scholarly journals Experimental Investigation on Cyclic Huff-n-Puff with Surfactants Based on Complex Fracture Networks in Water-Wet Oil Reservoirs with Extralow Permeability

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Bao Cao ◽  
Pu Wei ◽  
Fuchun Tian ◽  
Yang Yan ◽  
Kun Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Injection Pressure ◽  
Oil Reservoirs ◽  
Fracture Networks ◽  
Rapid Reduction ◽  
Secondary Fracture ◽  
Soaking Time ◽  
Complex Fracture ◽  
Secondary Fractures ◽  
Primary Fracture

The injection from a well to other wells can be difficult in extralow-permeability oil reservoirs. In order to address this issue, a method of cyclic huff-n-puff with surfactants based on complex fracture networks for a single horizontal well was proposed and then investigated in terms of the effects of injection and fracture parameters on the oil recovery in water-wet extralow-permeability models. Firstly, the interfacial tension (IFT) and contact angle with different surfactant concentrations were measured to determine the basic properties of the surfactants. Then, the experiments of huff-n-puff with surfactants at different threshold injection pressures and soaking time were carried out to determine the oil increasing effects and analyze the pore-scale (micropores, mesopores, and macropores) mechanisms by combining the technology of nuclear magnetic resonance (NMR), which showed that the recovery increased with threshold injection pressure mostly in mesopores and macropores, while that increased with soaking time mostly in micropores. Eventually, the experiments of cyclic huff-n-puff based on different fracture distributions were conducted in six plate-fractured models to investigate the effects of surfactants, primary fracture, and secondary fracture on each cycle of huff-n-puff. Cyclic huff-n-puff with surfactants assisted by complex fracture networks including both primary and secondary fractures would bring to a higher oil recovery. However, other methods should be taken after several cycles of huff-n-puff due to the rapid reduction of oil recovery of each cycle. The findings for the proposed method should provide a meaningful guide to the development of extralow-permeability oil reservoirs.

scholarly journals Experimental Investigation on Microscopic Residual Oil Distribution During CO2 Huff-and-Puff Process in Tight Oil Reservoirs

Energies ◽  
2018 ◽  
Vol 11 (10) ◽  
pp. 2843 ◽  
Author(s):  
Kun Qian ◽  
Shenglai Yang ◽  
Hongen Dou ◽  
Qian Wang ◽  
Lu Wang ◽  
...  
Keyword(s):  
Lower Limit ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Pore Distribution ◽  
Oil Reservoirs ◽  
Tight Oil ◽  
Residual Oil ◽  
Soaking Time ◽  
Oil Distribution ◽  
Tight Oil Reservoirs

The determination of microscopic residual oil distribution is beneficial for exploiting reservoirs to their maximum potential. In order to investigate microscopic residual oil during the carbon dioxide (CO2) huff-and-puff process in tight oil reservoirs, several CO2 huff-and-puff tests with tight sandstone cores were conducted at various conditions. Then, nuclear magnetic resonance (NMR) was used to determine the microscopic residual oil distribution of the cores. The experiments showed that the oil recovery factor increased from 27.22% to 52.56% when injection pressure increased from 5 MPa to 13 MPa. The oil recovery was unable to be substantially enhanced as the injection pressure further increased beyond the minimum miscible pressure. The lower limit of pore distribution where the oil was recoverable corresponded to relaxation times of 2.68 ms, 1.29 ms, and 0.74 ms at an injection pressure of 5 MPa, 11 MPa, and 16 MPa, respectively. Longer soaking time also increased the lower limit of the oil-recoverable pore distribution. However, more cycles had no obvious effect on expanding the interval of oil-recoverable pore distribution. Therefore, higher injection pressure and longer soaking time convert the residual oil in smaller and blind pores into recoverable oil. This investigation provides some technical ideas for oilfields in design development programs for optimizing the production parameters during the CO2 huff-and-puff process.

scholarly journals Hydrocarbon Gas Flooding Optimization considering Complex Fracture Networks through Numerical Simulation in the Tight Oil Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Yong Qin ◽  
Haochuan Zhang ◽  
Chang Liu ◽  
Haifeng Ding ◽  
Tianyu Liu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Reservoirs ◽  
Tight Oil ◽  
Oil Reservoir ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Gas Flooding ◽  
Hydrocarbon Gas ◽  
Tight Oil Reservoirs

