Fan Songlin, Xiaofang Wang, Jun Dong, Qiuyan You, Xiaochun Yang, Junfeng Zhao
Dagang Oilfield is a part of oil-gas reservoir with various reservoir types, broken fault block, high heterogeneity and complex geological situations. For example, in low pressure and high permeability reservoirs, permeability is higher than 2000 mD and pressure coefficient is less than 0.5. The salinity of formation water in low permeability reservoir is as high as 30000 mg/L, and the pour point of crude oil is as high as 40 °C. The statistics show that the average recovery time of the well yield after remedial work is over 7 days, and the average recovery rate of the well yield is less than 87% in Dagang Oilfield, which have an influence on the stable production and the benefit development of the oilfield. The problem above has not been effectively resolved for a long time because of the factors of technology and cost. In this paper, a series of low cost formation protection technology were developed. First, the low-cost nitrogen microbubble temporary blocking technology, which can block 2 mm aperture, was developed by improving preparation technology of nitrogen microbubble working fluid and adding degradable temporary blocking material. Second, the formation protection for complex low-permeability reservoirs was developed by enhancing the temperature of workover fluid and adding the high efficiency surfactants. The results show that the temperature of workover fluid increases by 20-50 °C. Finally, the low-cost workover operation technology with formation protection was developed. The cost can be reduced more than 50% while protecting the formation. So far, the all technologies were successfully applied in 2135 wells. After the application of technology, the average recovery time of the well yield is 3.5 days, the average recovery rate of the well yield is 96%, and the total production loss is 15.7 ° 104t. The problem of the formation pollution during the workover has been effectively resolved, which provides technical support for the production stability of complex fault block oilfield.
{"title":"Research of Formation Protection Technology in Complex Fault Block Oilfield","authors":"Fan Songlin, Xiaofang Wang, Jun Dong, Qiuyan You, Xiaochun Yang, Junfeng Zhao","doi":"10.2523/IPTC-19510-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19510-MS","url":null,"abstract":"\u0000 Dagang Oilfield is a part of oil-gas reservoir with various reservoir types, broken fault block, high heterogeneity and complex geological situations. For example, in low pressure and high permeability reservoirs, permeability is higher than 2000 mD and pressure coefficient is less than 0.5. The salinity of formation water in low permeability reservoir is as high as 30000 mg/L, and the pour point of crude oil is as high as 40 °C. The statistics show that the average recovery time of the well yield after remedial work is over 7 days, and the average recovery rate of the well yield is less than 87% in Dagang Oilfield, which have an influence on the stable production and the benefit development of the oilfield. The problem above has not been effectively resolved for a long time because of the factors of technology and cost. In this paper, a series of low cost formation protection technology were developed. First, the low-cost nitrogen microbubble temporary blocking technology, which can block 2 mm aperture, was developed by improving preparation technology of nitrogen microbubble working fluid and adding degradable temporary blocking material. Second, the formation protection for complex low-permeability reservoirs was developed by enhancing the temperature of workover fluid and adding the high efficiency surfactants. The results show that the temperature of workover fluid increases by 20-50 °C. Finally, the low-cost workover operation technology with formation protection was developed. The cost can be reduced more than 50% while protecting the formation. So far, the all technologies were successfully applied in 2135 wells. After the application of technology, the average recovery time of the well yield is 3.5 days, the average recovery rate of the well yield is 96%, and the total production loss is 15.7 ° 104t. The problem of the formation pollution during the workover has been effectively resolved, which provides technical support for the production stability of complex fault block oilfield.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74680286","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}
Xinquan Zheng, T. Moh, Nan Huang, Ning Ke, Gan Geng, Jer Huh Chin, Cheng Zhang, X. Wang, Dong Liu, Lei Yang
Being the world's third largest shale gas producer after the US and Canada, China delivered an output of 9 billion cubic meters (bcm) in 2017. China has the world's largest technically recoverable reserves of shale gas, of which US Energy Information Administration (EIA) estimates at 31.6 tcm, 68% higher than shale reserves in the US. Unlike the US who started to explore shale gas in the 1980s, China only completed the first shale gas well in 2011. Development of shale gas resources is expected to play a vital role in China's enthusiastically planned transition to a low-carbon energy future. On September 14th, 2016, Chinese National Energy Board released Shale Gas Development Plan 2016-2020. In the plan, shale gas production goal was set at 30 bcm for 2020. With an average shale gas production of 20MCM per well per year, it is estimated that a minimum of 1500 horizontal wells with 1000m lateral length are needed by the year of 2020. The question arises whether what kind of drilling performance is needed to meet the aggressive development target. In less than a decade, Petro China, its subsidiaries and contractors have made significant breakthroughs in shale gas exploration, not only in capacity, but also drilling techniques. The paper captures the success and lessons that the drillers had gained in the last 7 years in