L. Dennar, M. Amro, N. Kummer, E. Arochukwu, Ahmed Suleiman, Okpo Ekpeyong
Enhanced oil recovery has been gaining relevance over the years following success stories from already executed projects from various parts of the globe. The recoveries from such successful projects have tremendously increased the terminal life cycle recoveries from the subject reservoirs and subsequently the project Net Present Value and Value to Investment Ratio. More than 90% of Field Development Plans in the Niger Delta have not considered Enhanced Recovery Mechanism as part of the field development options and as such Top Quartile Recovery Factors are never achieved. In this study, the effectiveness of Enhanced Oil Recovery within the Niger-Delta reservoir sands via 3-Dimentional Dynamic Simulation, Economic models and Experimental investigations (temperature and pressure effects on polymer effectiveness) was done. The GN7000 reservoir was used as a case study for this work. This reservoir is the largest gas cap reservoir in the N-Onshore field within the Niger Delta area and it is at the mid-life stage. This study tested the effectiveness of three Recovery mechanisms (Water Flood, Polymer Flood and Polymer Alternating Gas). Simulated and Experimental result suggests that Polymer flooding and Polymer Alternating Gas (PAG) yields greater Technical Ultimate Recovery, better economic indices but greater complexity in polymer selection due to inherent high reservoir temperature and low salinity that make the use of synthetic polymers inadequate. Experimental investigation showed that biopolymers are most suitable for this sand. The suitability of some biopolymers (Xanthan and copolymers containing high level of 2-acrylamido2-methyl propane sulfonate (AMPS) showed good results. Study results shows that with the deployment of biopolymers with high viscosifying power and high resistance to thermal degradation an incremental recovery of 8% from the natural flow could be achieved. Research findings indicate that biopolymers could yield good results for Niger Delta sands within the pressure and temperature ranges of 93°C and 290 Bar.
{"title":"Exploring the Suitability of Polymer Injection in the Niger Delta Sands Using 3-D Simulation and Experimental Analysis - A Case Study-Paper ID 28","authors":"L. Dennar, M. Amro, N. Kummer, E. Arochukwu, Ahmed Suleiman, Okpo Ekpeyong","doi":"10.2118/207093-ms","DOIUrl":"https://doi.org/10.2118/207093-ms","url":null,"abstract":"\u0000 Enhanced oil recovery has been gaining relevance over the years following success stories from already executed projects from various parts of the globe. The recoveries from such successful projects have tremendously increased the terminal life cycle recoveries from the subject reservoirs and subsequently the project Net Present Value and Value to Investment Ratio.\u0000 More than 90% of Field Development Plans in the Niger Delta have not considered Enhanced Recovery Mechanism as part of the field development options and as such Top Quartile Recovery Factors are never achieved.\u0000 In this study, the effectiveness of Enhanced Oil Recovery within the Niger-Delta reservoir sands via 3-Dimentional Dynamic Simulation, Economic models and Experimental investigations (temperature and pressure effects on polymer effectiveness) was done. The GN7000 reservoir was used as a case study for this work. This reservoir is the largest gas cap reservoir in the N-Onshore field within the Niger Delta area and it is at the mid-life stage.\u0000 This study tested the effectiveness of three Recovery mechanisms (Water Flood, Polymer Flood and Polymer Alternating Gas). Simulated and Experimental result suggests that Polymer flooding and Polymer Alternating Gas (PAG) yields greater Technical Ultimate Recovery, better economic indices but greater complexity in polymer selection due to inherent high reservoir temperature and low salinity that make the use of synthetic polymers inadequate. Experimental investigation showed that biopolymers are most suitable for this sand. The suitability of some biopolymers (Xanthan and copolymers containing high level of 2-acrylamido2-methyl propane sulfonate (AMPS) showed good results. Study results shows that with the deployment of biopolymers with high viscosifying power and high resistance to thermal degradation an incremental recovery of 8% from the natural flow could be achieved. Research findings indicate that biopolymers could yield good results for Niger Delta sands within the pressure and temperature ranges of 93°C and 290 Bar.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79350647","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}
