UPM 16080 A Virtual Wellbore Modelling System to Prevent and Enhance the Detection of Well Control Events in Deepwater Drilling Brian Piccolo, Austin Johnson, Scott Petrie, Henry Pinkstone, Christian Leuchtenberg Abstract As drilling continuously progresses into deeper ocean environments and through fractured carbonate formations, the margins between formation pore and fracture pressure have become narrower and less predictable. As a consequence, the industry has seen an increase in events resulting in large influx volumes in the wellbore, uncontrolled gas breakout in the riser, and significant lost mud returns. Such events pose safety, environmental, and project completion risks as well as increase the cost and non-productive time associated with drilling a well. It s worth noting that while the deepwater environment poses a unique set of challenges, kick and loss events are also a concern on land projects. To address the above challenges, Managed Pressure Operations (MPO) has developed a virtual wellbore modelling system that can pinpoint deviations between actual and anticipated wellbore pressure, temperature, and flow rate behavior to alarm the driller of the onset or increased risk of a hazardous event. The virtual wellbore modelling system integrates conventional drilling data feeds from the rig s Supervisory Control And Data Acquisition(SCADA) system with advanced sensor technology placed throughout the rig, riser, and wellbore to accurately analyze the well for abnormalities that represent a kick or loss in real-time. This technology is also used to proactively protect the wellbore by analyzing pressure and flow rate feedback for symptoms of an unsafe change in drilling margins in advance of a significant well control event occurring. Once an alarm is raised, the driller can proactively adjust wellbore pressure to prevent a hazardous kick or loss event from happening in the first place. As such, MPO s use of virtual wellbore modelling is intended to rapidly detect the onset of a hazardous event as well as prevent such an event from occurring. The end benefit is improved safety and reduced costs for deepwater drilling projects. Furthermore, the challenges described in this paper also highlight why the development of a subsea metering system that could be deployed beneath the telescopic slip joint would provide a step change for drilling safety. Uncertain and Narrowing Drilling Margins. In order to successfully drill a well with a conventional drilling program, the pressure throughout the wellbore, known as the wellbore pressure gradient, must remain above the pore pressure gradient and below the fracture pressure gradient. Pore and fracture pressure gradients can collectively be referred to as formation pressure gradients. The term pore pressure gradient refers to the pressure of formation fluid (water, oil, gas) while residing within the formation pores. The term fracture pressure gradient refers to the pressure required to initiate a fracture in the wellbore. If wellbore pressure drops below pore pressure, an uncontrolled flow of hydrocarbons can enter the wellbore and ultimately flow to surface resulting in a significant risk to people, the environment, the installation, and the overall success of a drilling project. An unscheduled flow of hydrocarbons into the wellbore is called a kick or influx. Contrastingly, if wellbore pressure exceeds fracture pressure, wellbore fluids which often consist of drilling mud, can be lost to the formation resulting in a drop in wellbore hydrostatic pressure which can eventually lead to an influx from another part of the formation with a higher pore pressure. In practice, there are additional wellbore pressure control boundaries that are followed to maintain wellbore stability, enhance rate of penetration, reduce the risks of an influx on pump shutdown and also maintain adequate kick tolerance. This paper will only discuss kick tolerance briefly. Depending on whether conventional drilling or managed pressure drilling operations are being conducted, the options available to control wellbore pressure can vary. In conventional drilling, wellbore pressure is controlled by the managing the hydrostatic pressure of the drilling mud and circulating friction by managing drilling fluid rheology and the mud pump injection rate. In a form of drilling known as managed pressure drilling (MPD), the top of a wellbore is sealed around drillpipe allowing drilling returns to be diverted to a choke where applied surface back pressure (ASBP) can also be used to control wellbore pressure. By controlling hydrostatic pressure and circulating friction in drilling (and Copyright 2016, Letton Hall Group. This paper was developed for the UPM Forum, 24 25 February 2016, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