terms of drilling performance. It is well known that China shale gas reserves are in geologically challenging areas. The challenges consisted of hard formations with kicks, losses, frequent stuck pipe and over pressure formation. The problems were amplified by high geological formation dip, faults, and stratigraphic uncertainties. In this harsh drilling environment, rate of penetration was slow, trajectory control is difficult, mud weight and circulating pressure are high, downhole torsional vibration, drilling torque and stick&slip are high, rig equipment and downhole tools fail prematurely, and non-productive time is excessive. Over the years, the team had demonstrated that with systematic, scientific and engineering drilling approaches, a considerable improvement in drilling performance can be achieved. To deliver and execute the optimized drilling approaches, high intregration and synergy between each drilling segment are required. These approaches are nothing new in the drilling world, these are optimization in Well Plan, Mud Properties, Rig Capacity & Drilling Parameters, Bottome Hole Aseembly (BHA) selection and design, best Drilling Practice and Drilling Operation Efficiency. These are all part of a formula to success; the key is to rightly balance each one of them. The team sucessfully reduce average well days from 120 to 30 in one particular field. Along the way, the team also identify a few more components to the formula of success, with that, the short-term goal shall be further reducing the well days to 25 days, and less than 20 days in long term.
{"title":"Shale Gas Drilling Performance Break Through in Wei Yuan– Relentless Scientific and Engineering Approaches for the Unconventional Resources in Central China","authors":"Xinquan Zheng, T. Moh, Nan Huang, Ning Ke, Gan Geng, Jer Huh Chin, Cheng Zhang, X. Wang, Dong Liu, Lei Yang","doi":"10.2523/IPTC-19371-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19371-MS","url":null,"abstract":"\u0000 Being the world's third largest shale gas producer after the US and Canada, China delivered an output of 9 billion cubic meters (bcm) in 2017. China has the world's largest technically recoverable reserves of shale gas, of which US Energy Information Administration (EIA) estimates at 31.6 tcm, 68% higher than shale reserves in the US. Unlike the US who started to explore shale gas in the 1980s, China only completed the first shale gas well in 2011.\u0000 Development of shale gas resources is expected to play a vital role in China's enthusiastically planned transition to a low-carbon energy future. On September 14th, 2016, Chinese National Energy Board released Shale Gas Development Plan 2016-2020. In the plan, shale gas production goal was set at 30 bcm for 2020. With an average shale gas production of 20MCM per well per year, it is estimated that a minimum of 1500 horizontal wells with 1000m lateral length are needed by the year of 2020. The question arises whether what kind of drilling performance is needed to meet the aggressive development target.\u0000 In less than a decade, Petro China, its subsidiaries and contractors have made significant breakthroughs in shale gas exploration, not only in capacity, but also drilling techniques. The paper captures the success and lessons that the drillers had gained in the last 7 years in terms of drilling performance. It is well known that China shale gas reserves are in geologically challenging areas. The challenges consisted of hard formations with kicks, losses, frequent stuck pipe and over pressure formation. The problems were amplified by high geological formation dip, faults, and stratigraphic uncertainties. In this harsh drilling environment, rate of penetration was slow, trajectory control is difficult, mud weight and circulating pressure are high, downhole torsional vibration, drilling torque and stick&slip are high, rig equipment and downhole tools fail prematurely, and non-productive time is excessive. Over the years, the team had demonstrated that with systematic, scientific and engineering drilling approaches, a considerable improvement in drilling performance can be achieved. To deliver and execute the optimized drilling approaches, high intregration and synergy between each drilling segment are required. These approaches are nothing new in the drilling world, these are optimization in Well Plan, Mud Properties, Rig Capacity & Drilling Parameters, Bottome Hole Aseembly (BHA) selection and design, best Drilling Practice and Drilling Operation Efficiency. These are all part of a formula to success; the key is to rightly balance each one of them. The team sucessfully reduce average well days from 120 to 30 in one particular field. Along the way, the team also identify a few more components to the formula of success, with that, the short-term goal shall be further reducing the well days to 25 days, and less than 20 days in long term.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78597189","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}
Liu Xiaodong, Yonghui Gao, Hou Wei, Ma Yongle, Zhang Yong
