Gamal A. Alusta, H. Algdamsi, A. Amtereg, Ammar Agnia, Ahmed Alkouh, Bacem Kcharem
In this paper we introduce for the first time an innovative approach for deriving Oil Formation Volume Factor (Bo) by mean of artificial intelligence method. In a new proposed application Self-Organizing Map (SOM) technology has been merged with statistical prediction methods integrating in a single step dimensionality reduction, extraction of input data structure pattern and prediction of formation volume factor Bo. The SOM neural network method applies an unsupervised training algorithm combined with back propagation neural network BPNN to subdivide the entire set of PVT input into different patterns identifying a set of data that have something in common and run individual MLFF ANN models for each specific PVT cluster and computing Bo. PVT data for more than two hundred oil samples (total of 804 data points) were collected from the north African region representing different basin and covering a greater geographical area were used in this study. To establish clear Bound on the accuracy of Bo determination several statistical parameters and terminology included in the presentation of the result from SOM-Neural Network solution. the main outcome is the reduction of error obtained by the new proposed competitive Learning Structure integration of SOM and MLFF ANN to less than 1 % compared to other method. however also investigated in this work five independents means of model driven and data driven approach for estimating Bo theses are 1) Optimal Transformations for Multiple Regression as introduced by (McCain, 1998) using alternating conditional expectations (ACE) for selecting multiple regression transformations 2), Genetic programing and heuristic modeling using Symbolic Regression (SR) and cross validation for model automatic tuning 3) Machine learning predictive model (Nearest Neighbor Regression, Kernel Ridge regression, Gaussian Process Regression (GPR), Random Forest Regression (RF), Support Vector Regression (SVM), Decision Tree Regression (DT), Gradient Boosting Machine Regression (GBM), Group modeling data handling (GMDH). Regression Model Accuracy Metrics (Average absolute relative error, R-square), diagnostic plot was used to address the more adequate techniques and model for predicting Bo.
{"title":"Integration of Self Organizing Map and Date Driven Methods to Predict Oil Formation Volume Factor: North Africa Crude Oil Examples","authors":"Gamal A. Alusta, H. Algdamsi, A. Amtereg, Ammar Agnia, Ahmed Alkouh, Bacem Kcharem","doi":"10.2118/205782-ms","DOIUrl":"https://doi.org/10.2118/205782-ms","url":null,"abstract":"\u0000 In this paper we introduce for the first time an innovative approach for deriving Oil Formation Volume Factor (Bo) by mean of artificial intelligence method. In a new proposed application Self-Organizing Map (SOM) technology has been merged with statistical prediction methods integrating in a single step dimensionality reduction, extraction of input data structure pattern and prediction of formation volume factor Bo. The SOM neural network method applies an unsupervised training algorithm combined with back propagation neural network BPNN to subdivide the entire set of PVT input into different patterns identifying a set of data that have something in common and run individual MLFF ANN models for each specific PVT cluster and computing Bo. PVT data for more than two hundred oil samples (total of 804 data points) were collected from the north African region representing different basin and covering a greater geographical area were used in this study. To establish clear Bound on the accuracy of Bo determination several statistical parameters and terminology included in the presentation of the result from SOM-Neural Network solution. the main outcome is the reduction of error obtained by the new proposed competitive Learning Structure integration of SOM and MLFF ANN to less than 1 % compared to other method. however also investigated in this work five independents means of model driven and data driven approach for estimating Bo theses are 1) Optimal Transformations for Multiple Regression as introduced by (McCain, 1998) using alternating conditional expectations (ACE) for selecting multiple regression transformations 2), Genetic programing and heuristic modeling using Symbolic Regression (SR) and cross validation for model automatic tuning 3) Machine learning predictive model (Nearest Neighbor Regression, Kernel Ridge regression, Gaussian Process Regression (GPR), Random Forest Regression (RF), Support Vector Regression (SVM), Decision Tree Regression (DT), Gradient Boosting Machine Regression (GBM), Group modeling data handling (GMDH). Regression Model Accuracy Metrics (Average absolute relative error, R-square), diagnostic plot was used to address the more adequate techniques and model for predicting Bo.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89237986","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}
