Isemin. A. Isemin, King-Akanimo B. Nkundu, O. Agwu
A Kick, the influx of formation fluid into the wellbore while drilling, poses a major challenge to drilling operations and can spiral out of control into blowouts with severe fatal, fiscal and environmental consequences. Kicks characteristically have a higher occurrence when drilling in relatively unexplored formations and with the combined factors of a waning era of easy oil and increasing energy demand, the consequent push for petroleum exploration in unconventional formations demands better techniques to detect and control kicks. This work has detection of kicks as its objective. Traditional methods of detecting kicks by monitoring drilling mud levels in the tanks has proven to be cumbersome and error prone and it leaves little time for an effective response. Thus, the use of analytics of real time drilling data and advanced formation modelling is presented as an approach to create a better representation of the drilling environment sub-surface and identify potential threats of a kick along the course of drilling (with respect to the trajectory as well as decisions to be made following that course). The methodology seeks to create a comprehensive model that defines relevant physical parameters whose values can be used as data sets which describe the ongoing drilling process and its relationship with the background formation with the aim of bringing forth information which would give a representation of consequent events. Notable parameters include, porosity, rock density, drill string hook load, weight on bit (WOB), mud density, formation fluid resistivity, rate of penetration, ultra sound speed across media, drilling trajectory amongst others, all relative to time. The background formation is aptly described in discretized grid blocks and is then cross-matched with the real-time data from the drillstring to double-check the actual position of the drillstring at any point in time. The interactions of the formation with the drillstring trajectory are computed as described by the grid blocks in contact with the drill string trajectory as well as adjacent grid blocks. The data describing the formation can be regularly updated to represent whatever sensitive changes that might have occurred in the formation while drilling. This solution, though notably complex is well within the capacity computing power available in the upstream petroleum industry and shows great promise to eliminate all the disastrous consequences that arise from late detection of kicks.
{"title":"Utilization of Big Data Analytics and Advanced Formation Modelling for Detection of Kicks in Drilling Operations","authors":"Isemin. A. Isemin, King-Akanimo B. Nkundu, O. Agwu","doi":"10.2118/198841-MS","DOIUrl":"https://doi.org/10.2118/198841-MS","url":null,"abstract":"\u0000 A Kick, the influx of formation fluid into the wellbore while drilling, poses a major challenge to drilling operations and can spiral out of control into blowouts with severe fatal, fiscal and environmental consequences. Kicks characteristically have a higher occurrence when drilling in relatively unexplored formations and with the combined factors of a waning era of easy oil and increasing energy demand, the consequent push for petroleum exploration in unconventional formations demands better techniques to detect and control kicks. This work has detection of kicks as its objective. Traditional methods of detecting kicks by monitoring drilling mud levels in the tanks has proven to be cumbersome and error prone and it leaves little time for an effective response. Thus, the use of analytics of real time drilling data and advanced formation modelling is presented as an approach to create a better representation of the drilling environment sub-surface and identify potential threats of a kick along the course of drilling (with respect to the trajectory as well as decisions to be made following that course). The methodology seeks to create a comprehensive model that defines relevant physical parameters whose values can be used as data sets which describe the ongoing drilling process and its relationship with the background formation with the aim of bringing forth information which would give a representation of consequent events. Notable parameters include, porosity, rock density, drill string hook load, weight on bit (WOB), mud density, formation fluid resistivity, rate of penetration, ultra sound speed across media, drilling trajectory amongst others, all relative to time. The background formation is aptly described in discretized grid blocks and is then cross-matched with the real-time data from the drillstring to double-check the actual position of the drillstring at any point in time. The interactions of the formation with the drillstring trajectory are computed as described by the grid blocks in contact with the drill string trajectory as well as adjacent grid blocks. The data describing the formation can be regularly updated to represent whatever sensitive changes that might have occurred in the formation while drilling. This solution, though notably complex is well within the capacity computing power available in the upstream petroleum industry and shows great promise to eliminate all the disastrous consequences that arise from late detection of kicks.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88635256","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 this paper one of the areas of conflicts observed with the performance of horizontal wells standoff with respect to development of thin oil rim reservoirs is examined. In a technical paper as part of the critical review of literature on the exploitation of thin oil rim reservoirs with large gas cap and aquifer, this author had highlighted the problem. As part of sensitives in horizontal well standoff, Cosmos and Fatoke (2004) tested three positions; one-third, centre and two-third positions from the GOC in a Niger Delta field. They concluded that the landing closest to the GOC (one-third position) yielded lowest Oil compared to the centre and two-third positions. Surprisingly the work done by Sai Garimella et al (2011) in a 60ft Ghariff & Al Khlata shallow marine low permeability sandstone reservoirs in a field in Oman showed a different result with the one-third position indicating an optimum recovery from a horizontal well. Interestingly both authors positions on the performance had support from other authors. This study used a 3D reservoir model, investigated different horizontal well standoff performances and applied permeability reduction to simulate different reservoir quality. The objective was to see if the reservoir quality was a factor in the different horizontal well standoff performance seen from different regions of the world while noting their different depositional environments. Results from the investigation is presented in this paper and shows a different trend from both authors mentioned above.
