DON HANNEGAN, P.E., Weatherford; and KEN GRAY, Ph.D., University of Texas at Austin
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| A 3D rendering of Weatherford's Microflux control system (MFCS) for offshore closed-loop drilling and cementing on Atwod Oceanics Aurora jackup. |
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Real-time operations have historically been associated with data processing, but in the context of this article, it refers to the ability of onsite and offsite decision-makers to process information fast enough while drilling to keep up with the critical parameters of the circulating fluids system. Understanding those parameters, including formation pore pressure, fracture pressure, wellbore integrity, hydrocarbon content of annulus returns and abnormalities in mass flow in vs. out, is critical for safe, effective drilling, and successful isolation of potential flow zones during well construction.
The industry relies heavily on pre-drill predictions and offset well information for a fairly accurate idea of critical formation parameters. In some of the more challenging wells, especially those that present shifting and/or narrow mud-weight windows, there are invariably margins of error in the fracture/pore pressure maps used for planning. These margins, along with unknowns that can only be experienced in the drilling process, should be considered when designing the fluids and well construction programs.
Collectively, these relative unknowns are often dealt with by designing complex programs, which in some cases, fail to achieve the TD objective with a large enough whole diameter for production viability. In other cases, the authorization for expenditure (AFE) is exceeded, due to non-productive time (NPT), and the mud cost incurred dealing with trouble zones and resulting well control scenarios. The prospect may also be deemed technically un-drillable with a conventional open-to-atmosphere mud returns system. In more complex environments—deepwater, exploratory, HPHT, depleted formations, and shifting drilling margins—actual measurements of the critical parameters may be vitally important for real-time operations to be successful on all fronts.
CONVENTIONAL LIMITATIONS
Drilling with a conventional circulating fluids system that is open to the atmosphere has inherent limitations, regardless of whether or not the prospect appears challenging:
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Annulus returns must consistently arrive under the rig floor at near-atmospheric pressure for drilling to continue uninterrupted and avoid risk of a well control scenario developing. This operational condition is frequently upset by kick-loss scenarios that are typically associated with drilling in narrow, shifting and/or relatively unknown mud weight windows.
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Actual drilling windows must be accurately predicted for safe, effective drilling. Exploratory and HPHT prospects are notorious for uncomfortable margins of error in pre-drill predictions, and routine operations, such as wellbore strengthening, contribute to the list of relative unknowns.
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Significant changes in mud tank levels must be observed over a period of time to signal kicks or losses. A 15-to-20-bbl gain or loss in return flowrates may be required on some rigs to indicate well flow or loss circulation. Indicators may be further masked on deepwater rigs experiencing significant heave.
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The only way to adjust the equivalent mud weight (EMW) in the hole, short of exercising the BOP, is by changing the speed of the rig mud pumps to manipulate circulating annular friction pressure (AFP). This response limits the depths of open holes that may be drilled in narrow drilling windows.
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The wellbore pressure profile fluctuates significantly with each jointed pipe connection. When not circulating, the wellbore sees only hydrostatic pressure. While circulating, the wellbore sees hydrostatic pressure plus AFP, which consumes much of an already narrow drilling window.
MANAGED PRESSURE DRILLING
To overcome these limitations and address challenging reservoirs, newer technologies such as MPD systems must be adopted to aggressively manage risk. While MPD is recognized for its ability to drill the un-drillable, and to reduce time and cost, few have applied the technology on conventional drilling programs for its potential to reduce health, safety and environmental (HSE) risks. While HSE is inherent in other applications, few have cited HSE as the main driver for practicing MPD.
For challenging offshore wells being drilled with conventional fluids and cementing programs, MPD has considerable strengths in providing real-time information in support of real-time operations, where the foremost objective is to minimize HSE issues and concerns. A conventional fluids program’s objectives are to maintain a hydrostatically overbalanced condition at all times, and a conventional cementing program is one with the intent to comply with API Standard 65, Isolating Potential Flow Zones during Well Construction.
CLOSED-LOOP ADVANTAGES
Real-time information about what is happening within the circulating fluids system is available when drilling with a closed-loop system. Unlike a conventional system where, for drilling to proceed safely and without interruption, the algebraic summation of all the influencing factors must net zero-gage pressure for annulus returns at surface, a closed-loop system enables one to view the totality of the circulating fluids system, as if it were a pressure vessel.
A closed-loop system is enabled by adding key components to the rig’s existing circulating fluids system: a rotating control device (RCD), a dedicated MPD choke manifold system, auxiliary backpressure mud pump, mass flow meter, and a gas chromatograph, Fig. 1. Advantages are seen through the diversion of annular returns to the choke system to form a closed and pressurizable circulating loop. Mass flowrates, in and out, are precisely measured and compared with the aid of PLCs in the MPD choke manifold system. Time and temperature-corrected algorithms in the PLC software provide input to remote monitoring consoles that display critical parameters.
