**3. Conventional kick detection**

#### **3.1 Kick indicators**

There are certain indicators that of primary importance to kick detection. Two of these indicators provide positive signs of influx into the wellbore during drilling while third indicator is relevant to recognizing a kick during tripping operations. To recognize a kick while drilling, two major changes in the rig fluid circulating system (while the rig pumps are on) need to be detected. The first primary indicator is a flow rate increase while pumping at a constant rate as this signifies that the formation is aiding the rig pumps move fluid up the annulus via an influx into the wellbore. The second sign of primary importance while drilling is an increase in pit (mud tank) volume not attributable to surface interventions such as building addition drilling fluid volumes. Fluids entering the wellbore will displace an equal volume of drilling fluid in the flowline and cause an increase in pit level (referred to as *pit gain*). This change in pit level could take some time due to the tank surface area. Surface losses of circulated mud in the return line, shale shakers and transfer tanks supplementing the main mud tanks would have to be accounted for so that the pit gain can be reliable. While tripping the drill string, the kick indicator of primary importance is flow from the well when the rig pumps are off. One notable exception to this (returns from the well with the rig pumps off being a kick indicator) is when a slug is pumped downhole resulting in heavier mud in the drill string than in the annulus [1, 4].

In addition to these primary kick indicators there are warning signs while drilling which if promptly responded to will keep the well under control and prevent the occurrence of a well control incident. These warning signs (secondary indicators) include abrupt increase in the rate of penetration while drilling called a drilling break, *Advances in Well Control: Early Kick Detection and Automated Control Systems DOI: http://dx.doi.org/10.5772/intechopen.106800*

increase in torque and drag, changes in mud properties, increase in the shape and size of cuttings, decrease in shale density, increase in gas readings during tripping, connection, circulation or drilling, increase in the temperature of the drilling fluids returns and decrease in the calculated d-exponent. As these secondary indicators are not consistent in all situations they need to be considered collectively. They nonetheless give indication to the potential for an underbalanced situation [1, 4].

#### **3.2 Auxiliary drilling rig equipment for kick detection**

The American Petroleum Institute (API 53) standard for auxiliary equipment complimentary to both surface and subsea BOP installations, related to monitoring primary and secondary kick indicators, stipulates that the drilling rig has a trip tank, pit volume measuring and recording devices and a flow rate sensor [9]. The flow rate sensor on conventional drilling rigs is typically the flow paddle type for which the frequency (and voltage signal) generated is proportional to the flow rate. While the flow paddle meter is a low cost, low maintenance solution, it is not suitable for solidladen fluids and gas flow [10]. It is recommended that the flow rate sensor is mounted in the flow line for early detection of formation fluid entering the wellbore or a loss of returns. The trip tank, a low-volume calibrated tank, that can be isolated from other surface drilling fluid system equipment should be capable of accurately measuring the amount of fluid entering and returning from the well with readout of half a barrel (0.0795 m3 ) volume change. The trip tank is primarily used to measure the amount of drilling fluid required to fill the wellbore while tripping in or out of hole to ascertain whether the drilling fluid volume matches pipe displacement. The trip tank can also be used to measure volumes gained or lost in the annulus. The pit volume measuring and recording devices on the rig should be capable of automatically transmitting pneumatic or electric signals from sensors mounted on the drilling fluid pits to recorders and signaling devices on the rig floor such that pit volume gain or loss can be detected [4, 6, 9]. A Pit Volume Totalizer system meets these requirements on conventional drilling rigs. It is a centralized processor into which signals from sensors are fed. Flow into the wellbore is monitored using a mechanical or proximity type mud pump stroke counter while the rate of returns from the wellbore is monitored via a paddle flow type sensor placed in an open flowline. The level in the mud pits can be monitored using a mud level probe or an ultrasonic-type level sensor which can account for solids build up at the bottom of the tank that may affect float type readings [6].

These measurements, that aid in kick detection, are frequently monitored at the driller's console and corroborated by the mud logger's monitoring system. The conventional kick detection system is designed to raise alarms based primarily on threshold readings of delta flow (the difference between inlet and outlet flow rates) and pit gain over time. Mathematically, the delta flow method is represented thus:

$$
\Delta Q = Q\_i - Q\_o \tag{1}
$$

where; ∆ > *Q* 0 indicates lost circulation; and ∆ < *Q* 0 indicates that a kick has occurred [11]. The drilling crew should be able to recognize a kick volume of 5 bbl (0.795 m3 ) or less during trips while a kick volume of 10 bbl (1.590 m3 ) or less should be recognized while drilling. A flow check is performed if improper hole fill up is noticed during a trip as measured by the trip tank. If the flow check is positive the well should be shut in, conversely, the drill string should be run back to the bottom and the well circulated bottoms up [4, 9].