ASBP if applicable), a driller can work to ensure wellbore pressure optimized and within the formation pressure gradients as described above. While the objective of keeping wellbore pressure within formation pressure gradients appears straight forward, the complication arises from the fact that pore and fracture pressure gradients are not always certain. A common challenge experienced offshore are fractured carbonate regions which are highly unpredictable. The brittle nature of these formations can result in small fractures which can ultimately contain abnormally high pressured zones that are not easily detected with seismic. Contrastingly, fractures or cavernous sections can cause a sudden low fracture pressure gradient that can result in a significant or total loss of drilling mud. While fractured carbonates represent some of the most challenging hole sections in current offshore drilling, there is uncertainty associated with drilling any hole section. Herein lies one reason why Exploration is a suitable term for drilling operations. In addition to predictability, formation pressure gradients become narrower as drilling progresses into deeper offshore environments. Narrow formation pressure gradients require precise pressure control drilling methods in order to keep a safe wellbore pressure and ensure no kicks or losses. Such wells can ends up with kicks or losses simply by turning the muds pumps on or off. Furthermore narrow drilling margins have a lower kick tolerance requiring kicks to be detected in stopped within relatively small volumes in order to ensure that they can be safely circulated out of the wellbore. A kick volume that exceeds kick tolerance cannot be safely circulated out of the wellbore. This event will lead to an underground blowout where there is a continuous exchange of drilling mud lost to the formation while formation fluid enters the wellbore even after the SSBOP has been closed. Drilling margins become narrower as seawater depth increases because deepwater wells have less overburden stress than shallow water wells. Put another terms, a deepwater well with the same total depth as a shallow water well will have a lower fracture gradient at a given depth because the formation is under a comparatively lower vertical stress from the layers of dense rock above. In this simplified example, pore pressure increases at the same rate in a shallow and deepwater wells because vertical communication with the surface is assumed. Figure 1: Visual depiction describing the comparatively lower overburden stress in a deepwater well versus a shallow water well Drilling Margin Estimation and Validation. As mentioned before, when wellbore pressure exceeds drilling margins, the onset of a well control event can occur in the form of an influx or loss. Well control events of a significant size can harm people and impact the environment, and equipment, and the success of drilling project. The estimation of drilling margins is performed during well planning. Well design engineers can benefit from assumptions made by seismic surveys, empirical correlations, and logging data from nearby wells if available. While a significant amount of effort is put forth to estimate drilling margins, the end results are always based on varying degrees of confidence. For example, exploration wells, which are planned with limited data, will have lower confidence estimates. Similarly, even though development wells are planned with the benefit of data from nearby wells, these drilling projects are not free from uncertainty either as there is not always full visibility to the geologic conditions between wells. While the drilling contractor does take steps to validate fracture pressure and proceed cautiously with drilling margin estimates, there are inherent limitations. For example, a leak off test or formation integrity test is performed at the start of each hole section to confirm if the exposed formation below the casing shoe is strong enough to hold the planned wellbore pressure for the section. While this test works for the top of a hole section, the procedure does not account for the fact that the weakest formation section could be deeper and not yet exposed. In these circumstances, a weaker than expected fracture gradient is determined only when significant losses are sustained. In conventional drilling with a hydrostatically Upstream Production Measurement Forum 2016 2
overbalanced wellbore, pore pressure is often not verified at all as drilling progresses. Instead, an analysis of certain drilling parameters and cuttings can suggest the possibility of entering a high pressure zone. However, there is no conventional process in place for real-time pore pressure validation while drilling. As a result, an inaccurate pore pressure estimate may not be recognized until after an influx as occurred. As seen thus far, the deepwater drilling industry is taxed with the complexity of drilling through uncertain and narrow drilling margins. This leads to two major challenges. First, the existence of an inaccurate drilling margin estimate often does not manifest itself until after a well control event occurs. Secondly, there is a higher risk of exceeding kick tolerance when an influx is taken in narrow margin drilling projects which can result in a hazardous well control event that cannot be controlled by conventional means. Both cases justify the use of technology to prevent or at least rapidly detect the onset of a well control event. Conventional Well Control Event Detection This section will discuss the complications associated with well control event detection offshore and the limitations of conventional event detection equipment which remains the standard for offshore drilling projects. Factors that Complicate Well Control Event Detection Practices Offshore. Due to vessel motion, the deepwater drilling industry is also challenged with well control event detection. As with land drilling, deepwater drilling projects rely on unexpected changes in mud return flow rate and active pit volumes to determine if a kick or loss has occurred. For example, an increase