M. Habib, S. Imtiaz, F. Khan, Salim Ahmed, J. Baker
The sudden influx of reservoir fluids (i.e., reservoir kick) into the drilling annulus is one of the common abnormal events encountered in drilling operations. A kick can lead to a blowout, causing loss of lives, assets, and damage to the environment. This study presents a framework for real-time kick monitoring and management in managed-pressure-drilling (MPD) operation. The proposed framework consists of three distinct steps: the unscented Kalman filter (UKF) is used to detect and estimate the kick's severity; the estimated kick size and optimal control theory are used to calculate the time to mitigate the kick in the best-case scenario; and on the basis of the total predicted influx and pressure rise, the monitoring system generates a warning and activates the mitigation strategy. Thus, the proposed method can estimate, monitor, and manage kick in real time, enhancing the safety and efficiency of the MPD operation. The developed method was validated and demonstrated using a simulated MPD system, a pilot-scale experimental setup, and field data collected from an MPD operation in western Canada.
{"title":"Prediction of Reservoir-Kick Effect and Its Management in the Managed-Pressure-Drilling Operation","authors":"M. Habib, S. Imtiaz, F. Khan, Salim Ahmed, J. Baker","doi":"10.2118/205020-PA","DOIUrl":"https://doi.org/10.2118/205020-PA","url":null,"abstract":"\u0000 The sudden influx of reservoir fluids (i.e., reservoir kick) into the drilling annulus is one of the common abnormal events encountered in drilling operations. A kick can lead to a blowout, causing loss of lives, assets, and damage to the environment. This study presents a framework for real-time kick monitoring and management in managed-pressure-drilling (MPD) operation. The proposed framework consists of three distinct steps: the unscented Kalman filter (UKF) is used to detect and estimate the kick's severity; the estimated kick size and optimal control theory are used to calculate the time to mitigate the kick in the best-case scenario; and on the basis of the total predicted influx and pressure rise, the monitoring system generates a warning and activates the mitigation strategy. Thus, the proposed method can estimate, monitor, and manage kick in real time, enhancing the safety and efficiency of the MPD operation. The developed method was validated and demonstrated using a simulated MPD system, a pilot-scale experimental setup, and field data collected from an MPD operation in western Canada.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-28"},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46710179","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hameed Hussain Ahmed Mansoor, Srinivasa Reddy Devarapu, Robello Samuel, Tushar Sharma, S. Ponmani
Drilling technology in petroleum engineering is associated with problems such as high fluid loss, poor hole cleaning, and pipe sticking. Improvement of rheological and filtration properties of water-based drilling fluids (WDFs) plays a major role in resolving these drilling problems. The application of nanotechnology to WDF in the recent past has attracted much attention in addressing these drilling operations problems. In the present work, we investigate the application of natural aloe vera and CuO nanofluids combined as an additive in WDF to address the drilling problems. The nanofluids of three different concentrations of CuO nanoparticle (0.2, 0.4 , and 0.6 wt%) with aloe vera as a base fluid are prepared for this study by adopting a two-step method. The prepared nanofluids are characterized by their particle size and morphological characteristics. Conventional WDF (DF.0) is synthesized, and the prepared aloe-vera-based CuO nanofluid is added to the WDF to prepare nanofluid-enhancedwater-based drilling fluid (NFWDF) of different concentrations of nanoparticles, namely, 0.2 , 0.4, and 0.6 wt%. The prepared drilling fluid mixture is then characterized for its rheological and filtrate loss properties at various temperatures. Thermal stability and aging studies are performed for both WDF and NFWDF. The experimental results are then modeled using rheological models. The results reveal that aloe-vera-based CuO nanofluids improve the thermal stability and rheological properties of drilling fluid and significantly decrease the American Petroleum Institute (API) filtrate. Viscosity for WDF shows an approximately 61.7% decrease in heating up to 90°C. Further, the hot roll aging test causes a 63% decrease in the viscosity of WDF at 90°C. However, the addition of aloe-vera-based CuO nanofluids is found to aid in recovering the viscosities to a great extent. The fluid loss values before hot rolling are observed to be 6.6 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 5.9, 5.4, and 4.6 mL, respectively. The fluid loss value after hot rolling for the WDF is found to be 10.8 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 9.2, 8.5, and 7.7 mL, respectively. The rheological performance data of NFWDF project a better fit with the Herschel-Bulkley model and suggest improvement in rheological and filtration properties. There has been limited research work available in understanding the impact of aloe-vera-gel-based nanofluids in improving the performance of WDFs through the improvement of its rheological and filtration properties. This study aims to exploit the property of native aloe vera and CuO nanofluids combined together to enhance the rheological and filtration properties of WDF by conducting the tests both before and after hot rolling conditions. This study acts as an important precursor for developing novel additives for WDF to improve its rheological and filtration properties. This study is al