For the past century, optimization of drilling has caught the eyes of many researchers. The main areas center on ROP, fluid treatment, and bit selection. They all share the same goal of maximizing ROP and reducing NPT. In other to develop an optimal control system, ROP must be predicted accurately, unfortunately, it is a complex parameter that is affected by multiple drilling parameters, rock properties, fluid properties, and bit selection. Models used for prediction have developed from empirical models like Bourgoyne and Young's to more intelligent models such as SVM and ANN. With the continuous increase in data obtained from sensors while drilling, there is still much work to be done in this field. In this research, the improvement of an empirical model and the development of an intelligent model are presented. The Bourgoyne and Young's model uses multiple linear regression to estimate coefficients which it then inserts into an empirical formula to predict ROP. This model was modified using non-linear curve-fitting to estimate the coefficients and make it reduce bias to generalize better. Machine learning models such as Gradient Boosting, Random Forest, ANN, and DNN were used in the development of a predictive model for the ROP. These models were easier to develop compared to the empirical model since they rely more on data rather than statistical formulas. The data used in this research include drilling data from 3 wells drilled in 2 fields within the Niger Delta region in Nigeria. The models were developed and trained on one of the wells, while the remaining two were used for testing the performance of the models. The modified empirical model improved the efficiency of the base model by 14% during validation but performs poorly on unseen data from the other two wells. The Machine learning models outperform the empirical models and perform accurately on unseen data from the other wells. DNN was the best performing model achieving an average accuracy of 0.987 for the 3 wells.
{"title":"Development of an Optimal Model For Rate of Penetration Rop Using Deep Neural Networks DNN.","authors":"_ _","doi":"10.2118/207161-ms","DOIUrl":"https://doi.org/10.2118/207161-ms","url":null,"abstract":"\u0000 For the past century, optimization of drilling has caught the eyes of many researchers. The main areas center on ROP, fluid treatment, and bit selection. They all share the same goal of maximizing ROP and reducing NPT. In other to develop an optimal control system, ROP must be predicted accurately, unfortunately, it is a complex parameter that is affected by multiple drilling parameters, rock properties, fluid properties, and bit selection. Models used for prediction have developed from empirical models like Bourgoyne and Young's to more intelligent models such as SVM and ANN. With the continuous increase in data obtained from sensors while drilling, there is still much work to be done in this field. In this research, the improvement of an empirical model and the development of an intelligent model are presented. The Bourgoyne and Young's model uses multiple linear regression to estimate coefficients which it then inserts into an empirical formula to predict ROP. This model was modified using non-linear curve-fitting to estimate the coefficients and make it reduce bias to generalize better. Machine learning models such as Gradient Boosting, Random Forest, ANN, and DNN were used in the development of a predictive model for the ROP. These models were easier to develop compared to the empirical model since they rely more on data rather than statistical formulas. The data used in this research include drilling data from 3 wells drilled in 2 fields within the Niger Delta region in Nigeria. The models were developed and trained on one of the wells, while the remaining two were used for testing the performance of the models. The modified empirical model improved the efficiency of the base model by 14% during validation but performs poorly on unseen data from the other two wells. The Machine learning models outperform the empirical models and perform accurately on unseen data from the other wells. DNN was the best performing model achieving an average accuracy of 0.987 for the 3 wells.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77062220","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}
Osode Peter, Oluwatoyin Olusegun, Temitayo Ologun, Obinna Anyanwu
A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area. The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated. The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations. Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.