V. Sitompul, Muhammad Alfian, Fransiskus Ondihon Sitompul, D. T. Winata, Tino Diharja, G. Sutadiwiria, Sumadi Paryoto, E. D. Dusyanto, R. Rahadian, P. E. Erwanto, Alip Triwanto, Iik Sumirat, R. Alfajri, Muhammad Aji Ekalaya, Ahmad Ardhy Nurrakhman, Husein Asy'ari
Enhanced Oil Recovery (EOR) is a tertiary recovery which requires relatively a high cost of CAPEX and OPEX. The current EOR technique is generally stand alone and injected into single reservoir layer without contributing to the other layers (unconnected reservoir layer). For this reason, a breakthrough of low cost EOR technology (CAPEX & OPEX) is needed, especially since oil prices tend to fall low. Vibroseismic EOR is one of the EOR methods (categorized as mechanical EOR) that is inexpensive, fast response / yield, high mobility (can be moved to another place), environmentally friendly, and could be combined with the waterflood method or other EOR methods to get more effective and optimal result. However, the research & implementation on Vibroseismic EOR are still limited. The paper describes the pilot test of Vibroseismic EOR technology in Tempino Field. The initial stage is to select the suitable field for implementation Vibroseismic EOR. Then, the rock & fluid properties of the selected field are tested and examined by vibration and stimulation in the laboratory to obtain optimum frequency of 20 Hz S waves (circular / transverse) and 35 Hz P waves (longitudinal). The field scale-up process is carried out by measuring or testing field parameters called Vibroseis Field Parameter Test (VFP Test). VFP Test results get the optimum frequency of S and P waves of 20 Hz using 3 trucks and drive level 70% with amplitude value up to 0.024 rms (root mean square). Through the EOR vibroseismic method, the truck is the source of vibrations on the surface will generate acoustic waves propagating through the rock (subsurface) throughout the reservoir layer within the wave penetration range, generally reaching a depth of 6500 ft depending on the amplitude / power source of vibration, thickness of weathered layer, and rock type. The waves that reach the reservoir will affect the rock & fluids properties. The pilot test results on production wells showed a positive response within 1 month after vibration, especially those around the existing injection wells which the permeability was relatively good. The increased production accumulative of 10 (ten) monitoring production wells about 8% and withhold declining rate up to 20% from base case. Oil drainage around production wells and drainage direction are confirmed by changes in hydrocarbon saturation maps through passive seismic techniques measured before, during, and after vibration. The results of this pilot test show that Vibroseismic EOR technology is very promising to be developed to the full-scale stage and implemented in other areas.
{"title":"Breakthrough Enhanced Oil Recovery Technology with Low Cost & Fast Yield on Pilot Test of Vibroseismic EOR Technology in Tempino Field, Sumatera, Indonesia","authors":"V. Sitompul, Muhammad Alfian, Fransiskus Ondihon Sitompul, D. T. Winata, Tino Diharja, G. Sutadiwiria, Sumadi Paryoto, E. D. Dusyanto, R. Rahadian, P. E. Erwanto, Alip Triwanto, Iik Sumirat, R. Alfajri, Muhammad Aji Ekalaya, Ahmad Ardhy Nurrakhman, Husein Asy'ari","doi":"10.2118/205746-ms","DOIUrl":"https://doi.org/10.2118/205746-ms","url":null,"abstract":"\u0000 Enhanced Oil Recovery (EOR) is a tertiary recovery which requires relatively a high cost of CAPEX and OPEX. The current EOR technique is generally stand alone and injected into single reservoir layer without contributing to the other layers (unconnected reservoir layer). For this reason, a breakthrough of low cost EOR technology (CAPEX & OPEX) is needed, especially since oil prices tend to fall low. Vibroseismic EOR is one of the EOR methods (categorized as mechanical EOR) that is inexpensive, fast response / yield, high mobility (can be moved to another place), environmentally friendly, and could be combined with the waterflood method or other EOR methods to get more effective and optimal result. However, the research & implementation on Vibroseismic EOR are still limited. The paper describes the pilot test of Vibroseismic EOR technology in Tempino Field.\u0000 The initial stage is to select the suitable field for implementation Vibroseismic EOR. Then, the rock & fluid properties of the selected field are tested and examined by vibration and stimulation in the laboratory to obtain optimum frequency of 20 Hz S waves (circular / transverse) and 35 Hz P waves (longitudinal). The field scale-up process is carried out by measuring or testing field parameters called Vibroseis Field Parameter Test (VFP Test). VFP Test results get the optimum frequency of S and P waves of 20 Hz using 3 trucks and drive level 70% with amplitude value up to 0.024 rms (root mean square). Through the EOR vibroseismic method, the truck is the source of vibrations on the surface will generate acoustic waves propagating through the rock (subsurface) throughout the reservoir layer within the wave penetration range, generally reaching a depth of 6500 ft depending on the amplitude / power source of vibration, thickness of weathered layer, and rock type. The waves that reach the reservoir will affect the rock & fluids properties.