Bin Yang, M. Nie, Hong Shen, Yu Guo Li, Nian Da Xu, Huan Zhang, Cheng De Niu
PLxx oilfield is a mature oilfield which has been developed by horizontal wells for several years with water-injection production style. It features with shallow, complex, high challenging unconsolidated channel sand with lateral property variation due to pinch out, stacking or lamination. The thickness of pay zone changes from couple of to ten more meters which brings much high challenge to reservoir delineation while drilling and horizontal well placement execution. The oilfield locates at a faulted belt of Bo Hai Bay among which some small faults may happen. But it's difficult to be identified because of the low S/N ratio incurs from the shallow gas effect on the seismic data. Moreover, uneven flowing zone units exist within sandstone package due to dynamic reservoir production, uncertainty of lateral sand connections and possible inter-well interventions. As such, this makes the oil-water distribution more complicated and the oil-water contact isn't uniform in the sand package. In order to furtherly understand the complex channel sand, place the wellbore in the favorable sweet spot and enhance the oil recovery, a newly-developed visualized reservoir characterization while drilling integrated technology associated with RSS(rotary steerable system), HSVP(high speed data transmission system), RTC(remote transmission connection through Internet) and OSC(operation support center) was employed to optimize the operation efficiency during a three-wells drilling campaign in this oilfield. This newly-developed reservoir characterization technique is the industry innovative fully 9 components measuring azimuthal Electro-Magnetic propagation tool in one single sub. It provides not only the conventional propagation resistivity but also the geo-signal responses in a very quick, flexible way. In one of the case, the unique "Dual-diagonal orthogonal T-R antenna design" ensures the DOI (depth of investigation) as deep as 6.8meters. The reservoir boundaries such as the top, the bottom or the oil-water contact were distinctly characterized and the horizontal drainage section was precisely navigated within the profitable pay zone. The post-well reservoir characterization result is comparable with the seismic profile and very helpful to understand the dynamic reservoir flowing zone unit. The excellent performance is also reflected in the oil production; the initial oil production was increased from 40 m3/day to 69m3/day which is 75% higher than expected. Minimum 25% of oil recovery will be enhanced as forecast.
{"title":"Newly-Developed Visualized Reservoir Characterization While Drilling Technology Improves Understanding of Complex Channel Sand, Assists EOR in a Mature Oilfield in Bo Hai Bay","authors":"Bin Yang, M. Nie, Hong Shen, Yu Guo Li, Nian Da Xu, Huan Zhang, Cheng De Niu","doi":"10.4043/31440-ms","DOIUrl":"https://doi.org/10.4043/31440-ms","url":null,"abstract":"\u0000 PLxx oilfield is a mature oilfield which has been developed by horizontal wells for several years with water-injection production style. It features with shallow, complex, high challenging unconsolidated channel sand with lateral property variation due to pinch out, stacking or lamination. The thickness of pay zone changes from couple of to ten more meters which brings much high challenge to reservoir delineation while drilling and horizontal well placement execution. The oilfield locates at a faulted belt of Bo Hai Bay among which some small faults may happen. But it's difficult to be identified because of the low S/N ratio incurs from the shallow gas effect on the seismic data.\u0000 Moreover, uneven flowing zone units exist within sandstone package due to dynamic reservoir production, uncertainty of lateral sand connections and possible inter-well interventions. As such, this makes the oil-water distribution more complicated and the oil-water contact isn't uniform in the sand package.\u0000 In order to furtherly understand the complex channel sand, place the wellbore in the favorable sweet spot and enhance the oil recovery, a newly-developed visualized reservoir characterization while drilling integrated technology associated with RSS(rotary steerable system), HSVP(high speed data transmission system), RTC(remote transmission connection through Internet) and OSC(operation support center) was employed to optimize the operation efficiency during a three-wells drilling campaign in this oilfield. This newly-developed reservoir characterization technique is the industry innovative fully 9 components measuring azimuthal Electro-Magnetic propagation tool in one single sub. It provides not only the conventional propagation resistivity but also the geo-signal responses in a very quick, flexible way. In one of the case, the unique \"Dual-diagonal orthogonal T-R antenna design\" ensures the DOI (depth of investigation) as deep as 6.8meters.\u0000 The reservoir boundaries such as the top, the bottom or the oil-water contact were distinctly characterized and the horizontal drainage section was precisely navigated within the profitable pay zone. The post-well reservoir characterization result is comparable with the seismic profile and very helpful to understand the dynamic reservoir flowing zone unit. The excellent performance is also reflected in the oil production; the initial oil production was increased from 40 m3/day to 69m3/day which is 75% higher than expected. Minimum 25% of oil recovery will be enhanced as forecast.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86315512","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}
H. Rabbani, Muhammad Saad Khan, M. Qureshi, Mohammad Sohel Rahman, T. Seers, B. Lal
A mathematical model is presented to predict the formation of gas hydrates in porous media under various boundary conditions. The new mathematical modeling framework is based on coupling the analytical pore network approach (APNA) and equation proposed by De La Fuente et al. [1]. Further, we also integrate thermodynamic models to capture the phase boundary at which the formation of gas hydrates takes place. The proposed analytical framework is a set of equations that are computationally inexpensive to solve, allowing us to predict the formation of gas hydrates in complex porous media. Complete governing equations are provided, and the method is described in detail to permit readers to replicate all results. To demonstrate the formation of hydrates in porous media, we analyzed the saturation of hydrates in porous media with different properties. Our model shows that the hydrate formation rate is positively related to the porous media's pore size. The hydrates were found to be preferably formed in the porous media composed of relatively larger pores, which could be attributed to the weak capillary forces resisting the formation of hydrates in porous media. The novelty of the new analytical model is the ability to predict the gas hydrates formation in porous media in a reasonable time using standard engineering computers. Furthermore, the model can aid in the estimation of natural gas hydrate reservoirs, which offer the avenue for effective methane recovery from the vast natural gas hydrate reserves in continental margins.