Abstract Field data indicates that oil production decline quickly and the oil recovery factor is low due to low permeability and insufficient energy in the tight oil reservoirs. Enhanced oil recovery (EOR) is required to improve the oil production rates of tight oil reservoirs. Gas flooding is a good means to supplement formation energy and improve oil recovery factor, especially for hydrocarbon gas flooding when CO2 is insufficient. Due to the permeability in some areas is too low, the injected gas cannot spread farther, and the EOR performance is poor. So multifractured horizontal well (MFHW) are usually used to assist gas injection in oilfields. At present, there are few studies on the optimization of hydrocarbon gas flooding parameters especially under the complex fracture network. This article uses unstructured grids to characterize the complex fracture networks, which more realistically shows the flow of formation fluids. Based on actual reservoir data, this paper establishes the numerical model of hydrocarbon gas flooding under complex fracture networks. The article conducts numerical simulation to analyze the effect of different parameters on well performance and provides the optimal injection and production parameters for hydrocarbon gas flooding in the M tight oil reservoir. The optimal injection-production well spacing of the M tight oil reservoir is about 800 to 900 m. The EOR performance is better when the total gas injection rates are about 0.45 HCPV, and gas injection rates of each well are about 3000 to 3500 m3/d (0.021 to 0.025 HCPV/a). The recommended injection-production ratio is about 1.1 to 1.2. This work can offer engineers guidance for hydrocarbon gas flooding of the MFHW with complex fracture networks. Hydrocarbon gas flooding in tight oil reservoirs can enhance oil recovery. The findings of this study can help for a better understanding of the influence of different parameters on hydrocarbon gas flooding in the M tight oil reservoir. This work can also offer engineers guidance for hydrocarbon gas flooding of the MFHW with complex fracture networks.

scholarly journals A semi-analytical two-phase flow model of fractured horizontal well with complex fracture networks in natural fractured reservoirs

2021 ◽  
pp. 014459872110417
Author(s):  
Mengmeng Li ◽  
Gang Bi ◽  
Yu Shi ◽  
Kai Zhao
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Dual Porosity ◽  
Phase Flow ◽  
Fracture Networks ◽  
Two Phase ◽  
Secondary Fracture ◽  
Complex Fracture ◽  
Main Fracture

Complex fracture networks are easily developed along the horizontal wellbore during hydraulic fracturing. The water phase increases the seepage resistance of oil in natural fractured reservoir. The flow regimes become more intricate due to the complex fractures and the occurrence of two-phase flow. Therefore, a semi-analytical two-phase flow model is developed based on the assumption of orthogonal fracture networks to describe the complicate flow regimes. The natural micro-fractures are treated as a dual-porosity system and the hydraulic fracture with complex fracture networks are characterized explicitly by discretizing the fracture networks into multiple fracture segments. The model is solved according to Laplace transformation and Duhamel superposition principle. Results show that seven possible flow regimes are described according to the typical curves. The major difference between the vertical fractures and the fracture networks along the horizontal wellbore is the fluid “feed flow” behavior from the secondary fracture to the main fracture. A natural fracture pseudo-radial flow stage is added in the proposed model comparing with the conventional dual-porosity model. The water content has a major effect on the fluid total mobility and flow capacity in dual-porosity system and complex fracture networks. With the increase of the main fracture number, the interference of the fractures increases and the linear flow characteristics in the fracture become more obvious. The secondary fracture number has major influence on the fluid feed capacity from the secondary fracture to the main fracture. The elastic storativity ratio mainly influences the fracture flow period and inter-porosity flow period in the dual-porosity system. The inter-porosity flow coefficient corresponds to the inter-porosity flow period of the pressure curves. This work is significantly important for the hydraulic fracture characterization and performance prediction of the fractured horizontal well with complex fracture networks in natural fractured reservoirs.

scholarly journals Experimental and Numerical Study on Proppant Transport in a Complex Fracture System

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6290
Author(s):  
Zhaopeng Zhang ◽  
Shicheng Zhang ◽  
Xinfang Ma ◽  
Tiankui Guo ◽  
Wenzhe Zhang ◽  
...  
Keyword(s):  
Transport Mechanism ◽  
Numerical Study ◽  
Phase Method ◽  
Fracture System ◽  
Pumping Rate ◽  
Secondary Fracture ◽  
Proppant Transport ◽  
Complex Fracture ◽  
Primary Fracture ◽  
Slickwater Fracturing

Slickwater fracturing can create complex fracture networks in shale. A uniform proppant distribution in the network is preferred. However, proppant transport mechanism in the fracture network is still uncertain, which restricts the optimization of sand addition schemes. In this study, slot flow experiments are conducted to analyze the proppant placement in the complex fracture system. Dense discrete phase method is used to track the particle trajectories to study the transport mechanism into the branch. The effects of the pumping rate, sand ratio, sand size, and branch angle and location are discussed in detail. Results demonstrate that: (1) under a low pumping rate or coarse proppant conditions, the dune development in the branch depends on the dune geometry in the primary fracture, and a high proportion of sand can transport into the branch; (2) using a high pumping rate or fine proppants is beneficial to the uniform placement in the fracture system; (3) sand ratio dominates the proppant placement in the branch and passing-intersection fraction of a primary fracture; (4) more proppants may settle in the near-inlet and large-angle branch due to the size limit. Decreasing the pumping rate can contribute to a uniform proppant distribution in the secondary fracture. This study provides some guidance for the optimization of proppant addition scheme in the slickwater fracturing in unconventional resources.