{"title":"Experimental Investigation of Aloe-Vera-Based CuO Nanofluid as a Novel Additive in Improving the Rheological and Filtration Properties of Water-Based Drilling Fluid","authors":"Hameed Hussain Ahmed Mansoor, Srinivasa Reddy Devarapu, Robello Samuel, Tushar Sharma, S. Ponmani","doi":"10.2118/205004-PA","DOIUrl":"https://doi.org/10.2118/205004-PA","url":null,"abstract":"Drilling technology in petroleum engineering is associated with problems such as high fluid loss, poor hole cleaning, and pipe sticking. Improvement of rheological and filtration properties of water-based drilling fluids (WDFs) plays a major role in resolving these drilling problems. The application of nanotechnology to WDF in the recent past has attracted much attention in addressing these drilling operations problems. In the present work, we investigate the application of natural aloe vera and CuO nanofluids combined as an additive in WDF to address the drilling problems. The nanofluids of three different concentrations of CuO nanoparticle (0.2, 0.4 , and 0.6 wt%) with aloe vera as a base fluid are prepared for this study by adopting a two-step method. The prepared nanofluids are characterized by their particle size and morphological characteristics. Conventional WDF (DF.0) is synthesized, and the prepared aloe-vera-based CuO nanofluid is added to the WDF to prepare nanofluid-enhancedwater-based drilling fluid (NFWDF) of different concentrations of nanoparticles, namely, 0.2 , 0.4, and 0.6 wt%. The prepared drilling fluid mixture is then characterized for its rheological and filtrate loss properties at various temperatures. Thermal stability and aging studies are performed for both WDF and NFWDF. The experimental results are then modeled using rheological models. The results reveal that aloe-vera-based CuO nanofluids improve the thermal stability and rheological properties of drilling fluid and significantly decrease the American Petroleum Institute (API) filtrate. Viscosity for WDF shows an approximately 61.7% decrease in heating up to 90°C. Further, the hot roll aging test causes a 63% decrease in the viscosity of WDF at 90°C. However, the addition of aloe-vera-based CuO nanofluids is found to aid in recovering the viscosities to a great extent. The fluid loss values before hot rolling are observed to be 6.6 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 5.9, 5.4, and 4.6 mL, respectively. The fluid loss value after hot rolling for the WDF is found to be 10.8 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 9.2, 8.5, and 7.7 mL, respectively. The rheological performance data of NFWDF project a better fit with the Herschel-Bulkley model and suggest improvement in rheological and filtration properties. There has been limited research work available in understanding the impact of aloe-vera-gel-based nanofluids in improving the performance of WDFs through the improvement of its rheological and filtration properties. This study aims to exploit the property of native aloe vera and CuO nanofluids combined together to enhance the rheological and filtration properties of WDF by conducting the tests both before and after hot rolling conditions. This study acts as an important precursor for developing novel additives for WDF to improve its rheological and filtration properties. This study is al","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-10"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780599","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Dikshit, Amrendra Kumar, M. Langlais, B. Gadiyar, G. Woiceshyn, M. Parlar
For offshore wells requiring sand control, it is beneficial to extend the openhole length to access more reserves with a reduced well count. In challenging environments (e.g., low fracture pressure, highly unconsolidated sand), gravel packing with shunt tubes has been used successfully to virtually ensure a complete pack, thereby minimizing the risk of sand-control failure. Although shunt-tube gravel-pack technologies already exist, several issues must be addressed to gravel pack longer wells. First, the extra volume of gravel passing through shunt-tube manifolds raises erosion concerns. Second, the burst rating of the entire shunt system needs to be increased to allow continuous packing through shunts in a heel-to-toe fashion. Third, higher leakoff through the packed interval might increase gravel concentration, which increases friction and the risk of bridging inside the shunts. This study discusses the development and testing of a modified shunted screen that could extend openhole gravel-packing lengths to more than 7,000 ft with zonal isolation. The first step was to use computational fluid dynamics (CFD) simulations to investigate the erosion-prone areas in our existing conventional shunted-screen-technology (SST) manifold design. The CFD results were then used to modify the manifold and make it more resistant to erosion. Prototypes were manufactured and erosion tests were conducted to validate and qualify the new design for targeted proppant concentrations, flow rates, and treatment volumes. Any weak areas found in the shunt system were modified to enable higher burst pressure. The modified shunt system was then independently tested to quantify the burst limits. The concerns regarding high leakoff, friction, and bridging inside the tubes were first addressed by means of experimentation. The first nozzle distance was then modified according to these results. Verification of the modified system design was performed by means of gravel-pack testing on a full-scale model. It was observed that the proposed enhanced-SST (ESST) had no erosion failure after 450,000 lbm of proppant at a slurry rate of 5 bbl/min. The proposed ESST was successfully tested for 10,000-psi burst pressure after the erosion test. The initial motivation, design changes, and tests that led to the development of the modified system are presented herein.