{"title":"Produced Water Disposal in Deep Aquifers: Case History Review of Ughelli East-30 Pilot Injector","authors":"Osode Peter, Oluwatoyin Olusegun, Temitayo Ologun, Obinna Anyanwu","doi":"10.2118/207094-ms","DOIUrl":"https://doi.org/10.2118/207094-ms","url":null,"abstract":"\u0000 A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area.\u0000 The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated.\u0000 The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations.\u0000 Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82032174","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}
P. U. Ndunagu, E. E. Alaike, Theophile Megueptchie
The objective of this paper is to perform an energy optimization study using pinch analysis on the Heat Exchanger Network (HEN) of a Crude Distillation Unit to maximum heat recovery, minimize energy consumption and increase refining margin. The heat exchanger network (HEN) considered comprises exchangers from the pre-heat section of the atmospheric distillation unit, which recovers heat from the product streams to incrementally heat the crude oil feed stream before entering the furnace. This paper illustrates how to perform a detailed HEN retrofitting study using an established design method known as Pinch Analysis to reduce the operating cost by increasing energy savings of the HEN of an existing complex refinery of moderate capacity. Analysis and optimization were carried out on the HEN of the CDU consist a total of 19 heat exchangers which include: process to process (P2P) heat exchangers, heaters and coolers. In the analysis, different feasible retrofit scenarios were generated using the pinch analysis approach. The retrofit designs included the addition of new heat exchangers, rearrangement of heat exchanger (re-sequencing) and re-piping of existing exchangers. Aspen Hysys V9 was used to simulate the CDU and Aspen Energy Analyser was used to perform pinch analysis on the HEN of the pre-heat train. Several retrofit scenarios were generated, the optimum retrofit solution was a trade-off between the capital cost of increasing heat exchanger surface area, payback time, energy / operating cost savings of hot and cold utilities. Results indicated that by rearrangement (Re-sequencing), the pre-heat train can reduce hot (fired heat) and cold (air and cooling water) utilities consumption to improve energy savings by 8% which includes savings on fired heat of about 4.6 MW for a payback period of 2 years on capital investment. The results generated were based on a ΔTmin of 10°C and pinch temperature of 46.3°C. Initial sensitivity analysis on the ΔTmin indicated that variation of total cost index is quite sensitive and increases with increase in ΔTmin at the temperature range of 14.5-30°C, however total cost index remains constant and minimal at a temperature range between 10°C-14.5°C for the CDU preheat train under study. In addition, the implementation of the optimum retrofit result is straightforward and feasible with minimum changes to the existing base case/design.
本文的目的是利用夹点分析对某原油蒸馏装置的热交换器网络(HEN)进行能量优化研究，以最大限度地提高热回收率，最小化能耗，提高精炼余量。所考虑的热交换器网络(HEN)包括常压蒸馏装置预热段的换热器，它从产品流中回收热量，在进入加热炉之前对原油进料流进行增量加热。本文阐述了如何使用一种被称为夹点分析的既定设计方法进行详细的HEN改造研究，通过增加现有中等产能复杂炼油厂HEN的节能来降低运营成本。对CDU的HEN进行了分析和优化，该HEN由19个换热器组成，包括:过程对过程(P2P)换热器、加热器和冷却器。在分析中，利用捏点分析法生成了不同可行的改造方案。改造设计包括增加新的热交换器，重新排列热交换器(重新排序)和重新管道现有的交换器。采用Aspen Hysys V9对CDU进行仿真，利用Aspen Energy analyzer对预热系的HEN进行夹点分析。产生了几种改造方案，最佳改造方案是在增加热交换器表面积的资本成本、投资回报时间、冷热公用事业的能源/运营成本节约之间进行权衡。结果表明，通过重新安排(重新排序)，预热系统可以减少热(燃烧的热量)和冷(空气和冷却水)的公用事业消耗，提高8%的能源节约，其中包括节省约4.6兆瓦的燃烧热量，投资回报期为2年。生成的结果基于ΔTmin为10°C，夹夹温度为46.3°C。对ΔTmin的初始敏感性分析表明，在14.5 ~ 30℃温度范围内，总成本指数的变化非常敏感，随ΔTmin的增加而增加，而CDU预热列在10℃~ 14.5℃温度范围内总成本指数保持不变且最小。此外，最佳改造结果的实施是直接可行的，对现有基本情况/设计的更改最小。
