**4.1 Surface sensors for early kick detection**

Ultrasonic level sensors are preferred for measuring mud pit gain because they provide for greater sensitivity and accuracy as compared to other float meters (magnetostrictive, optical and differential pressure). They require low maintenance, and some models have a response time as low as 1 s thus very suitable for real time monitoring of the mud tank level [6, 21].

As regards flow measurement, there are two approaches: volumetric flow or mass flow measurement. The former is achieved using positive displacement flow measurements (such as pump stroke counters) or by employing flowmeters which provide estimates of velocity such as electromagnetic, turbine, ultrasonic, and vortex flowmeters [6]. Electromagnetic flowmeters installed both in the pump output and return flowlines have been used in implementing the delta flow approach for kick detection

especially where there is the restriction of space [11, 13]. Electromagnetic flowmeters have the advantages of simple structure with no moving parts and no obstruction of fluid flow by throttle parts or its flow path. Therefore, there is no resultant additional pressure loss, wear, blockage, or corrosion of the inner lining due to solids-laden flow [22]. However, their applicability is limited to water-based drilling fluid [23]. It has been reported that the accuracy of electromagnetic flowmeters for early kick detection can be improved by installation in a V-shaped flowline segment on the outlet flow path as challenges with transient large flow passage and solids deposition were resolved [24].

The use of ultrasound flowmeters is an alternative to electromagnetic measurement applicable in both water-based and oil-based drilling fluid. This type of flowmeters works on the principle that part of the reflected ultrasonic waves that get transmitted into the pipe wall from drilling muds gets transferred into Lamb waves and subsequent a relationship between the reflected signal frequency and the flow rate is obtained. The method is nonintrusive but suffers from great attenuation of ultrasound waves in mud. This problem is resolved by continuous detection of non-oriented reflected ultrasound Doppler frequency shift, which relates the drilling fluid flow rate to the collected repeated Lamb waves. A related flow rate algorithm is obtained through the even distribution characteristics of the reflection angles [25]. The installation of three ultrasonic sensors in an open channel with Venturi constriction provided high accuracy flow rate measurement comparable to electromagnetic flowmeter measurements which are not susceptible to cuttings settlement at low flow velocity [23].

However, the most proven meter for EKD is the Coriolis flowmeter: this is based on the mass flow measurement principle. It can provide mass flow rate, density, and temperature measurements of liquids and gases within a single meter in the presence of either water-based or oil-based drilling fluid. Coriolis flowmeters provide mass flow rate measurements independent of the physical properties of the fluid and are unaffected by changes fluid properties due to fluctuations in density, viscosity, temperature, or composition. Flow measurements can be transmitted in real time so that software models are updated and EKD is achieved. In the Coriolis flowmeter a rotation force is created as the flow loop rotates about a secondary axis in response to the circulation of drilling fluid through a circular path about a primary axis. This force is directly proportional to the angular momentum of the fluid flow around the circular path (which gives a direct indication of mass flow rate) while frequency at which flow tube vibrates provides a direct measure of the fluid density. However, the flow and density measurement accuracy of the Coriolis sensor becomes degraded by entrained gas fractions exceeding 5% [5, 26]. The pressure rating limited to about 3000 psi (207 bar) precludes it use to the standpipe and the pump suction line [6, 20]. The use of the density compensated Coriolis meter is limited in precise kick detection when the mud pumps are off with no flow as is the case when making connections or tripping. Active mud circulation through the Coriolis flow meter is required for a measurement to be taken [20]. Optimal performance of the Coriolis mass flowmeter is obtained with high profile, dual-tube sensors with low tube frequency [26]. A Coriolis meter installed on a conventional rig is shown in **Figure 2**.

#### **4.2 Smart flowback fingerprinting**

Kick detection based on surface measurements especially the delta flow approach that compares the flow rate into the well and the flow rate of the returns from the well as an indicator of either an influx or loss scenario could be complicated as issues such

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

**Figure 2.**

*Coriolis installation on the bell nipple of a conventional drilling rig. N.B.: The arrows indicate the bypass and flow direction through the Coriolis from bottom to top [26].*

as wellbore breathing or ballooning and changing thermal conditions could mask the occurrence of a kick. Borehole ballooning or breathing occurs when slow mud losses occur during drilling ahead and a subsequent flowing of the well when the pumps are off during a connection operation or flow check. Therefore, changes in mud pit volume during a drill pipe connection are keenly monitored. This is critical because kicks frequently occur during drill pipe connections [6, 27]. To address the masking of kicks, Smart Flowback Fingerprinting was developed, a method of kick detection using an automated process to monitor wellbore flowback. It uses statistical analysis to interpret flowback data obtained during static conditions in which the rates-ofchange for multiple successive drilling fluid flowback cycles to the mud pits are compared and analyzed [28]. It is expected that under static conditions, drilling fluid flowback cycles will have a repeatable profile when measured over successive cycles. Thus, any departure from the expected flowback profile could indicate a formation fluid influx. The technology enables real time detection of flowbacks exceeding normal volumes, without human intervention, with minimal false alarms depicted clearly as threshold and alarm curves. The system can accurately identify influx of formation fluids as distinguished from wellbore breathing and flowback which occurs when the well is static [28, 29].