in flow rate and trip tank/pit volumes is an indicator of an influx. Likewise, a drop in flow rate and pit volume represents lost returns. Based on this well control event detection philosophy, there is an assumption that flow rates and pit volumes are always constant when there is no well control event. However such a statement is rarely true in deepwater drilling and only partially true during land operations. The challenge with this event detection approach in deepwater drilling is that mud return flow rates and pit levels are always changing due to the expansion and contraction of the telescopic slip joint which allows for vessel motion while attached the riser. As such, when the slip joint extends, return flow rate drops and the active pit level drops resulting in similar symptoms to lost returns. Alternatively, when the slip joint contracts, return flow rate and the active pit volume increases offering similar symptoms to an influx. One should also note that heavy crane activity on an offshore drilling vessel can also cause the vessel to roll resulting in the liquid level dipping on side of trip tank and increasing on another side of the trip tank. Depending on the positioning of level sensors, this level change could give the appearance of a kick or loss. When conducting a static flow check, there are additional wellbore behaviors in drilling that also complicate the effort. A static flow check involves suspending drilling and shutting down all mud pumps so that one can determine if the well is still flowing when all drilling mud should be static. At a basic level, a well that flows with the mud pumps off implies the presence of a kick. However, a static flow check can be complicated by the presence of ballooning. Ballooning refers to a wellbore behavior in which the formation returns a small amount of drilling mud back to the wellbore due the wellbore pressure drop associated with turning off the mud pumps. This behavior is deciphered from an influx because it only lasts for a short while and has a tapering flow rate while an influx will continue at an increasing flow rate until the well is secured. In a conventional drilling operations, the rig crew does not know the difference between ballooning or an influx immediately, requiring additional time to diagnose the cause and ultimately shut-in the BOP. As such, kick volumes increase further. Additionally, a pump shut-down causes a drain back of mud volume into the active pits which can appear to be unintentional flow for a brief while further complicating event detection. Finally, drilling riser temperature can also cause fluid expansion or contraction which can mask small kick volumes further requiring additional time for a driller to positively detect an influx. When the mud pumps are shut down, riser volume cools and contracts. When the pumps are running, riser volume is warmer and can expand. Drilling projects without continuous circulation systems can be subject to these temperature changes on every drillpipe connection. As such, changes in trip tank/active pit volumes and flow rate offshore due to vessel motion, ballooning, and temperature changes must be deciphered from changes in the same indicators due to a well control event. The ambiguity and time required to decipher between whether a well control event is occurring or not often results in much larger kicks in the offshore environment. The severity of this issue is further compounded by a reduction in kick tolerance in deepwater environments which reduces the maximum influx volume which can be safely removed from the well by conventional means as described earlier. Upstream Production Measurement Forum 2016 3
Conventional Well Control Event Detection Equipment. Current well control event detection methods do not inform the rig crew as to what the flow rate in and out of the wellbore and the trip tank/active pit volume should precisely be at all times so that an anomalous event such as a kick or loss can be quickly identified. Existing event detection equipment also limit the precision required to detect small gains. to a choke manifold. A conventional drilling operation has no choke or RCD. Instead, drilling returns are directed up through the slip joint and through the main flowline instead. To begin, conventional event detection equipment has inherent inaccuracies. The current industry standard for event detection is a paddle flow meter and two trip tank/active mud pit level sensors; one from the rig and one from the mud logger. Small movements in the paddle flow meter which are often considered noise, can mask small changes in flow rate ultimately causing the driller to wait for larger flow rate changes to diagnose a kick or loss. Furthermore, the two level sensors can have different readings if one loses calibration or due to vessel motion which also increases the amount of time for the driller to confirm with confidence that a kick or loss has occurred. Finally, changes in pump efficiency can impact the mud pump rate into the wellbore which impact the expected flow rate out of the wellbore. Currently, pump flow rate is measured with a stroke counter. Even with improvements in flow metering precision, a rig crew still lacks the capability to know exactly what the flow rate should be at all times. As examples, vessel motion, pump rate, temperature changes, and wellbore ballooning can all have an impact on flow rate and level measurement. To compensate for this, the