本文分析了薄油环油藏开发过程中观测到的与水平井性能冲突的领域之一。在一篇技术论文中，作为对具有大气顶和含水层的薄油环油藏开发的文献综述的一部分，作者强调了这个问题。Cosmos和Fatoke(2004年)对三个井位进行了测试。三分之一、中心和三分之二的位置来自尼日尔三角洲油田的GOC。他们得出结论，与中心位置和三分之二位置相比，最靠近GOC(三分之一位置)的着陆点产油最少。令人惊讶的是，Sai Garimella等人(2011年)在阿曼油田60英尺的Ghariff & al Khlata浅海低渗透砂岩储层中所做的工作显示了不同的结果，三分之一的位置表明水平井的最佳采收率。有趣的是，两位作者对性能的立场都得到了其他作者的支持。该研究采用三维储层模型，研究了不同水平井的横向性能，并采用渗透率降数值模拟了不同的储层质量。目的是了解储层质量是否是造成世界不同地区不同沉积环境下不同水平井表现的一个因素。本文给出了调查结果，并显示了与上述两位作者不同的趋势。
{"title":"Horizontal Well Standoff Performance and Exploitation of Thin Oil Rim","authors":"Peter Obidike, M. Onyekonwu, C. Ubani","doi":"10.2118/198725-MS","DOIUrl":"https://doi.org/10.2118/198725-MS","url":null,"abstract":"\u0000 In this paper one of the areas of conflicts observed with the performance of horizontal wells standoff with respect to development of thin oil rim reservoirs is examined.\u0000 In a technical paper as part of the critical review of literature on the exploitation of thin oil rim reservoirs with large gas cap and aquifer, this author had highlighted the problem. As part of sensitives in horizontal well standoff, Cosmos and Fatoke (2004) tested three positions; one-third, centre and two-third positions from the GOC in a Niger Delta field. They concluded that the landing closest to the GOC (one-third position) yielded lowest Oil compared to the centre and two-third positions. Surprisingly the work done by Sai Garimella et al (2011) in a 60ft Ghariff & Al Khlata shallow marine low permeability sandstone reservoirs in a field in Oman showed a different result with the one-third position indicating an optimum recovery from a horizontal well. Interestingly both authors positions on the performance had support from other authors.\u0000 This study used a 3D reservoir model, investigated different horizontal well standoff performances and applied permeability reduction to simulate different reservoir quality. The objective was to see if the reservoir quality was a factor in the different horizontal well standoff performance seen from different regions of the world while noting their different depositional environments. Results from the investigation is presented in this paper and shows a different trend from both authors mentioned above.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85614091","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}
Successful oil and gas field development in clastic reservoirs is usually dependent on the amount of subsurface data available to be evaluated during field maturation. The general rule is that more data reduces subsurface uncertainties. This invites expensive appraisal campaigns that invariably leads to delays in investment decisions and increased costs in development projects. The present study highlights how the understanding and definition of the architecture of the reservoir coupled with the use of analogue database as a methodology can be used to enhance hydrocarbon development in fields that are not fully appraised. The un-appraised Kz field is used as a case study. Kz field, with an expectation In-Place oil of ca. 1150 MMstb is located SW of the Kashagan field in the Caspian Sea, Kazakhstan. The field consists of 11 stacked hydrocarbon-bearing reservoirs of varying thicknesses penetrated by a single exploration well. Due to the paucity of well penetration, subsurface uncertainty that impact on hydrocarbon volume and recovery is high. The methodology used was to combine the wells log and core data in addition to the use of sequence stratigraphic technique to derive sedimentological conceptual models. Analogue databases were then used to derive a geological meaningful range of dimensions for the geometry of the respective sand bodies. These ranges were then used an input for in-place volume ranges. Evaluation results showed a volume range that could support a go-forward decision for further investment in the field. Based on these results, some preliminary field development decisions were taken prior to dynamic simulation. Decisions include; (i) Drill six wells (ii) Do Multi-zone Well Completions and (iii) use two drill centers to optimally develop the field (Phase-1). The key strength of this approach is that some key Field Development decisions can already be made before appraisal using basic sedimentological concepts and analogue database studies.