{"title":"Extending Openhole Gravel-Packing Intervals through Enhanced Shunted Screens","authors":"A. Dikshit, Amrendra Kumar, M. Langlais, B. Gadiyar, G. Woiceshyn, M. Parlar","doi":"10.2118/201731-PA","DOIUrl":"https://doi.org/10.2118/201731-PA","url":null,"abstract":"For offshore wells requiring sand control, it is beneficial to extend the openhole length to access more reserves with a reduced well count. In challenging environments (e.g., low fracture pressure, highly unconsolidated sand), gravel packing with shunt tubes has been used successfully to virtually ensure a complete pack, thereby minimizing the risk of sand-control failure. Although shunt-tube gravel-pack technologies already exist, several issues must be addressed to gravel pack longer wells. First, the extra volume of gravel passing through shunt-tube manifolds raises erosion concerns. Second, the burst rating of the entire shunt system needs to be increased to allow continuous packing through shunts in a heel-to-toe fashion. Third, higher leakoff through the packed interval might increase gravel concentration, which increases friction and the risk of bridging inside the shunts. This study discusses the development and testing of a modified shunted screen that could extend openhole gravel-packing lengths to more than 7,000 ft with zonal isolation. The first step was to use computational fluid dynamics (CFD) simulations to investigate the erosion-prone areas in our existing conventional shunted-screen-technology (SST) manifold design. The CFD results were then used to modify the manifold and make it more resistant to erosion. Prototypes were manufactured and erosion tests were conducted to validate and qualify the new design for targeted proppant concentrations, flow rates, and treatment volumes. Any weak areas found in the shunt system were modified to enable higher burst pressure. The modified shunt system was then independently tested to quantify the burst limits. The concerns regarding high leakoff, friction, and bridging inside the tubes were first addressed by means of experimentation. The first nozzle distance was then modified according to these results. Verification of the modified system design was performed by means of gravel-pack testing on a full-scale model. It was observed that the proposed enhanced-SST (ESST) had no erosion failure after 450,000 lbm of proppant at a slurry rate of 5 bbl/min. The proposed ESST was successfully tested for 10,000-psi burst pressure after the erosion test. The initial motivation, design changes, and tests that led to the development of the modified system are presented herein.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-14"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780016","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. Cayeux, A. Ambrus, Lars Øy, Arvid Helleland, Svein Tore Brundtland, Harald Nevøy, M. Morys
The use of recorded downhole rotational speed measurements with a bandwidth up to 9 Hz gives new insights into the conditions under which stick-slip torsional oscillations occur. Observations made while drilling two reservoir sections have shown that, out of all the stick-slip situations identified, 72% of them for one well and 64% for the other well occurred in off-bottom conditions. In these off-bottom conditions, stick-slip was systematically observed while starting the topdrive (TD) until a sufficiently high TD rotational velocity was requested. For these two sections, off-bottomstick-slip was either related to using TD speeds below 120 rev/min or to reaming down during reciprocation procedures. In on-bottom conditions, stick-slip events occurred predominantly when the TD speed was less than 120 rev/min (53 and 32% of the on-bottom cases) but also in association with downlinking to the rotary steerable system (RSS) (23 and 46% of the on-bottom cases), and this, even though the TD speed was larger than 120 rev/min. These on-bottomstick-slip situations did not necessarily occur at a very high weight on bit (WOB) because 98% of them for one well and 46% for the other well took place when the WOB was lower than 10 ton. Downhole measurements have shown that when the drillstring is subject to strong stick-slip conditions, the downhole rotational speed changes from stationary to more than 300 rev/min in just a fraction of a second. Direct observations of downhole rotational speed at high frequency help in discovering conditions that were not suspected to lead to large torsional oscillations. This new information can be used to improve drilling operational procedures and models of the drilling process, therefore enabling increased drilling efficiency.
