|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Yang, Ruiyue (China University of Petroleum) | Chunyang, Hong (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water-related issues. Liquid nitrogen (LN 2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN 2 directly as a fracturing fluid. In this work, we examine the performance of LN 2 fracturing based on a newly developed cryogenic-fracturing system under truetriaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture-initiation behavior under cryogenic in-situ conditions revealed by cryo-scanning electron microscopy (cryo-SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic-damage numerical simulation. Finally, the potential application considerations of LN 2 fracturing in the field site are discussed. The results demonstrate that LN 2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high-tensile hoop stress and bring about extensive rock damage. Fracture-propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN 2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight-reservoir resources in an efficient and environmentally acceptable way. Introduction The commercial development of shale gas/oil, tight gas/oil, coalbed methane (CBM), and other low-permeability reservoirs relies on multistage fracturing in horizontal wells. However, massive hydraulic fracturing using water-based fluid has caused economic and environmental burdens.
Ma, Xiaopeng (China University of Petroleum ) | Zhang, Kai (China University of Petroleum) | Yao, Chuanjin (China University of Petroleum ) | Zhang, Liming (China University of Petroleum) | Wang, Jian (China University of Petroleum ) | Yang, Yongfei (China University of Petroleum ) | Yao, Jun (China University of Petroleum )
Summary Efficient identification and characterization of fracture networks are crucial for the exploitation of fractured media such as naturally fractured reservoirs. Using the information obtained from borehole logs, core images, and outcrops, fracture geometries can be roughly estimated. However, this estimation always has uncertainty, which can be decreased using inverse modeling. Following the Bayes framework, a common practice for inverse modeling is to sample from the posterior distribution of uncertain parameters, given the observational data. However, a challenge for fractured reservoirs is that the fractures often occur on different scales, and these fractures form an irregular network structure that is difficult to model and predict. In this work, a multiscale-parameterization method is developed to model the fracture network. Based on this parameterization method, we present a novel history-matching approach using a data-driven evolutionary algorithm to explore the Bayesian posterior space and decrease the uncertainties of the model parameters. Empirical studies on hypothetical and outcrop-based cases demonstrate that the proposed method can model and estimate the complex multiscale-fracture network on a limited computational budget. Moreover, in many situations, the distribution of fractures is extremely complex and constitutes a multiscale-fracture network (de Dreuzy et al. 2002; Schultz et al. 2008; Prioul and Jocker 2009). In addition, the flow pattern in such reservoirs is significantly influenced by the distribution of fractures. To develop and manage fractured reservoirs efficiently, sufficient reliable identification and description of the fracture network must be available. In the last decades, how to deal with complex fractured reservoirs has attracted much attention in the history-matching research community (Suzuki et al. 2007; Somogyvári et al. 2017; Zhang et al. 2018; Yao et al. 2019). History matching is an effective inverse modeling method that can provide reliable reservoir models by integrating static data and dynamic observations (Oliver and Chen 2011; Linde et al. 2015). However, because of the irregular and multiscale nature of fracture networks, applying history matching to model fractured reservoirs is still challenging. For fractured reservoirs, history matching usually requires selecting an appropriate numerical model to simulate the flow behavior as accurately as possible.
Countercurrent spontaneous imbibition is one of the most significant mechanisms for the mass transfer between fractures and matrixes in tight reservoirs. Adding surfactants and pressurization are two common methods to enhance the imbibition. In this study, we used the low-field nuclear magnetic resonance (NMR) instrument to monitor the dynamic imbibition processes with surfactants added and fluid pressure applied. The T2 relaxation distribution and corresponding water saturation profiles during the imbibition process were obtained by analyzing NMR responses. We found that sodium alpha-olefin sulfonate (AOS) could improve the oil recoveries of laboratory-scale cores to 22.31 and 29.59% with different concentrations (0.1 and 0.5 wt%). The surfactant addition not only expands the imbibition area, but also reduces the residual oil saturation in the imbibition profile. However, the actual maximum imbibition distances are only approximately a centimeter long (0.9412 and 1.1372 cm), which is insignificant for field scale. Due to the minimal imbibition distance, high-quality hydraulic fracturing is required to generate a large number of fractures for imbibition to ensure considerable oil recovery at the field scale. In addition, surfactant is consumed during spontaneous imbibition of oil-wet rocks and increasing surfactant concentration facilitates the imbibition process. However, arbitrarily increasing the concentration does not achieve the expected oil recovery because of the high adsorption capacity resulting from the high concentration. We need to consider economic efficiency to optimize a reasonable surfactant concentration. It was found that traditional dimensionless scaling models are not applicable in the complicated surfactant-enhanced imbibition. Hence, we proposed a new scaling group for scaling laboratory date to the field in fractured oil-wet formations. Moreover, we compared the imbibition process under different pressure conditions (7.5 and 15 MPa) and found that the effect of fluid pressure on countercurrent imbibition is not obvious.
