The saturation history dependent relative permeability (kr) data have been reported frequently in the laboratory investigations. Accurate estimation of kr data with hysteresis effects is crucial, specifically in Water Alternating Gas (WAG) injection which involves a sequence of drainage and imbibition cycles. Although there are a few methods to model the hysteresis effects in three-phase systems, the predicted values are still not adequate to simulate the hysteresis observed in experiments. In this study, a generalized three-phase hysteresis model was developed to simulate the observed hysteresis in the WAG experiments performed at Heriot-Watt University. It is discussed that the use of Land trapping coefficient in the hysteresis models is doubtful since it originates from the observed behaviour in two-phase systems which reach residual saturations. Hence, the new hysteresis model is developed based on innovative techniques to predict the oil and water saturation at the end of each injection cycle. Moreover, in the developed model, the formulations for estimation of hysteresis in water and gas kr data are updated to capture the observed behaviors in WAG experiments. The suggested hysteresis model was evaluated by comparing the simulation results with the available experimental data. The results showed that the developed model is able to simulate oil, water and gas production more accurately. Based on the results, the model can simulate the pressure behaviours observed in the experiments with dominated hysteresis. In addition, the developed model can predict the oil, water and gas saturations at the end of each cycle with higher accuracy compared to the available methods in the literature. The significant impacts of the hysteresis phenomenon on designing the best WAG injection scenario require a reliable hysteresis model for performing accurate reservoir simulations. The use of the suggested model elevates the accuracy of any feasibility analysis performed to evaluate the WAG injection scenario.
{"title":"Accurate Modeling of Relative Permeability Hysteresis in Water Alternating Gas Experiments","authors":"S. Aghabozorgi, M. Sohrabi","doi":"10.2118/197615-ms","DOIUrl":"https://doi.org/10.2118/197615-ms","url":null,"abstract":"\u0000 The saturation history dependent relative permeability (kr) data have been reported frequently in the laboratory investigations. Accurate estimation of kr data with hysteresis effects is crucial, specifically in Water Alternating Gas (WAG) injection which involves a sequence of drainage and imbibition cycles. Although there are a few methods to model the hysteresis effects in three-phase systems, the predicted values are still not adequate to simulate the hysteresis observed in experiments.\u0000 In this study, a generalized three-phase hysteresis model was developed to simulate the observed hysteresis in the WAG experiments performed at Heriot-Watt University. It is discussed that the use of Land trapping coefficient in the hysteresis models is doubtful since it originates from the observed behaviour in two-phase systems which reach residual saturations. Hence, the new hysteresis model is developed based on innovative techniques to predict the oil and water saturation at the end of each injection cycle. Moreover, in the developed model, the formulations for estimation of hysteresis in water and gas kr data are updated to capture the observed behaviors in WAG experiments.\u0000 The suggested hysteresis model was evaluated by comparing the simulation results with the available experimental data. The results showed that the developed model is able to simulate oil, water and gas production more accurately. Based on the results, the model can simulate the pressure behaviours observed in the experiments with dominated hysteresis. In addition, the developed model can predict the oil, water and gas saturations at the end of each cycle with higher accuracy compared to the available methods in the literature.\u0000 The significant impacts of the hysteresis phenomenon on designing the best WAG injection scenario require a reliable hysteresis model for performing accurate reservoir simulations. The use of the suggested model elevates the accuracy of any feasibility analysis performed to evaluate the WAG injection scenario.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90399074","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}
Xingcai Wu, Yongli Wang, A. Naabi, Hanbing Xu, Ibrahim S. Al Sinani, K. Busaidi, S. A. Jabri, S. Dhahab, Jianli Zhang, C. Xiong, Ye Yinzhu, X. Tian, Xu Jia, Jing Lv
