Xu, Wei (CNOOC Research Institute Co., Ltd.) | Chen, Kaiyuan (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Fang, Lei (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.)
The lacustrine delta sandbody deposited in the north of Albert Basin is unconsolidated due to the shallow burial depth, which leads to an ultra-high permeability (up to 20 D) with large variation and poor diagenesis. Log derived permeability differs greatly with DST results. Thus, permeability simulation is challenging in 3D geomodeling. A hierarchical geomodeling approach is presented to bridge the gap among the ultra-high permeability log, model and DST results. The ultimate permeability model successfully matched the logging data and DST results into the geological model.
Based on the study of sedimentary microfacies, the new method identifies different discrete rocktypes (DRT) according to the analyis of core, thin section and conventional and special core analysis (e.g., capillary pressure). In this procedure, pore throat radius, flow zone index (FZI) and other parameters are taken into account to identify the DRT. Then, hierarchical modeling approach is utilized in the geomodeling. Firstly, the sedimentary microfacies model is established within the stratigraphic framework. Secondly, the spatial distribution model of DRT is established under the control of sedimentary microfacies. Thirdly, the permeability distribution is simulated according to the different pore-permeability relation functions derived from each DRT. Finally, the permeability model is compared with the logging and testing results.
Winland equation was improved based on the capillary pressure (Pc) data of special core analysis. It is found that the highest correlation between pore throat radius and reservoir properties was reached when mercury injection was 35%. The corresponding formula of R35 is selected to calculate the radius of reservoir pore throat. Reservoirs are divided into four discrete rock types according to parameters such as pore throat radius and flow zone index. Each rock type has its respective lithology, thin section feature and pore-permeability relationship. The ultra-high permeability obtained by DST test reaches up to 20 D, which belongs to the first class (DRT1) quality reservoir. It is located in the center of the delta channel with high degree of sorting and roundness. DRT4 is mainly located in the bank of the channels. It has a much higher shale content and the permeability is generally less than 50 mD. Through three-dimensional geological model, sedimentary facies, rock types and pore-permeability model are coupled hierarchically. Different pore-permeability relationships are given to different DRTs. After reconstructing the permeability model, the simulation results are highly matched with the log and DST test results.
This hierarchical geomodeling approach can effectively solve the simulation problem in the ultra-high permeability reservoir. It realizes a quantitative characterization for the complex reservoir heterogeneity. The method presented can be applied to clastic reservoir. It also plays a significant positive role in carbonate reservoir characterization.
Chen, Meiyi (College of Earth Science, Northeast Petroleum University) | Ji, Qingsheng (Exploration and Development Research Institute) | Chen, Shoutian (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation) | Qin, Longpu (Exploration Department Daqing Oilfield Company Ltd) | Cong, Peihong (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation)
Based on the seismic prediction difficulties of the tight sandstone reservoir in Fuyu formation in Zhaoyuan area, single-well sequence division and connecting-well sub-layer correlation are carried out according to logging and lithologic data, and short-cycle interface position is calibrated precisely after a mutual calibration of logging and seismic data. Horizon tracing in the whole area is also carried out to build highfrequency isochronous stratigraphic framework. On this basis, the log facies modes and the sedimentary facies of the short-cycles under a high-frequency isochronous stratigraphic framework are analyzed in the target area, sand-body geometric scale parameters and their relations and sand-body development degree are calculated out, and a sand-body geological model is also built out. According to the seismic data and layer-by-layer geological model of sand bodies, a spatial distribution probability model of facies-controlled sand bodies is built out, which is used to constrain the pre-stack seismic data in facies-controlled inversion calculation. Based on the results of facies-controlled inversion, the tight sandstone prediction is carried out. Finally, a method of isochronal facies-controlled pre-stack seismic inversion prediction of tight sandstone reservoir is formed and it realizes the effective prediction of superimposed sand bodies in target area. Compared with actual drilling results, the sandstone of more than 2m has clear depiction and the sandstone of between 1-2m also has response, which indicates that this method is feasible and practicable.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Shale hydrocarbon production has become an increasingly important part of global oil and gas supply during the past decade. The life of projects in unconventional plays, such as shale oil and gas, tight oil and gas, coal bed methane etc., heavily depends on the Estimated Ultimate Recovery (EUR). However, the correlation to predict EUR in conventional plays becomes invalid for unconventional plays, which significantly affects the economics of relevant unconventional projects. The objective of this paper is to investigate the correlations between EUR and petrophysics/engineering/production parameters by data regression and interpolation analysis via big data mining from Eagle Ford. Furthermore, a 4-D interpolated EUR database and EUR prediction models are established based on the relevant regression and interpolation results. This study not only helps us understand the physics behind EUR prediction in unconventional plays, but also facilitates determining the viability of projects in unconventional formations from a big data perspective.
