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Tang, Yongqiang (Exploration & Production Research Institute) | Cui, Maolei (Exploration & Production Research Institute) | Xiao, Pufu (Exploration & Production Research Institute) | Lun, Zengmin (Exploration & Production Research Institute) | Wang, Rui (Exploration & Production Research Institute) | Zhao, Shuxia (Exploration & Production Research Institute)
Yongjin oilfield in Junggar Basin is a tight oil formation with extremely high pressure (higher than 100 MPa). This oilfield was not investigated optimistically in the past because of the super-low reservoir permeability and the considerable content of asphaltene and wax in the crude oil. However, the negative stereotype of such reservoir conditions with low-production was broken by a horizontal well drilled in Oct. 2018, which had unexpected high-production constantly for more than half a year. The well-developed tectonic bedding fractures are believed as the key to the high production in this horizontal well. In this paper, we comprehensively investigated the rule and mechanism of bedding fractures in the high oil recovery of the tight reservoir by multiple theoretical and experimental methods.
The tight rock samples with/without bedding fractures, which are used in the experiments, were drilled out from Yongjin oilfield. Based on nuclear magnetic resonance, the bedding fractures under different confining pressures (up to 30MPa) are characterized by the transverse relaxation time (T2) spectrum and magnetic resonance imaging. Besides, we designed a novel non-Darcy flow setup with the ultra-high-pressure holder and high-accuracy flow meter. With this setup, we observed the fluid-flow phenomena in the bedding fracture-matrix system under pressure of 100MPa and temperature of 135°C. We then introduced two low-velocity non-Darcy models for fitting the flow data in the fracture-matrix and matrix-only samples to reveal the flow mechanism in such reservoir conditions. By comparing the permeability, we distinguished the role of the bedding fractures in improving oil production.
The magnetic resonance images illustrate that the bedding fractures run straightly through the rock. Meanwhile, the T2 spectrum indicates that the size of fracture decreased with the confining pressures. Besides, the results of non-Darcy flow experiments demonstrate that a non-Darcy flow curve has linear and nonlinear flow part. The nonlinear flow starts from the zero-pressure gradient. Under the given overlay pressure, the permeability of fracture-matrix decreases with the drop of pore pressure gradually, and the permeability free-falls demotion after reaching a closure pressure. The nonlinear flow region is widen in the closed status. During elevating the pore pressure, we tested the cracking pressure of the samples, which is 3-10MPa larger than the closure pressure. The results show that when the fracture is open, the permeability of fracture-matrix sample is very sensitive to pressure, and hundreds/thousands of times larger than the matrix-only ones. The permeability of closed fracture-matrix sample is still dozens of times larger. Although the permeability of the matrix-only sample changes with pore pressure, the permeability is reversely insensitive to the change of pressure.
Both the non-Darcy flow characters in fracture-matrix and matrix-only systems provide the instructive function for the oilfield development management. Besides, maintaining the optimized flow pressure down hole to prevent the bedding fracture from closuring is a crucial advantage in Yongjin reservoir development.
Liang, Xingyuan (China University of Petroleum at Beijing) | Zhou, Fujian (China University of Petroleum at Beijing) | Liang, Tianbo (China University of Petroleum at Beijing) | Wang, Rui (China University of Petroleum at Beijing) | Su, Hang (China University of Petroleum at Beijing) | Wang, Xinglin (Rice University)
Liquid nanofluid (LNF) is being gradually used in unconventional reservoirs. However, the application of LNF during hydraulic fracturing in tight reservoirs needs to be further investigated. In this study, a series of experiments were conducted to discuss the above problem. First, a new method to evaluate wettability in different pore-scale was provided. Then core flooding experiments were conducted to study invasion pressure for the LNF. Finally, the efficiency of drag reduction after adding the LNF was evaluated. The result showed that imbibition and nuclear magnetic resonance (NMR) can be combined to evaluate the average wettability for the unconventional rock. Core flooding experiments stated that the LNF could reduce the invasion pressure, which would enhance the effective volume. Drag reduction experiments demonstrate that LNF makes drag reduction more efficient. Field application proved the LNF could help enhance the production in tight oil reservoirs. Several advantages of using LNF in the process of hydraulic fracturing were also revealed.