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| Fig. 1. Components of a closed-loop system for drilling and cementing operations in deep water include an RCD below the marine riser tension ring, auxiliary backpressure pump, PLC automated choke manifold system, flowmeter, and remote data acquisition capability. |
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The role of the auxiliary backpressure mud pump may be likened to the means by which critical parameters of one’s blood pressure are measured. Our body’s circulatory system is obviously a closed-loop system. A known amount of backpressure is applied by an inflatable around the arm, which enables algorithms in the monitoring system’s PLC to precisely measure and display critical parameters.
Wellbore integrity is quantified through formation integrity tests (FITs) and leak-off tests (LOTs) while drilling, enabling more frequent, cost effective testing. A frequent determination of the wellbore’s actual pressure containment integrity is especially beneficial when drilling the open hole, setting casing and conducting cementing operations in trouble zones. They may reveal more pertinent information than a conventional FIT or LOT, because they are conducted while circulating and without having to use the rig BOP for something other than its primary purpose.
For real-time well control operations to be most successful, kicks, losses and their magnitudes must be detected early, to provide the advance notice needed to make informed decisions and execute corrective action. Figure 2 describes a decision-tree originated with preparations to drill a challenging HPHT prospect in the North Sea. In this case, the operator dictates corrective action as soon as a combined influx greater than one barrel is detected. It is not practical to assume that this level of real-time resolution is achievable with a conventional mud return system. On some rigs, a 15-to-20-bbl pit gain or loss would be required to conclusively ascertain an influx or loss circulation.
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| Fig. 2. Well control decision tree: MPD application on HPHT prospect in the North Sea. |
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CLOSED-LOOP TECHNOLOGY
Marine RCDs. In offshore operations, specialized marine RCDs provide configuration options with the rig’s riser. The RCD illustrated in Fig. 1 is configured below the marine riser tension ring (BTR RCD). This location is uniquely suited for dynamically positioned drillships, which may be required to make up to 180° heading changes. The design also requires no modification to the rig’s upper marine riser system and telescoping slip joint. The RCD serves as a section of the lower marine riser package and accordingly has a tensile strength of 3,000,000 lb. When the bearing and annular seal assembly are absent from the body of the RCD, returns are via their conventional path. When the RCD bearing and annular seal assembly are remotely latched into the body, returns are via the flexible flowlines to the MPD choke manifold.
The annular BOP below the RCD facilitates deployment and servicing of the RCD during MPD, and enables safer, faster riser degassing, should it become necessary when the RCD bearing and annular seal are not installed, and annulus returns are taking their usual path through the marine diverter.
Another offshore RCD design is referred to as the Docking Station RCD. This design also uses a remote hydraulic latching mechanism, so that personnel are not required in the moonpool area, Fig. 3. It is configured above the marine riser tension ring, and consequently, may require modifications to the rig’s existing upper marine riser system. If the rig’s existing slip-joint has insufficient thru-bore to accommodate RCD bearing assembly deployment, a modified slip-joint with a shorter stroke is required.
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| Fig. 3. Docking station RCD above an annular BOP, both in the process of being configured above the marine riser tension ring on a moored semisubmersible rig. |
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PLC-automated choke manifold system. Weatherford’s Microflux control (MFC) system provides real-time drilling hydraulics information, such as the actual annular pressure limits; measures micro-quantities of in-flux and out-flux; enables dynamic FITs and LOTs; recognizes pack-off trends; and quantifies ballooning and breathing phenomenon. Using a dedicated, programmable logic controller (PLC) and proprietary software, the MFC system offers unprecedented visibility into the wellbore. This capability was achieved primarily through the advancement of high-resolution mass-flow metering, yielding volumetric flowrates and density with ±0.1% flowrate accuracy and ±0.0042 ppg. Other advances include high-resolution pressure sensors with ±1 psi accuracy; a closed-loop circulating system incorporating an RCD (to divert flow at surface and allowing pressure to be applied at surface if required); an intelligent drilling choke manifold (which acquires and evaluates the high-resolution data and can automatically alert and react, accordingly); a real-time hydraulic model (which incorporates high-resolution and standard data for current determination of the annular hydraulic pressure profile); and a human-machine interface.
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| Fig. 4. WFC screen shot displays influx identified in real time; choke closed to increase SBP; and kick suppressed within a minute. |
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Micro influxes refers to the total “micro” volume of influx of reservoir fluids that can be detected, compared to conventional methods. Control techniques can be determined automatically by the system or the system user, based on conventional well control techniques. Micro-influx identification enables accurate determination of the lower limits of the well—the actual formation pore pressure. Figure 4 is an MFC system screen shot, which illustrates the automatic choke response suppressing an influx with a virtual trip tank indicating a pit gain of 129 gal. Surface backpressure (SBP) is increased within seconds, and the consequential increase in equivalent mud weight regains mass balance within a minute.