driller will accept a certain amount of variation in kick/loss indicators while drilling operations progress based on her own experience over time. As a consequence to this, changes in flow rate and trip tank/active pit volume must exceed a certain tolerance before being recognized as a well control event, leading to larger than necessary kick and losses off shore. Real-time Drilling Margin Validation to Prevent the Onset of a Well Control Event In 2014, Managed Pressure Operations (MPO) field tested a software system designed to detect the onset of an unsafe and unexpected deviation from expected formation pressure gradients while drilling. With this warning, the driller can proactively adjust wellbore pressure to prevent a pending well control event from occurring. The system is designed to be utilized in a MPD configuration in which the top of the riser is sealed with a rotating control head and drilling mud returns are diverted Figure 2: Deepwater drilling configuration for MPD is shown. Based on operator defined parameters, the PDS software ultimately oscillates the opening size of a choke in a slow and controlled fashion between two preprogrammed positions while taking mud returns. In doing so, wellbore pressure and flow out of the riser will increase and decrease in a repeatable fashion as a function of wellbore compressibility in order to establish a reliable finger print over time. The flow out of the riser is tracked by an indicator called Flow Out which measured by a coriolis meter upstream of the choke. Wellbore pressure changes are inferred by tracking ASBP. However, bottom hole pressure can be used as well if available. While this occurs, the software analyzes the peaks and troughs of ASBP and Flow Out wave profiles to seek brief symptoms of a kick or loss thereby confirming an unexpected and unsafe change in a formation pressure gradient. It should be noted that since the peaks and troughs of the waveforms exists for only a brief moment, kick or loss volumes are negligible and the average wellbore pressure remains within drilling margins over time. Upstream Production Measurement Forum 2016 4
The software also draws data live rig data from WITS in order to ensure that changes in mud return flow rate and wellbore pressure over time due to drilling margin detection are differentiated from other rig activities which can also impact the same indicators. For example, changes in mud rheology, drill string rotation, mud pump injection rate, and intended adjustments in average choke pressure are all accounted for. As such, the expected wellbore pressure and flow out finger print is continuously validated. Once an unsafe drilling margin is detected, the rig crew can proactively respond by adjusting average wellbore by which ever means desired resulting in the prevention of a recordable well control event from occurring in the first place. The PDS approach is in stark contrast to the conventional methods which do not continuously ascertain formation gradient estimates while drilling resulting in the increased risk of a recordable well control event. The PDS testing was conducted in a live offshore drilling environment in 2014. The test results showed that the PDS could detect the presence of a weakening fracture gradient that had degraded to 20 psi above average wellbore pressure with only a half a barrels of lost returns. While the test was conducted under live drilling conditions (ie open hole of a side tracked well, medium depth wellbore, drill string rotating and reciprocating, oil based mud, and mud pumps at 300 gpm) the weakening fracture gradient was simulated by cracking open a ½ bleed off line upstream of the choke system. This simulated configuration was chosen for safety because this was the first offshore test. The process flow and equipment block diagram is shown in Figure 3. The testing was conducted during a tender assist drilling operation on a moored platform. Under this configuration a rotating control devices seals the riser around drill pipe and diverts riser flow to a topside coriolis meter and choke manifold. To conduct testing, one of the chokes was left in a fixed, partially open position while the other choke was oscillated as per the user inputs described earlier in this section. Figure 3: Process flow block diagram for formation pressure determination system offshore on a moored platform with a tender assist drilling operation. Additionally, the block diagram in Figure 3 represents a shallow water configuration with a high pressure riser that allows the blowout preventer to be at the riser top. This is different than the deepwater configuration in Figure 2. In either case, the wellbore pressure control principles are the same. Two tests were conducted offshore to validate the capability of the PDS. The first test was a signal reliability test that was intended to prove that the PDS could create a repeatable Flow Out and ASBP over time in order to enhance the reliability of detected changes. The second test simulated the sensitivity of the system to detect a weakening fracture gradient by diverting flow away from the choke and coriolis meter by opening a 1/2 bleed line upstream of both of those components. The signal reliability test results were successful. Figure 4 shows that ASBP applied by the choke and Flow Out behaved in a repeatable fashion. This was also further justified by showing that the choke position behaved exactly as intended throughout each oscillation. The results of this data demonstrate the capability of the PDS to establish expected Flow Out and ASBP beviours. Figure 4 Signal reliability test results from offshore testing Upstream Production Measurement Forum 2016 5
