production decline rates from shale oil reservoirs experience flow regimes starting with fracture linear flow (fracture dominated), then bilinear flow (fracture and stimulated rock dominated), then formation linear flow (stimulated rock dominated), and finally pseudo-radial flow (unstimulated matrix rock dominated) (Cinco-Ley 1982). In this thesis, daily production rates from a shale oil reservoir are modeled using a simple spreadsheet-based, finite difference serial flow simulator that models the single-phase flow of a slightly-compressible oil. This simulator is equivalent to flow through multiple tanks (subsequent part of the thesis will call these cells) through which flow passes serially through one tank into the other. The simulator consists of 11 tanks. The user must specify the compressibility-pore volume product of each tank and the transmissibility that governs flow from one tank to another. The calculated rate was fitted to the given data using the Solver function in Excel. The fitted matches were excellent. Although we can adjust all 22 parameters (2 per cell) to affect the simulation results, we found that adjusting only the first three cells nearest to the well was sufficient. In many cases, only two cells were enough. Adjusting 4 or more cells resulted in non-unique matches. Furthermore, the properties of the very first cells proved insensitive to the matches when using the 3 cells to match the data. The cells in the 2 cell model represent the stimulated zone and the unstimulated rock. Likewise, the cells in the 3 cell model represent the hydraulic fracture, the stimulated zone, and the unstimulated rock. The accessed pore volume and transmissibility were responsive to the injected sand mass and fluid volume up to approximately 10⁶ kg and 7000 m³ respectively; injecting more sand and fluids than this caused negligible increases in the accessed pore volume and transmissibility. This observation suggests that the sand does not migrate far into the fractures. Similarly, it was observed that the number of stages was positively correlated with cell transmissibility and pore volume up to 20 stages. These results suggest that fracture treatments were significantly over designed and injecting less sand and water in fewer stages would optimize the economics of similar projects. To our knowledge this is the first work to analyze the results of fracture treatments by matching with pore volumes and transmissibility in a simple serial cell flow.