In this example, the MFC system choke was fully open, as the rig’s choke would normally be while drilling conventionally. However, the rig’s choke is dedicated to well control. The MPD choke manifold is dedicated to drilling with more precision and, if on AUTO, automatically responds to suppress an influx of reservoir fluids, as soon as it is detected by the mass flowrate measurements. In the supervisory control and data acquisition (SCADA) mode, real-time data is provided for the driller to make an informed decision about whether or not, and by how much, SBP should be applied to suppress a detected kick. For example, informed of the magnitude of the kick and other considerations, the driller may, instead, choose to first try suppressing the influx by increasing the circulating rate.
Micro outfluxes occur when drilling fluid is lost to the formation. When using the MFC system, a fluid loss is detected very early and before the total volume lost escalates, to allow the driller to take action before he risks losing the primary well control barrier. The rate of losses is an important parameter on display. A total loss of circulation will be spotted very early, with the flow out showing a sudden drop to zero, alerting the driller to take corrective action. If the choke is fully open when losses are detected while drilling, the system is unable to reduce surface backpressure to mitigate the losses. However, the driller has the option of reducing the mud pump rate to determine if circulating AFP is inducing the losses. If the mud in the hole is hydrostatically underbalanced, and modest amounts of surface backpressure are being applied while circulating, opening the MPD choke with the system on AUTO may serve to mitigate the losses.
Formation integrity testing. True dynamic FITs and LOTs can be done at any depth to identify whether predictions of shoe integrity or leak-off are still applicable, and to verify or nullify the assumption that the weakest part of the hole is at the shoe. Underground blowouts have occurred by making the assumption that the weakest component is at the last casing shoe. Also, the test can be performed prior to increasing mud weight, to justify that the open hole can withstand a heavier mud weight in deeper formations, or is capable of handling the anticipated casing running surge pressures and cementing operations without losses.
LOTs are valuable for ascertaining the wellbore integrity, in the case that well control corrective actions are required. Specifically, they identify the maximum surface backpressure that can be safely applied when circulating out a kick. However, in some formations, intentionally pressurizing the formation, to the point of breakdown, may reduce the fracture pressure gradient from what it would otherwise have been, and possibly set the stage for a poor cement job.
FITs are relatively benign with regard to the risk of permanent deformation of the wellbore, and are typically used to verify if the last casing shoe will sustain the maximum pressures anticipated while drilling the next section’s open hole. The general assumption is that the casing shoe above the open hole to be drilled will be the weakest point encountered. However, an influx of reservoir fluids from one formation may energize the wellbore and fracture a weaker-than-predicted formation in the uncased hole, resulting in a subsurface blowout, where reservoir fluids may migrate to the seabed and to the sea surface.
Conducting a FIT after each stand is drilled may be prudent in trouble zones. However, conventional FITs may require drilling interruptions, and one conventional method requires use of the rig BOP. Dynamic FITs may be conducted at any time, using the MFC system, with minimum interruption to the drilling progress and without exercising the rig BOP.
In the example in Fig. 5, the operator established 500-psi surface backpressure as the test value. In this case, leak-off occurred at 475-psi surface backpressure. In effect, the failed FIT provided LOT data, because losses occurred in advance of the test to value. This awareness may suggest deviations from pre-planned fluids and casing programs; changes in mud density, circulating rate and casing set depth; or other remedial action such as a solid expandable system or running a liner. In any case, for drilling process safety reasons and for tweaking the cementing program, it is better to know the actual strength of the open hole, sooner than later.
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| Fig. 5. Screen display shows dynamic LOT confirmed through sustained losses and full returns seen once SBP was reduced. This was initially to be a FIT with a test-to value of 500-psi SBP. Failing to reach that desired or anticipated value, the test established a new leak-off value for the open hole. |
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Quantifying ballooning/breathing. Ballooning phenomenon is particularly troublesome in some formations. It is important to recognize in real time the difference between ballooning vs. losses, and breathing vs. the beginning of an influx. Misinterpretations are known contributors to offshore well control incidents. A skilled technician can interpret the flow in vs. flow out signatures and accurately determine ballooning vs. losses upon mud pump startup, and breathing vs. the beginning of a kick upon mud pump shutdown for connections. The ability to quickly make this determination significantly reduces the time required to safely make pipe connections.
Trend analysis and certain signatures of ballooning/breathing and related gas at the surface, due to the phenomenon can be helpful toward adjusting cementing calculations—and with the advance notice to do so. Figure 6 is an example of quantifying ballooning volume, for the purpose of compensating for that wellbore characteristic, in cementing simulators.