Figure 5 depicts zoomed view of Flow Out over time during signal reliability testing. This data shows that even small Flow Out changes due to compressibility, which appear to be noise in Figure 4 are also repeatable. Furthermore, the driller can be in the position to proactively adjust wellbore pressure to prevent a significant well control event from occurring. Some actions that the driller may take could include reducing average ASBP, reducing pump rate, rotating slower, or changing mud rheology. Figure 5 Flow out compressibility tracked during offshore testing Figure 6 from the signal reliability testing compares ASBP data with pressure while drilling (PWD) data to validate that changes in ASBP are proliferated throughout the entire wellbore as expected. A PWD is located at the base of the drillstring on the bottom hole assembly. Figure 6: ASBP and PWD pressure tracked during offshore testing. The second test was intended to simulate the detection of a weaker than expected fracture gradient. In order to do so, an operator on the rig manually opened a 1/2 bleed valve as the software system was reducing choke opening size in order to simulate a condition where a weakening formation gradient suddenly could not contain the intended wellbore pressure increase. The result was a brief and transient drop in flow out and the inability to increase choke pressure as high as intended. Figure 7 depicts the test results. Note the sudden deformation of pressure and flow out waves when the weakening fracture margin was detected on the right half of the image. The left half of the image represents the condition where the fracture gradient had not yet weakened to an unsafe value and thus, the PDS indicators were behaving as expected. The simulated fracture gradient detection test results show the ability to detect a fracture gradient that has weakened to only 20 psi above average wellbore pressure with only a ½ barrel of lost fluid. Since the average wellbore pressure remained within formation gradients the whole time, the driller has not incurred a significant well control event. Figure 7: Results of simulation fracture margin detection test done offshore in a live drilling environment The results of PDS testing suggest that unsafe and unexpected changes in formation pressure gradients can be detected and responded to prior to incurring a significant well control event. This capability directly addresses the concern discussed earlier that conventional drilling practices do not validate pore and fracture pressure margin estimates while drilling. For future testing, the PDS will be utilized to detect live pore and fracture pressure gradients. One should also note that the impacts of vessel heave are isolated from deepwater MPD operations because Flow Out is routed through fixed length lines back to surface instead of through a telescopic slip joint which continuously expands and contracts. That being said, the next system to be discussed will address the complexity of changing mud return rates due to vessel motion. Rapid Kick Detection in Deepwater To address the transient nature of flow rates and pit volumes in offshore drilling and the challenges this creates when trying to apply conventional well control event detection practices, MPO has deployed a full scale prototype of the Deepwater Kick Detection (DKD) system in Brazil in 2014. The DKD system has been designed to calculate expected flow out and pit volumes in real time to allow the driller to more rapidly differentiate between the onset of a well control event and the transience of Flow Out and trip tank/active pit levels due to the offshore environment and typical drilling operational factors. The DKD system also analyses drilling parameters, pressure, and temperatures to further validate event detection. The DKD system can be utilized during conventional drilling operations or managed pressure drilling. Much of the focus going forward will be on the conventional Upstream Production Measurement Forum 2016 6
drilling implementation of DKD. In terms of hardware, the DKD system consists of 6 equivalent flow area coriolis flow meters on the suction side of each mud pump and a 14 coriolis meter manifold that is tied into the flowline. The 14 coriolis meter manifold contains 14 equivalent flow area coriolis meter, a filter screen upstream of the flow meter, and interlocked isolation valves to direct flow through the meter or through the conventional return path if there is a blockage. Level sensors are placed on the telescopic slip joint to account for the change in riser volume on Flow Out and trip tank/ active pit volumes. An additional level sensor is placed on the trip tank and active mud pit so that 2 out of 3 voting is available for both. Finally, a level sensor and level switch are placed in the flow line to protect against blockage and automatically bypass. Figure 8 is a block process flow diagram describing the DKD system layout on the rig. available, than a single coriolis meter could be placed downstream of all mud pumps on the standpipe. Coriolis meters have been chosen due to their high turn down ratio and capability to measure density. The Flow In to the wellbore is a key factor in determining what