\u0000 The pilot test results on production wells showed a positive response within 1 month after vibration, especially those around the existing injection wells which the permeability was relatively good. The increased production accumulative of 10 (ten) monitoring production wells about 8% and withhold declining rate up to 20% from base case. Oil drainage around production wells and drainage direction are confirmed by changes in hydrocarbon saturation maps through passive seismic techniques measured before, during, and after vibration.\u0000 The results of this pilot test show that Vibroseismic EOR technology is very promising to be developed to the full-scale stage and implemented in other areas.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75260643","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}
In recent decades, the development of natural gas hydrates has become a research hotspot of scholars all over the world. However, the decomposed gas and water in marine gas hydrate production system may regenerate gas hydrates due to the low-temperature and high-pressure environment in seafloor. In this study, a transient temperature and pressure calculating model was established to predict the risk of hydrate reformation in production pipelines during offshore natural gas hydrate development. Using the proposed model, the region of hydrate reformation in gas hydrate production wells were predicted quantitatively. Meanwhile, the hydrate reformation management strategies through optimization of production design parameters in combination with hydrate inhibitor injection were proposed and discussed in detail. The results indicate that the risk of hydrate reformation is the highest in the drainage pipeline (DP); however, the flow in gas-water mixed transportation and gas production pipelines (MTP and GPP) basically does not satisfy the hydrate formation condition. In the process of production well design, adding additional the EH and ESP can fully eliminate the hydrate reformation risk in the DP without using the hydrate inhibitor.
{"title":"Optimization Strategies of Production Parameters to Prevent Hydrate Reformation in Marine Gas Hydrate Production System","authors":"Zheng Liu, Baojiang Sun, Zhiyuan Wang, Jianbo Zhang","doi":"10.2118/205695-ms","DOIUrl":"https://doi.org/10.2118/205695-ms","url":null,"abstract":"\u0000 In recent decades, the development of natural gas hydrates has become a research hotspot of scholars all over the world. However, the decomposed gas and water in marine gas hydrate production system may regenerate gas hydrates due to the low-temperature and high-pressure environment in seafloor. In this study, a transient temperature and pressure calculating model was established to predict the risk of hydrate reformation in production pipelines during offshore natural gas hydrate development. Using the proposed model, the region of hydrate reformation in gas hydrate production wells were predicted quantitatively. Meanwhile, the hydrate reformation management strategies through optimization of production design parameters in combination with hydrate inhibitor injection were proposed and discussed in detail. The results indicate that the risk of hydrate reformation is the highest in the drainage pipeline (DP); however, the flow in gas-water mixed transportation and gas production pipelines (MTP and GPP) basically does not satisfy the hydrate formation condition. In the process of production well design, adding additional the EH and ESP can fully eliminate the hydrate reformation risk in the DP without using the hydrate inhibitor.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74745579","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}
Alister Albert Suggust, Aizuddin Khalid, M. Z. Usop, M. Khalil
The Balingian province is located offshore Sarawak, comprising of at least 7 oil fields with its regional geology consisting of a combination of deltaic & shoreface system. Though consisting of clastic reservoirs, the fields are highly sophisticated in terms of reservoir compartmentalization, hence uncertainties in fluid contacts, differing depletion strategies and varying production performance per well. As the regional production has gone into brownfield stage, the challenge is to determine the most suitable secondary recovery method to prolong field life. The subsurface & feasibility studies conducted produced mixed results between application of water & gas injection, giving recovery factors between 30 to 40%, and implementation so much depending on source of water & gas and cost benefit analyses. The application of IOR across Balingian province are executed in pilot mode across all fields. While the pilots are still continuing, this paper is to share the methodology, recovery factors and process of the regional study and some results from the ongoing surveillance post-execution, and the wayforward.