Oil based drilling fluids, polysulfonate and other toxic drilling fluids have been restricted to use by strict environmental protection laws and regulations, when drilling in high temperature well in environmentally sensitive sea areas. Meanwhile, the environmental requirements of drilling fluid biological toxicity value LC50 greater than 30,000mg/L, Hg content of barite less than 1mg/L and Cd content less than 3 mg/L, which brings severe challenges for high temperature drilling fluids and offshore environmental protection. A kind of new non-toxic and high temperature polymer drilling fluid with the temperature resistance for 200°C and the biotoxicity value satisfied the discharge standard of the first class sea area has been developed in order to meet the requirements of high temperature deep well drilling operation and environmental protection. It can also drastically reduce the costs of waste disposal that is due to the drilling fluid and drilling cuttings can be discharged directly to the sea. A high temperature polymer filtrate reducer with temperature resistance for 200°Cand viscosifier with temperature resistance for 180°C both have been developed, which are used for high temperature filtration control and rheology regulation. This new system consists of these two high-temperature synthetic polymer materials, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight materials. The formula and performance of drilling fluid are studied which suitable for drilling under different formation pressure coefficients, and the performance of drilling fluids at different bottom hole temperatures are also reviewed, so as to prove it can provide superior fluid performance for various harsh drilling conditions. The test results showed that the drilling fluid has the following main technical features: temperature resistance for 200°C, 200°C thermal stability time more than 72h, HTHP water loss 15~25mL, aquatic biological toxicity LC50 value higher than 100,000mg/L, luminescent bacteria EC50 higher than 300,000 mg/L. The test results from a high temperature deep well in Bohai offshore oil field, with depth of the bottom well 6066m, and the bottom temperature 204°C, are also presented. This drilling fluid is environmentally friendly and meets the discharge requirements of offshore, which can greatly improve the HSE operation level and eliminate the rig costs associating with drilling and waste management, especially in remote sea and deep sea drilling, that the disposal cost of waste drilling fluid accounts for more than 30% of the total drilling fluid cost.
{"title":"Non-Toxic High Temperature Polymer Drilling Fluid Significantly Improving Marine Environmental AcceptabiIity and Reducing Cost for Offshore Drilling","authors":"Liu Xiaodong, Yonghui Gao, Hou Wei, Ma Yongle, Zhang Yong","doi":"10.2523/IPTC-19425-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19425-MS","url":null,"abstract":"\u0000 Oil based drilling fluids, polysulfonate and other toxic drilling fluids have been restricted to use by strict environmental protection laws and regulations, when drilling in high temperature well in environmentally sensitive sea areas. Meanwhile, the environmental requirements of drilling fluid biological toxicity value LC50 greater than 30,000mg/L, Hg content of barite less than 1mg/L and Cd content less than 3 mg/L, which brings severe challenges for high temperature drilling fluids and offshore environmental protection.\u0000 A kind of new non-toxic and high temperature polymer drilling fluid with the temperature resistance for 200°C and the biotoxicity value satisfied the discharge standard of the first class sea area has been developed in order to meet the requirements of high temperature deep well drilling operation and environmental protection. It can also drastically reduce the costs of waste disposal that is due to the drilling fluid and drilling cuttings can be discharged directly to the sea.\u0000 A high temperature polymer filtrate reducer with temperature resistance for 200°Cand viscosifier with temperature resistance for 180°C both have been developed, which are used for high temperature filtration control and rheology regulation. This new system consists of these two high-temperature synthetic polymer materials, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight materials. The formula and performance of drilling fluid are studied which suitable for drilling under different formation pressure coefficients, and the performance of drilling fluids at different bottom hole temperatures are also reviewed, so as to prove it can provide superior fluid performance for various harsh drilling conditions. The test results showed that the drilling fluid has the following main technical features: temperature resistance for 200°C, 200°C thermal stability time more than 72h, HTHP water loss 15~25mL, aquatic biological toxicity LC50 value higher than 100,000mg/L, luminescent bacteria EC50 higher than 300,000 mg/L. The test results from a high temperature deep well in Bohai offshore oil field, with depth of the bottom well 6066m, and the bottom temperature 204°C, are also presented.\u0000 This drilling fluid is environmentally friendly and meets the discharge requirements of offshore, which can greatly improve the HSE operation level and eliminate the rig costs associating with drilling and waste management, especially in remote sea and deep sea drilling, that the disposal cost of waste drilling fluid accounts for more than 30% of the total drilling fluid cost.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"128 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79017726","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}
Rock brittleness is a key factor to influence the fracture behavior in the formation. Therefore, it is important to evaluate the brittleness when doing the hydraulic fracturing. Previous studies provided various methods for rock brittleness evaluation. Few evaluations, however, could be applied for the naturally fractured carbonate formation because those methods did not integrate the influence from lithology, natural fractures and vugs. Hence, this paper indicated an integration evaluation method to investigate the brittleness in the naturally fractured carbonate formation. The rock in this study was from the formation in the Ordos Basin. The brittleness evaluation method asked the experiment studies that included triaxial compression test, continuous strength test, Kaiser test and X-Ray Diffraction analyze. Based on the results, the influence of substrate properties and fractures-vugs in fractured carbonate rock are analyzed. Then a method to evaluate the brittleness of fractured carbonate rock is raised in which the stress-strain curves of rock mechanics tests, geologic microcharacter and the characteristics of fractures are