Modeling tracer flowback in tight oil reservoirs with complex fracture networks

2017 ◽  
Vol 157 ◽  
pp. 1007-1020 ◽  
Author(s):  
Linkai Li ◽  
Hanqiao Jiang ◽  
Junjian Li ◽  
Keliu Wu ◽  
Fanle Meng ◽  
...  
Keyword(s):  
Oil Reservoirs ◽  
Tight Oil ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Tight Oil Reservoirs

A Semianalytical Approach for Obtaining Type Curves of Multiple-Fractured Horizontal Wells With Secondary-Fracture Networks

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 538-549 ◽  
Author(s):  
Zhiming Chen ◽  
Xinwei Liao ◽  
Xiaoliang Zhao ◽  
Sanbo Lv ◽  
Langtao Zhu
Keyword(s):  
Mathematical Model ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Fracture Networks ◽  
Transient Pressure ◽  
Secondary Fracture ◽  
Type Curves ◽  
Complex Fracture ◽  
Fracture Systems ◽  
Naturally Fractured

Summary In naturally fractured reservoirs, complex fracture systems can easily develop along a horizontal wellbore during hydraulic fracturing. In the fracture systems, multiple, discrete secondary fractures are connected to the multiple-fractured horizontal well (MFHW). Because of the fracture complexity, most studies about performance forecast of such MFHWs highly depend on numerical simulators. In this paper, a new semianalytical approach is proposed to overcome the challenge to analyze the pressure behavior of MFHWs in complex-fracture systems. First, a mathematical model for MFHWs with secondary-fracture networks is established. Then, with Gauss elimination and the Stehfest numerical algorithm (Stehfest 1970), the transient-pressure solution of the mathematical model is solved, and type curves of MFHWs with secondary-fracture networks are obtained. After that, model validation and sensitivity analysis are conducted. It is found that the presented approach can rapidly and accurately generate type curves of MFHWs with secondary-fracture networks. This work provides very meaningful references for reservoir engineers in fracturing evaluations as well as performance estimations of MFHWs in naturally fractured reservoirs.

scholarly journals Huff-n-Puff Experimental Studies of CO2 with Heavy Oil

Energies ◽  
2019 ◽  
Vol 12 (22) ◽  
pp. 4308 ◽  
Author(s):  
Evgeny Shilov ◽  
Alexey Cheremisin ◽  
Kirill Maksakov ◽  
Sergey Kharlanov
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Gas Injection ◽  
Experimental Studies ◽  
Injection Pressure ◽  
Critical Factor ◽  
Oil Reservoirs ◽  
Injection Process ◽  
Heavy Oil Reservoirs ◽  
Oil Flow

This work is devoted to CO2 Huff-n-Puff studies on heavy oil. Oil recovery for heavy oil reservoirs is sufficiently small in comparison with conventional reservoirs, and, due to the physical limitation of oil flow through porous media, a strong need for better understanding of tertiary recovery mechanisms of heavy oil exists. Notwithstanding that the idea of Huff-n-Puff gas injection technology for enhanced oil recovery has existed for dozens of years, there is still no any precise methodology for evaluating the applicability and efficiency of this technology in heavy oil reservoirs. Oil recovery factor is a question of vital importance for heavy oil reservoirs. In this work, we repeated Huff-n-Puff tests more than three times at five distinct pressure points to evaluate the applicability and efficiency of CO2 Huff-n-Puff injection to the heavy oil reservoirs. Additionally, the most critical factor that affects oil recovery in gas injection operation is the condition of miscibility. Experimental data allowed to distinguish the mixing zone of the light fractions of studied heavy oil samples. The experimental results showed that the pressure increase in the Huff-n-Puff injection process does not affect the oil recovery when the injection pressure stays between miscibility pressure of light components of oil and minimum miscibility pressure. It was detected that permeability decreases after Huff-n-Puff CO2 tests.

scholarly journals Investigation on degradation mechanism of polymer blockages in unconsolidated sandstone reservoirs

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 55-60
Author(s):  
Wenting Dong ◽  
Dong Zhang ◽  
Keliang Wang ◽  
Yue Qiu
Keyword(s):  
Oil Recovery ◽  
Degradation Mechanism ◽  
Injection Pressure ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Reservoir Properties ◽  
Thermal Analyzer ◽  
Sandstone Reservoirs ◽  
Suction Index ◽  
Weighing Method

AbstractPolymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

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