{"title":"Reservoir Architecture as a Driver for Effective Field Development Planning in an Un-Appraised Field; Kz field, Kazakhstan as a Case Study","authors":"O. Kakayor","doi":"10.2118/198816-MS","DOIUrl":"https://doi.org/10.2118/198816-MS","url":null,"abstract":"\u0000 Successful oil and gas field development in clastic reservoirs is usually dependent on the amount of subsurface data available to be evaluated during field maturation. The general rule is that more data reduces subsurface uncertainties. This invites expensive appraisal campaigns that invariably leads to delays in investment decisions and increased costs in development projects. The present study highlights how the understanding and definition of the architecture of the reservoir coupled with the use of analogue database as a methodology can be used to enhance hydrocarbon development in fields that are not fully appraised. The un-appraised Kz field is used as a case study.\u0000 Kz field, with an expectation In-Place oil of ca. 1150 MMstb is located SW of the Kashagan field in the Caspian Sea, Kazakhstan. The field consists of 11 stacked hydrocarbon-bearing reservoirs of varying thicknesses penetrated by a single exploration well. Due to the paucity of well penetration, subsurface uncertainty that impact on hydrocarbon volume and recovery is high. The methodology used was to combine the wells log and core data in addition to the use of sequence stratigraphic technique to derive sedimentological conceptual models. Analogue databases were then used to derive a geological meaningful range of dimensions for the geometry of the respective sand bodies. These ranges were then used an input for in-place volume ranges.\u0000 Evaluation results showed a volume range that could support a go-forward decision for further investment in the field. Based on these results, some preliminary field development decisions were taken prior to dynamic simulation. Decisions include; (i) Drill six wells (ii) Do Multi-zone Well Completions and (iii) use two drill centers to optimally develop the field (Phase-1). The key strength of this approach is that some key Field Development decisions can already be made before appraisal using basic sedimentological concepts and analogue database studies.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"414 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84893753","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}
Enhanced Oil Recovery (EOR) methods continue to be dominant in improving world’s oil reserves as producing fields mature. Global growth of 18% was recorded in proved reserves between 2007 and 2017 (BP Statistical Review, 2018), with North America, which has invested in several EOR techniques, contributing about 14% to this growth. This proves that EOR stands as a long-term solution to the menace of dwindling reserves. Recently, nanotechnology has been gaining attention for application in the petroleum industry. It has been established that nanoparticles dispersed in base fluids such as water, brine or certain organic solvents (nanofluid) exhibit some special properties proved to be advantageous for EOR purposes. Additional recovery of about 30% has been recorded. However, permeability damage, which has been widely reported, is yet to be critically studied and analysed. The objective of this research was to investigate how two important properties; concentration and injection rate of the nanofluid, affect oil recovery, and as well establish the thresholds of conditions which lead to permeability impairment and injection fluid loss during nanoflooding with silica nanoparticles. The permeability impairment layer which is gradually formed at the rock pore surface is termed nanoskin (a concept introduced by the author). Four core samples were flooded with brine followed by silica nanofluid of four different concentrations viz; 0.01, 0.5, 2.0 amd 3.0% wt/wt respectively. The flooding process was accompanied with changing injection rates viz; 0.5, 1.0, 2.0, 3.0 cm3/min. The result indicated that concentration of 2.0% wt/wt and injection rate of 2.0 cm3/min were threshold levels that guaranteed optimal oil recovery from the Niger Delta core samples. The overall result demonstrates that nanoflooding is a viable EOR technique and establishes a combination of parameters that will minimize nanoskin formation during nano-EOR process.
