Day 2 Wed, March 27, 2019最新文献

{"title":"Maximizing Production from Shale Reservoir by Using Micro-Sized Proppants","authors":"H. Lau, A. Radhamani, S. Ramakrishna","doi":"10.2523/IPTC-19437-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19437-MS","url":null,"abstract":"\u0000 This paper describes the interaction between hydraulic fractures and the multi-porosity system of matrix porosity and natural fracture porosity in shale reservoirs. During the process of hydraulic fracturing, a complex fracture network consisting of primary and secondary hydraulic fractures as well as natural fractures is created. It is postulated that only shale porosities connected with this network will contribute to hydrocarbon production. Furthermore, we propose a way to maximise well productivity by injecting micro-sized proppants that are less than 150 μm (100 mesh) into the natural fractures and secondary hydraulic fractures to prevent them from closing and thereby increasing the stimulated reservoir volume. The size of the micro-sized proppant should be designed to be between one-seventh and one-third the aperture size of the natural fractures. In addition, various materials for micro-sized proppants are proposed and discussed. Of these, hollow glass microsphere shows more promise because of its light density and track record of being used as an additive material in the oilfield. Although limited laboratory experiments and field tests have shown encouraging results of using micro-sized proppants to enhance the productivity of Barnett shale, more research is warranted to optimize the use of these micro-sized proppants in production enhancement in various shale formations.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"108 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114349598","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Oil Detection Based on Layer Buried-Depth Corrected Elastic Inversion in Deepwater of the Pearl River Basin","authors":"Xumin Liu, Zhaoming Chen, Hao Liu, Wenzhu Zhang","doi":"10.2523/IPTC-19157-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19157-MS","url":null,"abstract":"\u0000 Because of the high drilling expense and fewer wells having been drilled in Deepwater of the Pearl River Basin, the complexity and difficulty of oil and gas exploration in this area always restrict our development procedure. In order to overcome these problems in oil and gas exploration, this paper will propose a comprehensive and feasiable approach, which makes full use of both well logging data and seisimic data and combine techniques of rock physical modelling and seismic pre-stack inversion. Such a well-orgnised technical system searching is conducive to reduce exploration risk and promote success rate of hydrocarbon discovery. To illustrate the overall implementation procedure, a case study is applied and composed by 3 corresponding aspects: (1) based on well elastic parameters analysis, LamdaRho (Lame coefficient* Density) is inferred as the sensitive parameter of reservoir and hydrocarbon; (2) With the help of rock physic modeling and fluid substitution, we confirm that LMR is the most sensitive hydrocarbon parameter, and the LMR response varies from substituted fluid type;(3) Considering the difference of layer's buried-depth between evaluated structure and drilled wells, a buried depth correction is applied to eliminate its caused uncertainty of hydrocarbon predition.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128065678","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Multi-Scale Approach for Damage Control in Ultra-Deep Tight Sandstone Gas Reservoirs Based on the Multi-Scale Formation Damage Mechanisms","authors":"Dujie Zhang, Yili Kang, Lijun You, Xiangchen Li, Jiaxue Li, Yashu Chen","doi":"10.2523/IPTC-19254-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19254-MS","url":null,"abstract":"\u0000 Cretaceous Bashijiqike ultra-deep tight sandstone, the main pay zone of Keshen gas field in Tarim Basin, has characteristics such as huge buried depth (6500 m ~ 8000 m), ultra-low matrix permeability and well-developed natural fractures. Due to lacking of a thorough research on the formation damage mechanism, there is no corresponding formation damage control method. And that's why this reservoir is suffering from severe formation damage. In this paper, the multi-scale characteristic of the reservoir space and seepage channel was described firstly. Then, a series of experiments were carried out to determine the multi-scale damage mechanisms, including the fluid sensitivity damage of matrix and fracture, the phase trapping damage of matrix and fracture, the loading capacity and the dynamic damage of fracture induced by drilling fluids. Then, the multi-scale formation damage mechanisms were summarized. Results showed the gas reservoir are characterized by typical multi-scale structures, i.e. micro-nano pore-throat and multiscale natural fractures. Severe salt sensitivity damage, alkali sensitivity damage and water phase trapping damage were the main damage mechanism of micro-nano pore-throat. For micro-fracture (aperture ≤ 100 μm), the dynamic damage degree induced by drilling fluids can reach up to 60.01 %. For Mesoscale fracture (aperture > 100 μm), lost circulation induced by inadequate loading capacity of drilling fluids was the main