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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.
Li, Yaohua (China Geological Survey, Beijing, and University of Utah) | Song, Yan (China University of Petroleum, Beijing) | Jiang, Shu (China University of Geosciences) | Wang, Qianyou (China University of Petroleum, Beijing) | Jiang, Zhenxue (China University of Petroleum, Beijing) | Zhang, Fan (China University of Petroleum, Beijing)
Free gas in tight reservoirs begins to accumulate when the gas and oil state in the reservoir (i.e., in situ) has reached a critical point and the flow becomes unstable, unlike conventional gas flow caused by the gravitational differentiation (Nojabaei et al. 2013, 2016; Wang et al. 2013). The GOR in a conventional reservoir is usually controlled by the gas dissolved in oil (i.e., the solution gas), whereas in unconventional reservoirs, it is controlled by both the solution gas and the free gas in situ (Jones 2016, 2017). Therefore, capillary condensation must be considered when studying tight oil mobility in situ because the production of oil is controlled by the capillary force during the tight-oil development stage (Leverett 1941; Li and Sheng 2017; Wang et al. 2017; Yuan et al. 2017). Usually, the driving forces are different for the imbibition and waterflooding for oil production, in connection with the capillary force of the liquid phase in water-wet reservoirs and the hydraulic pressure of liquid oil in oil-wet reservoirs (Du and Chu 2012; Behmanesh et al. 2018). In general, capillary resistance for oil production is the same for imbibition and waterflooding, and is controlled by the interfacial tension between different phases [i.e., the solid, liquid, and vapor phases in a constrained space (Less et al. 2008; Wang et al. 2013, 2018; Gherabati et al. 2016; Luo et al. 2017; Yang et al. 2017; Chen et al. 2018)].
Wang, Junlei (PetroChina Research Institute of Petroleum Exploration and Development) | Luo, Wanjing (China University of Geosciences) | Chen, Zhiming (China University of Petroleum)
Summary 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.
Liquid sloshing might cause severe impact on the container, leading to damage and destruction of the structures. It is widely believed that installing baffles in the container is one of the most effective ways to reduce violent liquid sloshing, based on which great efforts have been devoted in the investigations of liquid sloshing with baffles for decades. However, most of these existing investigations were focused on the effects of baffle type and fluid mechanism in the sloshing process. Despite that some researchers studied the large deformation of rubber baffles using weak-coupled algorithm, structural responses of the baffles considering hydroelastic effects were rarely paid attention to. This paper carries out a numerical study on the hydroelastic effects of the fluid-structure interaction (FSI) in a sloshing tank with baffles using a strong-coupled FSI algorithm. Firstly, numerical implementation of the numerical sloshing tank which solves the incompressible Navier-Stokes (N-S) equations using SIMPLE method, and the FSI method which solves the monolithically strong-coupled FSI equation using an implicit scheme are introduced. Secondly, grid-independence test and validation on sloshing load are carried out to determine the grid system and show the effectiveness on liquid sloshing using present method. Lastly, liquid sloshing in tanks with horizontal and vertical baffles considering hydroelastic effects are numerically studied. Structural responses of the baffles and sloshing loads on the baffles are obtained and analyzed with a fast Fourier transform (FFT) method, from which the hydroelastic effects are revealed and discussed.
Liquid sloshing is the free surface motion of liquid in partially filled tanks/containers under the excitation of the container’s motion, which is quite commonly seen in the field of ocean engineering structures like ships and platforms. It is known that liquid sloshing might lead to instability and damage to floating structures, causing serious safety threats (Ibrahim, 2005; Faltinsen and Timokha, 2009), and thus understanding on sloshing phenomena and sloshing is of vital importance. As the pioneer, Faltinsen (1978) proposed a boundary element method (BEM) model to study the problem of liquid sloshing, after which researches on liquid sloshing have been flourishing and various analytical, numerical and experimental methods have been developed.
Yang, Jin (China University of Petroleum-Beijing) | Sun, Ting (China University of Petroleum-Beijing) | Zhao, Ying (China University of Petroleum-Beijing) | Borujeni, Ali Takbiri (West Virginia University West) | Shi, Haidong (PetroChina Research Institute of Petroleum Exploration & Development) | Yang, Hao (China University of Geosciences)
Gas kicks are often encountered during drilling the oil & gas formations. This paper proposes a data-driven method by employing machine learning for real-time detection of gas kicks. Firstly, logging data is recorded and compiled for gas cases. Secondly, artificial neural network is employed to detect gas kicks. Meanwhile, principal components analysis is used to reduce the dimensionality of parameters. At last, three gas kick accidents are studied to verify the power of the technology used. The method is shown to be highly reliable for identifying the gas kicks accidents at a shorter time than the reported detection using conventional techniques.
