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.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Zhang, Ming (Research Institute of Petroleum Exploration and Development of Petrochina) | Viljoen, Robin (Arrow Energy Pty Ltd) | Zhang, Wenqi (Research Institute of Petroleum Exploration and Development of Petrochina) | Jeffries, Max (Arrow Energy Pty Ltd) | Beaney, Simon (Arrow Energy Pty Ltd) | Chen, Wei (Arrow Energy Pty Ltd) | Wang, Quan (Arrow Energy Pty Ltd)
The study focused on the Permian aged Rangal coal measures within a 3D seismic volume in middle of Bowen basin. The Rangal Coal Measures (RCM) are a middle-rank coal seam gas (CSG) target with low permeability. Approximately 150 to 200 wells, with geophysical log data, are unevenly distributed in the seismic area of 51 km2. The effect of stress and related geomechanics on producing wells has been poorly understood. Petrophysical data, 3D seismic cube, geographic information system (GIS), borehole imager and well stress data were used to conduct the interpretative workflow. A novel four-step workflow was created to provide geomechanical insights in order to optimize future well designs for improved productivity and well integrity.
The first step in the workflow was to finely delineate fracture distribution by using coherence and max curvature methods in the seismic volume. This was followed by determining the most appropriate number of coal-sensitive attributes using step-wise regression methods. The multi-attribute emerged density inversion was conducted utilizing probabilistic neural network training and predicting, which was derived from the density cube and predicted coal thickness map. The resulting density cubes included the overburden zone which was calculated by well data interpolation in consideration of GIS overlays. This was followed by 2D stress simulation that was created by analyzing a combination of maximum/ minimum stress, principal stress, Young's Modulus, and Possion's ratio in measured well data. Inputs such as fracture networks, coal thickness, density and velocity cubes were combined to process the simulation using designed fracture reservoir characterization software (FRS). The workflow was completed by using GeoPressure Analysis (GPA) software and data such as: stress, density and the velocity cubes to calculate the overburden pressure (Pov) and pore pressure (Pp). The overburden pressure was computed by integrating the density volume. The pore pressure volume was analyzed using the Fillippone formula. Vertical effective stress (VES) and the pore pressure coefficient were calculated using the principles of rock theory. The minimum / maximum horizontal principal stress (SHmin / SHmax) were calculated by utilizing the Zoback and Healy formulas and using the following input data: calculated Pp, Pov, measured effective stress ratio of the minimum/maximum horizontal principal stress and measured horizontal stress.
Direct measured properties from geophysical logs such as principal stress showed good correlation with adjacent extracted values from the modeled principal stress. The well production properties indicated good correlation with geomechanical properties such as small fractures and stress. Single well average peak gas production and average peak gas production both decreased with the diversity factor of horizontal stress (DHSR) which was extrapolated from SHmax and SHmin.
The originality of this study lies in the comprehensive integration of geological, geophysical and petrophysical data to create a functional geomechanical model. The results indicate that this geomechanical study will be useful for well planning and predicting production properties in each future study area.
Accurate calculation of reservoir porosity is the key to geological interpretation and petroleum exploration decision. Porosity is influenced by various geological factors such as buried depth, tectonic position, sedimentary environment, lithologic change and diagenesis. How to make full use of multi logging information for comprehensive analysis and calculate the porosity is of great significance for reducing the risk of oil and gas exploration and development. From the point of view of petrophysics, reservoir porosity and logging data are typical nonlinear relations. Deep learning technology can automatically extract high-dimensional nonlinear features from data, then solve complex nonlinear problems through feature transformation. We propose a method for porosity prediction based on deep learning technology, the nonlinear relationship between multiple logging parameters and porosity is established with compensated neutron, acoustic time difference, natural gamma and compensation density well logs. The application results in real data indicate the effectiveness and practicability of porosity prediction using deep learning technology.