The tight oil reservoir has been one crucial part of petroleum resources (Hu et al., 2019; Li and Misra, 2018; Liang et al., 2020a). The hydraulic fracturing and horizontal well have been two main technologies to explore the tight and other unconventional reservoirs(Liang et al., 2020b; Wang et al., 2019, 2015, 2020b). However, the production decreases rapidly on account of low permeability and complex pore structure(Liang et al., 2017; Wang et al., 2020a). Imbibition has been one of the important methods to enhance oil recovery in unconventional reservoirs(Liang et al., 2020c; Liu et al., 2019; Meng et al., 2016). Imbibition help replaces the oil into fractures and helps increase production. Wettability is one of the most important factors, which influence the imbibition oil recovery. As we all know, the aqueous phase can be spontaneously imbibed into the rock with water-wet; while the rock with oil-wet cannot imbibe aqueous fracturing fluid spontaneously. The rock has been turned into oil/mix wet after contacting with crude oil for hundreds of years, especially for carbonate minerals. Wettability testing is much important so that people can understand the potential imbibition ability for the reservoir. Besides, people could evaluate the wettability alteration after using chemical additive, like surfactant or micro emulsion.
Sheng, Guanglong (School of Petroleum Engineering, Yangtze University) | Wang, Wendong (School of Petroleum Engineering, China University of Petroleum) | Zhao, Hui (School of Petroleum Engineering, Yangtze University) | Lun, Zengmin (Exploration and Development Academy of Petrochemical corporation of China) | Xu, Yufeng (School of Petroleum Engineering, Yangtze University) | Zhang, Qian (School of Petroleum Engineering, China University of Petroleum) | Yu, Wenfeng (School of Petroleum Engineering, China University of Petroleum) | Chai, Di (University of Kansas) | Li, Xiaoli (University of Kansas) | Lou, Yi (Guizhou Panjiang CBM development and utilization Co., Ltd)
A large amount of fracturing fluid in fracking is imbibed into the shale fracture/matrix system, which leads to a significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water two-phase flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi Formation in China and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine shale samples are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out on three dry and saturated fractured samples using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visualization container. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, we introduce the capillary force in the cross flow term of the triple-medium model to characterize the imbibition effect, develop a two-phase flow simulation model of shale gas considering the fracturing fluid imbibition retention, and analyze the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir. The impacts of the fracturing fluid imbibition and complexity of the fracture system on the two-phase flow are still unclear. We propose systematic experiments to overcome this difficulty, which could provide valuable indicative information on the two-phase flow. Valuable experiment data are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.
The steady domestic economic growth has led to an increase in demand for oil and gas. The conventional oil and gas resources cannot meet the high energy demand (Wang et al. 2020). The Chinese shale gas resources are widely distributed and have abundant reserves. The accumulated geological reserves of shale gas in the marine strata in the Sichuan Basin and its periphery are 764.3 × 109 m3(Zhang and Liu 2019). The shale reservoirs exhibit ultralow porosity and permeability (Du and Nojabaei 2019, Chai et al. 2019). In addition, the matrix permeability is generally of nD grade and the pore size is considerably smaller than those of sandstone (Javadpour et al. 2007). Various types of shale pores with multiple scales exist, including intragranular pores, microfractures, and fractures (Zou et al. 2013). The organic-rich shale has various hydrocarbon occurrences, mainly adsorbed gas and free gas, with a small amount of dissolved gas (Sheng et al. 2020). The above characteristics hinder the economic production from shale gas reservoirs (Yuan et al. 2015). The development of hydraulic fracturing technology in recent years has led to the developing value of shale gas considering the current oil price level (Zhou et al. 2015, Sheng et al. 2019).
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs' STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs’ STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
We investigate the effect of heterogeneous petrophysical properties on Low Salinity Water Flooding (LSWF). We considered reservoir scale models, where the geological properties were obtained from a giant Middle East carbonate reservoir. The results are compared against a typical sandstone model.