In this study, petrophysics/engineering/production data from 4067 wells in Eagle Ford is summarized for analysis. Firstly, a sensitivity analysis is carried out to determine the most sensitive petrophysics and engineering controlling factors. In particular, the physics behind the EUR predictions is discussed in details. Following it, the 2-D nonlinear regression and the multivariate linear regression are applied to evaluate the relationship between EUR and engineering/production data. In addition, a 4-D interpolated EUR database is established to predict EUR based on the petrophysics parameters. The applied nonlinear multivariate interpolation methodology is the Triangulated Irregular Network based Nearest Interpolation Method (3-D). Finally, the 4-D interpolated EUR database are applied to several wells in the Eagle Ford to test its accuracy, confidence and reliability.
Based on the sensitivity analysis results, Vitrinite Reflectance Equivalent (VRE), Total Organic Carbon (TOC) and Resource Density (porosity, hydrocarbon saturation and gross formation thickness) are the most sensitive and important parameters in Eagle Ford shale formation. Based on the data-mining results, effective lateral length has a positive monotonic relation with EUR; EUR increases with more proppant weight and higher true vertical depth. Frac stage and perf per cluster do not have a strong correlation with EUR. In addition, azimuth has a vague relation with EUR while drilling along the North-South orientation is the safest approach in Eagle Ford Shale. The physics behind the correlations is analyzed and discussed in detail. Finally, several DCA EURs of wells from Eagle Ford are used to test the established 4-D interpolated EUR database, and the study results show that the relative errors in EUR predictions are within 30%, indicating that the methodology in this study has great potentials for unlocking more reserves economically in shale formations.
This study offers an insightful understanding of unconventional hydrocarbon production mechanism from a big data perspective, as well as a feasible and accurate method to predict EUR and evaluate projects economic feasibility in Eagle Ford. This methodology can be also applied to other unconventional fields such as Utica, Permian and Bakken Shale plays, if data is available.
Wang, Xianjun (Daqing Oilfield Co.Ltd.) | Wang, Wei (Daqing Oilfield Co.Ltd.) | Li, Borui (Daqing Oilfield Co.Ltd.) | Li, Dongxu (Daqing Oilfield Co.Ltd.) | Gu, Mingyong (Daqing Oilfield Co.Ltd.) | Tang, Pengfei (Daqing Oilfield Co.Ltd.) | Zhang, Hao (Daqing Oilfield Co.Ltd.) | Liu, Yu (Daqing Oilfield Co.Ltd.) | Li, Yonghuan (Daqing Oilfield Co.Ltd.) | Wang, Jing (Daqing Oilfield Co.Ltd.)
Aiming to the development of the tight reservoirs with low permeability in Daqing Oilfield, the horizontal well fracturing technique has achieved good results. However, the output gradually decreases later. The initial average daily oil production per well is 17.0t and drops to 2.6t after some time. Also, the wells with the production lower than 2t constitute more than 50%. Thus, to realize the economic and effective exploitation, the refracturing technique is needed to improve the production.
According to the geological and producing conditions, two optimization methods have been formed, including the chart method and the dynamic method.
Based on cement quality and wellbore integrity of horizontal wells, 2 kinds of refracturing pipe strings including the double-packer isolation refracturing one and the single-packer isolation refracturing one have been formed. Besides, based on the initial fracturing parameters and completions, 4 refracturing modes are formed aiming to 4 scenarios including inadequately fractured stages, new fractures supplement, diverter refracturing within the fractures and multi-stage diverter refracturing, and are carried out for field tests.
(1) Small-scale initially fractured wells can be treated by the massive in-situ refracturing and 15 wells field tests are carried out. Compared with the initial fracturing, the sand amount and fracturing fluid are increased by 58% and 145% respectively and the daily oil production increases from 0.4t to 4.2t after refracturing.