#### **4.3 Downhole sensors for early kick detection**

The closer the location of real-time kick indicator sensors to the formation, the earlier the kick would be detected. Real-time downhole sensing alternatives for kick detection have been developed. Measurement while drilling (MWD) combined with Logging while drilling (LWD) provides a viable alternative to surface measurements for kick detection. MWD tools are added to the drilling bottomhole assembly (BHA) to take electro-mechanical measurements while drilling, simultaneously. They are very effective in guiding the drill bit to the target pay zone, the acquisition of wellbore deviation directional surveys and the measurement of drilling mechanics data such as downhole torque, pressure, and vibration, with real time transmission of acquired data to the surface. A major MWD application that aids in kick detection is the accurate downhole BHP measurement via the Pressure While Drilling (PWD) tool using high-accuracy quartz pressure gauges. The PWD tool enables continuous annular and wellbore downhole pressure monitoring so that BHP is kept within the safe drilling window [6, 13].

LWD tools provide petrophysical data such as porosity, resistivity, density, and gamma ray. As regards kick detection, three key measurements affected by borehole fluids are density, electrical resistivity, and acoustic velocity. Bulk density as measured by the gamma density tool will decline as the drilling fluid is diluted by a gas kick. An influx of petroleum fluids will result in a clear increase in electrical resistivity in either water-based or oil-based fluids while the compressional wave velocity in drilling fluids will increase with an influx of gas. MWD/LWD tools are in-built with electronic sensors and batteries packaged in the housing in such a way that they do not impede the high flow rates that occur during drilling. However, a major drawback with using MWD/LWD tools is the requirement of a minimum fluid flow rate for signal transmission to the surface in real time. This implies that there would be no data transmission at low flow rates (a minimum of 130 gallons/min is required for some tools), during connections and when other periods when the pumps are turned off. There are other challenges with mud pulse telemetry which include the reduction in the data transmission rate with increased depth and signal attenuation in compressible drilling fluids such as OBM. While MWD/LWD sensors can measure large amounts of formation evaluation and kick detection related data, mud pulse telemetry only allows data transmission at low rates which results in a time lag between the time the mud pulse reaches the surface and when it is generated downhole. In addition, MWD/LWD tools are limited to measuring data at the bottomhole assembly (BHA) which is placed a few meters above the drill bit. These challenges limit MWD/ LWD applicability for real time data transmission in ultradeep wells [6, 13].

The limitations posed by mud pulse telemetry in transmitting downhole measurements to the surface in real-time can be resolved with the Wired Drill Pipe (WDP) system. The WDP system has an embedded high strength coaxial cable and low-loss inductive coils incorporated into each joint of drill pipe during manufacture. This wired communication channel through drill pipe transfers signals at rates of about 57,000 bits/s, this is several orders of magnitude faster than is attainable via mud pulse telemetry or electromagnetic telemetry. It transmits alternating electrical signals between the BHA and the surface systems. In addition to measuring data near the drill bit and high bandwidth, WDP allows for data measurement along the entire length of the drill pipe string [5]. The use of fiber optic sensing as real-time downhole sensing option for kick detection has been proposed. Fiber optic measurements, Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) are already in the use for injection and production flow profiling, determination of crossflow across different zones and detection of flow behind casing in completed wells. The applicability of fiber optic sensing during drilling operations has only been tested for gas monitoring in the marine riser. The fiber optic cable is installed in a similar manner to a flexible production riser installation. Data transmission is achieved by

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

launching an intense laser pulse into the sensing fiber which gets scattered spontaneously as it interacts with the crystalline structure in the silica-based core of a fiber optic cable which is affected by thermal and pressure variations. A fraction of the back scattered light is captured and transmitted through the fiber guided modes and propagated towards a fast photodetector. The changes in the back-scattered light can be related to the acoustic and thermal variations along the fiber with its spectrum consisting of a Rayleigh band, Brillouin band, and Raman band which are used in DTS, DAS and Distributed Strain Sensing. Once the propagation time of a pulse at a particular wavelength is known along a fiber of specific refractive index, the position of the interaction can be located and the perturbation in the measure quantity on the fiber determined [16].