damage mechanism. Then, a complete multi-scale approach for damage control was proposed: ① Using oil-based drilling fluids to inhibit the fluids sensitivity damage and phase trapping damage of micro-nano pore-throat and natural microfracture; ②Optimizing the solid particle size distribution of drill-in fluid to reduce the dynamic damage degree of micro-fracture induced by drilling fluids; ③Adding acid soluble temporary plugging materials while drilling to prevent lost circulation. According to the proposed approach, the total production of the test well was 94 × 104 m3, which is much higher than that of non-test wells. This research provides a detailed case of forming the multi-scale approach for damage control based on the multi-scale formation damage mechanisms. This method is practical and useful, and it has important guiding significance to develop the ultra-deep fractured tight gas reservoirs efficiently.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127033373","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimizing Hardware & Workflow to Maximize Formation Fluid Scanning & Sampling While Drilling Success in Unconsolidated Formations","authors":"I. D. Santo, M. Turner, Yon Blanco, Scott Paul, S. Haq, V. Agarwal","doi":"10.2523/IPTC-19131-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19131-MS","url":null,"abstract":"\u0000 This paper presents a novel methodology to successfully maximize sampling and scanning of formation fluids using formation mapping-while-drilling (FMWD) technology in real time when drilling poorly consolidated formations. The methodology, based on a solid workflow built on experience garnered and captured in various operations and geomechanical studies performed around the world, can be applied in a wide range of wellbore geometries and formation types.\u0000 The methodology is based on four processes: 1. Predict, assess, and confirm potential fines migration and formation collapse during FMWD operations. The analysis is based on processing and interpreting existing geomechanical properties from offset wells and real-time newly acquired sonic and/or density data. 2. Design FMWD operations such that formation sanding is prevented, and formation integrity is maintained. 3. Prevent mobilized fines from entering the FMWD tool if partial formation collapsing occurs. 4. Focus the workflow on reducing the negative impact solids will have on the flowline, pump out, and optical analyzers if fines enter the tool.\u0000 The paper contains two case studies in which the methodology workflow resulted in successful sampling and real-time downhole fluid analysis of formations with very limited diagenesis and a history of sanding and collapsing during formation testing-while-drilling operations. These two case studies show how assessing offset wells during the planning phase and applying this workflow while evaluating logging while drilling (LWD) petrophysical data in real-time provide a quick insight into how a formation will respond during pump out. The results define station depth selection, timing of the operation with respect to wellbore exposure time, and pump out rate strategy. The application of fixed-rate pump out or intelligent pump out with a fixed differential can then be applied based on the real-time indicators. Specific screen sizes are selected in advance, which limit ingress of fines into the sampling tool. In both case studies, the operating company's objectives were met. An additional case study is presented in which the risk of sanding was not perceived, and no qualification of un-consolidation had taken place, ultimately resulting in formation breakdown in the sampling phase, mobilization of fines, and plugging of the tool; thus, highlighting the value of the novel methodology.\u0000 The innovation of this workflow is its holistic approach to sampling while drilling in unconsolidated formations, extensively covering both job planning and execution phases. Additionally, the workflow allows for optimizing tool configuration, and by risk identification, suggests a variety of measures to eliminate or mitigate the impact of partial formation collapse. This workflow extends the application of fluid mapping and sampling while drilling into operational environments, which were previously considered highly unsuitable for this technology.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124360455","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Innovative Reservoir Classification with Natural Fracture Geometry to Guide Well Stimulation for Unconventional Tight Gas Field","authors":"Jianhua Xu, Junpeng Yue, Hao Wang, B. Wygrala","doi":"10.2523/IPTC-19282-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19282-MS","url":null,"abstract":"\u0000 The Kenshen tight gas field, located on the northern margin of the Tarim basin, western China, has extreme reservoir conditions of an ultra_depth reservoir (6500 to 8000 m) with low porosity (2 to7%), low matrix permeability (0.001 to 0.5 md), high temperature (170 to 190°C), and high pore pressure (110-120 MPa). Those conditions result in high completion costs and a significant difference in individual well production rates; with only one-third of wells drilled meets expectations. Previous studies focused on natural fracture(NF) and attempted to classify reservoir qualities based on the density of NF. Unfortunately, some NFs were closed or cemented by clay or calcite, and it is hard to distinguish open NF from closed NFs using well images in oil-based mud, which is widely used in this tight gas field for reservoir protection. Thereby, no positive correlation between NFs density and productions has been identified, even with the same stimulation treatment.