{"title":"A Practical Approach to Energy Optimization Using Pinch Analysis: A Case Study of an Oil Refinery","authors":"P. U. Ndunagu, E. E. Alaike, Theophile Megueptchie","doi":"10.2118/207096-ms","DOIUrl":"https://doi.org/10.2118/207096-ms","url":null,"abstract":"\u0000 The objective of this paper is to perform an energy optimization study using pinch analysis on the Heat Exchanger Network (HEN) of a Crude Distillation Unit to maximum heat recovery, minimize energy consumption and increase refining margin. The heat exchanger network (HEN) considered comprises exchangers from the pre-heat section of the atmospheric distillation unit, which recovers heat from the product streams to incrementally heat the crude oil feed stream before entering the furnace. This paper illustrates how to perform a detailed HEN retrofitting study using an established design method known as Pinch Analysis to reduce the operating cost by increasing energy savings of the HEN of an existing complex refinery of moderate capacity. Analysis and optimization were carried out on the HEN of the CDU consist a total of 19 heat exchangers which include: process to process (P2P) heat exchangers, heaters and coolers. In the analysis, different feasible retrofit scenarios were generated using the pinch analysis approach. The retrofit designs included the addition of new heat exchangers, rearrangement of heat exchanger (re-sequencing) and re-piping of existing exchangers. Aspen Hysys V9 was used to simulate the CDU and Aspen Energy Analyser was used to perform pinch analysis on the HEN of the pre-heat train. Several retrofit scenarios were generated, the optimum retrofit solution was a trade-off between the capital cost of increasing heat exchanger surface area, payback time, energy / operating cost savings of hot and cold utilities. Results indicated that by rearrangement (Re-sequencing), the pre-heat train can reduce hot (fired heat) and cold (air and cooling water) utilities consumption to improve energy savings by 8% which includes savings on fired heat of about 4.6 MW for a payback period of 2 years on capital investment. The results generated were based on a ΔTmin of 10°C and pinch temperature of 46.3°C. Initial sensitivity analysis on the ΔTmin indicated that variation of total cost index is quite sensitive and increases with increase in ΔTmin at the temperature range of 14.5-30°C, however total cost index remains constant and minimal at a temperature range between 10°C-14.5°C for the CDU preheat train under study. In addition, the implementation of the optimum retrofit result is straightforward and feasible with minimum changes to the existing base case/design.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84043935","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. M. Abanum, Ibidabo David Alebere, Chinemerem Patricks-E
Life-saving rules (LSRs) are a set of defined rules that support and complement general site-specific safety rules and procedures (SRPs). LSRs are popular in the oil & gas (O&G) industry and are part of the safety management system framework designed to prevent incidents in the workplace. Complying with LSRs ensures its intent of incident prevention, drives the goal of creating decent work, economic growth and sustainable development. With the continuum of incidents in the industry, total compliance with LSRs and SRPs still remains a mirage. Even though the introduction of LSRs in the O&G caused a paradigm shift from fair to better safety performance, incident investigations continue to unveil cases of violations/non-compliance. In the space of continuous improvement, it becomes expedient to determine possible causes of these LSRs and SRPs non-compliance, with a view to nipping the causal factors in the bud. A descriptive cross-sectional study was conducted to determine the factors affecting the level of workers compliance with IOGP LSRs in selected O&G companies operating in Delta State, Nigeria. The research recruited 317 sharp end workers and selected leaders, through a multistage sampling technique. A semi-structured, self-administered questionnaire was used as instrument for data collection. The study in its findings was able to elicit numerous compliance determinants arising from socio-demography, occupational and organisational factors. These factors are barriers to strengthen if the goal of total compliance and zero incident must be achieved in the workplace. The study recommends that management should comply with Thomas Legge's aphorisms 1 & 4 on SRPs and design training programmes for employees to be imparted with requisite knowledge needed for compliance, commit to safety and lead a positive safety culture to drive continuous improvement. Furthermore, there is the need to pursue total compliance with LSRs, SRPs and any site-specific safety rules to achieve zero incidents in the O&G industry.