提出了一种预测不同边界条件下多孔介质中天然气水合物形成的数学模型。新的数学建模框架是基于耦合解析孔网络方法(APNA)和De La Fuente等人[1]提出的方程。此外，我们还整合了热力学模型来捕捉天然气水合物形成的相边界。所提出的分析框架是一组计算成本低廉的方程，使我们能够预测复杂多孔介质中天然气水合物的形成。提供了完整的控制方程，并详细描述了该方法，以允许读者复制所有结果。为了证明多孔介质中水合物的形成，我们分析了不同性质多孔介质中水合物的饱和度。我们的模型表明，水合物的形成速率与多孔介质的孔径呈正相关。在孔隙较大的多孔介质中，水合物更容易形成，这可能是由于毛细管力较弱，阻碍了多孔介质中水合物的形成。新分析模型的新颖之处在于，它能够使用标准工程计算机在合理的时间内预测多孔介质中天然气水合物的形成。此外，该模型还可以帮助估算天然气水合物储层，为从大陆边缘巨大的天然气水合物储量中有效开采甲烷提供途径。
{"title":"Analytical Modelling of Gas Hydrates in Porous Media","authors":"H. Rabbani, Muhammad Saad Khan, M. Qureshi, Mohammad Sohel Rahman, T. Seers, B. Lal","doi":"10.4043/31645-ms","DOIUrl":"https://doi.org/10.4043/31645-ms","url":null,"abstract":"\u0000 A mathematical model is presented to predict the formation of gas hydrates in porous media under various boundary conditions. The new mathematical modeling framework is based on coupling the analytical pore network approach (APNA) and equation proposed by De La Fuente et al. [1]. Further, we also integrate thermodynamic models to capture the phase boundary at which the formation of gas hydrates takes place. The proposed analytical framework is a set of equations that are computationally inexpensive to solve, allowing us to predict the formation of gas hydrates in complex porous media. Complete governing equations are provided, and the method is described in detail to permit readers to replicate all results. To demonstrate the formation of hydrates in porous media, we analyzed the saturation of hydrates in porous media with different properties. Our model shows that the hydrate formation rate is positively related to the porous media's pore size. The hydrates were found to be preferably formed in the porous media composed of relatively larger pores, which could be attributed to the weak capillary forces resisting the formation of hydrates in porous media. The novelty of the new analytical model is the ability to predict the gas hydrates formation in porous media in a reasonable time using standard engineering computers. Furthermore, the model can aid in the estimation of natural gas hydrate reservoirs, which offer the avenue for effective methane recovery from the vast natural gas hydrate reserves in continental margins.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79545706","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}
Seismic forward modelling is typically done using the finite difference (FD) approach. However, this method suffers from numerical dispersion problems which translates into less focused stacks and a decrease in bandwidth coverage. To mitigate this problem, the pseudo analytical method formulated by Etgen and Brandersberg-Dahl in 2009 was utilized. This paper demonstrates that pseudo analytics’ pseudo differential operator that utilizes velocity interpolation allows it to be more robust towards varying velocity and grid sizes while providing better amplitudes for shot gathers compared to the FD modelling scheme. FD and pseudo analytically generated gathers were then migrated using the reverse time migration (RTM) algorithm and showed that the pseudo analytically generated shot gathers were better at preserving shallower and higher frequency reflectors while at the same time better suppressed migration artifacts at the steeply dipping salt flank. The pseudo analytically generated gathers also provided an improved amplitude spectrum compared to FD especially in the lower frequency range of around 25-50 Hz. Various test cases demonstrate that the pseudo analytical method was shown to be a viable alternative to the typically used FD method in imaging at challenging geological environments such as salt.