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| Fig. 6. Quantifying wellbore ballooning characteristics. |
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FIT, LOT and ballooning—beyond wellbore considerations. Within the pressurized environment of a closed-loop system, critical circulating fluid parameters are precisely quantified in real time, which, itself, is a significant step-change beyond conventional drilling practices. However, more informed knowledge of the pressure vessel, itself, can significantly enable better interpretation of FIT, LOT, extended LOT (XLOT) and ballooning data in support of real-time operations decision-making.
Additional HSE and real-time autonomous drilling technologies can be enabled by dynamic density control (DDC) and wider windows (WW), which couple the MPD’s wellbore hydraulics with geomechanics technologies. In DDC and WW, Fig. 7 illustrates that the pressure vessel, itself, is more than the wellbore annulus. The operational annulus includes the rock and contained fluids surrounding the wellbore that respond to, interact with, and contribute to, pressure changes in the wellbore container. The container has a wall thickness of several feet, and the wall is usually leaky (fluid leakoff, fractures, fluid influxes, etc.). FIT, LOT, XLOT and ballooning/breathing all involve collective interactions of rocks, fluids, stresses, displacements and time. Taking these operational realities into account can provide significant benefits for HSE and real-time pressure control, drill-ahead kick/loss procedures, determination of ballooning/breathing flow vs. kicking flow, wellbore stability/collapse diagnostics, and pore pressure quantification without wellbore influx.
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| Fig. 7. Wider-window topical areas of study undertaken by University of Texas at Austin. |
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CLOSED-LOOP CEMENTING
Closed-loop cementing involves a host of actions, including verifying formation containment capability prior to running casing, monitoring pre-flush effectiveness, acquiring more precise spacer and slurry displacement information for comparison with conventional calculations, providing Pp/Fp/MW/EMW inputs to cementing simulation models and detection of induced fractures during cementing sequences. The latter is of particular concern, as an induced fracture may consume large quantities of the pre-determined volume of cement required for reservoir isolation. There is a possibility this could result in incomplete coverage and isolation.
Closed-loop cementing, and the real-time information that the technology provides contributes to compliance with the requirements of API Standard 65 – Isolation of Potential Flow Zones for Well Construction. There are many associated benefits of closed-loop cementing technology before, during and after cementing for well construction and plug-and-abandonments, including:
- Preparatory—quantify the pressure integrity of the wellbore with frequent dynamic FITs
- Cement placement—optimize fluid dynamics and detect induced fractures in real time, so that corrective action can be taken
- Curing—help ensure that balanced plugs are correctly placed; apply backpressure, if needed, to ensure that cement remains undisturbed, and to maintain more consistent annulus pressure during pre-set
- Testing—use of MPD kit to pressure test in lieu of using dedicated cementing equipment.
CONCLUSION
The need for real time, relevant data is central to real-time operations involving drilling hydraulics. As an ever-increasing number of wells are drilled in challenging offshore environments, actual measurement of critical wellbore parameters becomes increasingly vital to drilling wells safely, on time and within AFE. MPD technologies, applied to conventional drilling and cementing programs, provide a fast, accurate source of real-time data and drilling hazard mitigation. With growing offshore acceptance of MPD’s root concepts and specialized technology, it is likely that MPD, as practiced on conventional-wisdom fluids and well construction programs, will most likely be a significant contributor.
MPD is a safer way to drill the world’s most challenging offshore wells; it’s also a safer way to drill many that don’t meet that criteria. The achievement is the result of multiple factors, including closing mud returns under the rig floor; early kick-loss detection, drilling nearer-balanced safely with precise flowrate information; efficient EMW adjustment capability, improving chances of getting a good cement job right on first attempt; and reducing time from spud to TD—all the while feeding real-time critical parameters data into real-time operations. 
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The author
DON HANNEGAN is Strategic Technology Development manager—MPD for Weatherford. He is a registered professional engineer, a World Oil 2004 Innovative Thinker award recipient, 2006/2007 SPE International Distinguished Lecturer, 2012 IADC Exemplary Service award recipient, and author of the MPD Section of SPE’s new textbook, Advanced Drilling Technology & Well Construction. Presently he is serving as lead author of a new book to be published by the University of Texas Petroleum Extension Service (PETEX), Drilling Hazard Mitigation Tools & Technology.
KEN GRAY is a professor of petroleum engineering at The University of Texas. Dr. Gray served as Departmental Chairman from 1966–74 and originated the UT Center for Earth Sciences and Engineering. Inventor of Dynamic Density Control (DDC) and Dynamic Mud Weight Windows (DMWW) concepts, He holds B.S., M.S., and Ph.D. degrees in petroleum engineering. |
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