{"title":"Determinants of IOGP Life-Saving Rules Compliance Among Nigerian Petroleum Industry Workers","authors":"A. M. Abanum, Ibidabo David Alebere, Chinemerem Patricks-E","doi":"10.2118/208227-ms","DOIUrl":"https://doi.org/10.2118/208227-ms","url":null,"abstract":"\u0000 Life-saving rules (LSRs) are a set of defined rules that support and complement general site-specific safety rules and procedures (SRPs). LSRs are popular in the oil & gas (O&G) industry and are part of the safety management system framework designed to prevent incidents in the workplace. Complying with LSRs ensures its intent of incident prevention, drives the goal of creating decent work, economic growth and sustainable development. With the continuum of incidents in the industry, total compliance with LSRs and SRPs still remains a mirage. Even though the introduction of LSRs in the O&G caused a paradigm shift from fair to better safety performance, incident investigations continue to unveil cases of violations/non-compliance. In the space of continuous improvement, it becomes expedient to determine possible causes of these LSRs and SRPs non-compliance, with a view to nipping the causal factors in the bud. A descriptive cross-sectional study was conducted to determine the factors affecting the level of workers compliance with IOGP LSRs in selected O&G companies operating in Delta State, Nigeria. The research recruited 317 sharp end workers and selected leaders, through a multistage sampling technique. A semi-structured, self-administered questionnaire was used as instrument for data collection. The study in its findings was able to elicit numerous compliance determinants arising from socio-demography, occupational and organisational factors. These factors are barriers to strengthen if the goal of total compliance and zero incident must be achieved in the workplace. The study recommends that management should comply with Thomas Legge's aphorisms 1 & 4 on SRPs and design training programmes for employees to be imparted with requisite knowledge needed for compliance, commit to safety and lead a positive safety culture to drive continuous improvement. Furthermore, there is the need to pursue total compliance with LSRs, SRPs and any site-specific safety rules to achieve zero incidents in the O&G industry.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82448795","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}
Kayode Adegbulugbe, Akunna Ambakederemo, C. Elendu
An oil producing swamp field, BX, is located in the coastal region of the western Niger Delta with an average water depth of 15 – 20 ft. The wells in the most recent development drilling campaign were designed as horizontal wells with critical well objective of meeting the target oil production rates with sand control. In order to achieve these goals, the sand control methodology deployed is the Open Hole Gravel Pack (OHGP) pumped through Concentric Annular Pack Screen (CAPS) system. This completion methodology has similar comparisons to the AX field completions where 19 completions were successfully installed between 2016 and 2018. The lessons learnt from the AX campaign were implemented on the BX campaign and this contributed to the campaign's near-flawless completion execution evidenced by the world class operational excellence, very low Non-Productive Times (NPTs) best-in-class production performances with no sand production However, the following opportunities were identified and implemented during the BX campaign focused on either increasing operational efficiency or preventing post-completion productivity impairment:Elimination of slickline required for tubing test operations by incorporating a "RH" catcher sub into the completion designPerforming required analysis and implementing procedural change to ensure that the change from WBM to NAF does not compromise completion performance due to the presence of reactive shales intervals encountered in the lateralDeveloping and implementing an enhanced fluid loss protocol to address the fluid loss event in one of the BX well that prevented the execution of OHGP pumping operation in the well. The implementation of these opportunities contributed significantly to the continued consistent delivery of superior completions performance in the BX field. This paper aims to provide a background to these opportunities and highlights the steps and processes that were applied to ensure their flawless implementation.
{"title":"Nigeria JV Onshore OHGP Recent Experience: Beyond Flawless Execution","authors":"Kayode Adegbulugbe, Akunna Ambakederemo, C. Elendu","doi":"10.2118/207084-ms","DOIUrl":"https://doi.org/10.2118/207084-ms","url":null,"abstract":"\u0000 An oil producing swamp field, BX, is located in the coastal region of the western Niger Delta with an average water depth of 15 – 20 ft. The wells in the most recent development drilling campaign were designed as horizontal wells with critical well objective of meeting the target oil production rates with sand control. In order to achieve these goals, the sand control methodology deployed is the Open Hole Gravel Pack (OHGP) pumped through Concentric Annular Pack Screen (CAPS) system.\u0000 This completion methodology has similar comparisons to the AX field completions where 19 completions were successfully installed between 2016 and 2018. The lessons learnt from the AX campaign were implemented on the BX campaign and this contributed to the campaign's near-flawless completion execution evidenced by the world class operational excellence, very low Non-Productive Times (NPTs) best-in-class production performances with no sand production\u0000 However, the following opportunities were identified and implemented during the BX campaign focused on either increasing operational efficiency or preventing post-completion productivity impairment:Elimination of slickline required for tubing test operations by incorporating a \"RH\" catcher sub into the completion designPerforming required analysis and implementing procedural change to ensure that the change from WBM to NAF does not compromise completion performance due to the presence of reactive shales intervals encountered in the lateralDeveloping and implementing an enhanced fluid loss protocol to address the fluid loss event in one of the BX well that prevented the execution of OHGP pumping operation in the well.\u0000 The implementation of these opportunities contributed significantly to the continued consistent delivery of superior completions performance in the BX field. This paper aims to provide a background to these opportunities and highlights the steps and processes that were applied to ensure their flawless implementation.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73223097","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}