the Flow Out should be at any point in time. Furthermore, density measurement is a critical factor in predicting expected return fluid density, calculating bottoms up time, and measuring sweep effectiveness. See Figure 9 below for the configuration deployed in Brazil. Monitoring Flow In density is also especially important to bring about awareness to any miscommunication or error when transferring mud between tanks. Figure 8: DKD process flow block diagram The DKD system also pulls rig data from WITS including stand pipe pressure, hook load measurement, block position measurement, total gas, PWD, and subsea pressure and temperature from the depth of the Subsea Blowout Preventer (SSBOP) and the bottom hole assembly. Mud Pump Injection (Flow In) Measurement. DKD begins with measuring the Flow In which is the flow rate injected into the wellbore from the rig mud pumps. The flow rate injected directly into the riser from the riser booster pump is also included. Traditionally, the flow rate is calculated by tracking pump strokes and assuming a volumetric efficiency per stroke. However, volumetric efficiency can vary over time due to operational wear causing changes in the actual amount of mud being injected into the well for a given stroke rating. The injection side flow measurement is done with 6 equivalent flow area coriolis meters upstream of each mud pump. The reason for this configuration is that coriolis meters do not have the pressure rating be installed downstream of the pump system. If the appropriate pressure rating was Figure 9: 6 coriolis meter installed upstream of each mud pump Mud Return Measurement on the Flowline (Flow Out). With regards to measuring Flow Out, the DKD system utilizes a 14 coriolis flow meter manifold which is tied into the flowline to measure drilling mud returns. The core of the system is a 14 equivalent flow area coriolis meter. This system also includes a solids strainer on the return flow line which prevents large diameter solids from entering and plugging the coriolis meter. The coriolis meter tie-in also includes two interlocking remote diversion valves to divert flow back through flowline (conventional path) if plugging occurs or to divert flow to the coriolis meter under normal operating conditions. When diverting flow to the main flow line, a secondary benefit is that the solids strainer is flushed. Additionally, a back-up sparging/jetting line is connected to the return coriolis manifold to flush the meter in the event of solids build up past the strainer. Upstream Production Measurement Forum 2016 7
Figure 10: 14 equivalent flow area coriolis meter to measure flow out. Flow Line Coriolis Meter Installation Strategy. When installing the coriolis meter on the flowline, attention must be paid to ensure there is adequate hydrostatic head between the diverter outlet and the coriolis meter so that circulating friction from flow through the coriolis meter is overcome and there is no fluid flow back-up in the flow line. Additional head upstream of the meter also increases flow velocity which reduces the risk of solids and debris settling in the meter. Additionally, the coriolis meter outlet should be should exposed to some back pressure downstream of the meter to ensure the meter measures accurately. Figure 12: Photograph of flowline coriolis meter installed in Brazil 2014 Finally, two level sensors consisting of a tuning fork switch and a radar sensor monitor the flow line level upstream of the strainer. In the event of a solids build up or plugging, the sensors will detect an unsafe level and command the interlocked diversion valves on the 14 coriolis meter manifold to divert flow back through the flowline. These sensors are shown in Figure 13 and Figure 14. MPO installs the coriolis meter as close to the gumbo box as possible ensuring that the maximum hydrostatic pressure is acting on the upstream side of the meter. The outlet of the coriolis meter is tied into a shaker header box so that there is some back pressure on the outlet side of the meter to ensure measurement accuracy. A sketch of this installation is shown in Figure 11 and an actually photograph is shown in Figure 12. Figure 13 Tuning fork level switch which is used to detect an unsafe level changes in the flowline. Figure 11: Qualitiative sketch of coriolis installation and tie-in to flow line Figure 14: Radar level sensor to monitor flowline level Correcting Flow Out for Rig Heave. With the capability to measure Flow Out and Flow In, the DKD system also utilizes radar and laser sensors to monitor slip joint displacement and calculate an expected Flow Out based on rig heave. To Upstream Production Measurement Forum 2016 8