{"title":"Pioneering Secondary Recovery Strategies in a Complex Geological Environment and Challenging Reservoirs Located in Offshore Sarawak","authors":"Alister Albert Suggust, Aizuddin Khalid, M. Z. Usop, M. Khalil","doi":"10.2118/205811-ms","DOIUrl":"https://doi.org/10.2118/205811-ms","url":null,"abstract":"\u0000 The Balingian province is located offshore Sarawak, comprising of at least 7 oil fields with its regional geology consisting of a combination of deltaic & shoreface system. Though consisting of clastic reservoirs, the fields are highly sophisticated in terms of reservoir compartmentalization, hence uncertainties in fluid contacts, differing depletion strategies and varying production performance per well. As the regional production has gone into brownfield stage, the challenge is to determine the most suitable secondary recovery method to prolong field life. The subsurface & feasibility studies conducted produced mixed results between application of water & gas injection, giving recovery factors between 30 to 40%, and implementation so much depending on source of water & gas and cost benefit analyses. The application of IOR across Balingian province are executed in pilot mode across all fields. While the pilots are still continuing, this paper is to share the methodology, recovery factors and process of the regional study and some results from the ongoing surveillance post-execution, and the wayforward.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84684580","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}
M. Z. Musa, J. Tobing, Muhammad Ikhsan Akbar, I. Fajar, Wienarno Nurrakhmadi, H. Muttaqin
With the far-reaching reservoir target coupled with other surface constraint including fix well slot coordinate and pre-determined conductor size, the longest well with 2.5 ERD Index in Offshore East Java was pioneered. The team has big task in hand to ensure all aspect of ERD well engineering and construction are being addressed properly within the fast-paced time frame given. One of the approaches strategized by the team is to split the high angle big hole size long interval of middle section into two casing string which was not the common architecture applied in the other offset wells. The objective was to ensure that the middle section of the well will not be compromised and avoid complication in the deeper section of the well. Worth to mention that the middle section consists combination of challenging lithology that deserve the right solution to avoid unwanted problem. There are highly kartsitified carbonate formation, shale and sand interbedded formation, and thick time dependent shale formation. To mitigate the challenges previously mentioned, intermediate section which is normally drilled and isolated with 17-1/2" hole × 13-3/8" casing in previous wells, now separated into two sections which require enlargement: 17-1/2" to 20" and 14-3/4" to 17-1/2". This paper focuses on 14-3/4" × 17-1/2" which is the most challenging underreaming operation in this well and the first of its kind in this field application. Adding to the fact that the inclination reach 75 degree in this section, SOBM and RSS BHA are deployed to mitigate the torque and drag issue. State of the art modelling tool is also used by team to define effectively match BHA and drilling parameter with minimal lateral vibration and stick slip for this section Apart from drilling stage, the enlarged hole size requires a condition to have uncommon casing size and specification, 16" intermediate semi flush liner connection and 13-3/8" full flush intermediate casing connection to ensure sufficient annular area and less restriction during running to bottom. The relentless effort to secure one the most critical ERD well construction phase has really paid off by allowing the next phase of operation to be executed as per plan thus assuring the overall well objective is met.
{"title":"Pushing the Boundaries Through Successful Delivery of Highly Challenging ERD Well in Offshore East Java, Indonesia","authors":"M. Z. Musa, J. Tobing, Muhammad Ikhsan Akbar, I. Fajar, Wienarno Nurrakhmadi, H. Muttaqin","doi":"10.2118/205758-ms","DOIUrl":"https://doi.org/10.2118/205758-ms","url":null,"abstract":"\u0000 With the far-reaching reservoir target coupled with other surface constraint including fix well slot coordinate and pre-determined conductor size, the longest well with 2.5 ERD Index in Offshore East Java was pioneered. The team has big task in hand to ensure all aspect of ERD well engineering and construction are being addressed properly within the fast-paced time frame given. One of the approaches strategized by the team is to split the high angle big hole size long interval of middle section into two casing string which was not the common architecture applied in the other offset wells. The objective was to ensure that the middle section of the well will not be compromised and avoid complication in the deeper section of the well. Worth to mention that the middle section consists combination of challenging lithology that deserve the right solution to avoid unwanted problem. There are highly kartsitified carbonate formation, shale and sand interbedded formation, and thick time dependent shale formation.\u0000 To mitigate the challenges previously mentioned, intermediate section which is normally drilled and isolated with 17-1/2\" hole × 13-3/8\" casing in previous wells, now separated into two sections which require enlargement: 17-1/2\" to 20\" and 14-3/4\" to 17-1/2\". This paper focuses on 14-3/4\" × 17-1/2\" which is the most challenging underreaming operation in this well and the first of its kind in this field application.\u0000 Adding to the fact that the inclination reach 75 degree in this section, SOBM and RSS BHA are deployed to mitigate the torque and drag issue. State of the art modelling tool is also used by team to define effectively match BHA and drilling parameter with minimal lateral vibration and stick slip for this section Apart from drilling stage, the enlarged hole size requires a condition to have uncommon casing size and specification, 16\" intermediate semi flush liner connection and 13-3/8\" full flush intermediate casing connection to ensure sufficient annular area and less restriction during running to bottom.\u0000 The relentless effort to secure one the most critical ERD well construction phase has really paid off by allowing the next phase of operation to be executed as per plan thus assuring the overall well objective is met.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80780034","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}
