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.
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.
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.
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.
Prediction of overpressure in carbonate formation is still a difficult problem in overpressure researches. Commonly, the method to predict overpressure in clastic formation is empirical, which is based on Terzaghi effective stress theory. And there always exist a parameter (mostly p-wave velocity) which have clear response to overpressure. These empirical methods are not suitable to predict overpressure in carbonate formation with dense lithology and extremely inhomogeneous physical property. By analyzing the effects on saturated carbonate rocks under the action of stress and pore pressure, a theoretical method has been established based on poroelasticity theory, which can reflect the quantitative relationship between pore pressure and rock elastic parameters. In this study, the established method is applied in northeastern Sichuan basin to predicate overpressure in carbonate formation. The basic physical parameters (e.g., rock component and porosity) needed in application are obtained by well-logging comprehensive interpretation model in carbonate formation. Besides, we establish a rock physical model for carbonate rock to calculate S-wave velocity and rock elastic parameters, which are also used in the application. Finally, overpressure in carbonate rock is predicted by the quantitative poroelasticity model with basic physical parameters and rock elastic parameters. The prediction result shows that the predicted pressure is highly consistent with the drill-stem-testing pressure and the monitoring pressure while drilling. Therefore, the quantitative model, established in this study, could be a new approach to solve the problem of overpressure prediction in carbonate rocks.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 5
Presentation Type: Poster
Huang, Shaoping (China University of Geosciences) | Yan, Echuan (China University of Geosciences) | Li, Xingming (China University of Geosciences) | Liu, Xuyao (China University of Geosciences) | Chen, Qian (China University of Geosciences) | Yang, Kai (China University of Geosciences)
ABSTRACT: The anti-dumping layered rock slope is a common type of slope with various deformation and failure modes, complicated mechanics mechanism and many influencing factors. Through utilizing 3DEC to research on deformation and failure of toppling rock slope in 3D, ”curved book dumping” mode under the condition of two free faces was proposed, and based on ”Cantilever Theory”, a mechanical model was established for stress analysis. The action law of Geometry and structure characteristic parameters can be concluded from the research: deformation displacement of slope increases as slope height, slope angle and joint inclination increase; the displacement decreases as the included angle between the joint surface and the free face decreases; the largest deformation displacement of the slope appears either when the angle between the two free faces is 90°or when the joint spacing is 1.5m. The sensitivity sorting is concluded through orthogonal test on numerical simulation results: joint inclination angle > slope height > cut slope angle > angle of two free surface > angle between slope surfaces > layer thickness > included angle between the joint surface and the free face.
The anti-tilted slope refers to the slope that the strike of the rock strata is close to the trend of the slope, and the inclination of the slope is opposite to the slope. The dumping deformation is a typical failure form of rock slope. A method to analyze the stability of slopes based on the principle of limit equilibrium was proposed (Goodman et al, 1976). Many scholars have further developed and studied on the basis of Goodman's theory (ZANBAK C, 1983; AYDAN O et al, 1989; KLICHE CA, 1999; LIU C H et al, 2009; LIU C H et al, 2008; Hai Feng LU et al, 2012). A large number of scholars have conducted detailed studies on formation mechanism, criterion of instability, influencing factors and possible instability modes of anti-incline rock slopes by means of geological analysis, numerical simulation, physical simulation and modern scientific theory(Dong Xing CHENG et al, 2005; Xi Jie YIN et al, 2007; Bao Cheng ZUO et al, 2005). However, at present, the study is conducted under the condition of one free surface to research on the formation mechanism of anti-dip slope from a two-dimensional perspective (Bei Chuan HAN et al, 1999; Nichol S L,Hungr O and Evans S G, 2002; Ji Liang ZHU et al, 2001; Fa Quan WU et al,1997). Only a few scholars have studied the deformation and failure of anti-dip slope under the condition of two free surfaces (YOON W S et al, 2002: Liang Qing WANG et al, 2011: Jun QIU et al, 2016). In practical engineering, there may exist multiple free surfaces for the anti-dumping rock slope, and the slope is a spatial geometry. So the study should be conducted on the anti-incline rock slope in three-dimensional space, in this paper, 3DEC is used to study the genetic mechanism of the anti-tilting layered rock slope with different faces. The dumping deformation of the anti-inclined bedded rock slope is affected by many factors, a large number of scholars have studied the relationship between the stability of anti-dip slope and factors such as slope angle, rock dip, slope height, rock thickness and other factors (Dong Xing CHENG et al, 2005: Bei Chuan HAN et al. 1999: Jun QIU et al. 2016).