{"title":"Comparison Between the Pseudo-Analytical and Finite Difference Method for Seismic Modelling and Imaging","authors":"M. Muhammed, M. Isa, S. Mishra","doi":"10.4043/31687-ms","DOIUrl":"https://doi.org/10.4043/31687-ms","url":null,"abstract":"\u0000 Seismic forward modelling is typically done using the finite difference (FD) approach. However, this method suffers from numerical dispersion problems which translates into less focused stacks and a decrease in bandwidth coverage. To mitigate this problem, the pseudo analytical method formulated by Etgen and Brandersberg-Dahl in 2009 was utilized. This paper demonstrates that pseudo analytics’ pseudo differential operator that utilizes velocity interpolation allows it to be more robust towards varying velocity and grid sizes while providing better amplitudes for shot gathers compared to the FD modelling scheme. FD and pseudo analytically generated gathers were then migrated using the reverse time migration (RTM) algorithm and showed that the pseudo analytically generated shot gathers were better at preserving shallower and higher frequency reflectors while at the same time better suppressed migration artifacts at the steeply dipping salt flank. The pseudo analytically generated gathers also provided an improved amplitude spectrum compared to FD especially in the lower frequency range of around 25-50 Hz. Various test cases demonstrate that the pseudo analytical method was shown to be a viable alternative to the typically used FD method in imaging at challenging geological environments such as salt.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75226832","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}
Muhd Akram Kamaruzaman, Mohd Saifullah Din, Ernyza Endot, P. Sim, Chrissie Lojikim, C. Chang, Mohd Faiz Mohd Ramli
Central Luconia has been explored with hundreds of well since the 1950s. During that time, all offshore wells were drilled using hyperbolic positioning system which has lower accuracy compare to current satellite positioning system, which was only introduced in early 1990s. With this knowledge, the old exploration well's locations (which was drilled in 1970s) pose potential hazards in terms of seabed obstruction and potential well collision during the future development wells drilling. Without a reliable seismic to well tie, interpreter has difficulty in identifying the top of carbonate event for depth conversion, thus impacting the well delivery, static model building and subsurface reserves estimation. Onsite verification was carried out using a multibeam echosounder (MBES), a Side Scan Sonar (SSS), and a Sub Bottom Profiler (SBP) in accordance with standard site survey procedures, but the existing wellhead location was unable to be detected because the wells had been abandoned and cut off at the seabed level. Magnetometer was deployed to further investigate the existing wellhead location; the sensor was towed approximately about three (3) times water depth from the stern of the vessel and altitude 10m from the seabed. To navigate the towed sensor, Ultra Short Baseline (USBL) transponder was attached close to the sensor to get real time underwater positioning. Five (5) survey lines were designed centered at the suspected existing wellhead location with the coverage of 60m radius. During data acquisition, the magnetic anomalies were recorded in the system via receiver and total magnetic data was used for further analysis to derive the as-found wellhead location. During the interpretation, the area of ambient magnetic field distortion was identified and marked as anomaly which represents "area of suspected wellhead". The magnitude and pattern of such distortion was used for interpretation and combined with the coordinates from the positioning system (surface and underwater) onboard the survey vessel. The general total magnetic field reading is ranging between 40920nT and 41130nT with the magnetic anomaly/wellhead had magnetic value from 100nT to 115nT. The total magnetic field analytical signal value is ranging from 0 to 3.5. The target magnetic anomaly refers to the area with greatest analytical signal value where it is also the area with most drastic change of the total magnetic field. From the survey results, the as-found wellhead position varies from 48m - 53m compared to existing wellhead position. With the confirmation on the old wellhead location, this helps to derisk the well collisions study for future development well and also improves the seismic to well tie analysis to provide higher confidence in the Top Carbonate pick and a better inverted seismic match in the reservoir interval for properties distribution.