perform this calculation, the DKD system tracks the rate of volume change of the slip joint while the rig is heaving and adds this rate differential to the Flow In rate measurement from the rig mud pumps. With all other circumstances remaining the same, the Flow Out measured by the flowline coriolis meter should remain equal to this calculated flow rate unless a kick or loss is occurring. The radar and laser sensor is mounted to the traveling barrel of the telescopic slip joint while the targets are mounted to the fixed barrel. The two sensors are shown in Figure 15. Figure 15: Laser level sensor (left) and radar level sensor (right) mounted on the slip joint to monitor for slip joint displacement Trip Tank and Active Mud Pit Level Measurement. Currently, trip tanks and active mud pits have two level sensors; one from the shipyard and one from the mud logger. A loss of calibration or failure can cause each of these sensors to have different readings resulting in additional time lost to detect with confidence a level change that is associated with a kick or loss. To account for this issue, MPO adds a third sensor to the trip tank and active mud pit so that 2 out of 3 voting is possible. Furthermore, in the event of failure of one of the volume sensors, there is still two level sensors available on such a critical safety measurement. Figure 16: MPO places 3 rd radar based, level sensor on trip tanks and mud pits Vessel Roll Due to Crane Movement. Operation of a rig crane while moving heavy objects can cause the vessel to roll resulting in the trip tank and active pit level sensors to detect an increase or decrease volume. However, in reality there is no additional volume in these tanks. Instead, the vessel roll has caused the fluid on one side of the tank to dip while the other side increases. By combining awareness of the crane activity with expected Flow Out and trip tank/active mud pit values over time, the DKD system can be used to differentiate a level change from crane operation to a level change from the occurrence of an actual well control event. Riser Density Measurement. The DKD system also tracks changes in riser fluid density to monitor planned changes in drilling mud properties, ensure the hole is kept full while tripping, and track the presence of hydrocarbons in the riser. The riser density measurements are made by utilizing pressure transducer data from the SSBOP. A sudden decrease in riser pressure could indicate that the hole is not being kept full during tripping or that lighter fluid is in the riser, possibly from an influx. The influx may consist of free gas or it may be gas that is dissolved into oil based mud which is often not detected until the gas breaks out about 2000 below the rig floor. One manner of distinguishing between the two is to use the Flow In density measurement to determine if the riser density change was in fact planned. Contrastingly, a sudden increase in riser pressure would generally be attributed to an increase in drilling mud density entering the riser or an increased ROP causing a higher cuttings concentration in the riser. In order to distinguish the cause, the DKD system pulls data from WITS such as ROP as well as tracks Flow In density. Changes in riser density can also be confirmed with Flow Out measurements. For example, connection gas in the riser is reflected by a pressure drop in the SSBOP sensors and later confirmed by a drop in density recorded at the Flow Out coriolis meter. Trends that reflect an increase in connection gas from previous connections could also be used to caution the driller that the differential between pore pressure and wellbore pressure is being reduced which can increase the risk of a kick. Monitoring Temperature in the Wellbore and Riser. Temperature can also be used to track the onset of an influx in the wellbore or riser. Temperature transducers are available on the suction side of the mud pumps, flowline, SSBOP, and bottom hole assembly (BHA). Monitoring the wellbore for temperature changes at the BHA can be used to determine if an influx has been taken. Furthermore, monitoring the riser for heating and cooling when circulation starts or stops can be used to validate any increase or decrease in trip tank or active pit volumes as opposed to the onset of a well control event. Additional use of WITS Data. The pressure difference in the wellbore can be analysed with PWD data. The PWD can be used to assess any pressure changes from surge and swab Upstream Production Measurement Forum 2016 9
while the drillpipe is set in slips during a connection that may increase the risk of a well control event. Tripping speed can also be monitored to alarm the driller if speeds becomes excessive. In either case, the DKD system draws awareness to rig activity which may increase the risk of a kick or loss due to surge/swab. This data can be used to validate the detection of a well control event. Furthermore, an influx detection can also be supported with an increase in drillstring weight and/or a sudden increase in ROP, referred to as a drilling break. Considering these factors alongside changes in Flow Out and trip tank/active pit volumes can allow the driller too quickly and with confidence to determine the onset of a well control event. Managed Pressure Drilling Configuration of DKD. During MPD, the Flow Out measurement is taken by a 10 coriolis meter that is adjoined to the MPD choke manifold as installed in Brazil 2014. The coriolis meter is installed upstream of the choke manifold to reduce the impact of an inaccuracy caused by the increasing gas fraction often recognized downstream of the choke. The flowline coriolis is not used during MPD because the RCD on the riser diverts flow directly to the MPD choke and not up the slip joint to the conventional flowline. Another difference is that riser temperature and pressure at the depth of the RCD is also available. Vertically, displaced pressure transducers on the RCD can also inform the driller of a riser fluid density change at the depth of the RCD. Another benefit to the MPD configuration is that riser return flow is directed to the MPD choke manifold via flexible, high flow rate hoses. As a result, the drilling operation becomes isolated