considered. The method can give a better application in Ordos Basin. The results show that the failure mode of fractured carbonate rock under the effect of confining pressure is mainly the shear failure. The facture will have an obvious effect on the strength of rock. The brittleness of fractured carbonate rock appears as the ability for resisting inelastic deformation before rupture and losing rate of bearing capacity after rupture, besides the minerals of rock and the development of fracture will influence the brittleness. With the increasing of confining pressure, the fractures tend to be closed which leads to the increasing of brittleness. However, the carbonate in high confining pressure is characterized by plasticity, the brittleness would reduce. The brittleness was used to design hydraulic fracturing work in the naturally fractured carbonate formation of Ordos Basin. Hydraulic fracturing is necessary to guarantee a successful development in the naturally fractured carbonate formation. Therefore, the brittleness evaluation method is worth to study when designing the hydraulic fracturing.
{"title":"Study on the Brittleness Evaluation in the Naturally Fractured Carbonate Formation and Its Application in the Ordos Basin","authors":"Xinxing Ma, J. Kao, Zhou Zhou","doi":"10.2523/IPTC-19139-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19139-MS","url":null,"abstract":"\u0000 Rock brittleness is a key factor to influence the fracture behavior in the formation. Therefore, it is important to evaluate the brittleness when doing the hydraulic fracturing. Previous studies provided various methods for rock brittleness evaluation. Few evaluations, however, could be applied for the naturally fractured carbonate formation because those methods did not integrate the influence from lithology, natural fractures and vugs. Hence, this paper indicated an integration evaluation method to investigate the brittleness in the naturally fractured carbonate formation.\u0000 The rock in this study was from the formation in the Ordos Basin. The brittleness evaluation method asked the experiment studies that included triaxial compression test, continuous strength test, Kaiser test and X-Ray Diffraction analyze. Based on the results, the influence of substrate properties and fractures-vugs in fractured carbonate rock are analyzed. Then a method to evaluate the brittleness of fractured carbonate rock is raised in which the stress-strain curves of rock mechanics tests, geologic microcharacter and the characteristics of fractures are considered. The method can give a better application in Ordos Basin.\u0000 The results show that the failure mode of fractured carbonate rock under the effect of confining pressure is mainly the shear failure. The facture will have an obvious effect on the strength of rock. The brittleness of fractured carbonate rock appears as the ability for resisting inelastic deformation before rupture and losing rate of bearing capacity after rupture, besides the minerals of rock and the development of fracture will influence the brittleness. With the increasing of confining pressure, the fractures tend to be closed which leads to the increasing of brittleness. However, the carbonate in high confining pressure is characterized by plasticity, the brittleness would reduce. The brittleness was used to design hydraulic fracturing work in the naturally fractured carbonate formation of Ordos Basin.\u0000 Hydraulic fracturing is necessary to guarantee a successful development in the naturally fractured carbonate formation. Therefore, the brittleness evaluation method is worth to study when designing the hydraulic fracturing.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84407303","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 failure around the wellbore is studied using a modified form of Drucker-Prager failure criterion (MDP). The MDP has a linear shear failure envelope in the meridian plane and a curve-sided triangular failure curve in the deviatoric plane which can be controlled by the yield stress ratio (K). The model is compatible with the rock strength measurements under true-triaxial stress conditions similar to the modified Lade (MLa) failure criterion. The MDP is used for stress modelling and wellbore stability analyses. The stress modelling is done by calculating the magnitude of maximum horizontal stress (SHmax) from the observed failure in the image log. The stress modelling result is compared with the results from the Mohr-Coulomb (MC), Drucker-Prager (DP), and modified Lade (MLa) criteria. The MDP is also used for wellbore stability analysis using both analytical and numerical (finite element) approaches. The analytical approach is used to conduct a sensitivity analysis to investigate the impact of well trajectory on minimum required mud weight. The finite element analysis is conducted to investigate the dimension of the breakout developed under different mud weights. The results are compared against the other failure criteria. The SHmax magnitude calculated from the MDP model falls between the MC and DP. The analysis shows that the MDP with K = 0.778 is compatible with the MLa results for a rock with an internal friction angle close to 30° for both SHmax magnitude modelling and minimum required mud weight calculations for the wellbore stability analysis. The results from the finite element analyses shows that the calculated breakout widths and depths using the MDP model falls between the MC and DP models. The analysis shows that in the presented case, although the calculated breakout width is large, the depth and amount of failed material around the wellbore are relatively small to create any wellbore instability problems. Hence, a mud weight relatively lower than calculated required mud weight from the analytical approach can be used in practice to drill the well. The results show the importance of considering the depth of the breakouts in the mud weight design.