{"title":"Magnetometer Survey: Multi-Discipline Collaboration Impacting Bottom Line","authors":"Muhd Akram Kamaruzaman, Mohd Saifullah Din, Ernyza Endot, P. Sim, Chrissie Lojikim, C. Chang, Mohd Faiz Mohd Ramli","doi":"10.4043/31628-ms","DOIUrl":"https://doi.org/10.4043/31628-ms","url":null,"abstract":"\u0000 Central Luconia has been explored with hundreds of well since the 1950s. During that time, all offshore wells were drilled using hyperbolic positioning system which has lower accuracy compare to current satellite positioning system, which was only introduced in early 1990s. With this knowledge, the old exploration well's locations (which was drilled in 1970s) pose potential hazards in terms of seabed obstruction and potential well collision during the future development wells drilling. Without a reliable seismic to well tie, interpreter has difficulty in identifying the top of carbonate event for depth conversion, thus impacting the well delivery, static model building and subsurface reserves estimation.\u0000 Onsite verification was carried out using a multibeam echosounder (MBES), a Side Scan Sonar (SSS), and a Sub Bottom Profiler (SBP) in accordance with standard site survey procedures, but the existing wellhead location was unable to be detected because the wells had been abandoned and cut off at the seabed level. Magnetometer was deployed to further investigate the existing wellhead location; the sensor was towed approximately about three (3) times water depth from the stern of the vessel and altitude 10m from the seabed. To navigate the towed sensor, Ultra Short Baseline (USBL) transponder was attached close to the sensor to get real time underwater positioning. Five (5) survey lines were designed centered at the suspected existing wellhead location with the coverage of 60m radius. During data acquisition, the magnetic anomalies were recorded in the system via receiver and total magnetic data was used for further analysis to derive the as-found wellhead location. During the interpretation, the area of ambient magnetic field distortion was identified and marked as anomaly which represents \"area of suspected wellhead\". The magnitude and pattern of such distortion was used for interpretation and combined with the coordinates from the positioning system (surface and underwater) onboard the survey vessel.\u0000 The general total magnetic field reading is ranging between 40920nT and 41130nT with the magnetic anomaly/wellhead had magnetic value from 100nT to 115nT. The total magnetic field analytical signal value is ranging from 0 to 3.5. The target magnetic anomaly refers to the area with greatest analytical signal value where it is also the area with most drastic change of the total magnetic field. From the survey results, the as-found wellhead position varies from 48m - 53m compared to existing wellhead position. With the confirmation on the old wellhead location, this helps to derisk the well collisions study for future development well and also improves the seismic to well tie analysis to provide higher confidence in the Top Carbonate pick and a better inverted seismic match in the reservoir interval for properties distribution.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75926617","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}
Elijah Lip Heng How, A. Donald, P. Bettinelli, P. Chongrueanglap, Woi Loon Hooi, Anniza Ai Mei Soh
Vertical seismic profile (VSP) or checkshot surveys are useful measurements to obtain accurate time-depth pairs for time-depth conversion in seismic exploration. However, in deviated wells, the standard geometry correction for rig-source VSPs will not provide reliable time-depth profiles because of ray bending, anisotropy, and lateral velocity variation effects. The accuracy of the time-depth profile can be improved by using model-based correction or vertical incidence VSP simulation with transversely isotropic (TI) data from an advanced sonic measurement. Elastic anisotropy parameters derived from sonic combined with VSP time-depth information are shown to accurately place a deviated wellbore within the reservoir to improve the drainage and productivity of a reservoir in offshore Malaysia. For rig-source VSP in a deviated well, the source-receiver travel path is not a vertical straight line, but an oblique, refracted path. The seismic waves from the source travel along straight paths within a layer of constant velocity. On entering another layer, they undergo refraction and the direction of travel changes. The pseudo-vertical incidence VSP is simulated with a velocity model to accurately calculate the vertical traveltime. This deviated well passes through various layers of overburden before reaching the target reservoirs. Observations from the dipole shear anisotropy, formation dip, and using dispersion analysis, indicate that these shales can be considered transversely isotropic with a vertical axis of symmetry. A single well probabilistic inversion was used to solve for the five anisotropic constants by combining the sonic measurements and prior elastic anisotropy relationships. This advanced model-based correction was the optimal solution to improve the accuracy of checkshot time-depth velocity data in combination with the anisotropic velocity model. Isotropic model-based correction showed a 6-ms time difference compared with standard VSP geometry correction. However, the sonic data in the overburden formations showed a significant amount of layering that gave rise to significant uncertainty in the existing velocity model and thus the position of the top reservoir. The anisotropic parameters were determined at sonic scale for the shale directly overlaying the reservoir. The upscaled anisotropic velocity model showed that an 18-ms time difference with standard VSP geometry correction changed the depth of the reservoir up to 45 m. The new model now placed the reservoir at the correct position and can be used with more confidence for development purposes.
