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.
Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC International Limited)
In complex clastic reservoirs, deviation often exists in oil saturation derived from logging interpretation due to the borehole conditions and log quality. Especially in thin-sand reservoirs, oil saturation is generally lower than actual results because of boundary effect. An innovative approach of saturation height function coupled with rocktype is provided to improve the accuracy of saturation prediction in well logs and spatial distribution. The model results are compared with log derived results.
The new approach is based on the routine and special core analysis of over 100 core samples from the complex clastic reservoir in the north of Albert Basin in Uganda. Discrete rocktypes (DRT) are determined by flow zone index and pore throat radius which indicate the fluid flows. After converting the capillary pressure (Pc) data to reservoir conditions, Lambda curve fitting (Sw = A * PcB + C) is used to fit each capillary pressure curve. Then, a robust relationship between the fitting coefficients (A, B, C) and rock properties (i.e. porosity and permeability) is expressed as a nonlinear function for each DRT. Combined with the height above free water level, a water saturation (Sw) model is constructed by SHF within DRT model.
Using the porosity and permeability obtainedfrom routine core analysis, FZI and pore throat radius are calculated (e.g., by Winland function). Five different rocktypes (DRT1-5) are defined in the delta sand reservoir in the north of Albert Basin with distinct pore textures. The distinguishment is in accordance with the shape of capillary pressure curve, that is, the flow capability increases from DRT1 to DRT5. A strong correlation between Pc and Sw processed by Lambda curve is acquired for each core sample. Meanwhile, 3 coefficients A, B and C can be obtained in Lambda formula. By nonlinear regression, coherent relation between each factor and reservoir properties (porosity and permeability) for each DRT are obtained. Height above the free water level is estimated by geometrical modeling on the oil water contact. The Sw model is constructed by the new SHF function coupled with DRT model. It showed that the water saturation derived from SHF is highly consistent with log derived results and NMR results. Moreover, it provides more precise results in thinner sands and in spatial distribution.
Based on the identified different rocktype, a new SHF derived from capillary pressure data is utilized to establish the relationship between saturation, the height above the free water level and rock properties. The approach can significantly improve the accuracy of saturation prediction of thin reservoir and reasonably depict the spatial distribution characteristics of saturation. Furthermore, the approach will provide a more precise result in hydrocarbon volume calculation and numerical simulation.
Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.)
The Albert Basin of Uganda is located at the northern end of the western branch of the East African Rift System. It is a graben rich in oil and gas with a shallow research degree. In the south of the basin, a fan delta system controlled by the boundary fault is developed in the Miocene formation. Due to the few wells and poor quality of seismic data in this area, it is difficult to predict the spatial distribution of sedimentary reservoir sands. In this paper, sedimentary forward modeling coupled with 3D geological modeling is used to provide new ideas for reservoir prediction.
Sedimentary facies analysis is based on core description, well logs, paleontology, heavy mineral content and grain size data. Quantitative analysis of accommodation space, source supply, and sediment transport parameters can help explain the main factors that controlled the sedimentation. Milankovitch cycle method was used to establish the time scale of the basin. The simulation results were combined with 3D geological modeling to quantify the characteristics of the sand body distributions.
Sedimentary facies analysis shows that the Miocene formation in the south of Albert Basin deposited in a shallow lacustrine environment. A proximal fan delta deposition with subaqueous distributary channels was controlled by the east boundary faults. Firstly, the accommodation space was estimated according to the thickness of the stratum and the change of the ancient water depth. The source supply was estimated by the area of the project and formation thickness, and the transportation parameters were estimated according to the nonlinear transportation model based on the traction flow with a little gravity flow. Secondly, an astronomical stratigraphic framework of the Miocene strata in the south of Albert basin was established through the Milankovitch cycle stratigraphy, and it was used to restrain the process of stratigraphic forward modeling and to reproduce the sedimentary evolution process in the geological historical period. Thirdly, the stratigraphic forward modeling results were resampled into the geological model, a 3D reservoir probability distribution model is established from trend modeling to quantitatively characterize the spatial distribution of sand bodies. Finally, the sandstone distribution simulation results were transformed into quantitative control constraints for 3D geological facies modeling. Thus, the new approach significantly promotes the facies model quality and provides robust results for petrophysical property models.