{"title":"Experimental Investigation of Nanoskin Formation Threshold for Nano-Enhanced Oil Recovery Nano-EOR","authors":"Y. Omotosho, O. Falode, T. Ojo","doi":"10.2118/198857-MS","DOIUrl":"https://doi.org/10.2118/198857-MS","url":null,"abstract":"\u0000 Enhanced Oil Recovery (EOR) methods continue to be dominant in improving world’s oil reserves as producing fields mature. Global growth of 18% was recorded in proved reserves between 2007 and 2017 (BP Statistical Review, 2018), with North America, which has invested in several EOR techniques, contributing about 14% to this growth. This proves that EOR stands as a long-term solution to the menace of dwindling reserves. Recently, nanotechnology has been gaining attention for application in the petroleum industry. It has been established that nanoparticles dispersed in base fluids such as water, brine or certain organic solvents (nanofluid) exhibit some special properties proved to be advantageous for EOR purposes. Additional recovery of about 30% has been recorded. However, permeability damage, which has been widely reported, is yet to be critically studied and analysed.\u0000 The objective of this research was to investigate how two important properties; concentration and injection rate of the nanofluid, affect oil recovery, and as well establish the thresholds of conditions which lead to permeability impairment and injection fluid loss during nanoflooding with silica nanoparticles. The permeability impairment layer which is gradually formed at the rock pore surface is termed nanoskin (a concept introduced by the author).\u0000 Four core samples were flooded with brine followed by silica nanofluid of four different concentrations viz; 0.01, 0.5, 2.0 amd 3.0% wt/wt respectively. The flooding process was accompanied with changing injection rates viz; 0.5, 1.0, 2.0, 3.0 cm3/min.\u0000 The result indicated that concentration of 2.0% wt/wt and injection rate of 2.0 cm3/min were threshold levels that guaranteed optimal oil recovery from the Niger Delta core samples. The overall result demonstrates that nanoflooding is a viable EOR technique and establishes a combination of parameters that will minimize nanoskin formation during nano-EOR process.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90481230","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The most common methods of interpolation are direct, lagrange, newton divided difference, and spline. Each of these techniques has first, second, and third order approximating polynomials that can be used anytime the need for interpolation arises in mathematical analysis. Of all the methods outlined above, the first order approximating polynomials of these interpolation techniques have found great use because of the ease of application. The fact that these polynomials estimate approximate values calls for the need to check the most accurate interpolation method. Accuracy in reservoir modelling and analysis is of great importance to the petroleum industry because business decisions are taken from the outcome of such analysis. Most of these analyses depend on the accuracy of interpolation been employed. In this paper, some basic PVT parameters were analyzed with both large and few data points. Few data points were used in order to replicate real life scenario since most of the PVT parameters come with few data point after laboratory experiments. For the large data points, all the interpolating techniques irrespective of the order of their approximating polynomials gave a good result but with few data points, different results were obtained. From the results, it was observed that for PVT interpolations, spline third order approximating polynomial performed better than the rest with few data points.