{"title":"Verticalized Sonic Measurements in Deviated Wellbore for Accurate Velocity Modelling and Seismic Well Tie in Offshore Malaysia","authors":"Elijah Lip Heng How, A. Donald, P. Bettinelli, P. Chongrueanglap, Woi Loon Hooi, Anniza Ai Mei Soh","doi":"10.4043/31641-ms","DOIUrl":"https://doi.org/10.4043/31641-ms","url":null,"abstract":"\u0000 Vertical seismic profile (VSP) or checkshot surveys are useful measurements to obtain accurate time-depth pairs for time-depth conversion in seismic exploration. However, in deviated wells, the standard geometry correction for rig-source VSPs will not provide reliable time-depth profiles because of ray bending, anisotropy, and lateral velocity variation effects. The accuracy of the time-depth profile can be improved by using model-based correction or vertical incidence VSP simulation with transversely isotropic (TI) data from an advanced sonic measurement. Elastic anisotropy parameters derived from sonic combined with VSP time-depth information are shown to accurately place a deviated wellbore within the reservoir to improve the drainage and productivity of a reservoir in offshore Malaysia.\u0000 For rig-source VSP in a deviated well, the source-receiver travel path is not a vertical straight line, but an oblique, refracted path. The seismic waves from the source travel along straight paths within a layer of constant velocity. On entering another layer, they undergo refraction and the direction of travel changes. The pseudo-vertical incidence VSP is simulated with a velocity model to accurately calculate the vertical traveltime.\u0000 This deviated well passes through various layers of overburden before reaching the target reservoirs. Observations from the dipole shear anisotropy, formation dip, and using dispersion analysis, indicate that these shales can be considered transversely isotropic with a vertical axis of symmetry. A single well probabilistic inversion was used to solve for the five anisotropic constants by combining the sonic measurements and prior elastic anisotropy relationships. This advanced model-based correction was the optimal solution to improve the accuracy of checkshot time-depth velocity data in combination with the anisotropic velocity model.\u0000 Isotropic model-based correction showed a 6-ms time difference compared with standard VSP geometry correction. However, the sonic data in the overburden formations showed a significant amount of layering that gave rise to significant uncertainty in the existing velocity model and thus the position of the top reservoir. The anisotropic parameters were determined at sonic scale for the shale directly overlaying the reservoir. The upscaled anisotropic velocity model showed that an 18-ms time difference with standard VSP geometry correction changed the depth of the reservoir up to 45 m. The new model now placed the reservoir at the correct position and can be used with more confidence for development purposes.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"340 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80756986","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 main characteristic of the complicated carbonate reservoirs is notably strong heterogeneity, leading to a high uncertainty in formation parameter evaluation [1,2]. In general, logging, core analysis and pressure transient analysis (PTA) are used to evaluate the reservoir parameters of carbonate rocks. However, core and logging analysis can be used to get static parameters in the range of centimeter to meter, while PTA can obtain static and dynamic parameters in the range of hundreds of meters to several kilometers, such as skin coefficient, boundary conditions, permeability and cross flow coefficient. Therefore, the PTA results are more practical and reliable. However, the well test curve shows similar characteristics for multi-layers reservoirs, dual-medium reservoirs, and carbonate reservoirs with lithology mixed sedimentation lithology [3,4]. It is important to reduce the parameter evaluation multiplicity. However, many scholars did not consider the multiplicity of PTA interpretation in practical application, which led to large errors in the results [5,7]. Therefore, this paper comprehensively summarizes all the reasons leading to the depression of pressure derivative curve, and puts forward the corresponding identification approach, which has been applied in Abu Ghirab reservoir well test interpretation and created conditions for improving the accuracy of PTA.
{"title":"Integrated Well Test Interpretation Approach for Complicated Carbonate Reservoirs: A Field Case","authors":"Yongjie Liu, Zhaobo Sun, Renfeng Yang","doi":"10.4043/31528-ms","DOIUrl":"https://doi.org/10.4043/31528-ms","url":null,"abstract":"\u0000 The main characteristic of the complicated carbonate reservoirs is notably strong heterogeneity, leading to a high uncertainty in formation parameter evaluation [1,2]. In general, logging, core analysis and pressure transient analysis (PTA) are used to evaluate the reservoir parameters of carbonate rocks. However, core and logging analysis can be used to get static parameters in the range of centimeter to meter, while PTA can obtain static and dynamic parameters in the range of hundreds of meters to several kilometers, such as skin coefficient, boundary conditions, permeability and cross flow coefficient. Therefore, the PTA results are more practical and reliable. However, the well test curve shows similar characteristics for multi-layers reservoirs, dual-medium reservoirs, and carbonate reservoirs with lithology mixed sedimentation lithology [3,4]. It is important to reduce the parameter evaluation multiplicity.\u0000 However, many scholars did not consider the multiplicity of PTA interpretation in practical application, which led to large errors in the results [5,7]. Therefore, this paper comprehensively summarizes all the reasons leading to the depression of pressure derivative curve, and puts forward the corresponding identification approach, which has been applied in Abu Ghirab reservoir well test interpretation and created conditions for improving the accuracy of PTA.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87102555","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}
S. Ashraf, Rahmad Haidzar Muhamad Husin, Awang Rizalman, M. Bogaerts
Cement sheath integrity to prevent interzonal communication is closely related to the static gel strength. The API Standard 65-2 puts importance on the critical gel strength period (CGSP) measurement, which begins when the critical static gel strength (CSGS) is developed and ends when 500 lbf/100 ft2 is attained. The recommended duration for this period should be 45 min or less to be effective in isolating flow potentials. The API 10B-6 covers the three methods to measure the static gel strength development accepted in the industry, which are continuous and intermittent rotation followed by ultrasonic. A laboratory-based study is presented in this paper that compares these measurement methods. The slurry frameworks chosen for the comparison ranged between 11.5 to 18 lbm/gal and the temperature extended from 27 to 121°C. The formulation of the fluid system consisted of Class G cement, silica flour, weighting agent, or light weight extender for the blended phase. Liquid phase additives such as antifoam, fluid loss, dispersant, and retarder were used. The formulations were adjusted to simulate two placement times, i.e., one between 3 to 4 hr. and the second between 7 to 8 hr. The testing performed on the selected cement systems provided significant knowledge of the four different types of static gel strength development equipment used during the testing. There are two equipment's from different manufacturers operating using the continuous rotation method followed by one each for the intermittent rotation and the acoustic type. The overall average transit time for each slurry and the respective standard deviation were arranged for ease of comparison. It was found that there are less deviations in certain fluid systems compared with some other systems. As indicated by the API 10B-6, each equipment may well result in generating different static gel profiles due to cement sample size, apparatus configuration, and formulation. Slurry formulations can be modified to improve their transition time depending on conditions as needed.