Wang, Junlei (PetroChina Research Institute of Petroleum Exploration and Development) | Luo, Wanjing (China University of Geosciences) | Chen, Zhiming (China University of Petroleum)
The purpose of this paper is to determine the optimal strategy of bottomhole-pressure (BHP) drawdown management in a hydraulically fractured well with pressure-sensitive conductivity to remain conductive while maintaining a high enough drawdown to maximize the estimated ultimate recovery (EUR). In this work, a novel permeability-decay coefficient accounting for dynamic conductivity effect (DCE) is proposed to represent the pressure sensitivity in a fracture on the basis of experimental results. Using an existing method, the constant/variable BHP conditions and the hydraulic fractures with DCE are considered in the model. Model verification is performed by comparing with the solutions from the numerical method. Then, the mechanism of fracture closure and its effect on production performance are investigated using the semianalytical solution, and the interplay between pressure drawdown and productivity loss is captured by generating a set of type curves for the transient inflow performance relationship (TIPR).
Next, an easy-to-use approach is developed to find the optimal path of BHP decline vs. time, and the practical optimal drawdown is calibrated by capturing the time-lapse behavior, with consideration of the effect of production history on TIPR. It is found that if the relation of decay coefficient and pressure is a linear function, there will be a reversal behavior on TIPR as BHP drawdown increases. That is to say, an operating point exists on the TIPR curves, beyond which the production rate decreases; otherwise, the production rate increases. The operating point is defined as the optimal BHP drawdown at a given time, and the optimal profile of BHP drawdown is achieved by integrating operating points on TIPR curves corresponding to different times. Subsequently, a synthetic case generated by a coupled-geomechanical/reservoir simulator is defined to demonstrate that an optimal BHP-drawdown schedule developed by the semianalytical approach has the ability to enhance ultimate recovery by reducing the effective stress on the stress-sensitive fracture while maintaining the well productivity.
Polymer flooding is one of the important measures to exploit the remaining oil in the middle and high water cut of oil fields. And the key to the success of the polymer flooding is the selection of the polymer flooding well. Pressure index (PI) and the degree of fullness (FD) are significant parameters, which are commonly used for polymer flooding project design and injection well performance analysis in China, due to their economical application. However, PI and FD are insufficient in discrimination and calculation method, which can only reflect the present heterogeneity of the formation. As a result, efficiency of polymer flooding decision might be not as good as expected.
Improved pressure index (IPI) is established on basis of PI and FD. IPI is the ratio of the mean of pressure to the downfall of the wellhead pressure under the condition of unit water injection. The smaller the IPI value, the more the polymer flooding should be made. IPI not only takes the present heterogeneity of the formation into consideration, but also the transformation of pressure variation tendency. And IPI is a dimensionless parameter, which keeps initial advantages of PI and FD—simple and low cost.
This method has been applied to nearly 50 Wells. The success rate of polymer flooding exceeds 92%. The measure reduce the water cut at the same time increase oil production. It not only improves the recovery yield, but also brings good economic benefit. In addition, the paper presents a field case study to validate the methodology. IPI is far more accurate than PI and FD. In summary, IPI is not only feasible, but also saves a lot of money.
IPI has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.