{"title":"Divergent View on the Use of Interpolation Techniques in Reservoir Analysis","authors":"Ebuka Ezenworo, G. Achumba, K. Adenuga","doi":"10.2118/198839-MS","DOIUrl":"https://doi.org/10.2118/198839-MS","url":null,"abstract":"\u0000 The most common methods of interpolation are direct, lagrange, newton divided difference, and spline. Each of these techniques has first, second, and third order approximating polynomials that can be used anytime the need for interpolation arises in mathematical analysis. Of all the methods outlined above, the first order approximating polynomials of these interpolation techniques have found great use because of the ease of application. The fact that these polynomials estimate approximate values calls for the need to check the most accurate interpolation method. Accuracy in reservoir modelling and analysis is of great importance to the petroleum industry because business decisions are taken from the outcome of such analysis. Most of these analyses depend on the accuracy of interpolation been employed.\u0000 In this paper, some basic PVT parameters were analyzed with both large and few data points. Few data points were used in order to replicate real life scenario since most of the PVT parameters come with few data point after laboratory experiments. For the large data points, all the interpolating techniques irrespective of the order of their approximating polynomials gave a good result but with few data points, different results were obtained. From the results, it was observed that for PVT interpolations, spline third order approximating polynomial performed better than the rest with few data points.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83240412","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}
Y. Akinnurun, Cyrusba Dagogo-Jack, Innocent Okogbue, M. Ogweda, Anthony Afoaku, Tochukwu Dinyelu
Productivity impairment has been a reoccurring issue within the life cycle of wells globally. This is consequent on various factors which include near wellbore damage. The cause and extent of near wellbore damage for suspected wells, can be understood by evaluating the inflow performance, alongside a systemic understanding of the asset and identification of exceptions from expected trends. Some of the major deterrents to the remediation of near wellbore damage include, poor selection of candidate wells and improper selection/deployment of the remediation technology. Microemulsion fluids have been successfully deployed to effectively manage the persistent problem of near-wellbore damage in Rona Field. This technical paper describes the steps taken to implement a successful rigless microemulsion stimulation job (matrix stimulation) on two wells in Rona Field, which resulted in total production gain of about 1400 BOPD. In the course of this work, a structured candidate screening exercise was carried out on the wells and reservoirs in Rona Field, by leveraging embedded analytics in SEPAL well, reservoir and facility management (WRFM) tool to identify wells with impaired productivity due to formation damage. Thereafter, a carefully designed Microemulsion treatment system having an ultra-low interfacial tension, high solvency and compatibility with the formation fluids was formulated and deployed. The Microemulsion stimulation treatment resulted in approximately 411% and 30% increment in oil rates for RONA-07S and RONA-12S respectively. The lessons learnt, best practices adopted on the execution of the job, together with the operational challenges encountered and how they were resolved will be discussed in this paper.
{"title":"Production Enhancement Using Microemulsion Technology in Rona Field","authors":"Y. Akinnurun, Cyrusba Dagogo-Jack, Innocent Okogbue, M. Ogweda, Anthony Afoaku, Tochukwu Dinyelu","doi":"10.2118/198875-MS","DOIUrl":"https://doi.org/10.2118/198875-MS","url":null,"abstract":"Productivity impairment has been a reoccurring issue within the life cycle of wells globally. This is consequent on various factors which include near wellbore damage. The cause and extent of near wellbore damage for suspected wells, can be understood by evaluating the inflow performance, alongside a systemic understanding of the asset and identification of exceptions from expected trends. Some of the major deterrents to the remediation of near wellbore damage include, poor selection of candidate wells and improper selection/deployment of the remediation technology. Microemulsion fluids have been successfully deployed to effectively manage the persistent problem of near-wellbore damage in Rona Field. This technical paper describes the steps taken to implement a successful rigless microemulsion stimulation job (matrix stimulation) on two wells in Rona Field, which resulted in total production gain of about 1400 BOPD.\u0000 In the course of this work, a structured candidate screening exercise was carried out on the wells and reservoirs in Rona Field, by leveraging embedded analytics in SEPAL well, reservoir and facility management (WRFM) tool to identify wells with impaired productivity due to formation damage. Thereafter, a carefully designed Microemulsion treatment system having an ultra-low interfacial tension, high solvency and compatibility with the formation fluids was formulated and deployed.\u0000 The Microemulsion stimulation treatment resulted in approximately 411% and 30% increment in oil rates for RONA-07S and RONA-12S respectively. The lessons learnt, best practices adopted on the execution of the job, together with the operational challenges encountered and how they were resolved will be discussed in this paper.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78808620","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}
Well production allocation is the cornerstone of reservoir surveillance and sound reservoir management. The apparent simplicity of the allocation process often results in an underestimation of its critical importance. However, the accuracy of the production rates allocation has an overwhelming impact on the company's ability to use sound data and perform model-driven analytics. As a result, the reliability of production forecasts, reserves estimates, and production system optimization efforts are affected by the selected allocation approach. A common approach to well production allocation is based on the use of well tests closest in time to the point of interest. It assumes stable operating conditions and gradual changes in fractions of produced fluids. These assumptions rarely reflect reality and therefore lead to large allocation errors. Use of more sophisticated solutions, such as data-driven and model-driven integrated well-reservoir tools pose different challenges due to the constant need for time-consuming updates. In this paper, we present a quick and efficient approach for production data allocation based on single layer Radial Basis Function Network - a variation of Artificial Neural Network. The procedure takes advantage of full well test dataset and can be effectively used in real time. We show that this approach does not suffer from the limitations of the more common approaches while delivering improved results.