{"title":"Analysis of Torsional Stick-Slip Situations from Recorded Downhole Rotational Speed Measurements","authors":"E. Cayeux, A. Ambrus, Lars Øy, Arvid Helleland, Svein Tore Brundtland, Harald Nevøy, M. Morys","doi":"10.2118/199678-PA","DOIUrl":"https://doi.org/10.2118/199678-PA","url":null,"abstract":"The use of recorded downhole rotational speed measurements with a bandwidth up to 9 Hz gives new insights into the conditions under which stick-slip torsional oscillations occur. Observations made while drilling two reservoir sections have shown that, out of all the stick-slip situations identified, 72% of them for one well and 64% for the other well occurred in off-bottom conditions. In these off-bottom conditions, stick-slip was systematically observed while starting the topdrive (TD) until a sufficiently high TD rotational velocity was requested. For these two sections, off-bottomstick-slip was either related to using TD speeds below 120 rev/min or to reaming down during reciprocation procedures. In on-bottom conditions, stick-slip events occurred predominantly when the TD speed was less than 120 rev/min (53 and 32% of the on-bottom cases) but also in association with downlinking to the rotary steerable system (RSS) (23 and 46% of the on-bottom cases), and this, even though the TD speed was larger than 120 rev/min. These on-bottomstick-slip situations did not necessarily occur at a very high weight on bit (WOB) because 98% of them for one well and 46% for the other well took place when the WOB was lower than 10 ton. Downhole measurements have shown that when the drillstring is subject to strong stick-slip conditions, the downhole rotational speed changes from stationary to more than 300 rev/min in just a fraction of a second. Direct observations of downhole rotational speed at high frequency help in discovering conditions that were not suspected to lead to large torsional oscillations. This new information can be used to improve drilling operational procedures and models of the drilling process, therefore enabling increased drilling efficiency.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-15"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67776856","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
John-Morten Godhavn, Banzi Olorunju, Dmitri Gorski, M. Kvernland, Mateus Sant' Ana, O. Aamo, S. Sangesland
In this paper, we describe measured and simulated downhole pressure variations (“surge and swab”) during drillpipe connections when drilling an ultradeepwater well offshore Brazil on Bacalhau (former Carcará) Field. Floating rig motion caused by waves and swell (“rig heave”) induces surge and swab when the drillstring is suspended in slips to make up or break a drillpipe connection and topside heave compensation is temporarily deactivated. This is a known issue in regions with harsh weather, such as the North Sea, where pressure oscillations of up to 20 bar have been reported during connections. Recorded downhole drilling data from Bacalhau Field reveals significant pressure oscillations downhole (in the same order of magnitude as in the North Sea) each time the drillstring was suspended in slips to make a connection in the subsalt 8½-in. section of the well. Mud losses were experienced around the same well depth, and they might have been caused by surge and swab. Measured surge and swab pressure variations have been reproduced in an advanced proprietary surge and swab simulator that considers rig heave, drillpipe elasticity, well friction, non-Newtonian drilling mud, well trajectory, and geometry. Moreover, findings in this paper suggest that surge and swab was in fact significantly higher than recorded by the measurement while drilling (MWD) tool. The true magnitude of surge and swab is not captured in the recorded MWD data due to low sampling frequency of the downhole pressure recording (one measurement every 6 seconds, a standard downhole pressure sampling rate used on many operations today). This work shows that surge and swab during drillpipe connections on floaters may challenge the available pressure window for some wells, even in regions with calm weather such as Brazil. Managed pressure drilling (MPD) is a technique that improves control of the downhole pressure. It is, however, not possible to compensate fast downhole pressure transients, such as heave-induced surge and swab, using MPD choke topside. This is due to the long distance between the choke and the bit, which translates into a time delay in the same order of magnitude as typical wave and heave periods. A downhole choke combined with continuous circulation is one of the potential solutions. Surge and swab during drillpipe connections can result in a loss or an influx and should be considered in the well planning phase when mud weight, section lengths, etc. are selected.