(2) The wells having sparse initial fractures can be treated by refracturing to infill new fractures and 13 wells field tests are carried out. Compared with the initial fracturing, the gaps among fractures are reduced by 54.7%, and the daily oil production is increased from 1.7t to the 4.6t after refracturing.
(3) The wells with small angles formed by two directions between initial artificial fractures and wellbore can be treated by the diverter refracturing and 3 wells are treated by this to increase the production from 1.63t to 5.33t.
(4) 2 wells having not been sectionally fractured in light of their poor cement quality have been treated by the diverter refracturing within the scope of the whole wellbore, with the production increased from 1.5t to 4.5t.
In general, the daily oil production of 33 wells is averagely increased from 1.1t to 4.5t, which reaches 70.4% of the production after the initial fracturing.
After three years of technological breakthrough and field practices, a complete set of patented waterless fracturing operation technology and supporting equipment with independent intellectual property rights have been invented. Obvious oil production increase effect has been observed in multiple field tests on tight sandstone oil reservoir. In this paper, the latest development of Chinese liquid CO2 fracturing technique is introduced through a case study of typical well.
The target depth of operating well is 1730.8m-1757m, with a daily fluid production of 1.6t and oil production of 0.5t, indicating that the displacement relationship has not been effectively established. The fracturing treatment was carried out using the independently developed equipment system, which has treatment capability of available pump rates up to 12 m3/min, sand transportation of 27 m3 and CO2 injection of 1000 m3. During this operation, 860m3 liquid CO2 was injected at a displacement of 5-6m3/min. and 23m3 proppant was preloaded and totally pumped into reservoirs with maximum instantaneous proppant concentration of 12%.
After the fracturing, the daily fluid production increased from 1.9t to 3.9t, the daily oil production increased from 0.7t to 2.3t and the water cut decreased from 63.2% to 41.0%, achieving a significant increase in production. In addition, the oil pressure of one adjacent well increased from 0.5Mpa to 12.4Mpa and the daily oil production of four adjacent wells increased by 0.7-1.1t through the energy enhancement and miscibility of CO2.
The field test shows that liquid CO2 fracturing technology has a significant effects of energy storage and stimulation, adjusts the injection-production relationship effectively, and greatly enhances the single well production. It is expected to become the key technology of the development of tight sandstone oil resources.
Wang, Feng (PetroChina Jilin Oilfield Company) | Wang, Yucai (PetroChina Jilin Oilfield Company) | Zhu, Yongzhi (Oil and Gas Engineering Research Institute, PetroChina Jilin Oilfield Company) | Duan, Yongwei (Oil and Gas Engineering Research Institute, PetroChina Jilin Oilfield Company) | Chen, Shi (Oil and Gas Engineering Research Institute, PetroChina Jilin Oilfield Company) | Wang, Cuicui (Oil and Gas Engineering Research Institute, PetroChina Jilin Oilfield Company) | Zhao, Wei (Oil and Gas Engineering Research Institute, PetroChina Jilin Oilfield Company)
The low control reserve of a single well and the difficult on energy supplement in the reservoir are two key problems in tight oil reservoir development. It is testified that non-liquid CO2 fracturing not only efficiently increases the reservoir energy but also intensifies the reservoir transformation through the field test in Jinlin oil field.
The transformation volume of non-liquid CO2 fracturing is confirmed, through micro-seismic data monitor in the borehole during fracturing, that it is 2.5 times of that of normal hydraulic fracturing with the same liquid volume usage, which can remarkably increase the complexity of the fracture. Through the laboratory experiments and the oil sampling analysis after fracturing, CO2 is verified that it can reduce the oil viscosity efficiently, therefore, it can make oil miscible and enhance the flooding efficiency by non-liquid fracturing implementation. The results of reservoir static pressure test after fracturing prove that reservoir pressure remarkably increases compared with that before fracturing and has the effects of advanced energy storage.
Five tight oil wells fracturing have been successful in Jilin oil field until now. Oil production after fracturing increases obviously compared with that before fracturing. The average oil production increase per well is 2.31 ton. According to the research, the stimulation effects of non-liquid CO2 fracturing are seriously underestimated and there is wide prospect in the application of the technique during the tight oil reservoir development.
