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Abstract The Influx Management Envelope (IME) assists in identifying influx conditions which could compromise the primary well barrier and fluid handling capacity on surface. IME boundaries are influenced by changes in parameters such as mud weight, wellbore depth and geometry, pump rate, surface pressure, etc. Thus, any changes to these parameters will change the acceptable influx volume and intensity for Dynamic Influx Management. It is, therefore, critical to understand how changes in each of these variables affect IME limits so that its validity can be established within parameter ranges, rather than only for discrete values. This work presents an in-depth discussion of how IME limits are determined, with both detailed philosophical and practical guidance on methods to calculate the surface and subsurface limits. Recent deepwater applications of the IME are used to represent baselines for presenting methods of calculating IME limits, including a basic single bubble approach, through to the most robust approach of including transient, multiphase simulations. Parameter sensitivity analyses are performed to determine reasonable ranges for which an IME is valid, with the goal of understanding the required IME update frequency during operation.
Krivolapov, Dmitry Sergeevich (Schlumberger) | Magda, Andrey Vladimirovich (Schlumberger) | Soroka, Taras Bogdanovich (Schlumberger) | Dobrokhleb, Pavel Yurievich (Schlumberger) | Evdokimov, Stanislav Aleksandrovich (Schlumberger) | Gagloyev, Georgy Georgievich (Schlumberger) | Novoselov, Aleksandr Vadimovich (Schlumberger) | Ramazanov, Aynur Ravisovich (Schlumberger) | Attia, Mohamed Samir (Schlumberger) | Zvyagin, Vasiliy Fedorovich (Lukoil Nizhnevolzhskneft) | Nabiullin, Renat Ildusovich (Lukoil Nizhnevolzhskneft) | Khamidullin, Denis Radikovich (Lukoil Nizhnevolzhskneft)
Managed Pressure Drilling technology became popular and widespread in Western countries in the early 2000s and has long been successfully used for drilling complex wells onshore and offshore projects (for example in the North Sea, Gulf of Mexico and etc.) In Russia this technology has found its application relatively recently and still has never been used for offshore drilling.
This article describes the results of the first MPD offshore application in Russia for drilling an HTHP exploration well in the Caspian Sea. A fully automated MPD set with early kick detection system (EKD) and back pressure pump (BPP) was applied, allowing to control pressure and drilling fluid outflow besides drilling, during connections. The drilling conducted using reduced mud weight in «near balanced» conditions, which compared to conventional strategy sufficiently reduced formation overbalance and losses risk as well.
Specialized MPD tests used to determine formation and fracturing pressure limit in uncertainty geological conditions, optimizing core sampling drilling and mud roll-over strategy.
SPE/IADC Members Abstract We review the conflicting literature on gas migration velocities during kicks. We consider the laboratory and large scale test data that shows that for any local gas void fraction of more than 10%, the influx migrates at approximately 100 ft/min. We also review the evidence from field experience that shows that gas can migrate much more slowly (the typical rule of thumb suggests that gas bubbles move at approximately 15 ft/min) and in some cases remain stationary. We show that the yield stress of the drilling mud which holds cuttings in suspension whilst making connections, can also hold gas bubbles in suspension, and report an experimental study of these gas suspension effects. Significant volumes of gas can be held in suspension during a gas kick, this trapped gas remaining stationary until the mud is circulated out of the well. We consider the implications of this for well control operations, and present field data where gas was injected into a marine riser, it dispersed and remained stationary until circulated out. We show that a single bubble migration model, which neglects gas suspension, predicts that as the gas rises and expands it unloads the riser. By simulating the gas suspension characteristics we model the field data. We conclude that gas in moderate concentrations (more than 10%) migrates quickly, typically at 100 ft/min. This migrating influx leaves a trail of suspended gas in the mud that remains stationary. For small kicks in deep wells the entire influx can be distributed, at a low concentration, and remain in suspension until the gas-cut mud is circulated out of the well. Gas Migration Velocity - Literature Controversy There is a major controversy in the published literature over gas migration rates during kicks while drilling. Experimental tests in small flow loops and in test wells show the gas migration velocity is around 100 ft/min, while field estimates suggest that gas rises at around 15 ft/min or more slowly. We consider this discrepancy. Johnson and White showed that, in typical drilling geometries, in realistic drilling fluids, for gas concentrations larger than 10%, gas migration velocities were around 100 ft/min, significantly larger than the equivalent migration rates in water. The viscosity of drilling mud hinders the bubble break-up process allowing gas to migrate as bigger bubbles (which travel faster). They also observed that the yield stress of the drilling mud would hold low concentrations of gas in suspension with no migration. Rader et al. reported similar results for gas migration in a 3.7 m, (12 ft) flow loop and a 1800 m (6,000 ft) well. The gas velocity in the well was measured using the time of flight principle. Hovland and Rommetveit reported large scale tests in a 1500 m (5000 ft) deep test well, which had a maximum deviation of 630. They used the time of flight between pressure transducers mounted at different depths in the well to measure a gas slip velocity of 0.55 m/s (110 ft/min). A widely accepted "rule of thumb's used in the field says that gas bubbles migrate at 0.085 m/s, (15 ft/min). Blount claimed that he had evidence of gas migration rates of around 0.014 m/s (3 ft/min), although he did not specify how these were derived. In field situations an accurate estimation of gas migration during a well control incident is very difficult. P. 93