The field under study is located in the northern part of Oman where most of the fields have a tight carbonate oil reservoirs. Initially the field was produced under natural depletion for almost 15 years until 2005 when a line drive water flood development with horizontal wells took place and was deployed in the whole field. After more than 10 years of water injection, the water cut reached an average of 75% in the major producing blocks. The reservoir has a light oil with viscosity of 0.8 mPa.s, a downhole temperature of 87°C and average permeability of 10 mD. The calcium and magnesium concentration in formation water is high, about 4000 mg/L. Reservoir heterogeneity in tight carbonate reservoirs causes uneven water flood sweep efficiency and hence resulted in a lot of bypassed oil. The initial EOR methods screening in the field under study didn't recommend to use the conventional polymer flooding due to low reservoir permeability and hence injectivity challenge. However, a new unique nano-ploymer was recently developed in the market to be a potential EOR method for such tight formation reservoirs. Extensive laboratory experiments using the core and fluid samples from the studied reservoir followed by numerical simulation modeling work proved the technical feasibility for this new polymer. This was then followed by field testing pilot in one of the matured water flood sector and the performance is currently under monitoring. The new polymer is a particle-type and comes with various nanometer-micrometer sizes. This polymer has a low apparent viscosity of 1-4 mPa and when it is mixed with the injection water, the particles disperse in the water and the resultant mixture has a low viscosity making it easily to be injected. In addition, this nano-polymer has a high tolerance for both temperature and salinity. While the particles move into formation, they temporarily plug the preferential existing water paths and divert the injection water into the relatively small pores/throats and displace the remaining bypassed oil. The polymer particle has high deformation capacity, so it can deform and pass through the throat under certain pressure to plug even deeper parts of the formation. The process is repeated continuously so that it can inhibit water production and enhance oil production. For the lab experiments, 12 core plugs from the associated reservoir were collected, based on which, a series of experiments were conducted including: core thin section analysis, injectivity test for the nano-polymer and core flooding experiments on single plug and parallel double plugs. Subsequently, the lab results were utilized for numerical simulation and that was followed by economic evaluation. Based on the lab test results, a conceptual simulation model for the studiedfield's sector was used to estimate the incremental oil gain at different pore volume (PV) injection. The incremental oil gain was determined at different SMG PV injection starting from 0.05PV to
{"title":"A New Polymer Flooding Technology for Improving Low Permeability Carbonate Reservoir Recovery--From Lab Study to Pilot Test--Case Study from Oman","authors":"Xingcai Wu, Yongli Wang, A. Naabi, Hanbing Xu, Ibrahim S. Al Sinani, K. Busaidi, S. A. Jabri, S. Dhahab, Jianli Zhang, C. Xiong, Ye Yinzhu, X. Tian, Xu Jia, Jing Lv","doi":"10.2118/197912-ms","DOIUrl":"https://doi.org/10.2118/197912-ms","url":null,"abstract":"\u0000 The field under study is located in the northern part of Oman where most of the fields have a tight carbonate oil reservoirs. Initially the field was produced under natural depletion for almost 15 years until 2005 when a line drive water flood development with horizontal wells took place and was deployed in the whole field. After more than 10 years of water injection, the water cut reached an average of 75% in the major producing blocks. The reservoir has a light oil with viscosity of 0.8 mPa.s, a downhole temperature of 87°C and average permeability of 10 mD. The calcium and magnesium concentration in formation water is high, about 4000 mg/L.\u0000 Reservoir heterogeneity in tight carbonate reservoirs causes uneven water flood sweep efficiency and hence resulted in a lot of bypassed oil. The initial EOR methods screening in the field under study didn't recommend to use the conventional polymer flooding due to low reservoir permeability and hence injectivity challenge. However, a new unique nano-ploymer was recently developed in the market to be a potential EOR method for such tight formation reservoirs. Extensive laboratory experiments using the core and fluid samples from the studied reservoir followed by numerical simulation modeling work proved the technical feasibility for this new polymer. This was then followed by field testing pilot in one of the matured water flood sector and the performance is currently under monitoring.\u0000 The new polymer is a particle-type and comes with various nanometer-micrometer sizes. This polymer has a low apparent viscosity of 1-4 mPa and when it is mixed with the injection water, the particles disperse in the water and the resultant mixture has a low viscosity making it easily to be injected. In addition, this nano-polymer has a high tolerance for both temperature and salinity. While the particles move into formation, they temporarily plug the preferential existing water paths and divert the injection water into the relatively small pores/throats and displace the remaining bypassed oil. The polymer particle has high deformation capacity, so it can deform and pass through the throat under certain pressure to plug even deeper parts of the formation. The process is repeated continuously so that it can inhibit water production and enhance oil production.\u0000 For the lab experiments, 12 core plugs from the associated reservoir were collected, based on which, a series of experiments were conducted including: core thin section analysis, injectivity test for the nano-polymer and core flooding experiments on single plug and parallel double plugs. Subsequently, the lab results were utilized for numerical simulation and that was followed by economic evaluation.\u0000 Based on the lab test results, a conceptual simulation model for the studiedfield's sector was used to estimate the incremental oil gain at different pore volume (PV) injection. The incremental oil gain was determined at different SMG PV injection starting from 0.05PV to","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89091461","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}