Presentation Date: Wednesday, October 17, 2018
Start Time: 9:20:00 AM
Location: Poster Station 9
Presentation Type: Poster
Zhou, Haigen (College of Instrumentation and Electrical Engineering, Jilin University) | Zhang, Ming (College of Instrumentation and Electrical Engineering, Jilin University) | Liu, Changsheng (College of Instrumentation and Electrical Engineering, Jilin University) | Lin, Jun (College of Instrumentation and Electrical Engineering, Jilin University) | Kang, Lili (College of Instrumentation and Electrical Engineering, Jilin University)
Summary: F requency-domain ground -air borne electromagnetic method has the potential and advantages of rapid detection in large - area with a deep investigation depth. However, due to the limitations of source excitation method, data processing and interpretation methods, traditional scalar -resistivi ty mode in the frequency-domain ground -airborne electromagnetic method can't meet the requirements of high-precision and rapid imaging. Therefore, we propose d a new tensor-tipper real induction vector divergence detection method to improve the detection pr ecision of 3D target with two orthogonal artificial sources. The purpose of our study was to show the feasibility of tipper real induction vector divergence parameter for 3D target detection and its advantages by comparing with the traditional scalar-resistivity detection method with a single source. Introduction Ground -air borne electromagnetic method, also called semi-airborne electromagnetic method in some literatures, is the fusion of ground electromagnetic method and airborne electromagnetic method (Li et al .
Deng, Jianming (China National Offshore Company Tianjin) | Ma, Yingwen (China National Offshore Company Tianjin) | Zhang, Ming (China National Offshore Company Tianjin) | Qian, Jiacheng (Halliburton) | Fang, Chao (Halliburton) | Wang, Qiang (Formerly Halliburton) | Wang, Xiaobo (Formerly Halliburton)
This paper details the process of designing and executing a frac pack operation in a previously gravel-packed formation. Challenges and solutions are discussed as well as the methods used to properly squeeze fluid and proppant into the formation.
During the last 13 years in China, a single-trip multizone (STMZ) gravel-packing system has been widely used in Bohai Bay for sand control. Most of the wells were initially completed using high-rate water packing methods and then were sidetracked once production reduced to a certain level. However, operators desired a lower-cost work over plan. The proposed method involved recompleting a previous well by running service tools into the well to perform fracture packing within the existing multizone gravel-pack completion. High-viscosity fluid was pumped into the formation as a prepad, and then formation fracture packing was performed.
The successful treatment execution presented in this paper demonstrates the process of cleaning the wellbore for recompletion. Using the STMZ system proved the downhole service tool could be safely tripped back in and out of hole in the same trip following fracture packing of a previously gravel-packed multizone well completion. The method also shows that, through careful preplanning and designing of the tool and treatment, the risk of failure caused by a stuck tool string, unwanted fluid loss, or premature screenout can be minimized. The job execution and lessons learned along the way can also provide a guideline for improvement of future treatments in similar situations.
This paper presents the first successful fracture packing application in a previously gravel-packed well. The method presented provides a new method to enhance production of mature wells without performing a sidetrack, significantly reducing costs by recompleting the well.
Gas hydrate has been found both in the permafrost and deep ocean in China. However, due to easier access, much lower well cost and proximity to existing gas pipelines, gas hydrate in the permafrost is more attractive for commercial development. In this paper we examine the published data on gas hydrate exploration in various Chinese permafrosts, identify the key technical challenges and suggest directions for future study.
Our study has identified Qilian Mountain Permafrost, Mohe Basin and Qinghai-Tibetan Plateau as the three permafrosts with highest potential for gas hydrate development. Of the three, only Qilian has confirmed occurrence of gas hydrate by coring. From the perspective of field operations, Qilian ranks highest in potential for development due to its proven hydrate occurrence, thickness of hydrate bearing layer and proximity to existing gas pipelines. Mohe ranks second due to its benign operating conditions. However, it lacks existing gas pipelines. Qinghai-Tibetan Plateau ranks third due to its high elevation which limits access and lack of oilfield infrastructure.
We found that the key subsurface uncertainty is the gas hydrate saturation. There is little information on it for all three permafrosts. Other subsurface uncertainties include the thickness of the permafrost, geothermal gradient beneath the permafrost, porosity, gas hydrate composition and permeability of the hydrate-bearing layer. Future research needs to determine these reservoir properties accurately.