Quantitative identification of diagenetic facies is critical for favorable reservoir prediction. In this study, the diagenetic facies of the Chang-8 reservoir in the Zhenbei area of the Ordos Basin was investigated using an integrated analysis of casting thin sections, scanning electron microscopy (SEM) and X-ray diffraction (XRD). The Chang-8 reservoirs can be subdivided into five major diagenetic facies categories: 1) weakly-dissolved chlorite cemented facies, 2) moderately-compacted mineral dissolution-susceptive facies, 3) moderately-dissolved kaolinite-bearing facies, 4) moderately-compacted carbonate cemented facies, and 5) strongly-compacted tight sandstone facies. On the basis of the above analyses, the diagenetic facies were identified from well logs by involving the supervised-mode self-organizing-map neural network (SSOM) algorithm. Six wireline logs sensitive to the diagenetic facies characteristics were used as the model input, the diagenetic facies prediction model was built using SSOM. The prediction results of the diagenetic facies are in good agreement with the core analysis types, with a matching of 83.87%. Our work also sheds light on reservoir typing by linking the diagenetic facies with reservoir quality and oil testing data.
The collapse cycle of brittle shale is related to many factors, among which the strength weakening after contact with drilling fluid is an important factor, and the degree of strength weakening is closely related to the degree of rock damage. In order to study the influence of core damage on borehole collapse, shale cores were first loaded with different loads before the peak strength and then unloaded, and then the strength tests were carried out after immersing in the drilling fluid, through which a model of the influence of shale damage on the strength weakening and a collapse cycle evaluation method considering shale initial damage were established. The study results show that initial damage increases the needed drilling fluid density to maintain wellbore stability in subsequent drilling, and shortens the collapse cycle. Therefore, in complex brittle shale drilling, proper drilling fluid density should be selected before drilling to avoid serious initial damage.
During the drilling process, the drilling fluid column pressure replaces the support of the drilled rock, and the stress around the borehole is redistributed, resulting in stress concentration. Under the action of stress, the rock around the wellbore will be deformed or even destroyed, which causes wellbore instability. According to statistics, more than 90% of the wellbore instability in oil and gas drilling occurs in shale formation, among which the hard brittle shale formation accounts for 2/3 (Wang et al., 2006; Lu, 2011). The typical falling blocks from hard brittle shale formation are shown in Fig. 1. These blocks do not stick when exposed to water, but they flake easily. Some of the blocks are schistose, which is the characteristic of layered shale.
The research on the failure mechanism at home and abroad shows that the failure of brittle rock is mainly caused by the initiation, propagation and intersection of internal cracks during loading and unloading (Zhu et al., 2008). For fractured brittle formations, increasing the plugging capacity of drilling fluid can slow down the invasion and pressure transfer, but this method alone cannot maintain wellbore stability (Ottesen, 2010). In addition, the existence of micro-cracks in hard brittle shale makes the wellbore instability correlated with time and causes periodic collapse (Han et al., 2018).
Yu, Huiyong (PetrolChina Xinjiang Oilfield Company) | Lin, Botao (China University of Petroleum) | Shi, Can (China University of Petroleum) | Shi, Shanzhi (PetrolChina Xinjiang Oilfield Company) | Ma, Junxu (PetrolChina Xinjiang Oilfield Company)
The Jurassic conglomerate reservoir in Xinjiang province, northwest China, is one of the largest conglomerate type reservoirs in the world. Hydraulic fracturing stimulation has become a necessary and crucial development method for the hydrocarbon reserve in the region of concern. To efficiently guide the hydraulic fracturing operation, it is first desirable to predict the fracture gradient accurately. Firstly, the fracture gradient (FG) was calculated by Matthews & Kelly's method, Eaton's method, and Andersen's method. Then, six sets of leak-off test (LOT) are analyzed. By comparing the relationship between the two, it is found that the LOT value of the conglomerate section is much larger than the calculated value, and the LOT value of the sandstone section is close to the calculated value. This paper proposed an improved method for predicting fracture gradient for Jurassic conglomerate formations in Xinjiang. The gravel diameter correction coefficient η and the LOT correction factor φ were introduced. So, the improved fracture gradient prediction method can correct the influence of gravel diameter on the fracture pressure and the difference between the fracture gradient obtained by the LOT and the calculated values. The method can efficiently aid field engineers to optimize the hydraulic fracturing design or to select more reasonable and safer drilling fluids.