Dario De Benedictis, Shaymaa Ali Al Maskari, Noor Faisal Al Hashmi
A Lower Cretaceous reservoir in one of the Abu Dhabi onshore oilfields is the focus of this study aimed 1) to understand, predict and distribute the impact of diagenesis on the reservoir quality, and 2) to define the reservoir Static Rock Types (SRT). This will eventually help to define and predict the reservoir flow units to better frame strategies and choices for reservoir static and dynamic modelling, and to support the decision-making process for the oilfield business plan. A fully integrated geological-petrophysical approach was used to carry out the study. Nine geological facies are recognized in the reservoir and grouped in four main reservoir facies categories: 1) rudist-bearing facies, 2) grain-supported skeletal and Orbitolinid facies, 3) Bacinella/Lithocodium-coral facies, and 4) mudstone-supported facies. Rudist-bearing and Bacinella/Lithocodium-coral facies represent the best reservoir facies. Rudist deposits mainly formed stacked patches- or sheet-like accumulations of reworked skeletal debris on platform top settings in the northeast of the field. In the main reservoir section, geological facies distribution mainly follows the hydrodynamic trend of the depositional settings. Rudist facies properties primarily depend on the depositional texture and the original shell mineralogy and structure (e.g. Caprinids vs. Caprotinids-Requienids). Bacinella/Lithocodium-coral deposits form stacked shallowing-up peritidal cycles, representing the genetic units of the lower section of the reservoir. Evidences of epikarst in the uppermost cycles indicate the location of a major sequence boundary correlatable also to neighboring fields. The impact of diagenesis appears strongly driven by the depositional facies characteristics, and a paragenetic sequence is proposed for this reservoir. A link between geological facies features, including original grain mineralogy and depositional settings, and reservoir quality parameters is established, allowing the prediction and distribution of reservoir properties in the reservoir laterally and stratigraphically. Seven SRTs are identified by integrating geological observations and the result of the petrophysical synthesis. SRTs definition closely follows the reservoir stratigraphic framework, allowing creating a two-fold scheme: two SRTs characterize the cyclic peritidal deposits of the Bacinella/Lithocodium-coral section, and five SRTs are identified in the upper rudist-rich section. Petrophysical evidences from MICP data also strongly support this approach. A refined geological concept and stratigraphic framework is proposed for the reservoir to integrate the results of the sedimentological/petrographic analysis and petrophysical synthesis. Through linking geology and petrophysics, a new robust scheme of SRTs is created to enhance the identification and prediction of the reservoir flow units.
阿布扎比某陆上油田的下白垩统储层是本研究的重点，旨在1)了解、预测和分布成岩作用对储层质量的影响;2)定义储层静态岩石类型(SRT)。这最终将有助于定义和预测储层流量单元，从而更好地为储层静态和动态建模制定策略和选择，并支持油田业务计划的决策过程。研究采用了全面综合的地质-岩石物理方法。在储层中识别出9种地质相，并将其划分为4大类:1)含砾岩相，2)颗粒支撑的骨架和轨道岩相，3)Bacinella/ lithocodim -coral相，4)泥岩支撑相。含砾岩相和Bacinella/Lithocodium-coral相是最好的储集相。在油田东北部的平台顶部，Rudist沉积物主要形成堆积的斑块或片状的骨架碎屑堆积。在主储层段，地质相分布主要遵循沉积环境的水动力趋势。原始相性质主要取决于沉积结构和原始壳矿物学和结构(如Caprinids vs. capprotinids - requienids)。Bacinella/Lithocodium-coral沉积物形成堆积的浅滩滨潮旋回，代表了储层下部的成因单元。上旋回的表层岩溶证据表明了一个主要层序边界的位置，并与邻近的场相关。沉积相特征对成岩作用的影响强烈，并提出了该储层的共生层序。建立了包括原始颗粒矿物学和沉积环境在内的地质相特征与储层质量参数之间的联系，从而可以在横向和地层上预测和分布储层物性。综合地质观测和岩石物理综合结果，确定了7个srt。srt的定义与储层地层格架密切相关，从而形成了一个双重方案:两个srt表征Bacinella/Lithocodium-coral剖面的旋回潮外沉积，而在上部富陆剖面中发现了五个srt。来自MICP数据的岩石物理证据也有力地支持了这一方法。结合沉积岩学分析和岩石物理综合的结果，提出了该储层的精细地质概念和地层格架。通过将地质与岩石物理相结合，建立了一种新的鲁棒srt方案，以提高储层流动单元的识别和预测能力。
{"title":"Geological Facies and Static Rock Types in a Highly Heterogeneous Lower Cretaceous Carbonate Reservoir from an Onshore Field in Abu Dhabi, UAE","authors":"Dario De Benedictis, Shaymaa Ali Al Maskari, Noor Faisal Al Hashmi","doi":"10.2118/197292-ms","DOIUrl":"https://doi.org/10.2118/197292-ms","url":null,"abstract":"\u0000 A Lower Cretaceous reservoir in one of the Abu Dhabi onshore oilfields is the focus of this study aimed 1) to understand, predict and distribute the impact of diagenesis on the reservoir quality, and 2) to define the reservoir Static Rock Types (SRT). This will eventually help to define and predict the reservoir flow units to better frame strategies and choices for reservoir static and dynamic modelling, and to support the decision-making process for the oilfield business plan.\u0000 A fully integrated geological-petrophysical approach was used to carry out the study.