{"title":"Wellbore Failure Modelling Using a Modified Drucker-Prager Criterion","authors":"A. Younessi","doi":"10.2523/IPTC-19126-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19126-MS","url":null,"abstract":"\u0000 The failure around the wellbore is studied using a modified form of Drucker-Prager failure criterion (MDP). The MDP has a linear shear failure envelope in the meridian plane and a curve-sided triangular failure curve in the deviatoric plane which can be controlled by the yield stress ratio (K). The model is compatible with the rock strength measurements under true-triaxial stress conditions similar to the modified Lade (MLa) failure criterion.\u0000 The MDP is used for stress modelling and wellbore stability analyses. The stress modelling is done by calculating the magnitude of maximum horizontal stress (SHmax) from the observed failure in the image log. The stress modelling result is compared with the results from the Mohr-Coulomb (MC), Drucker-Prager (DP), and modified Lade (MLa) criteria. The MDP is also used for wellbore stability analysis using both analytical and numerical (finite element) approaches. The analytical approach is used to conduct a sensitivity analysis to investigate the impact of well trajectory on minimum required mud weight. The finite element analysis is conducted to investigate the dimension of the breakout developed under different mud weights. The results are compared against the other failure criteria.\u0000 The SHmax magnitude calculated from the MDP model falls between the MC and DP. The analysis shows that the MDP with K = 0.778 is compatible with the MLa results for a rock with an internal friction angle close to 30° for both SHmax magnitude modelling and minimum required mud weight calculations for the wellbore stability analysis.\u0000 The results from the finite element analyses shows that the calculated breakout widths and depths using the MDP model falls between the MC and DP models. The analysis shows that in the presented case, although the calculated breakout width is large, the depth and amount of failed material around the wellbore are relatively small to create any wellbore instability problems. Hence, a mud weight relatively lower than calculated required mud weight from the analytical approach can be used in practice to drill the well. The results show the importance of considering the depth of the breakouts in the mud weight design.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84568250","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Hardy, Mark Baker, A. Robson, Jackson Williams, Chris Murphy, Liam O'Sullivan
Insights from appraisal well tests can take months to incorporate into subsurface modelling, causing delays to development planning and resulting in key decisions being made using incomplete data and sub-optimal methods. This is due to the time-consuming process of updating or rebuilding reservoir models, simulating them and subsequently analysing the results. In this project, a combination of automated geomodelling, rapid dynamic simulation and statistical analysis were applied to reduce the time to insights from months to days. Well test pressure data was used to condition a suite of reservoir models and evaluate the impact on the optimal development scenario. The application of this process increased confidence in the decision and reduced the modelled probability of low-side outcomes. In addition, we trialled a process to deliver an improvement to the geological understanding of the field through a reduction in the model uncertainties. We also discuss an extension of this concept to perform a robust value-of-information assessment of appraisal or development planning decisions.