Presently, field application of Alkali-Surfactant-Polymer flooding (ASP) has achieved great technical success with incremental oil recovery more than 20%. The synergistic effects induced by the three components, alkali, surfactant, and polymer greatly activate remaining oil after water flooding.
With the depletion of oil resources, ASP technique expanded to reservoirs having harsh conditions, such as high temperature, high salinity, low permeability, and heavy oil. For such oilfields, severe conditions bring great technical challenges to chemical agents, making it more difficult to obtain a suitable formulation than that in a conventional reservoir.
The ASP flooding feasibility study was conducted for a massive reservoir with high reservoir temperature ranging from 80 °C to 85 °C and low salinity less than 3000 mg/L. Various evaluations, including polymer testing, surfactant screening and evaluation, long term thermal stability, phase behavior were conducted in the laboratory. Then, the performance of optimized ASP formulation was tested by two runs of core flooding.
Through detailed in-lab study, thermal tolerant polymer and surfactant were selected with satisfying performance. Sound emulsification was observed in phase behavior study of Alkali-Surfactant (AS). ASP flooding utilizing weak alkali Na2CO3 was recommended for such high temperature, low salinity (HTLS) reservoir. Results from core flooding tests demonstrated an incremental oil recovery range from 16.89% to 20.38%. ASP shows promising technical potential for such low salinity reservoir.
After more than thirty years research and application, combined chemical flooding (CCF) has been proved as one of the most effective EOR techniques for the improvement of ultimate recovery in mature oilfields (Ji, et al., 2016; Liao, et al., 2017). In Daqing oilfield with moderate reservoir temperature and salinity, enlarged industrial mass application of Alkali-Surfactant-Polymer flooding (ASP) has achieved great success both technically and economically (Cheng et al, 2014). In the ASP formulation, alkali is beneficial to the reduction of interfacial tension (IFT), decreasing adsorption of surfactant on rock, and formation of in-situ surfactants through reactions between alkali and acidic components in crude oil. In ASP flooding, polymer viscosifies injection fluid and changes mobility ratio of water/oil. Surfactant remarkably decreases IFT with the help of alkali and mobilizes remaining oil after conventional water flooding (Shen, 2003). As for binary Surfactant-Polymer formulation (SP), surfactant must have higher interfacial activity compared with its counterpart in ASP due to elimination of alkali (Wang, et al., 2008; Qiao, 2012; Cai, et al., 2017). Even though ASP flooding has some side-effects caused by alkali, more availability of surfactant and higher enhanced oil recovery make ASP an important option in CEOR.
Yuan, Qingwang (University of Regina) | Wang, Shuoshi (University of Oklahoma) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
The frontal instabilities are a key control factor which can significantly affect the sweep efficiency and oil recovery in miscible flooding processes. Under unfavorable viscosity ratio between injection solvent and oil, the frontal instabilities are nearly unavoidable. However, how to suppress the instabilities, especially with low additional costs, should be carefully investigated. The present study examines the time-dependent displacement rates on flow instabilities in miscible flooding. Within the capacity of injection pumps, the injection rates are varied with time in a fast alternating manner. It is found that this kind of variable rates can stabilizing frontal instabilities by enhancing initial uniform mixing of solvent and oil. It therefore suppresses the later development of instabilities. Eventually, a much less unstable front is obtained when compared with the constant injection rate. Other parameters such as the amplitude of rates are also examined. The variations of propagation of front with time are analyzed for the change of rate strength. It is can therefore be concluded that this kind of time-dependent rate can improve oil recovery at very low additional rate within the capacity of pumps for the field EOR processes.
This study aims to develop a semianalytical model to calculate the productivity index (PI) of a horizontal well with pressure drop along the wellbore. It has been indicated that by introducing novel definitions of horizontal-well permeability and conductivity, the equation of fluid flow along a horizontal well with pressure drop has the same form as the one for fluid flow in a varying-conductivity fracture. Thus, the varying-conductivity-fracture model and PI model can be used to obtain the PI of a horizontal well. Results indicate that the PI of a horizontal well depends on the interaction between horizontal-well conductivity, penetration ratio, and Reynolds number. New type curves of the penetration ratios with various combinations of parameters have been presented. A complete-penetration zone and a partial-penetration zone can be identified on the type curves. Based on the type curves, two examples have also been presented to illustrate the advantages of this work in optimizing parameters of horizontal wells.