\u0000 Nine geological facies are recognized in the reservoir and grouped in four main reservoir facies categories: 1) rudist-bearing facies, 2) grain-supported skeletal and Orbitolinid facies, 3) Bacinella/Lithocodium-coral facies, and 4) mudstone-supported facies. Rudist-bearing and Bacinella/Lithocodium-coral facies represent the best reservoir facies.\u0000 Rudist deposits mainly formed stacked patches- or sheet-like accumulations of reworked skeletal debris on platform top settings in the northeast of the field. In the main reservoir section, geological facies distribution mainly follows the hydrodynamic trend of the depositional settings. Rudist facies properties primarily depend on the depositional texture and the original shell mineralogy and structure (e.g. Caprinids vs. Caprotinids-Requienids).\u0000 Bacinella/Lithocodium-coral deposits form stacked shallowing-up peritidal cycles, representing the genetic units of the lower section of the reservoir. Evidences of epikarst in the uppermost cycles indicate the location of a major sequence boundary correlatable also to neighboring fields.\u0000 The impact of diagenesis appears strongly driven by the depositional facies characteristics, and a paragenetic sequence is proposed for this reservoir.\u0000 A link between geological facies features, including original grain mineralogy and depositional settings, and reservoir quality parameters is established, allowing the prediction and distribution of reservoir properties in the reservoir laterally and stratigraphically.\u0000 Seven SRTs are identified by integrating geological observations and the result of the petrophysical synthesis. SRTs definition closely follows the reservoir stratigraphic framework, allowing creating a two-fold scheme: two SRTs characterize the cyclic peritidal deposits of the Bacinella/Lithocodium-coral section, and five SRTs are identified in the upper rudist-rich section. Petrophysical evidences from MICP data also strongly support this approach.\u0000 A refined geological concept and stratigraphic framework is proposed for the reservoir to integrate the results of the sedimentological/petrographic analysis and petrophysical synthesis.\u0000 Through linking geology and petrophysics, a new robust scheme of SRTs is created to enhance the identification and prediction of the reservoir flow units.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86404416","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}
A crucial part of optimizing well production is accurate flow metering for both onshore and offshore environments. The industry currently relies on test separators and multiphase meters. These methods have limitations in terms of cost, transportation and safety. In this paper, an alternative method to classify water cut measurement in oil wells based on Distributed Acoustic Sensing (DAS) data and machine learning will be discussed. Fiber optics is an effective tool to perform downhole logging, however, the challenge usually resides in the analysis and processing of the logged data. After performing a flowing survey on an oil well a dataset was developed using the logged DAS data in combination with production logging tool (PLT) measurements. After extraction, processing and labeling the raw DAS data, this dataset is used for training supervised machine learning models. In this paper, different classical machine learning models to train this dataset is assessed in terms of accuracy, speed and training/testing segments. The data gathered from the PLT shows a limitation in the variation of water cut percentages between the zones ranging from 71% to 76%. This limits our ability to assess the validity of the model, risk of overfitting, since most points share a similar target value. This is also reflected on the Rayleigh backscatter collected by the laser box where samples from different production zones share a similar value distribution across most frequency ranges. Three different classification machine learning models were selected simple Decision Tree and two ensemble method models—adaptive boost and Random Forest. The ensemble method models offer a parallel and sequential training schemes that increases the variance and reduce the bias in the model. After splitting and shuffling the data, were 10% of the original data was used for training, all models were trained in different percentages of the training set. Multiple metrics were chosen to assess the model's performance including accuracy, F-score and confusion matrices. Random forest classifier appears to be the best choice for this challenge, with a maximum accuracy of 98% and F-score of 0.99. The models show high dependency on low frequencies—lower than 500 Hz—where value distribution across production zones in DAS measurements is comparatively higher. Both ensemble method models are less bias with a maximum feature weight of about 0.1, in contrast, the simple Decision Tree model was highly dependent on a single frequency response. In future work, a more complex and diverse dataset will be collected from wells with a wider range of variances in terms of conditions and types. Moreover, after creating a more robust dataset alternative approaches can be assessed both classical machine learning models—regression and classification—and deep learning.