{"title":"Significant Surge and Swab Offshore Brazil Induced by Rig Heave during Drillpipe Connections","authors":"John-Morten Godhavn, Banzi Olorunju, Dmitri Gorski, M. Kvernland, Mateus Sant' Ana, O. Aamo, S. Sangesland","doi":"10.2118/200518-PA","DOIUrl":"https://doi.org/10.2118/200518-PA","url":null,"abstract":"In this paper, we describe measured and simulated downhole pressure variations (“surge and swab”) during drillpipe connections when drilling an ultradeepwater well offshore Brazil on Bacalhau (former Carcará) Field. Floating rig motion caused by waves and swell (“rig heave”) induces surge and swab when the drillstring is suspended in slips to make up or break a drillpipe connection and topside heave compensation is temporarily deactivated. This is a known issue in regions with harsh weather, such as the North Sea, where pressure oscillations of up to 20 bar have been reported during connections. Recorded downhole drilling data from Bacalhau Field reveals significant pressure oscillations downhole (in the same order of magnitude as in the North Sea) each time the drillstring was suspended in slips to make a connection in the subsalt 8½-in. section of the well. Mud losses were experienced around the same well depth, and they might have been caused by surge and swab. Measured surge and swab pressure variations have been reproduced in an advanced proprietary surge and swab simulator that considers rig heave, drillpipe elasticity, well friction, non-Newtonian drilling mud, well trajectory, and geometry. Moreover, findings in this paper suggest that surge and swab was in fact significantly higher than recorded by the measurement while drilling (MWD) tool. The true magnitude of surge and swab is not captured in the recorded MWD data due to low sampling frequency of the downhole pressure recording (one measurement every 6 seconds, a standard downhole pressure sampling rate used on many operations today). This work shows that surge and swab during drillpipe connections on floaters may challenge the available pressure window for some wells, even in regions with calm weather such as Brazil. Managed pressure drilling (MPD) is a technique that improves control of the downhole pressure. It is, however, not possible to compensate fast downhole pressure transients, such as heave-induced surge and swab, using MPD choke topside. This is due to the long distance between the choke and the bit, which translates into a time delay in the same order of magnitude as typical wave and heave periods. A downhole choke combined with continuous circulation is one of the potential solutions. Surge and swab during drillpipe connections can result in a loss or an influx and should be considered in the well planning phase when mud weight, section lengths, etc. are selected.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-8"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67778991","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Interest is high in a method to reliably run single-trip completions without involving complex/expensive technologies (Robertson et al. 2019). The reward for such a design would be reduced rig time, safety risks, and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field tested to open without intervention after completion is circulated to total depth (TD) and a liner hanger and openhole isolation packers are set. A field-proven sliding-sleeve door (SSD) valve that required shifting via a shifting tool run on coiled tubing, slickline (SL), or wireline was upgraded to open automatically after relieving tubing pressure once packers (and/or a liner hanger) are set. This PSSD technology, which is integrable to almost any type of sand control screen, is equipped with a backup contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two- or three-position valve can be integrated with inflow control devices (ICDs) (includes autonomous ICDs/autonomous inflow control valves) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved valuable because it revealed failure modes that could not have appeared in the smaller-scale laboratory test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. The production logging tool run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, in which PSSDs with ICDs performed as designed. The unique two- or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection. The PSSD allows the flexibility to change ICD size easily at the wellsite. Therefore, this technology can be used in carbonate as well as sandstone wells. Wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the cost savings of single-trip completions, including ones that require ICD and stimulation options.
人们对一种不涉及复杂/昂贵技术的可靠单趟完井方法非常感兴趣(Robertson et al. 2019)。这种设计将减少钻井时间、安全风险和完井成本。如上所述，开发了一种独特的压力激活滑动侧门(PSSD)阀，并进行了现场测试，该阀在完井循环至总深度(TD)后无需干预即可打开，并安装了尾管悬挂器和裸眼隔离封隔器。一种经过现场验证的滑套门(SSD)阀，需要在连续油管、钢丝绳(SL)或电缆上通过移动工具进行移动，一旦封隔器(和/或尾管悬挂器)坐封，即可在释放油管压力后自动打开。该PSSD技术可与几乎任何类型的防砂筛管集成，并且在主防砂筛管无法打开时配备了备用应急装置。一旦打开，安装的pssd可以无限频率地机械移动。双位或三位阀可与流入控制装置(ICD)集成(包括自主ICD /自主流入控制阀)，并允许在安装后的任何时间进行机械切换，以关闭、刺激或调整ICD设置。在经过计算机辅助设计阶段以满足所有操作/机械要求之后，建造并测试了原型，随后进行了现场安装。尽管压力激活功能已被添加到成熟/经过验证的SSD技术中，但设计阶段仍存在一些挑战。在全尺寸垂直测试井中进行的原型测试证明是有价值的，因为它揭示了在小型实验室测试设施中无法出现的失效模式。从第一次现场试验中吸取的经验教训有助于改进现场处理程序。首次安装时运行的生产测井工具确认带有icd的pssd按设计打开。第二次现场安装涉及不同的尺寸和配置，其中带有icd的pssd按照设计执行。独特的两个或三个位置PSSD适用于任何类型的防砂或碎屑筛管以及任何类型的生产/注入ICD。PSSD可以灵活地在井场轻松更改ICD尺寸。因此，该技术既可用于碳酸盐岩井，也可用于砂岩井。那些通常无法承受现有单趟完井技术成本的井，现在可以从单趟完井技术中节省成本，包括那些需要ICD和增产措施的井。