## **3.3 Auxiliary drilling rig equipment for kick detection**

Mud logging as a service is typically provided under Surface Logging Services which involves the use surface measurements to infer formation and wellbore properties. Real time monitoring of data obtainable through mud logging provides several parameters for kick detection which include increase in pit volume (pit gain), pump rate, return flow rate, rate of penetration (ROP), total gas, connection gas and drop in pump pressure. None of these parameters requires sophisticated downhole electronics or advanced signal processing. These parameters can be categorized into instantaneous parameters (drilling parameters) and lagged parameters. The drilling parameters are ROP, pit gain, pump pressure, pump rate and return flow rate. The lagged parameters, on the other hand, comprise gas parameters delayed by the lag time. Lag time, a definite time interval that is always required for pumping the drilled formation cuttings and drilling fluid from the hole bottom to the surface, depends on both the volume of drilling fluid in the annulus and the flow rate at which the drilling fluid is circulated. Correlating the frequency and level of the connection gas with respect to the mud weight can give an accurate indication of differential pressure and thus indicate near-balance or underbalanced drilling. With the pumps off, the equivalent circulating density decreases to the static drilling fluid weight. The connection gas, as an indicator of underbalanced situation, reflects as sharp peaks on the mud log. This is contrasted to total gas readings which increase in a smooth fashion due to drilling through a gas formation without corresponding increase in pore pressure. The lag time of the gas peak due to connection gas would be relative to when pumps are off. Hence, human interpretation (provided by the mud logging engineer or mud logger) is required to continuously monitor and analyze acquired parameters for decisive actions to prevent or mitigate a well control incident [12–14].

### **3.4 Limitations of conventional kick detection systems**

While these traditional monitoring systems for kick detection are somewhat reliable, their response time is somewhat slow and thus potentially aggravate the initial problem of the gas influx in some scenarios. An overview of loss of well control (LOWC) events that occurred after the BOP had been landed on the wellhead in the US Gulf of Mexico (Outer Continental Shelf) between 2011 and 2015 showed that kicks were not detected before the well started flowing to the surface or surrounding formations in 50% of the recorded cases. It was inferred that the LOWC events could have been prevented if the kicks had been observed early. Case studies of the Macondo blowout and the Bardolino loss of well control event further emphasize the importance of an efficient and adaptable early kick detection system. The Macondo accident resulted in the loss of 11 lives, the release of 680,000 m3 (4,250,000 bbls) of crude oil in 85 days to the environment, billions of dollars in economic damages and mitigations arising from the event. The Bardolino incident, on the other hand, due to early detection of kick and proper interpretation of the signs of kick, was managed without any spill or loss of life [5, 7, 8, 15].

Gas kick detection is particularly challenging in deep offshore environments for several reasons. First, as the water depth increases, the safe drilling fluid operating window between the fracture and formation pressures narrows. Secondly, relying on lagged parameters becomes increasingly unreliable with increasing depth in ultradeep waters where bottoms-up circulation can take as much as 4 h. In event that the well kicks during this period, the kick volume increases, and the time spent waiting

### *Advances in Well Control: Early Kick Detection and Automated Control Systems DOI: http://dx.doi.org/10.5772/intechopen.106800*

for the kick indicators reduces the drillers' ability to mitigate potential impact. Thirdly, the solubility of gas from the formation in non-aqueous drilling fluids under high pressure could lead to large gas volumes being dissolved in the drilling fluid until the saturation pressure is attained. Gas solubility in these drilling fluids such as oilbased systems could be as high as 100 times greater in solubility than in water-based systems. Consequently, gas remains dissolved (and largely undetected) in the drilling fluid during a kick until much lower pressures are encountered towards the surface as pit gain as compared to the bottom of the marine riser. This gas influx initially translates to undiscernible increase in pit gain until the gas is released at shallow depths which could compromise well integrity and ultimately blowout. This masking of influx gas has been found to worsen with increase in the mud flow rate. Fourthly, currents and wave motion further influence measurements on marine vessels which make early kick detection difficult. Fifthly, in subsea wells for which kicks have been detected and the well shut-in, dissolved gas could hamper subsequent circulations carried out to restore well control by blockage of choke and kill lines due to the formation of hydrates at low temperatures [16–18]. The limitations are being addressed through more sensitive early kick detection systems.