{"title":"Machine Learning Approach to Classify Water Cut Measurements using DAS Fiber Optic Data","authors":"M. Alkhalaf, F. Hveding, Muhmmad Arsalan","doi":"10.2118/197349-ms","DOIUrl":"https://doi.org/10.2118/197349-ms","url":null,"abstract":"\u0000 A crucial part of optimizing well production is accurate flow metering for both onshore and offshore environments. The industry currently relies on test separators and multiphase meters. These methods have limitations in terms of cost, transportation and safety. In this paper, an alternative method to classify water cut measurement in oil wells based on Distributed Acoustic Sensing (DAS) data and machine learning will be discussed. Fiber optics is an effective tool to perform downhole logging, however, the challenge usually resides in the analysis and processing of the logged data. After performing a flowing survey on an oil well a dataset was developed using the logged DAS data in combination with production logging tool (PLT) measurements. After extraction, processing and labeling the raw DAS data, this dataset is used for training supervised machine learning models.\u0000 In this paper, different classical machine learning models to train this dataset is assessed in terms of accuracy, speed and training/testing segments. The data gathered from the PLT shows a limitation in the variation of water cut percentages between the zones ranging from 71% to 76%. This limits our ability to assess the validity of the model, risk of overfitting, since most points share a similar target value. This is also reflected on the Rayleigh backscatter collected by the laser box where samples from different production zones share a similar value distribution across most frequency ranges. Three different classification machine learning models were selected simple Decision Tree and two ensemble method models—adaptive boost and Random Forest. The ensemble method models offer a parallel and sequential training schemes that increases the variance and reduce the bias in the model. After splitting and shuffling the data, were 10% of the original data was used for training, all models were trained in different percentages of the training set. Multiple metrics were chosen to assess the model's performance including accuracy, F-score and confusion matrices. Random forest classifier appears to be the best choice for this challenge, with a maximum accuracy of 98% and F-score of 0.99. The models show high dependency on low frequencies—lower than 500 Hz—where value distribution across production zones in DAS measurements is comparatively higher. Both ensemble method models are less bias with a maximum feature weight of about 0.1, in contrast, the simple Decision Tree model was highly dependent on a single frequency response. In future work, a more complex and diverse dataset will be collected from wells with a wider range of variances in terms of conditions and types. Moreover, after creating a more robust dataset alternative approaches can be assessed both classical machine learning models—regression and classification—and deep learning.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83981291","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}
C. Peerakham, Sineenat Kruennumjai, T. Junmano, Cholavit Boonchun, Krit Ngamkamollert, Pradondate Ut-ang, J. Whangkitjamorn, Suwin Sompopsart
In Greater Bongkot North (GBN) Gas Condensate Field located in Gulf of Thailand, many oil wells have recently encountered liquid loading problems. Numerous attempts of gas pressurizing and lowering wellhead pressure have been made but could not sustain continuous oil production. This paper describes the use of innovative technique, Single Point Gas Lift (SPGL) Application, to revive oil production and increase oil recovery from liquid loading wells without the need for an expensive workover operation. SPGL is a retrofit retrievable gas lift straddle that can be installed in the existing production tubing via slick-line unit. This fit-for-purpose solution requires 3 main stages of planning and execution. Firstly, design parameters are identified by simulation software e.g. injection depth, injection rate and pressure. Then, gas lift vale (GLV) is installed by punching the tubing at designed depth, followed by installation of gas lift assembly across the punched depth which includes orifice, check valve and pack-off. Lastly, gas supply is injected into annulus and passes through the installed GLV into production tubing. The pilot test was conducted at well Bongkot-1, a liquid loaded horizontal oil well. SPGL installation was completed successfully followed by deployment of nitrogen injection unit as gas supply in order to prove the concept of SPGL. The gas lifting operation was begun with well unloading and then varying injection rate to determine an optimum gas injection rate. As a result of total 16 hours of nitrogen injection, the cumulative oil production volume of 3,000 STB was realized, indicating the success of the SPGL application. Consequently, long term production phase by utilizing gas supply from high pressure donor well is being implemented. The result proves that SPGL helps to not only revive liquid loading well but also recover more oil reserves and generate more revenues with low cost and simple operation. In 2019, at least 4 oil wells have been scheduled for installation of SPGL application and later with more proven track record of success, it could be extendedly applied to other oil/gas condensate wells, having liquid loading problems, in Greater Bongkot North Field and other fields operated by PTTEP.