{"title":"Design to First Deployment: Pressure-Activated Sliding Sleeve for Single-Trip Completion","authors":"A. Dikshit, Amrendra Kumar, G. Woiceshyn","doi":"10.2118/203057-PA","DOIUrl":"https://doi.org/10.2118/203057-PA","url":null,"abstract":"Interest is high in a method to reliably run single-trip completions without involving complex/expensive technologies (Robertson et al. 2019). The reward for such a design would be reduced rig time, safety risks, and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field tested to open without intervention after completion is circulated to total depth (TD) and a liner hanger and openhole isolation packers are set. A field-proven sliding-sleeve door (SSD) valve that required shifting via a shifting tool run on coiled tubing, slickline (SL), or wireline was upgraded to open automatically after relieving tubing pressure once packers (and/or a liner hanger) are set. This PSSD technology, which is integrable to almost any type of sand control screen, is equipped with a backup contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two- or three-position valve can be integrated with inflow control devices (ICDs) (includes autonomous ICDs/autonomous inflow control valves) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved valuable because it revealed failure modes that could not have appeared in the smaller-scale laboratory test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. The production logging tool run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, in which PSSDs with ICDs performed as designed. The unique two- or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection. The PSSD allows the flexibility to change ICD size easily at the wellsite. Therefore, this technology can be used in carbonate as well as sandstone wells. Wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the cost savings of single-trip completions, including ones that require ICD and stimulation options.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-14"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780042","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Effective removal of mudcake from the wellbore before cementing is critical to developing an excellent bond between cement and formation. The application of spacer can remove mudcake effectively. The evaluation of mudcake removal efficiency is significant to the design of spacer. The methods proposed by scholars have limits on the development of mudcake and the simulation of the flushing process. For this paper, a novel apparatus used to test mudcake removal efficiency was designed. A novel experimental method for mudcake removal efficiency of spacer was proposed. The influence factors of mudcake removal efficiency are discussed. The method can evaluate the flushing efficiency quantitatively and provide guidance for designing of spacer.
{"title":"A Novel Experimental Method for Mudcake Removal Efficiency of Spacer","authors":"Rui Zheng, Yong Li, Jianzhou Jin, Zi-Shuai Liu","doi":"10.2118/205008-PA","DOIUrl":"https://doi.org/10.2118/205008-PA","url":null,"abstract":"Effective removal of mudcake from the wellbore before cementing is critical to developing an excellent bond between cement and formation. The application of spacer can remove mudcake effectively. The evaluation of mudcake removal efficiency is significant to the design of spacer. The methods proposed by scholars have limits on the development of mudcake and the simulation of the flushing process. For this paper, a novel apparatus used to test mudcake removal efficiency was designed. A novel experimental method for mudcake removal efficiency of spacer was proposed. The influence factors of mudcake removal efficiency are discussed. The method can evaluate the flushing efficiency quantitatively and provide guidance for designing of spacer.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-10"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Peyton, Joanna Salamaga, A. McPhee, A. Jongejan
Negative tests, or inflow tests, are conducted to verify the integrity of well barriers in the direction of potential flow, subjecting a barrier to a negative pressure differential, while monitoring for signs of a leak. A common practice is to observe the rate of flowback from the well. Flowback may be a sign of a leak due to an influx of formation fluids into the well. However, even when there is no leak, flowback is commonly observed due to thermal expansion of wellbore fluids. Heat transfer will occur between the wellbore fluids in each annulus and with the surrounding formation until temperatures reach an equilibrium. This behavior is described by the process of thermal diffusion, with the resulting temperature increase causing expansion of wellbore fluids and flowback from the well. Industry guidelines state “Horner” analysis may be used when monitoring flowback or pressure buildup during an inflow test. In doing so, engineers and wellsite supervisors may use a “Horner plot” to determine if flowback or pressure buildup is attributable to thermal effects. Those without a reservoir engineering background may not be aware the method was originally derived from a radial flow equation for the purpose of monitoring pressure buildup in a well when shut in after a period of production. The apparent similarity of the radial flow and thermal diffusion equations is what led Horner's technique to subsequently be applied to the prediction of static formation temperature from well logs. However, although thermal expansion is a function of formation temperature, Horner analysis of flowback or pressure buildup during an inflow test has remained a black box that is poorly understood. For the first time, with support from empirical data from offshore wells, we reveal that Horner analysis of thermal expansion is a practice without theoretical justification. The radial equation on which Horner analysis depends, along with the constraints implied by the boundary conditions, fails to accurately account for the conditions of an inflow test. As a result, the method should not be used for analyzing flowback or pressure buildup during an inflow test. Instead, a new method is proposed to interpret a trend of flowback when monitoring well barriers. The findings of this study can help improve understanding Horner analysis and techniques for interpreting inflow tests.