{"title":"Statistical Model Updates for Fast-Tracked Model Insights and Value-of-Information","authors":"M. Hardy, Mark Baker, A. Robson, Jackson Williams, Chris Murphy, Liam O'Sullivan","doi":"10.2523/IPTC-19388-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19388-MS","url":null,"abstract":"\u0000 Insights from appraisal well tests can take months to incorporate into subsurface modelling, causing delays to development planning and resulting in key decisions being made using incomplete data and sub-optimal methods. This is due to the time-consuming process of updating or rebuilding reservoir models, simulating them and subsequently analysing the results. In this project, a combination of automated geomodelling, rapid dynamic simulation and statistical analysis were applied to reduce the time to insights from months to days. Well test pressure data was used to condition a suite of reservoir models and evaluate the impact on the optimal development scenario. The application of this process increased confidence in the decision and reduced the modelled probability of low-side outcomes. In addition, we trialled a process to deliver an improvement to the geological understanding of the field through a reduction in the model uncertainties. We also discuss an extension of this concept to perform a robust value-of-information assessment of appraisal or development planning decisions.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80923174","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}
Considering carbonate oil reservoirs, a rock fracture is a planar-shaped void filled with oil, water, gas and/or rock fines. These fractures vary in scale forming connected and complex networks of fractures. They have an effect on deliverability of fluids depending on their geometrical complexity, extent, matrix-fracture interaction, wettability, and orientation. In fractured reservoir rocks, relative to the rock matrix, fractures form highly permeable flow pathways that dominate fluid flow and transport in the reservoir which might have favorable or non-favorable effects on hydrocarbon production. It is crucial to characterize the fluid flow in the fracture networks to examine the root-cause relationships, the impact on hydrocarbon recovery and quantify the efficiency of enhanced recovery mechanisms. This work describes the development of a machine learning model for history matching and predicting two-phase relative permeability. Capitalizing on the main principles of the 4th Industrial Revolution (IR 4.0), the development of this model was achieved by training machine learning (ML) algorithms and using advanced predictive data analytics on data collected from lab experiments as input. The model derived from the analysis describes two-phase flow of oil and water in a single discretized fracture taking into account fracture aperture, wall roughness, orientation and, flow rates and direction. It also accommodates fluids and fracture characteristics to match laboratory SCAL experimental of co-current oil and water flow in a mixed-wettability single fracture modeled as narrow gap in a Hele-Shaw cell. The experimental data exhibit variations in shape and end-points that mainly reflect the effects of fracture aperture, roughness, inclination, and hysteresis effects. This in turn demonstrate the effects of phase interference, saturation changes, and major forces acting on two-phase flow in fractures like capillary and viscous forces. The empirical relationship showed an acceptable match to the experimentally derived relative permeability in most of the cases as well as good predictive capabilities against the blind tests on other sets of experimental data and numerical simulation models. Having both fracture relative permeability data (describing the fluids flow) and detailed fracture characterization improves our understanding of the reservoir dynamics and fractured network impact on hydrocarbon recovery.
{"title":"Prediction of Two-Phase Flow Relative Permeability in Discrete Fractures","authors":"A. Al-Turki, Amell A. Al-Ghamdi, M. Maučec","doi":"10.2523/IPTC-19557-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19557-MS","url":null,"abstract":"\u0000 Considering carbonate oil reservoirs, a rock fracture is a planar-shaped void filled with oil, water, gas and/or rock fines. These fractures vary in scale forming connected and complex networks of fractures. They have an effect on deliverability of fluids depending on their geometrical complexity, extent, matrix-fracture interaction, wettability, and orientation. In fractured reservoir rocks, relative to the rock matrix, fractures form highly permeable flow pathways that dominate fluid flow and transport in the reservoir which might have favorable or non-favorable effects on hydrocarbon production. It is crucial to characterize the fluid flow in the fracture networks to examine the root-cause relationships, the impact on hydrocarbon recovery and quantify the efficiency of enhanced recovery mechanisms.\u0000 This work describes the development of a machine learning model for history matching and predicting two-phase relative permeability. Capitalizing on the main principles of the 4th Industrial Revolution (IR 4.0), the development of this model was achieved by training machine learning (ML) algorithms and using advanced predictive data analytics on data collected from lab experiments as input. The model derived from the analysis describes two-phase flow of oil and water in a single discretized fracture taking into account fracture aperture, wall roughness, orientation and, flow rates and direction. It also accommodates fluids and fracture characteristics to match laboratory SCAL experimental of co-current oil and water flow in a mixed-wettability single fracture modeled as narrow gap in a Hele-Shaw cell.\u0000 The experimental data exhibit variations in shape and end-points that mainly reflect the effects of fracture aperture, roughness, inclination, and hysteresis effects. This in turn demonstrate the effects of phase interference, saturation changes, and major forces acting on two-phase flow in fractures like capillary and viscous forces.\u0000 The empirical relationship showed an acceptable match to the experimentally derived relative permeability in most of the cases as well as good predictive capabilities against the blind tests on other sets of experimental data and numerical simulation models. Having both fracture relative permeability data (describing the fluids flow) and detailed fracture characterization improves our understanding of the reservoir dynamics and fractured network impact on hydrocarbon recovery.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81166534","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}