{"title":"Single Point Gas Lift SPGL, A Quick Win Retrofit Gas Lift Application to Maximize Oil Production and Recovery in Greater Bongkot North Field, Thailand","authors":"C. Peerakham, Sineenat Kruennumjai, T. Junmano, Cholavit Boonchun, Krit Ngamkamollert, Pradondate Ut-ang, J. Whangkitjamorn, Suwin Sompopsart","doi":"10.2118/197809-ms","DOIUrl":"https://doi.org/10.2118/197809-ms","url":null,"abstract":"\u0000 In Greater Bongkot North (GBN) Gas Condensate Field located in Gulf of Thailand, many oil wells have recently encountered liquid loading problems. Numerous attempts of gas pressurizing and lowering wellhead pressure have been made but could not sustain continuous oil production. This paper describes the use of innovative technique, Single Point Gas Lift (SPGL) Application, to revive oil production and increase oil recovery from liquid loading wells without the need for an expensive workover operation.\u0000 SPGL is a retrofit retrievable gas lift straddle that can be installed in the existing production tubing via slick-line unit. This fit-for-purpose solution requires 3 main stages of planning and execution. Firstly, design parameters are identified by simulation software e.g. injection depth, injection rate and pressure. Then, gas lift vale (GLV) is installed by punching the tubing at designed depth, followed by installation of gas lift assembly across the punched depth which includes orifice, check valve and pack-off. Lastly, gas supply is injected into annulus and passes through the installed GLV into production tubing.\u0000 The pilot test was conducted at well Bongkot-1, a liquid loaded horizontal oil well. SPGL installation was completed successfully followed by deployment of nitrogen injection unit as gas supply in order to prove the concept of SPGL. The gas lifting operation was begun with well unloading and then varying injection rate to determine an optimum gas injection rate. As a result of total 16 hours of nitrogen injection, the cumulative oil production volume of 3,000 STB was realized, indicating the success of the SPGL application. Consequently, long term production phase by utilizing gas supply from high pressure donor well is being implemented.\u0000 The result proves that SPGL helps to not only revive liquid loading well but also recover more oil reserves and generate more revenues with low cost and simple operation. In 2019, at least 4 oil wells have been scheduled for installation of SPGL application and later with more proven track record of success, it could be extendedly applied to other oil/gas condensate wells, having liquid loading problems, in Greater Bongkot North Field and other fields operated by PTTEP.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88516635","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}
The Project portfolio in the Oil & Gas industry across the value chain is quite large. Significant investments are done in complex environments to manage these Portfolio with annual budgets in International Oil Companies and National Oil Companies running into several billions of dollars. There are many challenges managing Projects and one of the key functions that helps in managing Projects is "Project Controls". A Unified Value Assurance Process for Projects in the Upstream Business unit was rolled out in July 2015. Based on the learnings from previous project execution and challenges to manage Project schedules, cost, budgets and risks, it was felt that the knowledge level of the Project Management and Project controls function needs to be raised. It was in this context that an idea to set up a Projects Academy came about. Preliminary evaluation for this academy showed extensive efforts, coordination, involvement of external parties and extended time to get the Project Academy set-up. As a quick win, the upstream business line supported the establishment of a "Project Control Learning Academy" with in-house resources. We will present in this paper how the Project Control Learning Academy was set-up and training being imparted through Human Capital function. We will also address the lessons learnt and the future course of action for enhancing the Academy.
{"title":"Setting Up of Project Control Learning Academy in ADNOC","authors":"N. Balasubramanian, A. Albreiki, A. Basioni","doi":"10.2118/197639-ms","DOIUrl":"https://doi.org/10.2118/197639-ms","url":null,"abstract":"\u0000 The Project portfolio in the Oil & Gas industry across the value chain is quite large. Significant investments are done in complex environments to manage these Portfolio with annual budgets in International Oil Companies and National Oil Companies running into several billions of dollars. There are many challenges managing Projects and one of the key functions that helps in managing Projects is \"Project Controls\".\u0000 A Unified Value Assurance Process for Projects in the Upstream Business unit was rolled out in July 2015. Based on the learnings from previous project execution and challenges to manage Project schedules, cost, budgets and risks, it was felt that the knowledge level of the Project Management and Project controls function needs to be raised. It was in this context that an idea to set up a Projects Academy came about. Preliminary evaluation for this academy showed extensive efforts, coordination, involvement of external parties and extended time to get the Project Academy set-up. As a quick win, the upstream business line supported the establishment of a \"Project Control Learning Academy\" with in-house resources.\u0000 We will present in this paper how the Project Control Learning Academy was set-up and training being imparted through Human Capital function. We will also address the lessons learnt and the future course of action for enhancing the Academy.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86471461","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}
Optimizing resources and pushing the drilling limits to tap into deeper reservoirs at minimal cost has always been the primary objective of many operators worldwide. Moreover, the prolonged current market conditions are pressurizing every stakeholder involved within the well-delivery process to reduce time and the associated costs like never before. This paper deals with an Offshore Artificial Island project where the drilling limits were constantly challenged by adopting new technologies and practices in an extended-reach drilling (ERD) campaign. The complexity of these extended-reach wells was managed effectively with excellent planning and execution. Implementation of new and existing technologies and the adoption of revamped operational practices has managed the challenges of equipment capabilities, torque and drag, ECD, wellbore stability, hole cleaning and stuck pipe avoidance to name a few. The project drilled longer wells at less costs. This approach has resulted in drilling and completion of wells comfortably within the equipment-rating envelope. Additional technological means such as newly developed lubricant and mechanical drill pipe torque reducer subs helped reduce the friction factor and eliminate drill string buckling. Existing technology in the bottom-hole assembly (BHA) minimized the tortuosity in the wellbore, along with transmitted real-time downhole drilling data (Torque, Weight on Bit, Mechanical Specific Energy, and Equivalent Circulating Density) which helped in active drilling parameters optimization for efficient drilling. Similar technologies and practices were used in landing the completion string. The geo-mechanical studies undertaken at the concept stage and later revised against the offset well information helped in drilling the troublesome shale formations with no associated events. Specific importance was given to maximizing the hole cleaning by having the right tools in the BHA that could accommodate higher flow rates while using a tandem drill string for lower hydraulics. In addition, the newly formulated field / formation specific drilling and reaming practices minimized the stuck pipe, saving approximately 10% in overall well costs. This paper discusses the successful drilling of a number of offshore ERD wells with various complexities and tailored solutions with minimal downhole problems and within continuously revising planned times and budgets. The lessons learned and techniques associated with drilling of extended-reach wells at lower costs will be detailed in this paper. This information would give insights and considerations to all stakeholders who intend to drill extended reach wells or challenge their current limiters. This proven successful methodology and its results are considered a benchmark for the nearby fields in the region.