Osita Robinson Madu, Jerry Orrelo Athoja, Amarachi Queen Kalu, Obi Mike Onyekonwu
In-depth knowledge of geostatistical analysis, environment of deposition and reservoir facies types is important for optimal distribution of reservoir properties across the reservoir grid. Geostatistics is a veritable tool that is quantitatively used to model spatial continuity, anisotropy direction and capture reservoir heterogeneity for optimal distribution of reservoir properties. When spatial continuity and heterogeneity level of the reservoir are adequately understood and modeled, representative property distribution becomes possible. In the face of limited well data, modeling major and minor directions of horizontal variogram is highly impaired and it becomes difficult to adequately distribute properties within the reservoir grid with enough control. This study is focused on the integration of seismic data, core data, well logs and geological knowledge to carry out geostatistical analysis to optimally distribute facies, porosity and permeability properties within the grid. The degree of reservoir heterogeneity was determined quantitatively using semivariogram and Lorenz plots of core porosity and permeability data. Variogram map generated from seismic attribute was used in combination with the sparse well data points to determine the horizontal variogram. The available well data was adequate enough to model the vertical variogram. The environment of deposition was interpreted as lower to upper shoreface with channel deposits and some shallow marine influence. The properties were normal-scored and modeled with the determined variogram parameters while biasing them with facies. Results of the semivariogram and Lorenz plots showed that the reservoir is fairly heterogenous in terms of spatial continuity. Major direction of the geological continuity is in the Northeast-Southwest direction while the minor direction is orthogonal to it. Final result of the modeled properties was in consonance with the facies types described from the environment of deposition.
{"title":"Integrated Approach to Geostatistics For Optimal Reservoir Properties Distribution – Case Study of X-Reservoir in Niger Delta Basin","authors":"Osita Robinson Madu, Jerry Orrelo Athoja, Amarachi Queen Kalu, Obi Mike Onyekonwu","doi":"10.2118/207116-ms","DOIUrl":"https://doi.org/10.2118/207116-ms","url":null,"abstract":"\u0000 In-depth knowledge of geostatistical analysis, environment of deposition and reservoir facies types is important for optimal distribution of reservoir properties across the reservoir grid. Geostatistics is a veritable tool that is quantitatively used to model spatial continuity, anisotropy direction and capture reservoir heterogeneity for optimal distribution of reservoir properties. When spatial continuity and heterogeneity level of the reservoir are adequately understood and modeled, representative property distribution becomes possible. In the face of limited well data, modeling major and minor directions of horizontal variogram is highly impaired and it becomes difficult to adequately distribute properties within the reservoir grid with enough control. This study is focused on the integration of seismic data, core data, well logs and geological knowledge to carry out geostatistical analysis to optimally distribute facies, porosity and permeability properties within the grid. The degree of reservoir heterogeneity was determined quantitatively using semivariogram and Lorenz plots of core porosity and permeability data. Variogram map generated from seismic attribute was used in combination with the sparse well data points to determine the horizontal variogram. The available well data was adequate enough to model the vertical variogram. The environment of deposition was interpreted as lower to upper shoreface with channel deposits and some shallow marine influence. The properties were normal-scored and modeled with the determined variogram parameters while biasing them with facies. Results of the semivariogram and Lorenz plots showed that the reservoir is fairly heterogenous in terms of spatial continuity. Major direction of the geological continuity is in the Northeast-Southwest direction while the minor direction is orthogonal to it. Final result of the modeled properties was in consonance with the facies types described from the environment of deposition.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73782273","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. Ndokwu, K. Amadi, Victor Okowi, K. Okengwu, Jones E. Acra
The quest to gain more knowledge of the subsurface and to reduce uncertainty in the interpretation of subsurface data has been an age-long effort in the oil and gas industry. To achieve this, asset owners use tools with improved resolution, utilize different types of logging tools and integrate the interpretation from these logging tools. This paper will review some projects where data from borehole imaging tools were used to support geosteering decisions and to gain more knowledge of reservoir structure. Borehole images are logs based on the circumferential measurement of a petrophysical parameter along a borehole wall. Logging-while-drilling borehole images can be used for structural, sedimentological and petrophysical analysis. These near-wellbore analyses contribute greatly to the success of most geosteering jobs. Geosteering is a process used in placing high-angled and horizontal wells in subsurface intervals of interest. It involves the use and integration of data from varied sources. This paper will show different scenarios, in different depositional environments, where borehole imaging supported the geosteering process and how geological interpretations from geosteering brought more clarity to borehole imaging analysis. Examples of these will highlight the stratigraphic relationship between geological structures and wellbore trajectory, detection of subsurface structural discontinuities, primary sedimentary structures, and the interpretation of complex geological structures. This paper will broaden our understanding of the applications of borehole imaging and how it integrates with geosteering in achieving oil and gas well objectives.