from the expansion and contraction of the slip joint effectively eliminating the impacts of rig heave on Flow Out and trip tank/active pit volumes. MPO still recommends installing the DKD flowline coriolis meter and slip joint displacement sensors so that the rig may be protected during periods where the rig is drilling conventionally and MPD equipment is not in use. Deepwater Kick Detection Challenges. Several challenges still exist pertaining to deepwater kick detection. The largest challenge to overcome is that flow measurement equipment must operate over a wide range of flow rates, 10-2000 gpm. Additionally, the drilling mud return flow can contain gas (intentionally or unintentionally) as well as liquid creating the potential for multiphase flow. Furthermore, pressure drops through the flow line meter must be minimized so that there is no flow line back-up. Ideally, one meter would be placed downstream of all mud pumps instead of one meter upstream of each mud pump to reduce costs and foot print. However, when considering a coriolis meter, there is no existing options with the 5,000 to 10,000 psi rating that is needed to be downstream of the mud pumps. Furthermore, it would be ideal to have a flow meter on the riser beneath the telescopic slip joint which can detect flow out without the complication of rig heave. MPO efforts in this space have been subject to trade-offs. The single phase coriolis meter has the benefit of a wide turn down ratio with the downsides of producing erroneous readings when exposed to a small amount of gas and a low pressure rating. Contrastingly, pressure differential meters can have a high pressure rating and function with a larger gas cut. However, when designing these meters for a wide turndown ratio, these meters can have a high pressure drop. Non-intrusive sonar meters can work reliably when calibrated and have no additional pressure drop, but do not work well at slow flow rates and need to be re-calibrated for density changes. Regardless, of which option chosen, none of the meters seem to cover the flow rate range of 10-2000gpm well. To combat this, MPO has considered alternative options. For example, at low flow rates, flow could be diverted to a smaller flow meter. Another option would be to utilize the stroke counter to calculate flow rates at a low flow rate based on a volumetric efficiency that is continuously updated by the DKD system while flow meter is measuring flow rates within its optimal range. With all of the above taken into consideration, there does not seem to be a single flow meter option on the market to address the full range of needs for kick detection at this time. Conclusions 1. Conventional methods of well control event detection assume that Flow Out and trip tank/active put volume is constant which is only partially true for land operations and not valid for deepwater operations. Rig heave as an example can cause these indicators to continuously fluctuate offshore. 2. Existing efforts to validate pore pressure and fracture pressure gradient estimates while drilling are limited. As a result, the actual formation pressure environment while drilling is often not ascertained unless a recordable event has occurred. 3. A pressure determination system has been developed which systematically checks for an unsafe and unexpected change in pore or fracture pressure gradients while drilling. This can alert the driller to adjust well bore pressure in order to prevent a pending well control event from occurring. In doing so, the PDS can ascertain pore and fracture pressure gradients while drilling. Upstream Production Measurement Forum 2016 10
4. A deepwater kick detection system has been developed which takes into account vessel motion, pressure, and temperature, and mud pump injection rate to determine exactly what Flow Out and trip tank/active pit volumes should be at any point in time. Density measurments are also taken at each flow meter and in the riser to determine the presence of hydrocarbons and ensure the hole is kept full during tripping. In doing so, deviations from expected can more rapidly be diagnosed as a well control event. 5. At this point in time, there does not seem to be a single flow meter solution that covers the full requirements of deepwater kick detection in terms of having a turndown ratio to cover 10-2000gpm, low pressure drop, accuracy with significant gas cut, and a high pressure rating. 6. Vessel heave can continuously vary flow out and trip tank/active pit volumes while drilling. An advancement in kick detection technology would be the availability of a flow meter below the slip joint that would not be subject to rig heave. References 1. Johnson, A., Leuchtenberg, C., Petrie, S., & Cunningham, D. (2014, March 4). Advancing Deepwater Kick Detection. IADC/SPE-167990-MS 2. Leuchtenberg, C. (2013). Patent No. WO 2013/164478 A2. World Intellectual Property Organization. 3. Piccolo, B., Leuchtenberg, C. (2015, April 13-14). Physical Concept Validation Testing Performed for a Pore and Fracture Pressure Margin Prediction System During Offshore MPD Operations. SPE/IADC-173809-MS 4. Piccolo, B., Savage, P., Pinkstone, H., & Leuchtenberg, C. (2014, April 8). Verification of Pore and Fracture Pressure Margins during Managed Pressure Drilling. IADC/SPE- 168958-MS 5. Bourgoyne, Adam T. Applied Drilling Engineering. Richardson, TX: Society of Petroleum Engineers, 1986. Print. Upstream Production Measurement Forum 2016 11