The Jurassic conglomerate reservoir in Xinjiang province, northwest China, is one of the largest conglomerate reservoirs in the world. Figure 1 shows the location map of the study area. The reservoir is featured by an extremely low permeability and substantial heterogeneity, while the natural fractures rarely exist. To more efficiently develop conglomerate reservoirs, hydraulic fracturing has become a necessary and crucial stimulation method in the region of concern. Fracture gradient refers to the fluid pressure beyond which the formation produces hydraulic fractures or opens the original fractures. It is one of the basic parameters required for drilling and fracturing designs.
Pang, Huiwen (China University of Petroleum) | Jin, Yan (China University of Petroleum) | Dong, Jingnan (CNPC Engineering Technology R&D Company Limited) | Gao, Yanfang (China University of Petroleum) | Wang, Hanqing (China University of Petroleum) | Wang, Zhenyu (China University of Petroleum)
X-ray computer tomography scanning (X-ray CT) has been adopted for investigating rock's microstructure, which could characterize sample's inner pore structure non-destructively. Image segmentation is the first step towards pore space identification. Segmentation of a porous media means conversion of gray scale CT volumes into different regions that permits quantitative characterization. Macroscopic properties of the segmented image can vary greatly with different segmentation methods. In general, CT images of rock and soil samples are required to convert into binary images of particles and pores. X-ray computer tomography technique could also be used for visualizing the specific bitumen-pore-grain structure of oil sands. Segmentation of oil sands refers to the process of partitioning the image into three regions of void, grains and bitumen. At present, the applicability investigation of various segmentation methods for oil sands seems to lag.
In this study, four methods for identifying bitumen and pore regions from 2D oil sands Micro CT scan images are compared. Image information entropy is used as a weight to calculate the average porosity of the sample. Image-derived porosity obtained according to the segmentation are given in this paper. Several technical issues of image preprocessing of CT images of oil sands are discussed, and the porosity and bitumen content derived from image applied the segmentation methods are compared to the laboratory measurement of oil sands cores. The research presented is the foundation of quantitative pore space analysis and hydraulic modeling of oil sands based on digital cores.
Oil sands is a nature mixture of sand, clay, water, and extra heavy crude oil, which is called bitumen. The most effective oil sand bitumen thermal recovery technology is the steam assisted gravity drainage (SAGD) process. Bitumen is immobile at reservoir temperatures and becomes less viscous or even begin to flow with the increase of temperature. To understand the characterization of pore structures and pore networks of oil sands is regard as a significant approach to evaluate the mechanical and hydraulic properties.
During the oil and gas development from weakly consolidated sandstone reservoirs, sand production problem is highly prone to occur, resulting in oil production reduction, down-hole tool abrasion and even oil well scrapping. At present, analysis of sand production in oil and gas wells is mainly the prediction of critical down-hole pressure, and there are relatively few studies on the prediction of sand production volume with different practical down-hole pressures. Quantitative prediction of sand production involves elastoplastic behavior of the formation rock and fluid flow within the pores, and it is influenced and controlled by various factors such as mechanical properties of the formation, fluid properties, completion and production technologies. In order to accurately predict the volume of sand production, it is assumed that the weakly consolidated sandstone is a homogeneous isotropic porous elastoplastic medium for which the Mohr-Coulomb criterion is adopted to describe the abrupt strain softening and residual plastic flow. A finite element sand production model has been established for modeling the coupled reservoir matrix mechanical behavior and hydraulic erosion. By comparing with the results of laboratory sand production experiments of weakly consolidated sandstone, the erosion intensity coefficient in the model was determined. Parametric studies have been performed to predict the sand production volume of a realistic oilfield under different conditions. The calculation results show that the borehole diameter of weakly consolidated sandstone is enlarged after erosion for a certain period of time, and there is a change process from rapid sand production, stable sand production to slow down to the trend of no sand production. In the case of high production differential pressure, the total sand production volume is larger than the low production differential pressure. The simulation results can be beneficial for the decision-making of sand production management in weakly consolidated sandstone reservoirs.
The problem of sand production has always been accompanied by the exploitation of oil and natural gas resources. Researchers have been working hard to solve the safety and economic problems caused by sand production for many years.