\u0000 In this study, a comprehensive geological study was conducted to find a new way of characterizing the effectiveness of NF. First, the initial and development stages of NFs were recontructed through a tectonic activity study. Two stages were detected and showed different strikes. Second, petroleum system modeling technology was applied to simulate source rock maturation and gas migration, which revealed that gas generated in the Jurassic source rock migrated to the Cretaceous reservoir formation through faults activated in the same period as the late stage of NFs development. NFs developed earlier were closed or cemented by calcite of later deposition; those at late stage were open and effective for gas charge. Also in this study, Advanced analyses of borehole images indicated an alternative way to delineate NFs developed at different stages using geometry (i.e, crossed NFs shall include those ones developed at later stage). Parallel NFs with its development unidentified can be classified through the intersection angle of fracture strike and maximum stress direction. The smaller the intersection angle is, the easier it is for stimulation and alos the higher for the well production. Based on this study, we have divided reservoirs in the study area into three classes: class 1, reservoir with crossed NFs; class 2, reservoir with fractures of small intersection angle; class 3, reservoir with fractures of large intersection angle. This innovative reservoir classification through NF geometry is currently used in the field to determine formation stimulation method. Class 1 reservoir can benefit from acidizing alone with low completion cost. Class 2 reservoir of should be hydraulically fractured with acid. Class 3 reservoir of should be fractured with sand and proppant sand to achieve economical production.\u0000 Reservoir classification with NFs geometry had been applied successfully to guide stimulation design in the Keshen tight gas reservoirs. It is a practical and feasible way to choose the most appr","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122808804","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated Detection of Water Production in a Highly Heterogeneous and Tight Formation Using CRM Model: A Case Study on Water Flooding Gaither Draw Unit, Wyoming, USA","authors":"Kailei Liu, Xingru Wu, Kegang Ling","doi":"10.2523/IPTC-19333-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19333-MS","url":null,"abstract":"\u0000 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.\u0000 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.\u0000 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.\u0000 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.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131849307","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of Sandstone Stimulation using Thermochemical Fluid Through Distributed Temperature Sensing and CT Real-Time Downhole Flow Measurement Tool","authors":"A. Al-Nakhli, M. Bataweel, Mohammed Arifin, D. Ahmed","doi":"10.2523/IPTC-19359-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19359-MS","url":null,"abstract":"\u0000 Distributed Temperature Sensing (DTS) was used to evaluate a novel sandstone stimulation treatment based on exothermic reaction. The technology is based on injecting in-situ heat generating fluid (IHGF) that generate in-situ heat i.e., ~>400F and nitrogen pressure to mobilize and remove near well bore damage in sandstone formations. Distributed temperature sensing (DTS) in real-time was used for fluid placement, treatment optimization and evaluation. Coiled Tubing (CT) real-time downhole flow measurement tool was used to conduct injection profiling before and after pumping the IHGF.\u0000 Application of exothermic reaction downhole is very challenging as generated pressure can exceed will head pressure, and generated heat can exceed well completion rating. To have advanced assessment of the technology, generated temperature and pressure increase was captured in real-time with distributed temperature sensing (DTS) coiled tubing telemetry. Hence, CT with fiber optic real-time telemetry was used to pump the IHGF in two injection wells to increase their injectivity. These real-time measurements provided the benefits of recording DTS and enabled recording the injection profile through its real-time downhole flow measurement tool.\u0000 DTS and the CT real-time downhole flow measurement tool was used to acquire initial and post-treatment injection profiling of two water injection wells. The results were used in conjunction to optimize the IHGF placement. DTS was also conducted during and after pumping the IHGF to understand the heat generation in real-time and optimizing the treatment as needed. After the treatment, the injection profiling was conducted to evaluate the treatment.