{"title":"Horner Analysis for Negative Inflow Tests of Well Barriers","authors":"J. Peyton, Joanna Salamaga, A. McPhee, A. Jongejan","doi":"10.2118/204479-PA","DOIUrl":"https://doi.org/10.2118/204479-PA","url":null,"abstract":"Negative tests, or inflow tests, are conducted to verify the integrity of well barriers in the direction of potential flow, subjecting a barrier to a negative pressure differential, while monitoring for signs of a leak. A common practice is to observe the rate of flowback from the well. Flowback may be a sign of a leak due to an influx of formation fluids into the well. However, even when there is no leak, flowback is commonly observed due to thermal expansion of wellbore fluids. Heat transfer will occur between the wellbore fluids in each annulus and with the surrounding formation until temperatures reach an equilibrium. This behavior is described by the process of thermal diffusion, with the resulting temperature increase causing expansion of wellbore fluids and flowback from the well. Industry guidelines state “Horner” analysis may be used when monitoring flowback or pressure buildup during an inflow test. In doing so, engineers and wellsite supervisors may use a “Horner plot” to determine if flowback or pressure buildup is attributable to thermal effects. Those without a reservoir engineering background may not be aware the method was originally derived from a radial flow equation for the purpose of monitoring pressure buildup in a well when shut in after a period of production. The apparent similarity of the radial flow and thermal diffusion equations is what led Horner's technique to subsequently be applied to the prediction of static formation temperature from well logs. However, although thermal expansion is a function of formation temperature, Horner analysis of flowback or pressure buildup during an inflow test has remained a black box that is poorly understood. For the first time, with support from empirical data from offshore wells, we reveal that Horner analysis of thermal expansion is a practice without theoretical justification. The radial equation on which Horner analysis depends, along with the constraints implied by the boundary conditions, fails to accurately account for the conditions of an inflow test. As a result, the method should not be used for analyzing flowback or pressure buildup during an inflow test. Instead, a new method is proposed to interpret a trend of flowback when monitoring well barriers. The findings of this study can help improve understanding Horner analysis and techniques for interpreting inflow tests.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-13"},"PeriodicalIF":1.4,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780956","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper, we provide some new insights into stick/slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fifty-six field runs under various drilling conditions were collected with the help of on-bit vibration sensors. Stick/slip vibration occurrence during drilling was analyzed. Two types of stick/slip vibrations were identified: cutting-action-induced stick/slip and friction-induced stick/slip. Methods were developed to determine whether a stick/slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency (DE) is well correlated with the occurrence of cutting-action-induced bit stick/slip vibration. If a PDC bit is designed so that its DE is greater than a critical value, then the cutting-action-induced bit stick/slip vibration is not expected in drilling. Increasing the aggressiveness of the cutting structure of a PDC bit within a limited critical depth of cut is found to be helpful to mitigate bit stick/slip vibration.
{"title":"Identification and Mitigation of Friction- and Cutting-Action-Induced Stick/Slip Vibrations with PDC Bits","authors":"Shilin Chen, J. Wisinger, B. Dunbar, Chris Propes","doi":"10.2118/199639-PA","DOIUrl":"https://doi.org/10.2118/199639-PA","url":null,"abstract":"In this paper, we provide some new insights into stick/slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fifty-six field runs under various drilling conditions were collected with the help of on-bit vibration sensors. Stick/slip vibration occurrence during drilling was analyzed. Two types of stick/slip vibrations were identified: cutting-action-induced stick/slip and friction-induced stick/slip. Methods were developed to determine whether a stick/slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency (DE) is well correlated with the occurrence of cutting-action-induced bit stick/slip vibration. If a PDC bit is designed so that its DE is greater than a critical value, then the cutting-action-induced bit stick/slip vibration is not expected in drilling. Increasing the aggressiveness of the cutting structure of a PDC bit within a limited critical depth of cut is found to be helpful to mitigate bit stick/slip vibration.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"576-587"},"PeriodicalIF":1.4,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199639-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45848268","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