We simulated low salinity induced wettability changes in field scale models in which the petrophysical properties were randomly distributed with spatial correlation. We examined a wide range of geological realisations which mimic complex geological structures. Sandstone was simulated using a log-linear porosity-permeability relation with fairly good correlation. A carbonate reservoir from the Middle East was simulated where a much less correlated porosity permeability relationship was obtained. The salinity of formation water was set to typically observed values for the sandstone and carbonate cases. A number of simulations were then carried out to assess the flow behaviour.
We have found that the general trend of permeability-porosity correlation has a key role that could mitigate or aggravate the impact of spatial distributions of petrophysical properties. We considered models with a log-linear permeability-porosity correlation, as generally observed for sandstone reservoirs. These are likely to be directly affected by the spatial distribution more than models with a power permeability-porosity correlation, which is often reported for flow units of carbonate reservoirs. The scatter of data in the permeability-porosity correlations had a relatively small impact on the flow performance. On the other hand, the effect of heterogeneity decreases with the width of the effective salinity range. Thus, uncertainty in carbonate reservoirs arises due to the ambiguity of spatial distribution of permeability and porosity would be less affects the LSWF predictability than in sandstone case. Overall, the incremental oil recovery due to LSWF was higher in the carbonate models than the sandstone cases. We observe from uncertainty analysis that the formation waterfront was less fingered than the low salinity waterfront and the salinity concentration. The dispersivity of salinity front and the water cut can be estimated for models with various degrees of heterogeneity.
The outcome of the study is a better understanding of the implications of heterogeneity on LSWF. In some cases the behaviour can appear like a waterflood in very heterogeneous cases. It is important to assess the reservoir effectively to determine the best business decision.
Zeng, Jie (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Li, Wai (The University of Western Australia) | Tian, Jianwei (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Guo, Jianchun (Southwest Petroleum University)
The permeability of fractured sorbing media, such as shale and coal, is mainly controlled by effective stresses and sorption-induced strains. Although the influence of effective stresses on permeability has been extensively studied, how sorption-induced strains affect permeability evolution has not been fully understood. Sorption-induced strains can impact the permeability in opposite ways at different time scales. If the swelling occurs at matrix surfaces (local swelling), the swelling strain purely reduces fracture aperture and results in a permeability decline. However, when the whole rock is fully invaded by injected gas, the swelling of the whole rock (global swelling) increases fracture aperture and the bulk volume, enhancing the permeability. Most existing models only use fracture (pore) pressure to describe rock swelling, assuming that the rock is fully invaded and matrix-fracture pressure equilibrium is achieved. They cannot explain some experimental data because rocks may never be fully invaded during permeability measurement. Moreover, different pore types are not considered and local swelling can be heterogeneous due to complex matrix components.
In this paper, the non-equilibrium effects are depicted by defining two continua (matrices and fractures) with distinct pressure values. The transition between local swelling and global swelling is quantified by the pressure difference between the two systems. The larger the pressure difference is, the heavier local swelling effects will be. And global swelling is only a function of fracture pressure. Different pore types are included in our permeability model. And the heterogeneous local swelling strain is characterized by a splitting strain function.
This model is verified against laboratory data from common permeability measurement conditions. Under constant effective stress and constant confining stress conditions, the permeability changes at different times and becomes stable after a relatively long time. With the matrix-fracture pressure difference first increases to a maximum value and then decreases to zero, local swelling effects change from zero to a peak value and finally drop to zero. By combining permeability curves at different injection pressure levels, 3-D permeability surfaces are obtained. The impacts of rock properties, heterogeneous local swelling, and multiple pore types on permeability evolution are analyzed. Adsorption and mechanical properties control specific regions of permeability curves. Effects of heterogeneous local swelling are determined by the adsorption capacity of the dominant matrix component. The existence of multiple pore types makes the permeability curve deviate from those of single-pore-type cases and affects a wider range of permeability curves compared with heterogeneous local swelling.