{"title":"The Synergy Between Borehole Imaging and Geosteering","authors":"C. Ndokwu, K. Amadi, Victor Okowi, K. Okengwu, Jones E. Acra","doi":"10.2118/207197-ms","DOIUrl":"https://doi.org/10.2118/207197-ms","url":null,"abstract":"\u0000 The quest to gain more knowledge of the subsurface and to reduce uncertainty in the interpretation of subsurface data has been an age-long effort in the oil and gas industry. To achieve this, asset owners use tools with improved resolution, utilize different types of logging tools and integrate the interpretation from these logging tools. This paper will review some projects where data from borehole imaging tools were used to support geosteering decisions and to gain more knowledge of reservoir structure.\u0000 Borehole images are logs based on the circumferential measurement of a petrophysical parameter along a borehole wall. Logging-while-drilling borehole images can be used for structural, sedimentological and petrophysical analysis. These near-wellbore analyses contribute greatly to the success of most geosteering jobs. Geosteering is a process used in placing high-angled and horizontal wells in subsurface intervals of interest. It involves the use and integration of data from varied sources.\u0000 This paper will show different scenarios, in different depositional environments, where borehole imaging supported the geosteering process and how geological interpretations from geosteering brought more clarity to borehole imaging analysis. Examples of these will highlight the stratigraphic relationship between geological structures and wellbore trajectory, detection of subsurface structural discontinuities, primary sedimentary structures, and the interpretation of complex geological structures. This paper will broaden our understanding of the applications of borehole imaging and how it integrates with geosteering in achieving oil and gas well objectives.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73971064","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}
Abdulganiyu Salako, Bosun Pelemo, Modupe A. Otubanjo, Z. Lawan, Elizabeth O. Olushoga, S. Eyitayo, C. Ukaonu, K. Lawal, S. Matemilola, S. Owolabi
Well delivery is an expensive scope in the exploration and field development process. Among other drivers, an ideal well must be delivered safely while achieving top-quartile performance on cost, schedule and business objectives. However, delivering an ideal well amid subsurface uncertainties and tightening budgets is usually challenging. As part of the drive for continued value creation, this paper presents an empirical process-improvement initiative for de-risking and optimizing the landing of the drain-hole sections of highly deviated wells amid subsurface uncertainties and at minimal costs. A review of the conventional procedure for executing subsurface scope of the delivery of development wells has been accomplished. The review takes advantage of a combination of recent experiences in delivering four horizontal development wells in an offshore field in the Niger Delta, in addition to a catalogue of available knowledge and best practices from other fields and operators. This review culminates in an improved well delivery optimization process and practice. In addition to promoting operational HSE excellence, it increases the chance of delivering an ideal well, including the mitigation of a subsurface-related non-productive time (NPT) and other related costs. As a complement to the practice, a simple workflow is provided to aid robust decision-making and facilitate applications in practice. For completeness, relevant examples are included to demonstrate the applicability of this new process.