{"title":"Comparing Oilwell Cement Static Gel Strength Development by Ultrasonic, Intermittent and Continuous Rotation Measurement Methods","authors":"S. Ashraf, Rahmad Haidzar Muhamad Husin, Awang Rizalman, M. Bogaerts","doi":"10.4043/31348-ms","DOIUrl":"https://doi.org/10.4043/31348-ms","url":null,"abstract":"\u0000 Cement sheath integrity to prevent interzonal communication is closely related to the static gel strength. The API Standard 65-2 puts importance on the critical gel strength period (CGSP) measurement, which begins when the critical static gel strength (CSGS) is developed and ends when 500 lbf/100 ft2 is attained. The recommended duration for this period should be 45 min or less to be effective in isolating flow potentials. The API 10B-6 covers the three methods to measure the static gel strength development accepted in the industry, which are continuous and intermittent rotation followed by ultrasonic. A laboratory-based study is presented in this paper that compares these measurement methods.\u0000 The slurry frameworks chosen for the comparison ranged between 11.5 to 18 lbm/gal and the temperature extended from 27 to 121°C. The formulation of the fluid system consisted of Class G cement, silica flour, weighting agent, or light weight extender for the blended phase. Liquid phase additives such as antifoam, fluid loss, dispersant, and retarder were used. The formulations were adjusted to simulate two placement times, i.e., one between 3 to 4 hr. and the second between 7 to 8 hr.\u0000 The testing performed on the selected cement systems provided significant knowledge of the four different types of static gel strength development equipment used during the testing. There are two equipment's from different manufacturers operating using the continuous rotation method followed by one each for the intermittent rotation and the acoustic type.\u0000 The overall average transit time for each slurry and the respective standard deviation were arranged for ease of comparison. It was found that there are less deviations in certain fluid systems compared with some other systems. As indicated by the API 10B-6, each equipment may well result in generating different static gel profiles due to cement sample size, apparatus configuration, and formulation. Slurry formulations can be modified to improve their transition time depending on conditions as needed.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86959773","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}
Hongfu Shi, Kuiqian Ma, Cunliang Chen, Fei Shi, Xiaodong Han
After the reservoir enters the medium-high water-cut period, due to the heterogeneity of the reservoir, the difference of fluid mobility, and the difference in injection and production, large water flow channels are gradually formed in the formation, which result in fixed streamline in the formation, and the inefficient or ineffective water circulation. Ineffective injection water circulation severely inhibits water flooding effect. Conventional tapping measures can’t change the problem of ineffective water circulation. However, the profile control technology changes the flow direction of subsequent injected water by plugging the high permeability layer or large pores, improving the water injection profile, and increasing the formation water retention rate, so as to expand the swept volume. Therefore, profile controlling technology has always been an important method water control and oil stabilization technologies for the reservoirs with thief zones. The success or failure of profile control measures depends to a large extent on thief zones identification and its description, sensitivity analysis of plugging agent performance, scientific and reasonable profile control decision-making and optimization, in addition to selection of candidate wells, optimization of construction parameters, effect prediction and effect evaluation.