Oil & gas companies leverage value of information to deliver asset performance from their portfolio to achieve their strategic targets. This requires a transparent, consistent, and balanced reporting of any subsurface project's technical evaluation. To undertake such quality assurance and to build confidence in any evaluation, peer reviews are an essential element of the generally accepted industry standard procedure. Peers aim to review work to identify deficiencies due to inadequate technical investigation, recognize cost effective opportunities and advise for any additional technical work. Any international upstream oil & gas company will deal with various subsurface challenges, especially for a new field. A standardization of peer assists and peer reviews by qualitative analysis has been designed, starting with development projects. Checklists help quality assurance in a structured manner by organizing the facts into a framework, and they are intended to serve two main purposes: (1) Assist the systematic review of the subsurface work to request further technical assistance if necessary, and (2) Aid the review of various subsurface disciplines to ensure that the data supports the appropriate conclusions. It is important to streamline the technical assurance process within any organization. Ideally, informal peer assists concentrate on specific discipline interactions before a formalized technical peer review. A set of review checklists has been developed to aid Geophysicists, Geologists, Petrophysicists, and Reservoir Engineers in their review of subsurface projects. The checklist for a field development project consists of 213 subsurface standards in total: 60 Geophysical, 36 Geological, 62 Petrophysical and 55 Reservoir Engineering standards. Each discipline review is then followed by two key recommendations: (1) further work is required or not, and/or (2) a recommendation to proceed to the next phase is made or not. Because of the high level of detail for the analysis of each subsurface discipline, it is recommended that the checklists be used as part of an informal peer assist rather than a formal peer review. For each discipline, a summary of the outcome is agreed between the project member and the peer (typically a subject matter expert). The use of such qualitative analysis is a big step in the right direction to resolve issues of detailed technical assurance before the formal peer review. Such integration of the subsurface approach drives better business decisions. A case study is presented to show how this systematic approach was used and how the results are consistent, comparable, encompassing and objective. This paper outlines a clear and concise method that has been tried and tested and that allows for relevant technical work to be presented at the correct decision gates and thereby allow data evaluation to be done in a more ordered and efficient way, and this would be of interest to organizations that are required to undertak
{"title":"Value of Information through Standardization of Peer Reviews by Qualitative Analysis","authors":"S. Kumar, D. Spencer, J. Brown, T. Esmaiel","doi":"10.2118/205581-ms","DOIUrl":"https://doi.org/10.2118/205581-ms","url":null,"abstract":"\u0000 Oil & gas companies leverage value of information to deliver asset performance from their portfolio to achieve their strategic targets. This requires a transparent, consistent, and balanced reporting of any subsurface project's technical evaluation. To undertake such quality assurance and to build confidence in any evaluation, peer reviews are an essential element of the generally accepted industry standard procedure. Peers aim to review work to identify deficiencies due to inadequate technical investigation, recognize cost effective opportunities and advise for any additional technical work.\u0000 Any international upstream oil & gas company will deal with various subsurface challenges, especially for a new field. A standardization of peer assists and peer reviews by qualitative analysis has been designed, starting with development projects. Checklists help quality assurance in a structured manner by organizing the facts into a framework, and they are intended to serve two main purposes: (1) Assist the systematic review of the subsurface work to request further technical assistance if necessary, and (2) Aid the review of various subsurface disciplines to ensure that the data supports the appropriate conclusions.\u0000 It is important to streamline the technical assurance process within any organization. Ideally, informal peer assists concentrate on specific discipline interactions before a formalized technical peer review. A set of review checklists has been developed to aid Geophysicists, Geologists, Petrophysicists, and Reservoir Engineers in their review of subsurface projects. The checklist for a field development project consists of 213 subsurface standards in total: 60 Geophysical, 36 Geological, 62 Petrophysical and 55 Reservoir Engineering standards. Each discipline review is then followed by two key recommendations: (1) further work is required or not, and/or (2) a recommendation to proceed to the next phase is made or not. Because of the high level of detail for the analysis of each subsurface discipline, it is recommended that the checklists be used as part of an informal peer assist rather than a formal peer review. For each discipline, a summary of the outcome is agreed between the project member and the peer (typically a subject matter expert). The use of such qualitative analysis is a big step in the right direction to resolve issues of detailed technical assurance before the formal peer review. Such integration of the subsurface approach drives better business decisions.\u0000 A case study is presented to show how this systematic approach was used and how the results are consistent, comparable, encompassing and objective. This paper outlines a clear and concise method that has been tried and tested and that allows for relevant technical work to be presented at the correct decision gates and thereby allow data evaluation to be done in a more ordered and efficient way, and this would be of interest to organizations that are required to undertak","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"90 1079 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90817057","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}