Reservoirs and the lateral seal of stratigraphic traps are controlled by the depositional environment or diagenesis. The recognition of facies and lithology from seismic attributes is an effective approach for identifying stratigraphic traps related to the depositional environment. In this paper, the occurrence of stratigraphic traps related to depositional environment in Permian aeolian clastics and Jurassic carbonate-evaporites was studied. To identify these stratigraphic traps, multiple seismic attributes were classified using supervised and unsupervised artificial neural networks (ANNs), which allowed the recognition of seismic facies and lithology. Neural networks are a powerful classification technique, which incorporates multiple attributes into a number of classes to identify sedimentary facies. Two algorithms comprising supervised and unsupervised neural networks are commonly implemented. With a supervised learning algorithm, prior information such as typical facies at the control wells are required to train the multilayer perceptron (MLP) network. With an unsupervised algorithm, only seismic data is input to the neural network, and competitive-learning techniques are employed to classify or self-organize the data based on its internal characteristics. Without prior information, the output classes are not labeled with lithofacies. According to the availability of prior information, supervised and unsupervised learning were applied to recognize dune-playa and carbonate-evaporite combinations, respectively. To characterize the depositional environments, joint interpretation with a geological model is necessary for both supervised and unsupervised classification. Two major findings have been derived from this work. First, the learning technology based on ANNs is effective to recognize sedimentary facies. The microfacies and lithologies identified by both supervised and unsupervised ANNs are very consistent with the drilled wells. Second, the recognition of depositional facies and lithology can characterize the stratigraphic traps in the study areas. Lateral seal plays a key role in stratigraphic traps. Playa siltstone and tight lagoonal limestone constitute the lateral seal in dune-playa and carbonate-evaporite combinations, respectively.
{"title":"Seismic Facies Recognition and Stratigraphic Trap Characterization Based on Neural Networks","authors":"Si-Hai Zhang, Yin Xu, M. Abu-Ali, M. Teng","doi":"10.2523/IPTC-19503-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19503-MS","url":null,"abstract":"\u0000 Reservoirs and the lateral seal of stratigraphic traps are controlled by the depositional environment or diagenesis. The recognition of facies and lithology from seismic attributes is an effective approach for identifying stratigraphic traps related to the depositional environment. In this paper, the occurrence of stratigraphic traps related to depositional environment in Permian aeolian clastics and Jurassic carbonate-evaporites was studied. To identify these stratigraphic traps, multiple seismic attributes were classified using supervised and unsupervised artificial neural networks (ANNs), which allowed the recognition of seismic facies and lithology.\u0000 Neural networks are a powerful classification technique, which incorporates multiple attributes into a number of classes to identify sedimentary facies. Two algorithms comprising supervised and unsupervised neural networks are commonly implemented. With a supervised learning algorithm, prior information such as typical facies at the control wells are required to train the multilayer perceptron (MLP) network. With an unsupervised algorithm, only seismic data is input to the neural network, and competitive-learning techniques are employed to classify or self-organize the data based on its internal characteristics. Without prior information, the output classes are not labeled with lithofacies. According to the availability of prior information, supervised and unsupervised learning were applied to recognize dune-playa and carbonate-evaporite combinations, respectively. To characterize the depositional environments, joint interpretation with a geological model is necessary for both supervised and unsupervised classification.\u0000 Two major findings have been derived from this work. First, the learning technology based on ANNs is effective to recognize sedimentary facies. The microfacies and lithologies identified by both supervised and unsupervised ANNs are very consistent with the drilled wells. Second, the recognition of depositional facies and lithology can characterize the stratigraphic traps in the study areas. Lateral seal plays a key role in stratigraphic traps. Playa siltstone and tight lagoonal limestone constitute the lateral seal in dune-playa and carbonate-evaporite combinations, respectively.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83493817","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}
With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper. Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of "force-chain" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment. The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures. Using this novel experimental apparatus, the strengthened tight plugging formulas were also optimized for drilling fluid at the wedge fractures with different widths, which exhibited tight plugging characteristic self-adapting to different openings with pressure resistance up to 8MPa, thus improving loss-prevention ability of drilling fluid and significantly enhancing wellbore pressure containment of subsurface formation.