{"title":"Technologies and Practices to Push The Extended Reach Drilling Envelope within The Existing Constraints","authors":"Phalgun Paila, R. Singh, Kashif Abid","doi":"10.2118/197123-ms","DOIUrl":"https://doi.org/10.2118/197123-ms","url":null,"abstract":"\u0000 Optimizing resources and pushing the drilling limits to tap into deeper reservoirs at minimal cost has always been the primary objective of many operators worldwide. Moreover, the prolonged current market conditions are pressurizing every stakeholder involved within the well-delivery process to reduce time and the associated costs like never before. This paper deals with an Offshore Artificial Island project where the drilling limits were constantly challenged by adopting new technologies and practices in an extended-reach drilling (ERD) campaign.\u0000 The complexity of these extended-reach wells was managed effectively with excellent planning and execution. Implementation of new and existing technologies and the adoption of revamped operational practices has managed the challenges of equipment capabilities, torque and drag, ECD, wellbore stability, hole cleaning and stuck pipe avoidance to name a few. The project drilled longer wells at less costs. This approach has resulted in drilling and completion of wells comfortably within the equipment-rating envelope. Additional technological means such as newly developed lubricant and mechanical drill pipe torque reducer subs helped reduce the friction factor and eliminate drill string buckling. Existing technology in the bottom-hole assembly (BHA) minimized the tortuosity in the wellbore, along with transmitted real-time downhole drilling data (Torque, Weight on Bit, Mechanical Specific Energy, and Equivalent Circulating Density) which helped in active drilling parameters optimization for efficient drilling. Similar technologies and practices were used in landing the completion string.\u0000 The geo-mechanical studies undertaken at the concept stage and later revised against the offset well information helped in drilling the troublesome shale formations with no associated events. Specific importance was given to maximizing the hole cleaning by having the right tools in the BHA that could accommodate higher flow rates while using a tandem drill string for lower hydraulics. In addition, the newly formulated field / formation specific drilling and reaming practices minimized the stuck pipe, saving approximately 10% in overall well costs.\u0000 This paper discusses the successful drilling of a number of offshore ERD wells with various complexities and tailored solutions with minimal downhole problems and within continuously revising planned times and budgets. The lessons learned and techniques associated with drilling of extended-reach wells at lower costs will be detailed in this paper. This information would give insights and considerations to all stakeholders who intend to drill extended reach wells or challenge their current limiters. This proven successful methodology and its results are considered a benchmark for the nearby fields in the region.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86542950","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}
T. Cousins, R. Davies, C. Gravestock, T. Jewell, M. Simmons, O. Sutcliffe
Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate. The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking. This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established. Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into "white space" away from data control.
{"title":"Exploration and Production: Reducing Geological Risk in the Middle East","authors":"T. Cousins, R. Davies, C. Gravestock, T. Jewell, M. Simmons, O. Sutcliffe","doi":"10.2118/197161-ms","DOIUrl":"https://doi.org/10.2118/197161-ms","url":null,"abstract":"\u0000 Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate.\u0000 The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking.\u0000 This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established.\u0000 Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into \"white space\" away from data control.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85693336","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}
Shaikha Al Jenaibi, Tasnim Al Mzaini, L. Saputelli, H. Hafez, Carlos Mata, R. Narayanan, K. Mogensen, R. Mohan, Frank Charles, Z. Mammadov, Alvaro Escorcia, G. Mijares, J. Rodriguez, Cristina Hernandez
Meeting energy demands and generating profit to shareholders is a continuous quest for oil and gas companies. Production and business planning in integrated oil and gas operating companies is a complex process involving numerous organizations, historic data collection, modeling, prediction, and forecasting. Integrated business planning complexity intensifies due to the uncertain nature of past facts and future conditions. We propose a framework for integrating upstream and downstream production planning processes using data-driven models representing the upstream capacities, downstream processes, and a countrywide profit model. The upstream production model forecasts optimum capacity scenarios of the reservoir fluids with their compositional characteristics and hydraulic performance of the surface facilities while honoring business rules, and based on the various long-term expenditure scenarios, downtime requirements, and downstream demand schedules. An integrated optimization model for value chain has the potential to protect profitability for oil and gas companies in times of unbalanced market forces.