Grain size characteristics (d50, UC) of formation sands are crucial parameters in a sand control design. UC and d50 are commonly derived from sieve or laser particle size analysis (LPSA) techniques on a limited number of core samples in the process of drilling, which cannot represent the variations of grain sizes in the formation by the limited number of core samples. Moreover, staged and hierarchic design of sand control usually needs the whole longitudinal distribution profile of grain size. The grain size characteristics of the reservoir are formed in the process of a long history and have a good correlation with the formation environment of the sediments. Sand control design can only use test well data, because of lacking actual producing position cores. The vertical and horizontal anisotropy and heterogeneity of reservoirs bring difficulties and greater risks to the design of sand control schemes. Therefore, it is very important to find a simple and effective reservoir granularity prediction method. The existing prediction models by artificial intelligence method use single point logging data as eigenvalues to predict d50 and UC without considering the longitudinal continuity of data. This paper presents an efficient solution to predict grain size profile based on conventional logging curves by using four machine learning method (ANN, Random forest, XGBoost, SVM). In order to make full use of the geological continuity of the reservoir, the longitudinal continuous points according to the spatial correlation are adopted as the machine learning feature parameters from the perspective of geological analysis and the data-driven grain size profile prediction model are established by using the logging curve trend and background information, which further improves the prediction accuracy of the model and provides basic data for sand control. The ANN model of five point mapping has the best prediction effect in predicting d50 with a highest correlation coefficient 0.819 and a lowest error MAE 9.59. The XGBoost model of five point mapping has the best prediction effect in predicting UC with a highest correlation coefficient 0.402 and a lowest error RMSE 1.15. This method has been successfully used in offshore oil field in sand control optimization.
{"title":"Formation Grain Size Profile Prediction Model Considering the Longitudinal Continuity of Reservoir Using Artificial Intelligence Tools","authors":"Shanshan Liu, Zhiming Wang","doi":"10.2118/205683-ms","DOIUrl":"https://doi.org/10.2118/205683-ms","url":null,"abstract":"Grain size characteristics (d50, UC) of formation sands are crucial parameters in a sand control design. UC and d50 are commonly derived from sieve or laser particle size analysis (LPSA) techniques on a limited number of core samples in the process of drilling, which cannot represent the variations of grain sizes in the formation by the limited number of core samples. Moreover, staged and hierarchic design of sand control usually needs the whole longitudinal distribution profile of grain size. The grain size characteristics of the reservoir are formed in the process of a long history and have a good correlation with the formation environment of the sediments. Sand control design can only use test well data, because of lacking actual producing position cores. The vertical and horizontal anisotropy and heterogeneity of reservoirs bring difficulties and greater risks to the design of sand control schemes. Therefore, it is very important to find a simple and effective reservoir granularity prediction method. The existing prediction models by artificial intelligence method use single point logging data as eigenvalues to predict d50 and UC without considering the longitudinal continuity of data. This paper presents an efficient solution to predict grain size profile based on conventional logging curves by using four machine learning method (ANN, Random forest, XGBoost, SVM). In order to make full use of the geological continuity of the reservoir, the longitudinal continuous points according to the spatial correlation are adopted as the machine learning feature parameters from the perspective of geological analysis and the data-driven grain size profile prediction model are established by using the logging curve trend and background information, which further improves the prediction accuracy of the model and provides basic data for sand control. The ANN model of five point mapping has the best prediction effect in predicting d50 with a highest correlation coefficient 0.819 and a lowest error MAE 9.59. The XGBoost model of five point mapping has the best prediction effect in predicting UC with a highest correlation coefficient 0.402 and a lowest error RMSE 1.15. This method has been successfully used in offshore oil field in sand control optimization.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89207007","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}
Over the last five years, the oil market has experienced its most significant downturn since 1990s which resulted in the greatest immediate impact on the exploration and development drilling segment of the industry. With the objective to counter the influence of this potentially long period of downturn in global oil price, oil & gas operators have opted for different approaches to secure their future recovery and growth. The digital transformation across their drilling and completion activities could be a solution which helps to improve the drilling efficiency, shorten the well time, and cut down the well cost to the tolerable investment. In addition to that, the need of switching to a digital environment has recently became an urgent requirement, especially when everywhere in the world applies the social distancing and work from home concept during Covid-19 pandemic. Therefore, establishing a digital workplace has set an approach in a way drilling and completion teams handling internal and external communications, collaborations and content management to support drilling and completion activities. In order to understand more in depth, this paper, as a part of the digital transformation project carried out by Phu Quoc Petroleum Operating Company (PQPOC), the Operator of Block B Gas Development Project (Blocks B&48/95 and 52/97) located offshore of the South West of Vietnam, will make clear how to build a digital workplace on SharePoint, what features should be included in this platform, and how it can support drilling and completion activities.