At present, the trend of oil exploration and development around the world is toward the ocean to deep water, and deepwater drilling faces many challenges such as high wellbore temperature pressure control requirements, poor borehole stability, narrow drilling fluid safety density window, and many other challenges. The deepwater environment makes the well control more complicated, and the drilling risk increases sharply. Once the blowout is out of control, the damage is huge, which will not only cause huge economic losses and casualties, but also cause great damage to the offshore ecological environment (BP, 2010; Zhang, Zhang, Yue, et al, 2018).
Therefore, the prevention and control of deepwater oil and gas well overflow and blowout is a major problem that needs to be solved urgently in offshore oil and gas development. Early detection of overflow (especially gas kick) plays an extremely important role in well control. Gas kick is the induction of a kick or directly leads to a blowout.
One of the main factors, and avoiding and preventing blowout accidents is an important guarantee for safe drilling. If the gas can be detected immediately after entering the wellbore, and effective measures are taken in time, not only can the blowout be avoided, but also the downhole complex accidents occurring in the well control process can be obviously reduced, thereby protecting the oil and gas layer, increasing the drilling rate and ensuring the drilling efficiency.
Wang, Wendong (China University of Petroleum) | Zhang, Kaijie (China University of Petroleum) | Su, Yuliang (China University of Petroleum) | Tang, Meirong (PetroChina Oil & Gas Technology Research Institute of Changqing Oil field) | Zhang, Qi (China University of Geosciences) | Sheng, Guanglong (China University of Petroleum)
In the development of shale oil and gas reservoir, hydraulic fracture treatments may induce complex network configuration, which is very challenging to characterize. The existing fracture properties interpretation methods mostly rely on simplifying assumptions and are typically empirical in nature. The aim of this work is therefore to introduce an integrated framework involving fractal theory, inverse analysis of micro-seismic events (MSE), and rate-transient analysis to map the heterogeneity and distribution of fracture properties. In this work, a general framework is proposed to characterize both the geometry configuration and the owing properties of the complex fracture network (CFN). The CFN characterization framework is naturally divided into two stages: characterize the fracture geometry network by microseismic data and characterize the fracture dynamic properties by production data. In the fracture configuration characterization stage, a stochastic fractal fracture model based on an L-system fractal geometry is applied to describe the CFN geometry. Moreover, the genetic algorithm (GA) as a mixed integer programming (MIP) algorithm are applied to find the most probable fracture configuration based on the microseismic data. As to the owing properties characterization stage, we introduced embedded discrete fracture model (EDFM) for the computational concern and a Bayesian framework is used to quantify these fracture dynamical properties e.g., conductivity, porosity and pressure dependent multiplier by assimilating the production data. In addition, rate-transient analysis is also applied to calibrate the total fracture length and estimate effective stimulated-reservoir volume (ESRV). In order to validate this framework, a synthetic numerical case is developed. The result indicates that our integrated framework is able to characterize both CFN configuration and properties by assimilating microseismic and production data sequentially. The proposed workflow shows that the characterized CFN model would yield reasonable probability predictions in unconventional production rate.
Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods.
The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology.
This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units.
This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Too many required pre-existing fractures (over fifteen) by the HTPF method restrict the wide application under various stress measurement conditions. Considering the shortcomings of HTPF method, a rock mechanics equation to describe the shearing stresses intrinsically present on geological discontinuity planes is established, and at the same time, the least square fitting method and the trial searching algorithm code to determine the frictional coefficient of preexisting fractures are utilized to determine complete stress tensors by inversions. Theoretically, each hydraulic test on every preexisting fracture can help establish two mechanical equations, and then three tests on preexisting fractures can determine a complete stress tensor. However, practically, in order to guarantee the inversion code to be convergent, at least four to five pre-existing fractures are needed. Here, this method is named modified hydraulic testing on pre-existing fractures method, abbreviated as M-HTPF method. The M-HTPF method was applied in a stress measurement campaign in Weifang area, Shandong Province. During this stress measurement campaign, the shut-in pressures determined by the hydraulic fracturing test on pre-existing fractures, and azimuth and dip angle data defined by televiewer logging of five geological fractures were utilized to determine the complete stress tensor. The stress tensor is characterized by: σ1=8.85MPa, N58.12°W ∠ 14.18σ; σ2=6.61MPa, N26.2°E ∠ -21.54°; σ3=5.01, N62.86°E ∠ 63.86°. The M-HTPF method offers a new access to determine a complete stress tensor using a single borehole.