Examination of core samples and logs from Qilian shows that gas hydrate distribution is discontinuous both vertically and areally. Therefore, a better way to quantify the uneven hydrate distribution in the reservoir is needed for reservoir engineering calculations.
Current estimates of well production rate by reservoir simulation are sub-commerical and probably due to the assumption of pure methane hydrate which limits the thickness of the gas hydrate stability zone. Also, the assumption of using horizontal wells for hydrate production may be optimistic due to shallow depths and the discontinuous nature of hydrate distribution. Consequently, new recovery methods besides depressurization and thermal stimulation will be needed to increase the well production rate.
Furthermore, we have identified a number of similarities in production engineering aspects of gas production from hydrate and coalbed methane (CBM) wells. Common challenges include reservoir depressurization by water production, solids production, need for artificial lift and difficulty in drilling long horizontal wells in shallow reservoirs. Therefore, some best practices from CBM production, such as pad drilling, artificial lift and water treatment methods, may be usable for gas hydrate production.
Per recent analyses, in the near future, over half amount of the oil extracted globally, will require some form of enhanced oil recovery (EOR) techniques. Existing literature and historical investigations suggest that in oil reservoirs having viscosities between 10 – 150 m.Pa.s, there is a significant potential for tertiary recovery through the application of polymer flooding. For reservoir oil viscosities above 150 mPa.s, the polymer pumping efficiency goes down as polymer injectivity reduces significantly with increasing injection water viscosity that are used to attain a favorable mobility ratio at such high oil viscosities. To overcome this limiting factor, in this study, we propose the use of supramolecular assemblies (SMA) that have adjustable viscosity properties. Complexation of long-chain amino-amides and maleic acid is used to make these assemblies, which allow it to have reversible viscosity depending on the solution pH level.
To maintain high injection efficiency, during pumping, SMA solutions will be kept at low viscosity values. On entry in deep reservoir or at oil contact phase, through introduction of an external stimulus the viscosity of SMA solution will be reversed to a much higher viscosity. This will allow to sufficiently improve the mobility ratio. Preliminary results from lab-scale studies have indicated that along with reversibly adjustable viscosity property, SMA solutions are also tolerant to high temperatures and salt concentrations.
Supramolecular solutions can be considered as healable polymer systems, since unlike conventional polymer they disassemble and re-assemble when exposed to high temperature and stress conditions. In such conditions, conventional polymers generally undergo degradation. Additionally, through molecular scission processes SMA solutions can also be used in highly confining environments as well as in permafrost conditions and thin zones where conventional thermal techniques are not applicable.
The objective of this work is the development of novel SMA system that have the aforementioned properties of reversibly adjustable viscosity through pH, tolerance to high temperature and salt concentrations through desired interfacial properties. Lab-scale preliminary results have shown the potential economic benefits of the use of SMA solutions on a field-wide scale. Based on the results, it must be emphasized that SMA systems have a worldwide application in oil reservoirs for EOR purposes.
Zhang, Ming (Research Institute of Petroleum Exploration and Development) | Thomas, Gan (Arrow Energy Pty Ltd) | Yang, Yong (Research Institute of Petroleum Exploration and Development) | Stephan, Tony (Arrow Energy Pty Ltd) | Sibgatulin, Artem (Arrow Energy Pty Ltd) | Mazumder, Saikat (Arrow Energy Pty Ltd) | Chen, Wei (Arrow Energy Pty Ltd)
Coalbed methane (CBM) geology dominance in Surat basin is a coal-based fluvial depositional system. For CBM subsurface modelling, it is still primarily driven by simple deterministic static model and building on the understanding of long extends of coal continuity in lateral distribution. In reality, coal seams (or plies) tend to split or merge laterally across a large distance of few kilometers. Hence, the extend flow contribution or net coal distributions are not homogenous and can changed quite significantly, which we believe using a proper calibrated facies model will be able to predict such behaviors for both coals and its boundary lithology. In our facies modelling work, the coal swamp and shaly swamps depositions are primarily targets for CBM reservoirs and other facies in juxtaposition to them will also influence the lateral continuation of the coal swamp, the heterogeneity of swamp distribution and gas drainage.