{"title":"Pilot Test of Deep Profile Controlling and Sweep Improvement Based on Plugging Agent Location Optimization in Offshore Oilfield","authors":"Hongfu Shi, Kuiqian Ma, Cunliang Chen, Fei Shi, Xiaodong Han","doi":"10.4043/31519-ms","DOIUrl":"https://doi.org/10.4043/31519-ms","url":null,"abstract":"\u0000 After the reservoir enters the medium-high water-cut period, due to the heterogeneity of the reservoir, the difference of fluid mobility, and the difference in injection and production, large water flow channels are gradually formed in the formation, which result in fixed streamline in the formation, and the inefficient or ineffective water circulation. Ineffective injection water circulation severely inhibits water flooding effect. Conventional tapping measures can’t change the problem of ineffective water circulation. However, the profile control technology changes the flow direction of subsequent injected water by plugging the high permeability layer or large pores, improving the water injection profile, and increasing the formation water retention rate, so as to expand the swept volume. Therefore, profile controlling technology has always been an important method water control and oil stabilization technologies for the reservoirs with thief zones.\u0000 The success or failure of profile control measures depends to a large extent on thief zones identification and its description, sensitivity analysis of plugging agent performance, scientific and reasonable profile control decision-making and optimization, in addition to selection of candidate wells, optimization of construction parameters, effect prediction and effect evaluation.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83785883","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}
Interest in Floating Offshore Wind Farm (FOWF) is regaining momentum as countries and energy producers vie for economic and innovative solutions to decarbonize products and operations with net zero targets in perspective. Typically tapping offshore wind is costlier in comparison to land based solutions, despite the flexibility it offers due to remote operations away from populated areas. Floating wind farms offer an attractive mix of flexibility and cost effectiveness by eliminating the need for large supporting structures and enabling further deep-sea installations and access to stronger winds. While floating wind turbine technology is promising, it needs further maturation along with favorable policy implementation on the part of regulators to make floating wind farms attractive to operators/investors. This paper investigates Technology, Project Management challenges and opportunities from a large, Joint Venture capital project context with net zero target perspectives. Conceptually, floating wind energy is generated by a cluster of floating wind turbines, as against conventional fixed-bottom turbines which account for the majority of wind installations today. Several recent technological advancements have led to innovative floating wind solutions and also driven the costs downward. However, technological challenges like mooring and anchoring systems suited for harsh environments and policy challenges still present barriers to increased investment decisions. In both cases, synergies could potentially be harnessed from existing Oil & Gas deep sea technology. This paper will attempt to address such technology and policy challenges, as well as project management perspectives in maturing floating wind technology. Further, the project development lifecycle will be analyzed from stakeholder and risk management, technology maturation, decision making, and complexity management perspectives. While alleviating cost and flexibility challenges related to stick-built fixed-base solutions, floating technologies may have strategic potential to unlock the full potential of offshore wind and to serve as a vehicle to achieve green transition goals. This paper summarizes the potential risks and opportunities from political, economic, socio-cultural, technological, legal and environmental (PESTLE) points of view. Potential stakeholder influences and a decision quality matrix will be identified and documented. FOWF, PESTLE, Project Management, Complexity Management
{"title":"Floating Offshore Wind Energy – Brief Review of Prospects, Project Development Life Cycle, Policy and Technology Challenges and Project Management Complexity","authors":"Prasannakumar K. Purayil, Sujith Pratap Chandran","doi":"10.4043/31543-ms","DOIUrl":"https://doi.org/10.4043/31543-ms","url":null,"abstract":"Interest in Floating Offshore Wind Farm (FOWF) is regaining momentum as countries and energy producers vie for economic and innovative solutions to decarbonize products and operations with net zero targets in perspective. Typically tapping offshore wind is costlier in comparison to land based solutions, despite the flexibility it offers due to remote operations away from populated areas. Floating wind farms offer an attractive mix of flexibility and cost effectiveness by eliminating the need for large supporting structures and enabling further deep-sea installations and access to stronger winds. While floating wind turbine technology is promising, it needs further maturation along with favorable policy implementation on the part of regulators to make floating wind farms attractive to operators/investors. This paper investigates Technology, Project Management challenges and opportunities from a large, Joint Venture capital project context with net zero target perspectives. Conceptually, floating wind energy is generated by a cluster of floating wind turbines, as against conventional fixed-bottom turbines which account for the majority of wind installations today. Several recent technological advancements have led to innovative floating wind solutions and also driven the costs downward. However, technological challenges like mooring and anchoring systems suited for harsh environments and policy challenges still present barriers to increased investment decisions. In both cases, synergies could potentially be harnessed from existing Oil & Gas deep sea technology. This paper will attempt to address such technology and policy challenges, as well as project management perspectives in maturing floating wind technology. Further, the project development lifecycle will be analyzed from stakeholder and risk management, technology maturation, decision making, and complexity management perspectives. While alleviating cost and flexibility challenges related to stick-built fixed-base solutions, floating technologies may have strategic potential to unlock the full potential of offshore wind and to serve as a vehicle to achieve green transition goals. This paper summarizes the potential risks and opportunities from political, economic, socio-cultural, technological, legal and environmental (PESTLE) points of view. Potential stakeholder influences and a decision quality matrix will be identified and documented. FOWF, PESTLE, Project Management, Complexity Management","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82819832","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}