Relative permeability and capillary pressure are the key parameters of the multiphase flow in a reservoir. To ensure an accurate determination of these functions in the areas of interest, the core flooding and centrifuge experiments on the relevant core samples need to be interpreted meticulously. In this work, relative permeability and capillary pressure functions are determined synchronously by history matching of multiple experiments simultaneously in order to increase the precision of results based on additional constraints coming from extra measurements. To take into account the underlying physics without making crude assumptions, the Special Core Analysis (SCAL) experiments are chosen to be simulated instead of using well know simplified analytical or semianalytical solutions. Corresponding numerical models are implemented with MRST (Lie, 2019) library. The history matching approach is based on the adjoint gradient method for the constrained optimization problem. Relative permeability and capillary pressure curves, which are the objectives of history matching, within current implementation can have a variety of representations as Corey, LET, B-Splines and NURBS. For the purpose of analyzing the influence of correlations on the history matching results in this study, the interpretation process with assumed analytical correlations is compared to history matching based on generic NURBS representation of relevant functions.
Li, Longlong (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Khait, Mark (TU Delft) | Voskov, Denis (TU Delft) | Abushaikha, Ahmad (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
The continuous progress of reservoir monitoring technology provides encouraging capacities to reduce uncertainties in the subsurface characterization and to mitigate risks in field development applying the reservoir simulation approach. However, it is always challenging to take full advantage of the observation data, since an accurate representation of strong heterogeneities requires a high-resolution grid. Most of the discretization methods cannot handle full tensor permeability, and high nonlinearity introduced by complex physical process drastically reduces simulation efficiency. In this work, we develop an advanced parallel framework for reservoir simulation with the implementation of state of the art discretization and linearization methods. We apply the multipoint flux approximation (MPFA) method to handle the full tensor permeability in unstructured grids. To keep the fidelity of the geological model and improve computational efficiency, we use massively parallel computations via Message Passing Interface (MPI). Complex subsurface physics is described by mass-based formulations making the framework flexible for general-purpose reservoir simulation. However, the representation of phase behavior introduces additional workload when compared with the phase-based formulations in the traditional approach. Here, we apply the Operator-Based Linearization (OBL) approach which not only overcomes this drawback but also turns it to an advantage. In this method, the conservation equations are described in an operator form. By constructing a library of tabulated operators, the repeated work spent on complex phase behavior and property evaluation can be significantly reduced. We benchmark the parallel framework with analytical solutions under single-phase flow and multiphase flow. The results demonstrate that the parallel framework provides accurate simulation results for structured and unstructured grids. We validate that MPFA implemented in our parallel framework converges to real solutions when the permeability is a full tensor. Besides, several realistic cases have been rigorously tested confirming high computational capacity, efficiency, and accuracy of the advanced massively parallel framework for general-purpose reservoir simulation. With the implementation of MPFA and OBL approaches, the parallel framework is fully equipped for the simulation of problems with full tensor permeability, high-heterogeneities, and complex physical processes.
Many oil reservoirs worldwide have cycle dependent oil recovery either by design (e.g. WAG injection) or unintended (e.g. repeated expansion/shrinkage of gas cap). However, to reliably predict oil recovery involving three-phase flow process, a transformational shift in the procedure to model such complex recovery method is needed. Therefore, this study focused on identifying the shortcomings of the current reservoir simulators to improve the simulation formulation of the cycle-dependent three-phase relative- permeability hysteresis.
To achieve this objective, several core-scale water-alternating-gas (WAG) injection experiments were analysed to identify the trends and behaviours of oil recovery by the different WAG cycles. Furthermore, these experiments were simulated to identify the limitations of the current commercial simulators available in the industry. Based on the simulation efforts to match the observed experimental results, a new methodology to improve the modelling process of WAG injection using the current simulation capabilities was suggested. Then the WAG injection core-flood experiments utilized in this study were simulated to validate the new approach.
The results of unsteady-state WAG injection experiments performed at different conditions were used in this simulation study. The simulation of the WAG injection experiments confirmed the positive impact of updating the three-phase relative-permeability hysteresis parameters in the later WAG injection cycles. This change significantly improved the match between simulation and WAG experimental results. Therefore, a systematic workflow for acquiring and analyzing the relevant data to generate the input parameters required for WAG injection simulation is presented. In addition, a logical procedure is suggested to update the simulation model after the third injection cycle as a workaround to overcome the limitation in the current commercial simulators.
This guideline can be incorporated in the numerical simulators to improve the accuracy of oil recovery prediction by any cycle-dependent three-phase process using the current simulation capabilities.