深水作业安全卫士 DKD深水井涌检测系统

Numerous developments in automation have made the modern mobile offshore drilling unit a marvel of engineering achievement and a model of efficiency. Yet, even with the surge in advancements, kick detection, which can be comparatively elementary for a fixed drilling unit, has proved to be significantly more difficult to master on a vessel subject to wave motion and currents. This paper describes experiences, challenges, and approaches to solving the problems related to creating an advanced early kickdetection system suitable for floating mobile offshore drilling units.

Managed-pressure drilling (MPD) has surfaced as a natural response to drilling in unconventional or otherwise difficult fields, and the need for an enhanced kick-detection system has been established somewhat naturally from the imposed needs of MPD systems. MPD is based upon the most fundamental principles of drilling; balancing the equivalent circulating density to formation pressure minimizes influx and stabilizes the wellbore. The MPD system aims to drill a well within a margin of the balanced pressure of the formations being drilled. To accomplish this goal, a rotary head or other annular sealing device is coupled with an active drilling choke that can automatically adjust the casing pressure. Though configurations of the MPD system may vary, the primary feedback mechanism for the MPD system in all cases is the return flow rate. When bottomhole pressure (BHP) is lower than formation pressure, influx of formation fluid occurs.

Closing the system with an annular seal offers many benefits. The closed system creates a fixed, known well volume that is a function of the casing and bit diameters and the volume occupied by the drillstring. With fluid in the wellbore being mostly incompressible, the pressure upstream of the choke and the flow rate through the return line become valuable in determining the size and severity of kicks. Sealing the wellbore has also led to the use of meters that can measure multiphase flow accurately. Conventionally, wellbore and fluid characteristics are determined by analyzing trends and catching samples after the fact, whereas a closed-loop system allows a higher level of automation, real-time automated analysis, and actionable data on the basis of which engineers can quickly make decisions.

These solutions have undoubtedly reduced the amount of time required to trigger an alarm. But there still exists a void in terms of what is done with the feedback from the closed-well system. To complicate this matter, deepwater drilling presents challenges to kick detection to which fixed offshore installations are not subject. Additionally, deepwater formations tend to be some of the most prolific in the world, often displaying high productivity—desirable for production, but risky from a drilling perspective.

Fortunately, an advanced, robust kickdetection system can be constructed from many components that are already available and, in many cases, already used in the downstream sector of the industry.

Deepwater Kick Detection (DKD)

Besides adding smart meters to conventional pressure/volume/temperature (PVT) systems, the DKD system must account for vessel movement, wellbore effects, and changes in rheology and drilling parameters, and it must feed information directly to the MPD system. This may be done in such a way as to be evolutionary and natural, as opposed to revolutionary and incoherent, with the larger-rig-design philosophy. Ultimately, DKD should be achieved in such a way as to refine and automate existing drilling-data measurements and enhance proven practice with the addition of accurate flow measurement.

It is important to note that improvements in the accuracy of instrumentation alone will not provide the full DKD solution; process is as important as precision and accuracy, if not more so. One of the root causes identified in the Macondo blowout was that simultaneous operations interfered with the crew’s ability to recognize the influx. A simple calculation comparing the number of pump strokes with the tank level could have been used to identify the influx.

Risers pose unique challenges and unique opportunities for offshore drilling operations. On one hand, risers are large, heavy, and time consuming to run, and they do not often protect against high pressure. On the other hand, risers allow for instruments to be present in the annulus—a luxury that traditional casing strings cannot offer. Spaced along the length of the riser, multiple pressure readings allow for density measurement as the fluid is returning to the surface. The type and the spacing of the pressure transducers are important. Over long distances and large pressure changes, a simple comparison may be performed between two independent transducers. However, as the distance shortens and the change becomes smaller, the readings are unusable because of the resolution required. Diaphragm-type pressure transducers are favorable over a shorter distance. As far as downhole pressure readings are concerned, an incorporation of BHP would be desirable. Pressurewhile-drilling tools do make this possible, but careful consideration should be given as to how such data are incorporated.

Concerning floating rigs specifically, an account must be given for the effect of wave motion. Accurate measurement of flow and pressure is vital, but it is also vital to have an understanding of what the flow and pressure should be. It is known that wave motion has a noticeable effect on riser volume because of the use of a telescopic slip joint. In the case of a highpressure diverter or rotating control device installed above the slip joint, a direct measurement can be made of the riser heave through use of a laser range finder or similar device. With the known dimensions and displacement of the slip joint, a slip-joint correction factor may be applied to the known displacement, resulting in a real-time calculation of riser volume as a function of wave motion. With a known riser-heave displacement and a volumetric correction factor applied, the DKD system may anticipate nonsteady-state conditions and send alarms when anomalies occur.

With the onset of pumped riser systems and the possibility of riserless systems, an alternative form of riser-heave measurement must be achieved in the event that the telescopic slip joint is not installed. Global positioning offers one solution, while installing accelerometers offers another. In field trials, accelerometers have not yet proved reliable when compared with the laser range finder. In cases where the return flow is routed through a hose (as opposed to the riser), considerations should be made to account for any possible lag caused by using a hose.

Drilling parameters such as drillpipe rotational speed, rate of penetration, and weight on bit can affect BHP. The DKD then must contain a robust control and data-processing system.

An automated DKD system mitigates risks and delivers value to the drilling operation by alerting the crew to small, manageable problems before these have the chance to become large, unwieldy problems. When considering kick management through conventional means, considerable volumes of formation fluid may enter the well before a problem is suspected. A considerable amount of fluid may further be invited into the well while performing a conventional flow check. It is not uncommon to see kicks of 50 to 100 bbl or more in deepwater environments. It is evident that the best way to reduce the amount of corrective work is to reduce the magnitude of the event.

Conclusions

A DKD system will require a holistic approach to sufficiently meet the challenges posed by drilling in deep water. In addition to traditional volumetric flow accounting, a mass-flow accounting approach should be implemented, as well as modeling to account for fluid and wellbore effects. By detecting kicks earlier, less work is required to resolve the event. Reduced kick volume results in significant time savings, which is realized through a reduction in total circulating time. Ultimately, the need for high specification pressure-control equipment may be reduced if the source problem, gas influx, is mitigated.