{"title":"Use of Radial Basis Function Networks for Efficient Well Production Allocation","authors":"M. Zubarev, D. Zubarev","doi":"10.2118/198860-MS","DOIUrl":"https://doi.org/10.2118/198860-MS","url":null,"abstract":"\u0000 Well production allocation is the cornerstone of reservoir surveillance and sound reservoir management. The apparent simplicity of the allocation process often results in an underestimation of its critical importance. However, the accuracy of the production rates allocation has an overwhelming impact on the company's ability to use sound data and perform model-driven analytics. As a result, the reliability of production forecasts, reserves estimates, and production system optimization efforts are affected by the selected allocation approach.\u0000 A common approach to well production allocation is based on the use of well tests closest in time to the point of interest. It assumes stable operating conditions and gradual changes in fractions of produced fluids. These assumptions rarely reflect reality and therefore lead to large allocation errors. Use of more sophisticated solutions, such as data-driven and model-driven integrated well-reservoir tools pose different challenges due to the constant need for time-consuming updates.\u0000 In this paper, we present a quick and efficient approach for production data allocation based on single layer Radial Basis Function Network - a variation of Artificial Neural Network. The procedure takes advantage of full well test dataset and can be effectively used in real time. We show that this approach does not suffer from the limitations of the more common approaches while delivering improved results.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78943408","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}
Aisha Tukur, P. Nzerem, Nhoyidi Nsan, I. Okafor, A. Gimba, O. Ogolo, A. Oluwaseun, O. Andrew
The general success ratio of wells drilled lies at 1:4, which highlights the difficulty in properly ascertaining sweetspots. well placement location selection is one of the most important processes to ensure optimal recovery of hydrocarbons. Conventionally, a subjective decision is based on the visualization of the HUPHISO (a product of net-to-gross, porosity and oil saturation) map. While this approach identifies regions of high HUPHISO regarded as sweetspots in the reservoir; it lacks consideration for neighbouring regions of the sweetspot. This sometimes lead to placement of wells in a sweetspot but near an adjoining aquifer; giving rise to early water breakthrough - low hydrocarbon recovery. Recently, heuristic optimization techniques. Genetic algorithm (GA) and simulated annealing (SA) has received attention as methods of selection of well-placement locations. This project developed and implemented GA and SA well-placement algorithms and compared the reservoir performance outputs to that of conventional method. Firstly, a reservoir performance model was built using a reservoir flow simulator. In the base case, the wells were placed based on a subjective selection of gridblocks upon the visualization of the HUPHISO map. Thereafter, JAVA routines of GA and SA well-placement algorithms were developed. The numeric data (ASCII format) underlying the map were then exported to the routines. Finally, the performance model was updated with new well locations as selected based on the GA and SA-based approach and the results were compared to the base case. The Comparison of the results showed that both GA and SA-based approach resulted to an increased recovery and time before water breakthrough.