High-torque, low-speed drilling mud motors are typically used to drive rotary-steerable systems (RSS) to improve the rate of penetration (ROP) of the RSS bottomhole assemblies (BHA). Downhole drilling dysfunctions are common when powered RSS BHAs are pushed to the limit for maximum drilling performance. High-frequency (HF) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box of the RSS, slow-rotating housing (SRH) of the RSS, bit box of the mud motor, and top subassembly (sub) of the mud motor to better understand drilling conditions in different shale plays throughout North America. Embedded sensors placed on the outer diameter of the BHA vs. centerline-mounted sensors give a different measurement response and a different vision of the actual dynamics being experienced in the BHA. The HF sensors were deployed in the in-house developed push-the-bit RSS and mud motors, allowing us to model the motor-assist RSS BHAs with analytical models and finite-element analysis models to predict the HF torsional oscillation (TO) and axial oscillation (AO) frequencies. The derivation of the high-frequency axial oscillation (HFAO) and TO analytical equations is detailed in the paper. In one of the example motor-assist RSS BHA analyses, the simulation results reveal that the fundamental high-frequency torsional oscillation (HFTO) frequency is 11.1 Hz whereas the fundamental HFAO frequency is 32.9 Hz, which is approximately three times higher than the fundamental-mode HFTO frequency. A good correlation was observed between the simulation result and the field data gathered from the HF accelerometer and gyro sensors embedded in the RSS and mud motors. Two new types of HF axial drilling dynamics with a polycrystalline diamond compact (PDC) bit—(1) the third-order-mode HFAO and (2) the harmonics of the HFTO coupled to the longitudinal axis—were discovered and reported in detail. One example in this paper shows that the dominant HFTO frequency shifts occurred in the middle of drilling a stand with no connection involved and no surface parameter changes. The examination of the time-domain signal reveals that (1) the “baseline” HFTO-induced tangential accelerations are due to the mud motor output revolutions per minute (RPM) (2) the variation of the HFTO-induced peak tangential accelerations comes from the drillstring stick/slip, which is transmitted to the drill bit through the mud motor, and (3) the 76 and 114 Hz HFTO-induced accelerations are both approximately in a sinusoidal waveform, except in the 3-second transition period, where the mixture of both frequencies is observed. The 114 Hz-HFTO-induced tangential acceleration measured at the bit box is coupled with the 0.16 Hz drillstring stick/slip oscillation. The analytical equation is provided to describe the HFTO coupled with stick/slip as an analogy to communication theory. In addition, the extensive modeling and field measurement of the HFTO and HFAO lead to the mitigati
{"title":"Simulation and Measurement of High-Frequency Torsional Oscillation (HFTO)/High-Frequency Axial Oscillation (HFAO) and Downhole HFTO Mitigation: Knowledge Gains Continue Using Embedded High-Frequency Drilling Dynamics Sensors","authors":"J. Sugiura, Steve Jones","doi":"10.2118/199658-PA","DOIUrl":"https://doi.org/10.2118/199658-PA","url":null,"abstract":"\u0000 High-torque, low-speed drilling mud motors are typically used to drive rotary-steerable systems (RSS) to improve the rate of penetration (ROP) of the RSS bottomhole assemblies (BHA). Downhole drilling dysfunctions are common when powered RSS BHAs are pushed to the limit for maximum drilling performance. High-frequency (HF) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box of the RSS, slow-rotating housing (SRH) of the RSS, bit box of the mud motor, and top subassembly (sub) of the mud motor to better understand drilling conditions in different shale plays throughout North America. Embedded sensors placed on the outer diameter of the BHA vs. centerline-mounted sensors give a different measurement response and a different vision of the actual dynamics being experienced in the BHA.\u0000 The HF sensors were deployed in the in-house developed push-the-bit RSS and mud motors, allowing us to model the motor-assist RSS BHAs with analytical models and finite-element analysis models to predict the HF torsional oscillation (TO) and axial oscillation (AO) frequencies. The derivation of the high-frequency axial oscillation (HFAO) and TO analytical equations is detailed in the paper. In one of the example motor-assist RSS BHA analyses, the simulation results reveal that the fundamental high-frequency torsional oscillation (HFTO) frequency is 11.1 Hz whereas the fundamental HFAO frequency is 32.9 Hz, which is approximately three times higher than the fundamental-mode HFTO frequency. A good correlation was observed between the simulation result and the field data gathered from the HF accelerometer and gyro sensors embedded in the RSS and mud motors.\u0000 Two new types of HF axial drilling dynamics with a polycrystalline diamond compact (PDC) bit—(1) the third-order-mode HFAO and (2) the harmonics of the HFTO coupled to the longitudinal axis—were discovered and reported in detail. One example in this paper shows that the dominant HFTO frequency shifts occurred in the middle of drilling a stand with no connection involved and no surface parameter changes. The examination of the time-domain signal reveals that (1) the “baseline” HFTO-induced tangential accelerations are due to the mud motor output revolutions per minute (RPM) (2) the variation of the HFTO-induced peak tangential accelerations comes from the drillstring stick/slip, which is transmitted to the drill bit through the mud motor, and (3) the 76 and 114 Hz HFTO-induced accelerations are both approximately in a sinusoidal waveform, except in the 3-second transition period, where the mixture of both frequencies is observed. The 114 Hz-HFTO-induced tangential acceleration measured at the bit box is coupled with the 0.16 Hz drillstring stick/slip oscillation. The analytical equation is provided to describe the HFTO coupled with stick/slip as an analogy to communication theory. In addition, the extensive modeling and field measurement of the HFTO and HFAO lead to the mitigati","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"553-575"},"PeriodicalIF":1.4,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199658-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48659288","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","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：