In 1984, Cornet and Valette proposed that the hydraulic test on pre-existing fractures could be utilized to measure the normal stress on the fracture plane so as to determine in-situ stress tensors. On the first international rock stress symposium, Cornet (1986) named this method to determine in-situ stresses the hydraulic test on pre-existing fractures (abbreviated as HTPF). After that, many scientists applied the HTPF method in different field measurements and compared the application effects between the HTPF method and the Hydraulic fracturing (HF) method, and generally, they got fairly good results. Cornet and Burlet (1992) summarized 8 HTPF application cases in France, and then gave some key points and suggestions for carrying out the campaign of HTPF, which offered lots of reference experiences and cases for the popularization of HTPF. In order to determine in-situ stress in a mountainous region, Cornet et al. (1997) conducted HTPF measurements in an inclined borehole, and they combined a genetic algorithm and a Monte Carlo technique to optimize the inversion procedure, finally they got satisfied stress measurement results. In 2003, Cornet et al. developed new HTPF test equipment, the key downhole component of which is a probe combining electrical imaging with an inflatable straddle packer, and consequently, they can determine the normal stress applied on the tested fracture planes by analyzing both hydraulic and electrical signals observed during shut-in phases simultaneously. At the same time, Haimson and Cornet (2003) jointly published a paper to recommend HF and HTPF methods to determine in-situ stresses, sponsored by the International Society for Rock Mechanics (ISRM). In China mainland, Chinese scientists also used this methods in different engineering cases.
Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Wu, Shuhong (Research Institute of Petroleum Exploration and Development, PetroChina) | Yu, Tao (Research Institute of Petroleum Exploration and Development, PetroChina) | Ping, Yi (Changqing Oilfield Company, PetroChina) | Qin, He (China University of Petroleum) | Yuan, Jiangru (Research Institute of Petroleum Exploration and Development, PetroChina) | Zhu, Zhouyuan (China University of Petroleum) | Su, Hao (China University of Geosciences)
Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from tight oil reservoirs. However, the primary recovery factor remains very low, usually less than 15%. It is a big challenge to supply formation drive energy to sustain production. After hydraulic fracturing, there is often pre-mature water breakthrough or gas channeling when we inject water or gas. Therefore, CO2 huff-n-puff becomes an attractive option to improve oil recovery in tight oil reservoirs.
Based on typical reservoir and fracture properties in Ordos Long-7 tight oil reservoir, a compositional reservoir simulation model with hydraulic fracture network was established to evaluate the performance of CO2 huff-n-puff enhanced oil recovery (EOR) method. Through numerical simulation, we perform sensitivity study to explore the impacts of operation parameters such as CO2 injection rate, injection time, soaking time, number of huff-n-puff cycles on EOR performance. Some of these parameters have rarely been investigated for recovery in tight reservoirs, such as in-situ fluid composition, fracture pore volume and hydraulic fracture characterization. Furthermore, correlation analysis is used to evaluate the performance of CO2 huff-n-puff process.
In this study, we find that hydraulic fracture morphology and fracture conductivity can have a large impact on the performance of CO2 huff-n-puff. Due to the existence of natural fractures in tight reservoirs and the stimulated reservoir volume, CO2 huff-n-puff can not only mobilize the crude oil near the well, but also have certain recovery effects on the remaining oil between the adjacent wells. Simulation results show that the most important parameter is number of cycles, followed by CO2 injection rate and soaking time. It is found that the optimum injection pressure of CO2 huff-n-puff process can be set around the minimum miscibility pressure (MMP) for CO2 and the crude. We set the soaking time period to be 30 days, injection rate to be 150 ton/day, number of cycles to be 4 for optimized oil recovery. The incremental oil recovery factor after one cycle is 1.59%, and the output-to-input ratio is 1:1.75.
The findings in this work have the potential to advance our understandings of the role of CO2 EOR in developing unconventional oil reservoirs, which will benefit both the energy industry and the environment with the potential benefit of CO2 geological sequestration.