{"title":"Value Chain Optimization in Oil & Gas Companies – Integrated Workflows","authors":"Shaikha Al Jenaibi, Tasnim Al Mzaini, L. Saputelli, H. Hafez, Carlos Mata, R. Narayanan, K. Mogensen, R. Mohan, Frank Charles, Z. Mammadov, Alvaro Escorcia, G. Mijares, J. Rodriguez, Cristina Hernandez","doi":"10.2118/197925-ms","DOIUrl":"https://doi.org/10.2118/197925-ms","url":null,"abstract":"\u0000 Meeting energy demands and generating profit to shareholders is a continuous quest for oil and gas companies. Production and business planning in integrated oil and gas operating companies is a complex process involving numerous organizations, historic data collection, modeling, prediction, and forecasting. Integrated business planning complexity intensifies due to the uncertain nature of past facts and future conditions.\u0000 We propose a framework for integrating upstream and downstream production planning processes using data-driven models representing the upstream capacities, downstream processes, and a countrywide profit model.\u0000 The upstream production model forecasts optimum capacity scenarios of the reservoir fluids with their compositional characteristics and hydraulic performance of the surface facilities while honoring business rules, and based on the various long-term expenditure scenarios, downtime requirements, and downstream demand schedules.\u0000 An integrated optimization model for value chain has the potential to protect profitability for oil and gas companies in times of unbalanced market forces.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79741886","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}
E. Spelta, V. Caronni, G. Carrasquero, M. Catanzaro, M. Rossi, R. L. Tagliamonte, A. Valdisturlo
A robust and detailed reservoir model is an essential requirement when a fast track approach drives the development of a green field. Such a tool can only be developed through the orchestration of Geological and Geophysical (G&G) and Reservoir Engineering disciplines. This integration effort is, first of all, aimed at identifying the key characteristics of the reservoir most impacting its dynamic behavior at different scale and, eventually, at capturing them with the proper modelling approach. This paper decribes such approach to the case of a complex deep-water reservoir belonging to slope-toe of slope environment. A 3D integrated static model was built by incorporating core and log data, their petrophysical interpretation, a description of the depositional and architectural elements, a quantitative seismic reservoir characterization and the few dynamic information available at this early development stage. The implemented geomodeling workflow focused on heterogenetiy that could affect reservoir performance such as structural-stratigraphic discontinuities that could act as hydraulic barriers. Facies in the interwell space were distributed by applying seismic-derived 3D trends. Facies distribution eventually provided the framework within which petrophysical properties modelling was performed. During the implementation of this integrated G&G and Reservoir workflow, continuous crosschecks of consistency and robustness of the model led to elaborate the final product. The resulting reservoir model captured critical uncertainties (e.g. degree of reservoir heterogeneity including stratigraphic discontinuities) leading to an optimized development scheme, that allowed to minimize risks, despite the few data available.
{"title":"When Effective Integration Drives the Development: A Successful Case History","authors":"E. Spelta, V. Caronni, G. Carrasquero, M. Catanzaro, M. Rossi, R. L. Tagliamonte, A. Valdisturlo","doi":"10.2118/197900-ms","DOIUrl":"https://doi.org/10.2118/197900-ms","url":null,"abstract":"\u0000 A robust and detailed reservoir model is an essential requirement when a fast track approach drives the development of a green field. Such a tool can only be developed through the orchestration of Geological and Geophysical (G&G) and Reservoir Engineering disciplines. This integration effort is, first of all, aimed at identifying the key characteristics of the reservoir most impacting its dynamic behavior at different scale and, eventually, at capturing them with the proper modelling approach.\u0000 This paper decribes such approach to the case of a complex deep-water reservoir belonging to slope-toe of slope environment. A 3D integrated static model was built by incorporating core and log data, their petrophysical interpretation, a description of the depositional and architectural elements, a quantitative seismic reservoir characterization and the few dynamic information available at this early development stage.\u0000 The implemented geomodeling workflow focused on heterogenetiy that could affect reservoir performance such as structural-stratigraphic discontinuities that could act as hydraulic barriers. Facies in the interwell space were distributed by applying seismic-derived 3D trends. Facies distribution eventually provided the framework within which petrophysical properties modelling was performed. During the implementation of this integrated G&G and Reservoir workflow, continuous crosschecks of consistency and robustness of the model led to elaborate the final product.\u0000 The resulting reservoir model captured critical uncertainties (e.g. degree of reservoir heterogeneity including stratigraphic discontinuities) leading to an optimized development scheme, that allowed to minimize risks, despite the few data available.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81191781","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}
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