Klemens Katterbauer, Abdulaziz Al Qasim, Abdallah Al Shehri, A. Yousif
Hydrogen has become a very promising green energy source and it has the potential to be utilized in a variety of applications. Hydrogen, as a power source, has the benefits of being transportable and stored over long periods of times, and does not lead to any carbon emissions related to the utilization of the power source. Thermal EOR methods are among the most used recovery methods. They involve the introduction of thermal energy or heat into the reservoir to raise the temperature of the oil and reduce its viscosity. The heat makes the oil mobile and assists in moving it towards the producer wells. The heat can be added externally by injecting a hot fluid such as steam or hot water into the formations, or it can be generated internally through in-situ combustion by burning the oil in depleted gas or waterflooded reservoirs using air or oxygen. This method is an attractive alternative to produce cost-efficiently significant amounts of hydrogen from these depleted or waterflooded reservoirs. A major challenge is to optimize injection of air/oxygen to maximize hydrogen production via ensuring that the in-situ combustion sufficiently supports the breakdown of water into hydrogen molecules. which can then be separated from other gases via a palladium copper alloy membrane, leaving clean blue hydrogen. A crucial challenge in this process is achieving sufficient temperature in the reservoir in order to achieve this combustion process. The temperatures typically must reach around 500 degree Celsius to break the molecules apart. Hence, accurately monitoring the temperature within the reservoir plays a crucial role in order to optimize the oxygen injection and maximize recovery from the reservoir. Artificial intelligence (AI) practices have allowed to significantly improve optimization of reservoir production, based on observations in the near wellbore reservoir layers. This work utilizes a data-driven physics-inspired AI model for the optimal control of the high temperature wireless sensors for the optimal control of the oxygen injection in real-time. The framework was examined on a synthetic reservoir model with various producers and injectors. Each producer and injector contain various wireless high temperature sensors that are connected to each other. The framework then utilizes the temperature sensor data, in addition to the produced hydrogen, to optimize oxygen injection. This work represents a first and innovative approach to optimize subsurface wireless high temperature wireless sensing for maximizing hydrogen recovery from waterflooded reservoirs. The data-driven approach allows to optimize the hydrogen recovery representing a crucial element towards the drive for economical extraction of blue hydrogen.
{"title":"A Novel Artificial Intelligence Framework for the Optimal Control of Wireless Temperature Sensors for Optimizing Oxygen Injection in Subsurface Reservoirs","authors":"Klemens Katterbauer, Abdulaziz Al Qasim, Abdallah Al Shehri, A. Yousif","doi":"10.4043/31558-ms","DOIUrl":"https://doi.org/10.4043/31558-ms","url":null,"abstract":"\u0000 Hydrogen has become a very promising green energy source and it has the potential to be utilized in a variety of applications. Hydrogen, as a power source, has the benefits of being transportable and stored over long periods of times, and does not lead to any carbon emissions related to the utilization of the power source. Thermal EOR methods are among the most used recovery methods. They involve the introduction of thermal energy or heat into the reservoir to raise the temperature of the oil and reduce its viscosity. The heat makes the oil mobile and assists in moving it towards the producer wells. The heat can be added externally by injecting a hot fluid such as steam or hot water into the formations, or it can be generated internally through in-situ combustion by burning the oil in depleted gas or waterflooded reservoirs using air or oxygen. This method is an attractive alternative to produce cost-efficiently significant amounts of hydrogen from these depleted or waterflooded reservoirs. A major challenge is to optimize injection of air/oxygen to maximize hydrogen production via ensuring that the in-situ combustion sufficiently supports the breakdown of water into hydrogen molecules.\u0000 which can then be separated from other gases via a palladium copper alloy membrane, leaving clean blue hydrogen. A crucial challenge in this process is achieving sufficient temperature in the reservoir in order to achieve this combustion process. The temperatures typically must reach around 500 degree Celsius to break the molecules apart. Hence, accurately monitoring the temperature within the reservoir plays a crucial role in order to optimize the oxygen injection and maximize recovery from the reservoir.\u0000 Artificial intelligence (AI) practices have allowed to significantly improve optimization of reservoir production, based on observations in the near wellbore reservoir layers. This work utilizes a data-driven physics-inspired AI model for the optimal control of the high temperature wireless sensors for the optimal control of the oxygen injection in real-time.\u0000 The framework was examined on a synthetic reservoir model with various producers and injectors. Each producer and injector contain various wireless high temperature sensors that are connected to each other. The framework then utilizes the temperature sensor data, in addition to the produced hydrogen, to optimize oxygen injection.\u0000 This work represents a first and innovative approach to optimize subsurface wireless high temperature wireless sensing for maximizing hydrogen recovery from waterflooded reservoirs. The data-driven approach allows to optimize the hydrogen recovery representing a crucial element towards the drive for economical extraction of blue hydrogen.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81043351","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：