This paper summarized four-step procedures to address swamp-based fluvial depositional facies modelling for an integrated approach to identify micro-facies, upscale the coal continuity and sand body, model the lithofacies and estimate the different potential flow patterns based on the multi-realization. This study involved the investigation of a region of 24,000 km2 and the log normalization on the available logs for a quantitative lithofacies interpretation firstly. Then the division of the fining-up sequence cycles, individual ply formation and the boundaries of top of sandstone (together 80,000 tops) have been carefully conducted to derive the variograms and 2D distributions of channels for the description of the coal flow drainage extension. The study focused on the creation of the fluvial facies and five micro-facies of channels, flooding plains, lacustrine, swamp and shaly swamp with geometry parameters, such as the coal thickness, percentage and the channels width, orientation, amplitude, wavelength from the generated 2D maps. The coals continuity and sand body were also thoroughly investigated and upscaled. After structure modeling, the team conducted three-order object facies modeling in reasonable stochastic modelling of fluvial system to descript 3D continuity of the flow patterns of coal swamp. Finally, the coal volume calculation of P10, P50 and P90 has been obtained through the multi-realization of property modeling, which was based on the facies modeling.
The study combines the knowledge of both conventional and unconventional reservoir modelling techniques and the work will be used for better reservoir simulation, as well as basin wide field development planning. In this study, the project team investigated ~1200 wells with geophysical logs, >50 wells with core data, conducted ply formation picking (~40,000 tops) and stochastic static modelling, which successfully correlated and outlined the statistics of sand geometry and ply lengths (areas) to build the concept of fluvial depositional system.
The integrated facies modelling workflow is a novel approach in CBM industry to better understand the coal heterogeneity both lateral continuation and vertical distributions. The geo-statistics outcome will provide multi-realizations for coal and gas production predictions.
Temizel, Cenk (Area Energy) | Zhang, Ming (University of Kansas) | Biopharm, Frontida (University of Kansas) | Jia, Bao (University of Kansas) | Putra, Dike (Energy Rafflesia) | Moreno, Raul (Consultant) | Al-Otaibi, Basel (Kuwait Oil Co.) | Alkouh, Ahmad (Middle East Oilfield Services)
Per recent analyses, in the near future, over half amount of the oil extracted globally will require some form of enhanced oil recovery (EOR) technique. Existing literature and historical investigations suggest that in oil reservoirs having viscosities between 10 — 150 m. Pa.s, there is a substantial prospective for tertiary recovery through the implementation of polymer flooding. For reservoir oil viscosities above 150 mPa.s, the polymer pumping efficiency goes down as polymer injectivity reduces significantly with increasing injection water viscosity that is used to attain a favorable mobility ratio at such high oil viscosities. To overcome this limiting factor, in this study, we propose the use of supramolecular assemblies (SMA) that have adjustable viscosity properties. Complex long-chain amino-amides and maleic acid are used to make these assemblies, which allow it to have reversible viscosity depending on the solution pH level.
To maintain high injection efficiency, during pumping, SMA solutions will be kept at low viscosity values. On entry in deep reservoir or at oil contact phase, through introduction of an external stimulus, the viscosity of SMA solution will be reversed to a much higher viscosity. This will allow to sufficiently improve the mobility ratio. Preliminary results from lab-scale studies have indicated that along with reversibly adjustable viscosity property, SMA solutions are also tolerant to high temperatures and salt concentrations.
Supramolecular solutions can be contemplated as remedy polymer systems, since unlike conventional polymers they disassemble and re-assemble when exposed to high temperature and stress conditions. In such conditions, conventional polymers generally undergo degradation. Additionally, through molecular scission processes SMA solutions can also be used in highly confining environments as well as in permafrost conditions and thin zones where conventional thermal techniques are not applicable.
The objective of this work is the development of a novel SMA system that has the aforementioned properties of reversibly adjustable viscosity through pH, tolerance to high temperature and salt concentrations through desired interfacial properties. Lab-scale preliminary results have shown the potential economic benefits of the use of SMA solutions on a field-wide scale. Based on the results, it must be emphasized that SMA systems have a worldwide application in oil reservoirs for EOR purposes.