{"title":"Well Placement Optimization Using Simulated Annealing and Genetic Algorithm","authors":"Aisha Tukur, P. Nzerem, Nhoyidi Nsan, I. Okafor, A. Gimba, O. Ogolo, A. Oluwaseun, O. Andrew","doi":"10.2118/198858-MS","DOIUrl":"https://doi.org/10.2118/198858-MS","url":null,"abstract":"\u0000 The general success ratio of wells drilled lies at 1:4, which highlights the difficulty in properly ascertaining sweetspots. well placement location selection is one of the most important processes to ensure optimal recovery of hydrocarbons. Conventionally, a subjective decision is based on the visualization of the HUPHISO (a product of net-to-gross, porosity and oil saturation) map. While this approach identifies regions of high HUPHISO regarded as sweetspots in the reservoir; it lacks consideration for neighbouring regions of the sweetspot. This sometimes lead to placement of wells in a sweetspot but near an adjoining aquifer; giving rise to early water breakthrough - low hydrocarbon recovery. Recently, heuristic optimization techniques. Genetic algorithm (GA) and simulated annealing (SA) has received attention as methods of selection of well-placement locations. This project developed and implemented GA and SA well-placement algorithms and compared the reservoir performance outputs to that of conventional method. Firstly, a reservoir performance model was built using a reservoir flow simulator. In the base case, the wells were placed based on a subjective selection of gridblocks upon the visualization of the HUPHISO map. Thereafter, JAVA routines of GA and SA well-placement algorithms were developed. The numeric data (ASCII format) underlying the map were then exported to the routines.\u0000 Finally, the performance model was updated with new well locations as selected based on the GA and SA-based approach and the results were compared to the base case. The Comparison of the results showed that both GA and SA-based approach resulted to an increased recovery and time before water breakthrough.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"165 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76921268","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}
Accurate estimation of two-phase compressibility factor is of great importance in predicting the performance of a gas condensate reservoir using the material balance approach. Over the years, several correlations for estimating gas compressibility factor have been developed. Some of these correlations are; the Standing and Katz, Rayes etal, Dranchuk and Abou-Kassem, Brill and Beggs’ and Hall-Yarborough’s correlations. However, these correlations have not been so successful in predicting the compressibility factor of gas reservoir fluids in the two-phase region (below dew point pressure) and this explains why the industry still relies on the expensive and time-consuming constant volume depletion (CVD) approach. Therefore, this paper presents two different correlations for estimating two-phase compressibility factor using stochastic and robust gradient-based Newton-Raphson optimization algorithm. The first correlation presents the two-phase Z-factor as a function of pseudo-reduced pressure, pseudo-reduced temperature and the specific gravity. The second correlation on the other hand presents the two-phase Z-factor as a function of the single-phase Z-factor (obtained using Standing and Katz approach). Both correlations were developed using over 50 constant volume depletion (CVD) data of reservoir fluid samples obtained from gas condensate reservoirs around the world. Furthermore, in order to develop these correlations, two different models were proposed and the heptane-plus (C7+) and acid gas fractions were accounted for using the Sutton’s and Lee Kesler correlations respectively. Moreover, using the expected values of the pseudo-reduced pressure, pseudo-reduced temperature, specific gravity and single-phase Z-factor (all obtained using appropriate probability distributions) as the input variables, the optimum values of the models’ fitting parameters that minimize the sum of squares of the errors (SSE) were obtained using the stochastic and robust optimization algorithm(an algorithm obtained from Taylor series expansion of the error function and implemented on Octave programming language for the purpose of this study). Finally, having developed the correlations using 70% of the available data, the performances of these correlations were evaluated using 30% of the available data and the results obtained shows that these correlations outperform other pre-existing correlations.
{"title":"Development of Two-Phase Compressibility Factor Correlations Using a Stochastic and Robust Gradient-Based Optimization Algorithm.","authors":"A. Sheriff","doi":"10.2118/198792-MS","DOIUrl":"https://doi.org/10.2118/198792-MS","url":null,"abstract":"\u0000 Accurate estimation of two-phase compressibility factor is of great importance in predicting the performance of a gas condensate reservoir using the material balance approach. Over the years, several correlations for estimating gas compressibility factor have been developed. Some of these correlations are; the Standing and Katz, Rayes etal, Dranchuk and Abou-Kassem, Brill and Beggs’ and Hall-Yarborough’s correlations. However, these correlations have not been so successful in predicting the compressibility factor of gas reservoir fluids in the two-phase region (below dew point pressure) and this explains why the industry still relies on the expensive and time-consuming constant volume depletion (CVD) approach. Therefore, this paper presents two different correlations for estimating two-phase compressibility factor using stochastic and robust gradient-based Newton-Raphson optimization algorithm. The first correlation presents the