{"title":"Experimental Investigation on Wellbore Strengthening Mechanism and Tight Fracture Plugging Drilling Fluid Based on Granular Matter Mechanics","authors":"Junyi Liu, Guo Baoyu, Z. Qiu","doi":"10.2523/IPTC-19144-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19144-MS","url":null,"abstract":"\u0000 With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper.\u0000 Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of \"force-chain\" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment.\u0000 The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures. Using this novel experimental apparatus, the strengthened tight plugging formulas were also optimized for drilling fluid at the wedge fractures with different widths, which exhibited tight plugging characteristic self-adapting to different openings with pressure resistance up to 8MPa, thus improving loss-prevention ability of drilling fluid and significantly enhancing wellbore pressure containment of subsurface formation.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84974878","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}
Jason Fuxa, Paolo Di Giampaolo, G. Ferrara, M. D. Pietro, M. Sportelli, G. Ripa, Antonio di Campli
This paper details a field application of Shaped Memory Polymer (SMP) material for sand management delivering an innovative approach for sand control completions. The use of the technology has enabled profitable exploitation of residual reserves in a mature gas field offshore Adriatic Sea. The paper reviews details of the field deployment, with both economic and well performance results described. The offshore field was discovered in 1971 and 102 wells have been drilled to date. The trap is a very gentle, slightly asymmetrical anticline made by Pleistocene sandy turbidites, sedimented on the underlying carbonate substrate. Methane gas bearing layers have been sealed by several argillaceous intercalations that worked also as the source rocks of this multilayer reservoir. The sandy layers in this Pleistocene sequence, have thickness ranging from few centimeters up to some meters, and porosity from 22 up to 33%. Isolation of multiple gas-water contacts and fines production have been two crucial issues while producing the field. Since 2000, all seven platforms in this field have required workovers by means of performing sidetracks. Due to the reservoir characteristics, the well interventions have been completed with multi-layer, stacked cased-hole sand control completions. Despite a continuous improvement of procedures and technique, the traditional sand control methods have been efficient but were no longer profitable, due to challenging market conditions. An open-hole completion using SMP combined with zonal isolation and selective production has proved to be an effective alternative to cased-hole sand control. This novel completion approach resulted in a significant reduction in both cost and rig time. It is estimated that nearly two weeks of rig time was saved and an overall workover cost reduction of approximately 35%, with further efficiencies to be realized on upcoming deployments. To date, the completion has proved to be an effective sand control method, with no produced solids, no plugging effect, and gas production that has met expectations.
{"title":"Shaped Memory Polymer: An Innovative Approach to Sand Control Open Hole Completion in Thin, Multilayered, Depleted Low Permeability Gas Reservoirs","authors":"Jason Fuxa, Paolo Di Giampaolo, G. Ferrara, M. D. Pietro, M. Sportelli, G. Ripa, Antonio di Campli","doi":"10.2523/IPTC-19160-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19160-MS","url":null,"abstract":"\u0000 This paper details a field application of Shaped Memory Polymer (SMP) material for sand management delivering an innovative approach for sand control completions. The use of the technology has enabled profitable exploitation of residual reserves in a mature gas field offshore Adriatic Sea. The paper reviews details of the field deployment, with both economic and well performance results described.\u0000 The offshore field was discovered in 1971 and 102 wells have been drilled to date. The trap is a very gentle, slightly asymmetrical anticline made by Pleistocene sandy turbidites, sedimented on the underlying carbonate substrate. Methane gas bearing layers have been sealed by several argillaceous intercalations that worked also as the source rocks of this multilayer reservoir. The sandy layers in this Pleistocene sequence, have thickness ranging from few centimeters up to some meters, and porosity from 22 up to 33%. Isolation of multiple gas-water contacts and fines production have been two crucial issues while producing the field.\u0000 Since 2000, all seven platforms in this field have required workovers by means of performing sidetracks. Due to the reservoir characteristics, the well interventions have been completed with multi-layer, stacked cased-hole sand control completions. Despite a continuous improvement of procedures and technique, the traditional sand control methods have been efficient but were no longer profitable, due to challenging market conditions.\u0000 An open-hole completion using SMP combined with zonal isolation and selective production has proved to be an effective alternative to cased-hole sand control. This novel completion approach resulted in a significant reduction in both cost and rig time. It is estimated that nearly two weeks of rig time was saved and an overall workover cost reduction of approximately 35%, with further efficiencies to be realized on upcoming deployments. To date, the completion has proved to be an effective sand control method, with no produced solids, no plugging effect, and gas production that has met expectations.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77746240","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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