{"title":"A Simple Strategy For Subsurface Delivery of Effective Development Wells – Field Examples","authors":"Abdulganiyu Salako, Bosun Pelemo, Modupe A. Otubanjo, Z. Lawan, Elizabeth O. Olushoga, S. Eyitayo, C. Ukaonu, K. Lawal, S. Matemilola, S. Owolabi","doi":"10.2118/207120-ms","DOIUrl":"https://doi.org/10.2118/207120-ms","url":null,"abstract":"\u0000 Well delivery is an expensive scope in the exploration and field development process. Among other drivers, an ideal well must be delivered safely while achieving top-quartile performance on cost, schedule and business objectives. However, delivering an ideal well amid subsurface uncertainties and tightening budgets is usually challenging.\u0000 As part of the drive for continued value creation, this paper presents an empirical process-improvement initiative for de-risking and optimizing the landing of the drain-hole sections of highly deviated wells amid subsurface uncertainties and at minimal costs. A review of the conventional procedure for executing subsurface scope of the delivery of development wells has been accomplished. The review takes advantage of a combination of recent experiences in delivering four horizontal development wells in an offshore field in the Niger Delta, in addition to a catalogue of available knowledge and best practices from other fields and operators.\u0000 This review culminates in an improved well delivery optimization process and practice. In addition to promoting operational HSE excellence, it increases the chance of delivering an ideal well, including the mitigation of a subsurface-related non-productive time (NPT) and other related costs. As a complement to the practice, a simple workflow is provided to aid robust decision-making and facilitate applications in practice. For completeness, relevant examples are included to demonstrate the applicability of this new process.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85616745","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}
N. Okereke, I. Ogazi, Anitie Umofia, N. Abili, N. Ohia, S. Ekwueme
Recent developments in offshore oil and gas production indicate a trend of deployment of subsea separation technologies in a reasonable number of offshore oil and gas fields in the Northsea and Offshore Brazil. Although Pazflor field Offshore Angola has adopted a vertical gravity separator, there is still a slow acceptance of this technology in Offshore West-Africa. This work reviewed over ten technical papers and also captured expert views; identifying some of the challenges and potential benefits of subsea separation technologies to deepwater West-Africa. Subsea separation of gas and liquid phase for instance creates the opportunity to overcome hydrostatic pressure in lifting the produced fluid to the topside Floating Production Storage and Offloading (FPSO) vessel using single phase or hybrid pumps. Gas/liquid phase separation could also reduce possibility of flow assurance challenges like hydrates formation and slugging. In spite of these potential advantages, there are also challenges facing the deployment of subsea separation, especillay in West Africa oil fields. This work reviewed current trends, opportunities, challenges and best practices with respect to subsea separation. Also, possibility of a future driven by compact separators in deepwater environments was explored in this work. Strengths, weakness, opportunities and threats (SWOT) analysis was conducted to identify the key technical challenges and opportunities of already deployed subsea separation technologies in Pazflor and Shell BC 10 field. Improved phase separation was identified as one of the key benefits of compact separators. The challenges in accessing installation vessels for deployment of gravity based subsea separators in West-Africa was also highlighted as one of the key technical challenge in the deployment of subsea separators in Offshore West-Africa. Recommendations for future subsea separation technologies application in Deepwater West-Africa was also done in this work.
{"title":"Adopting Subsea Separation Technologies for Deepwater West-Africa: A Review Study","authors":"N. Okereke, I. Ogazi, Anitie Umofia, N. Abili, N. Ohia, S. Ekwueme","doi":"10.2118/207201-ms","DOIUrl":"https://doi.org/10.2118/207201-ms","url":null,"abstract":"\u0000 Recent developments in offshore oil and gas production indicate a trend of deployment of subsea separation technologies in a reasonable number of offshore oil and gas fields in the Northsea and Offshore Brazil. Although Pazflor field Offshore Angola has adopted a vertical gravity separator, there is still a slow acceptance of this technology in Offshore West-Africa. This work reviewed over ten technical papers and also captured expert views; identifying some of the challenges and potential benefits of subsea separation technologies to deepwater West-Africa. Subsea separation of gas and liquid phase for instance creates the opportunity to overcome hydrostatic pressure in lifting the produced fluid to the topside Floating Production Storage and Offloading (FPSO) vessel using single phase or hybrid pumps. Gas/liquid phase separation could also reduce possibility of flow assurance challenges like hydrates formation and slugging. In spite of these potential advantages, there are also challenges facing the deployment of subsea separation, especillay in West Africa oil fields. This work reviewed current trends, opportunities, challenges and best practices with respect to subsea separation. Also, possibility of a future driven by compact separators in deepwater environments was explored in this work. Strengths, weakness, opportunities and threats (SWOT) analysis was conducted to identify the key technical challenges and opportunities of already deployed subsea separation technologies in Pazflor and Shell BC 10 field. Improved phase separation was identified as one of the key benefits of compact separators. The challenges in accessing installation vessels for deployment of gravity based subsea separators in West-Africa was also highlighted as one of the key technical challenge in the deployment of subsea separators in Offshore West-Africa. Recommendations for future subsea separation technologies application in Deepwater West-Africa was also done in this work.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73401435","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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