Integration of stratigraphic forward modeling with 3D geological modeling can effectively solve the problem of reservoir characterization in an early stage of oilfield development through the interaction of the dual model coupling. This method has unique advantages in the reservoir research in the area with fewer data and great variation of sand.
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.
Li, Jinxiang (CNOOC Uganda Limited) | Yin, Fei (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum-Beijing) | Gao, Deli (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum-Beijing) | Yang, Zhi (CNOOC Uganda Limited) | Xiang, Ming (CNOOC Uganda Limited) | Huang, Chuanchao (CNOOC Uganda Limited)
Fault reactivation is an unfavorable incident during petroleum well drilling and production because the reactivated fault imperils the well integrity potentially. Coring and rock mechanics experiments are performed to obtain the rock properties of the fault in a Uganda oilfield. The three-dimensional finite element model of directional wells passing through reactivated faults is established. The mechanical behaviors of wells under various scenarios are analyzed by numerical simulation. The influence rules of slip displacement of fault, well inclination angle, wall thickness of casing, steel grade of casing and property of cement sheath on mechanical state of wells through faults are revealed. Research results indicate that decreasing the intersection angle between directional well and fault plane and employing cement sheath with low elastic modulus can enhance well integrity effectively. The research achievements provide the integrity assessment method and mitigation measures for the directional wells through reactivated faults.
A vast body of conventional source rock analyses show that the Kimmeridge Clay Formation of the UK ( Draupne or Mandal formations of Norway and Farsund Formation of Denmark) contains large volumes of residual (i.e. unexpelled) oil where buried below about 3.2km. Free oil yields from both Rock-Eval pyrolysis and solvent extraction average at ~6 kg liquids/tonne rock with a range from 3 – 9 kg/tonne. Unlike most onshore basins where the source rocks are uplifted and hence generation has ceased, the North Sea, with rapid Tertiary-Recent sedimentation, offers the opportunity to drill directly into an actively generating world class oil-prone source rock. Prior knowledge locates sweet spots by selecting optimum maturity, thickness, organic richness and sedimentary facies (lithology) The pyrolysis and extract data quoted above equate to an average 140 bbls/acre.ft with a range of 70-210 bbls/acre.ft), the challenge being to extract it economically.
Fan, Junjia (Research Institute of Petroleum Exploration and Development and Peking University) | Zhou, Haimin (Peking University) | Liu, Shobo (Peking University) | Liu, Keyu (CSIRO Earth Science and Resource Engineering)
Tight sandstone gas as one kind of unconventional resources has taken up a significant part in natural gas resource growth in recent years. Tight sandstone gas originated from the definition of U.S. Gas Policy Act of 1978, that regulated in-situ gas permeability to be equal to or less than 0.1 md for the reservoir to qualify as a tight gas formation Gas flow in tight sandstone behaves as non-Darcy flow has been reached a consensus by scholars; however gas-water flow characterization and the main factors for gas-water flow in tight sandstone remain complicated. Scholars proposed that there is a "Permeability Jail?? for water-gas flowing in tight sandstone reservoirs which means both water and gas cannot flow in "Permeability Jail?? range. This may explain why neither gas nor water produced in tight sandstone reservoir in wells of some tight gas field.
In order to get a better understanding on water-gas flow characteristics and to figure out the major affecting factors for gas-water migration in tight sandstone, we analyses pore structure, bulk and clay mineral constitutes and gas-water two phases flow characteristics of five tight sandstone samples with low permeability (<0.1md) and low porosity from the tight gas fields in Kuqa Depression, Tarim Basin by using of micro CT scanning, XRD analysis and physical simulation experiments.
Experimental results indicate that 1) "Permeability Jail?? does not existed in five tight sandstone samples, but flow ranges for gas-water of five samples are different; 2) pore structures and fractures play significant roles for the gas-water flowing, and fractures can improve the gas-water permeability significantly; 3) for permeability, the pore connectivity is more important than total porosity of rocks; 4) content of clay minerals in tight sandstones affected the gas-water migration, the higher the clay minerals contents are, the lower the permeability of rocks is.