{"title":"Building the Digital Workplace on SharePoint to Support Drilling and Completion Activities","authors":"C. Nguyen, Tri Tran Minh Le, Son Le","doi":"10.2118/205794-ms","DOIUrl":"https://doi.org/10.2118/205794-ms","url":null,"abstract":"\u0000 Over the last five years, the oil market has experienced its most significant downturn since 1990s which resulted in the greatest immediate impact on the exploration and development drilling segment of the industry. With the objective to counter the influence of this potentially long period of downturn in global oil price, oil & gas operators have opted for different approaches to secure their future recovery and growth. The digital transformation across their drilling and completion activities could be a solution which helps to improve the drilling efficiency, shorten the well time, and cut down the well cost to the tolerable investment. In addition to that, the need of switching to a digital environment has recently became an urgent requirement, especially when everywhere in the world applies the social distancing and work from home concept during Covid-19 pandemic. Therefore, establishing a digital workplace has set an approach in a way drilling and completion teams handling internal and external communications, collaborations and content management to support drilling and completion activities.\u0000 In order to understand more in depth, this paper, as a part of the digital transformation project carried out by Phu Quoc Petroleum Operating Company (PQPOC), the Operator of Block B Gas Development Project (Blocks B&48/95 and 52/97) located offshore of the South West of Vietnam, will make clear how to build a digital workplace on SharePoint, what features should be included in this platform, and how it can support drilling and completion activities.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88098231","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}
In the oil industry, the drilling fluid is yield stress fluid. The gas invading the wellbore during the drilling process is distributed in the wellbore in the form of bubbles. When the buoyancy of the bubble is less than the resistance of the yield stress, the bubble will be suspended in the drilling fluid, which will lead to wellbore pressure inaccurately predicting and overflow. In this paper, the prediction model of gas limit suspension concentration under different yield stresses of drilling fluids is obtained by experiments, and the calculation method of wellbore pressure considering the influence of gas suspension under shut-in conditions is established. Based on the calculation of the basic data of a case well, the distribution of gas in different yield stress drilling fluids and the influence of gas suspension on the wellbore pressure are analyzed. The results show that with the increase of yield stress, the volume of suspended single bubbles increases, the gas suspension concentration increases, and the height at which the gas can rise is reduced. When the yield stress of drilling fluid is 2 Pa, the increment of wellhead pressure decreases by 37.1% compared with that without considering gas suspension, and when the yield stress of drilling fluid is 10Pa, the increment of wellhead pressure can decrease by 78.6%, which shows that when the yield stress of drilling fluid is different, the final stable wellhead pressure is quite different. This is of great significance for the optimization design of field overflow and kill parameters, and for the accurate calculation of wellbore pressure by considering the suspension effect of drilling fluid on the invasion gas through the shut in wellhead pressure.
{"title":"A Wellbore Pressure Calculation Method Considering Gas Suspension in Wellbore Shut-In Condition","authors":"Z. Zhang, Baojiang Sun, Zhiyuan Wang, Shaowei Pan, Wenqiang Lou, Shikun Tong, Bingliang Guo","doi":"10.2118/205768-ms","DOIUrl":"https://doi.org/10.2118/205768-ms","url":null,"abstract":"\u0000 In the oil industry, the drilling fluid is yield stress fluid. The gas invading the wellbore during the drilling process is distributed in the wellbore in the form of bubbles. When the buoyancy of the bubble is less than the resistance of the yield stress, the bubble will be suspended in the drilling fluid, which will lead to wellbore pressure inaccurately predicting and overflow. In this paper, the prediction model of gas limit suspension concentration under different yield stresses of drilling fluids is obtained by experiments, and the calculation method of wellbore pressure considering the influence of gas suspension under shut-in conditions is established. Based on the calculation of the basic data of a case well, the distribution of gas in different yield stress drilling fluids and the influence of gas suspension on the wellbore pressure are analyzed. The results show that with the increase of yield stress, the volume of suspended single bubbles increases, the gas suspension concentration increases, and the height at which the gas can rise is reduced. When the yield stress of drilling fluid is 2 Pa, the increment of wellhead pressure decreases by 37.1% compared with that without considering gas suspension, and when the yield stress of drilling fluid is 10Pa, the increment of wellhead pressure can decrease by 78.6%, which shows that when the yield stress of drilling fluid is different, the final stable wellhead pressure is quite different. This is of great significance for the optimization design of field overflow and kill parameters, and for the accurate calculation of wellbore pressure by considering the suspension effect of drilling fluid on the invasion gas through the shut in wellhead pressure.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76020814","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}