Wang, Shuai (China National Offshore Oil Corporation Research Institute) | Tian, Ji (China National Offshore Oil Corporation Research Institute) | Tan, Xianhong (China National Offshore Oil Corporation Research Institute) | Wang, Ling (E&D Research Institute of Liaohe Oilfield Company) | Zhang, Shaohui (PetroChina Research Institute of Petroleum Exploration & Development)
The low permeability reservoir development effects can be effectively improved with the use of advanced water injection technology, which means the water is injected several months before the oil production. Advanced water injection can improve the formation pressure in advance, and establish an effective displacement system. However, with the increase of reservoir permeability, the increasing value of recovery tends to decline in advanced water injection. Therefore, it is necessary to study the permeability limits of advanced water injection.
In this paper, the laboratory experiments of the low permeability natural core from A oilfield were carried out, and the changes of core permeability, pore structure and oil displacement efficiency in advanced water injection were analyzed. Meanwhile, the changes of sweep efficiency and recovery in advanced water injection were figured out with numerical simulation method, and the effect of advanced water injection tested in A oilfield was analyzed.
The results of the laboratory experiments showed that, for the cores of permeability less than 10.0 mD, as the core pressure drops from 19.0 MPa to 17.0 MPa, the permeability declines by 15.0 percentage points. When the pressure is restored, the degree of permeability recovery is 2.0 percentage points. Also, with the pressure increase, the oil displacement efficiency of the core permeability less than 10.0 mD increase 1.2 percentage points, while the oil displacement efficiency of the core permeability above 10.0 mD increase only 0.3 percentage points. The results of numerical simulation showed that, with the use of advanced water injection in the formation of permeability less than 10.0 mD, the sweep efficiency increases by more than 5.0 percentage points and the ultimate recovery increases by more than 0.4 percentage points.
In addition, the effect of advanced water injection tested in A oilfield was much better than that of the conventional water injection oilfield. The daily single well oil production was 1.6 multiple higher than that of the conventional water injection oilfield, and the annual decline rate was 13.0 percentage points lower than that of the conventional water injection oilfield.
Taken together, the permeability limits of advanced water injection is 10.0 mD, and better development effect and higher recovery can be obtained with advanced water injection technology for reservoirs of permeability less than this value.
This paper can provide a reservoir screening criteria for the advanced water injection technology and can guide the further application of this technology in low permeability reservoirs.
Production rapid decline is the major problem for the tight sandstone reservoirs in Jilin oilfield. For the particular reservoir investigated in this study, production is not only subjected to the reservoir properties, but also the well completion designs especially fracturing. A comprehensive study has been conducted for multi-stage fractured horizontal wells. New fracturing improvement strategies are presented in this paper for future operations in the studied field and also those who may have similar tight sandstone reservoirs to share.
Through the integrated studies of the petrophysical characteristics, geomechanical properties and fracturing data from the fractured wells of the tight oil reservoirs in Jilin Field, numerous fracturing modeling scenarios were compared with actual fracturing monitoring data. A fully three dimension finite element simulation, associated with the analytical result from earlier production data, and the theory of interaction between fracture clusters, were built in this study. We conducted the inversing design parameters from the multi-stage hydraulic fracture with some monitoring data to improve the understanding of the reservoir properties. Additionally, a calibrated geomechanical stress model for a completed well in this field was built. At the end, the production model was presented. Data was provided to facilitate later comparison with the actual multi-stage hydraulic fracture production and valuable lessons have learned through those iteration studies.
With thoroughly trained and well calibrated model, a new fracturing strategy has been developed for the studied tight oil field. The best NPV can be achieved with the optimal fracture conductivity, fracture geometry and well performance. But first of all, the most valuable lesson we learned is that, the Effective Propped Volume (EPV) is the dominating factor for the fractured well performance, instead of the so-called Stimulated Reservoir Volume (SRV). SRV is a misinterpreted concept yet un-calculable. By adopting a numerical simulator and a proficient technology, we developed the most suitable design (perforation, fracture spacing etc.) and the fluid system (slick water, linear gel etc.) for this reservoir so that the optimal fracture geometry and fracture conductivity can be achieved. Besides that, the fracture geometry and proppant distribution were simulated. The simulated oil production data from the finite element fracture and production software is highly matched with the recorded oil production data.
An adaptability evaluation was conducted along with this study. To ensure the relevance and the authenticity of design, we analyzed the effective factors of treating material from both the laboratory and the field data in this field. A novel fracturing fluid system was applied. The fluids are more effective and leave less damage to the formation.