\u0000 The paper describe the application of CT with fiber optic real-time telemetry for unique treatment involving exothermic reaction for sandstone stimulation. The successful treatment will positively impact sandstone stimulation in oil and gas industry. Results will enlighten the heat generation through IHGF resulted in removing the nearby well damage, followed by increase in injectivity and the effect of real-time measurements have in better treatment execution and evaluation.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130499680","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geomechanical Anisotropic Method Increased Fracturing Efficiency in Tight Oil Production: A Case Study of Yanchang Formation, Ordos Basin","authors":"Sheng-li Xi, Y. Hou, Xianwen Li, Xifeng Hu, Peng Liu, Xianran Zhao","doi":"10.2523/IPTC-19110-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19110-MS","url":null,"abstract":"\u0000 The Triassic Yanchang formation is rich in tight oil resource at Ordos Basin. The oil sandstone and oil shale of Chang 7 member are widely spread in the basin and have huge potential in oil production. Due to low porosity and low permeability, producing oil from tight oil reservoir depends on hydraulic fracturing. A successful hydraulic fracture requires accurate estimations of horizontal stresses and rock elastic properties in design and operation.\u0000 Chang 7-2 is shale and sandstone interbed reservoir and Chang 7-3 is shale oil reservoir with lamination sedimentary structure. The rocks with lamination structure are very anisotropic, and it needs to be considered in computation of horizontal stresses and rock elastic properties.\u0000 In this paper, we present a case study to illustrate the advantages of anisotropic geomechanics model. Anisotropic horizontal stresses and rock elastic properties were calculated and used in hydraulic fracturing design. The perforation intervals were selected at depths with low stress magnitude based on stress profile. The perforations efficiency was analyzed, and perforation interval with low efficiency was removed. Major stimulation operation parameters, total volume, proppant volume and slurry rate, were optimized with anisotropic geomechanics model. Fracturing operation results showed that the total volume was decreased by 16.5%, proppant pumped increased by 11.4% and daily oil production increased by 73.7%. This case study demonstrated that anisotropic geomechanics model help to improve operation efficiency and increase oil production.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114959453","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fluid Discrimination Using Bulk Modulus and Neural Network","authors":"Changcheng Liu, D. Ghosh, A. Salim, W. S. Chow","doi":"10.2523/IPTC-19317-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19317-MS","url":null,"abstract":"\u0000 Hydrocarbon prediction using the rock physical parameters is a common technique in the oil and gas industry. However, the rock physical parameters are controlled by porosity, the volume of clay, pore-filled fluid type and lithology simultaneously. Many methods are proposed to predict the existence of hydrocarbon. This paper proposes a new method ΔK which is the difference between the real bulk modulus and the bulk modulus in the brine- substitute case. The algorithm is validated through stochastic numerical modelling. The brines are separated by the ΔK, and the gas can be detected with acceptable accuracy. Furthermore, a model using deep learning approach is trained to predict the ΔK. The trained model is effective that the predicted values using this model have a strong correlation with the original ΔK. The ΔK can be applied to the data which contains Vp, Vs and density using this approach model. In this study, the ΔK is applied to the Marmousi II dataset to examine the performance and yields a good result. The combination of the deep learning and the ΔK improves our ability in hydrocarbon prediction.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114990530","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Potential and Risk Analysis of Offshore Fractured Light Reservoir","authors":"Hongfu Shi, Baolin Yue, Xianbo Luo, Fei Shi, Bo Xiao","doi":"10.2523/IPTC-19083-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19083-MS","url":null,"abstract":"\u0000 The exploration and development of offshore oilfield facing unprecedented challenges include the decline in the quality of oil reserves, increase of invest and strict environmental protection policies. Usually, low permeability reservoir, heavy oil reservoir complex fault block and small reservoir located far from an existing facility are classified into marginal oilfield. More and more marginal oilfield is put on the schedule of development. In the view of economic, The internal rate of marginal oilfield return is lower than the benchmark rate of return of the industry, but higher than the cost discount rate of the industry. An integrated work flow is presented to improve the tap the potential and mitigate the risk of marginal oilfield involved in dependent development of small oilfields, unit exploitation of small oilfield group, simple platform, extended reach well and phased development. The LD oil field is taken as an example to state the strategy of marginal oilfield.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133651739","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}