Fianti Ramadhani, S. Nurdin, M. Etuhoko, Yang Zhi, Sugeng Mulyono, Arvin Mintardja, Marc Dawson
Four high-pressure-high temperature (HPHT) and sour gas wells are currently operating at Madura offshore as the only productive assets for Husky-CNOOC Madura Limited (HCML). Each well performance is very crucial to fulfill the demand of the gas customers in East Java, Indonesia. Since starting production in 2017, the wells experienced two main well integrity challenges, high annulus pressure and wellhead growth. Both challenges are very dependent to the well flow rate and the flow duration. A continuous operation monitoring is highly required in order to keep the wells operating safely. To overcome the challenges, HCML established a Well Integrity Management System (WIMS) document that approached several international standards as its basis. As company grows, development plan challenged the WIMS to perform faster and more efficient as compared to the existing manual system. From there, the journey of WIMS digitalization began. The journey started with the alignment of the existing WIMS document to the ISO-16530-1 at Operational Phase with more stringent boundary to operate the wells safely. The alignment covers, but not limited to the organizational structure, well barriers and criteria, monitoring and surveillance, annulus pressure management, and maintenance. The document also covered risk assessment and management of well integrity failure, which was the backbone of the WIMS digitalization. The current digital solutions allow production data to be accessed and retrieved directly from the system for analysis purposes. It compares the recorded data with pre-determined rules and parameters set in the system. It triggers a notification to the responsible personnel to perform the required action should any anomaly occurs. It also can send a reminder to users to schedule and complete a well Integrity test to ensure that a well is always in compliance with the WIMS. All test reports and documentation are stored in the system as preparation for any future audit. A key requirement of the expert software system was access to future developments that can offer enhanced functionality of the well integrity platform through additional near time capabilities such as predictive erosion and corrosion for downhole flow wetted components. This is being developed to enhance workover scheduling for existing wells and material selection for new wells and is planned to update automatically critical well integrity criteria such as tubing burst, collapse and MAASP.
{"title":"An Expert Software System has Accomplished Full Implementation of Well Integrity Management System WIMS Resulting to Excellent Safety and Production Sustainability for Critical Sour HPHT Field in Offshore Madura Strait, Indonesia","authors":"Fianti Ramadhani, S. Nurdin, M. Etuhoko, Yang Zhi, Sugeng Mulyono, Arvin Mintardja, Marc Dawson","doi":"10.2118/205697-ms","DOIUrl":"https://doi.org/10.2118/205697-ms","url":null,"abstract":"\u0000 Four high-pressure-high temperature (HPHT) and sour gas wells are currently operating at Madura offshore as the only productive assets for Husky-CNOOC Madura Limited (HCML). Each well performance is very crucial to fulfill the demand of the gas customers in East Java, Indonesia.\u0000 Since starting production in 2017, the wells experienced two main well integrity challenges, high annulus pressure and wellhead growth. Both challenges are very dependent to the well flow rate and the flow duration. A continuous operation monitoring is highly required in order to keep the wells operating safely.\u0000 To overcome the challenges, HCML established a Well Integrity Management System (WIMS) document that approached several international standards as its basis. As company grows, development plan challenged the WIMS to perform faster and more efficient as compared to the existing manual system. From there, the journey of WIMS digitalization began. The journey started with the alignment of the existing WIMS document to the ISO-16530-1 at Operational Phase with more stringent boundary to operate the wells safely. The alignment covers, but not limited to the organizational structure, well barriers and criteria, monitoring and surveillance, annulus pressure management, and maintenance. The document also covered risk assessment and management of well integrity failure, which was the backbone of the WIMS digitalization.\u0000 The current digital solutions allow production data to be accessed and retrieved directly from the system for analysis purposes. It compares the recorded data with pre-determined rules and parameters set in the system. It triggers a notification to the responsible personnel to perform the required action should any anomaly occurs. It also can send a reminder to users to schedule and complete a well Integrity test to ensure that a well is always in compliance with the WIMS. All test reports and documentation are stored in the system as preparation for any future audit.\u0000 A key requirement of the expert software system was access to future developments that can offer enhanced functionality of the well integrity platform through additional near time capabilities such as predictive erosion and corrosion for downhole flow wetted components. This is being developed to enhance workover scheduling for existing wells and material selection for new wells and is planned to update automatically critical well integrity criteria such as tubing burst, collapse and MAASP.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88474657","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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