two-phase Z-factor as a function of pseudo-reduced pressure, pseudo-reduced temperature and the specific gravity. The second correlation on the other hand presents the two-phase Z-factor as a function of the single-phase Z-factor (obtained using Standing and Katz approach). Both correlations were developed using over 50 constant volume depletion (CVD) data of reservoir fluid samples obtained from gas condensate reservoirs around the world. Furthermore, in order to develop these correlations, two different models were proposed and the heptane-plus (C7+) and acid gas fractions were accounted for using the Sutton’s and Lee Kesler correlations respectively. Moreover, using the expected values of the pseudo-reduced pressure, pseudo-reduced temperature, specific gravity and single-phase Z-factor (all obtained using appropriate probability distributions) as the input variables, the optimum values of the models’ fitting parameters that minimize the sum of squares of the errors (SSE) were obtained using the stochastic and robust optimization algorithm(an algorithm obtained from Taylor series expansion of the error function and implemented on Octave programming language for the purpose of this study). Finally, having developed the correlations using 70% of the available data, the performances of these correlations were evaluated using 30% of the available data and the results obtained shows that these correlations outperform other pre-existing correlations.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78280286","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}
Drilling fluid is one of the major substances used when drilling a well, as it serves numerous purposes such as lubrication and cooling of the drilling bit, cuttings removal to mention a few. And one of its major constituent is the bentonite, clay that serves as the dispersed phase. The cost of procuring the bentonite clay for the production of drilling fluid is expensive because of its importation into the country hereby increasing the overall cost of drilling a well. This paper investigated the suitability of suspected clay from Uwheru and Otor-Udu village in Delta State, Nigeria for the production of water based drilling fluid. The mud was formulated using 21.0g of each clay local sample and 350ml of fresh water. Different concentrations of pH and viscosity chemical additives were used. Comparative analysis was made on the drilling mud sample formulated from clay obtained from the study areas namely (Uwheru and Otor-Udu) to determine their suitability for the formulation of drilling fluids and to determine if it meets the API standard. The properties tested for include the mud density, pH, sand content and rheological properties. After laboratory work was conducted, the two formulated mud samples had same mud weight of 8.5ppg which was slightly below the API standard for bentonite clay of 8.65minimum and 9.60maximum. A pH control additive (NaOH) and Viscosifier additive (CMC) were added. In conclusion, analysis was made on the experimental values of Uwheru which had values of 3cp for 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.1ml and density of 8.5ppg while that of Otor-Udu had values of 3cp and 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.05ml and density of 8.5ppg. From the analysis made between the local clay formulated drilling fluid samples and the standard API values for bentonite using graphs and charts, the local clay can be improvised for bentonite.
{"title":"Formulation of Water Based Drilling Fluid Using Local Mud Uwheru & Otor-Udu Clay","authors":"Aihie John Odion","doi":"10.2118/198737-MS","DOIUrl":"https://doi.org/10.2118/198737-MS","url":null,"abstract":"\u0000 Drilling fluid is one of the major substances used when drilling a well, as it serves numerous purposes such as lubrication and cooling of the drilling bit, cuttings removal to mention a few. And one of its major constituent is the bentonite, clay that serves as the dispersed phase. The cost of procuring the bentonite clay for the production of drilling fluid is expensive because of its importation into the country hereby increasing the overall cost of drilling a well.\u0000 This paper investigated the suitability of suspected clay from Uwheru and Otor-Udu village in Delta State, Nigeria for the production of water based drilling fluid. The mud was formulated using 21.0g of each clay local sample and 350ml of fresh water. Different concentrations of pH and viscosity chemical additives were used. Comparative analysis was made on the drilling mud sample formulated from clay obtained from the study areas namely (Uwheru and Otor-Udu) to determine their suitability for the formulation of drilling fluids and to determine if it meets the API standard. The properties tested for include the mud density, pH, sand content and rheological properties.\u0000 After laboratory work was conducted, the two formulated mud samples had same mud weight of 8.5ppg which was slightly below the API standard for bentonite clay of 8.65minimum and 9.60maximum. A pH control additive (NaOH) and Viscosifier additive (CMC) were added.\u0000 In conclusion, analysis was made on the experimental values of Uwheru which had values of 3cp for 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.1ml and density of 8.5ppg while that of Otor-Udu had values of 3cp and 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.05ml and density of 8.5ppg. From the analysis made between the local clay formulated drilling fluid samples and the standard API values for bentonite using graphs and charts, the local clay can be improvised for bentonite.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80022779","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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