9.3: The Drilling Process | PNG 301 - Dutton Institute

We have discussed the components of the drilling rig, now let&#;s discuss the drilling process itself. An oil or gas well is drilled in a very ordered sequence. The steps in this sequence are almost universally applied to the drilling of all wells.

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1. Plan the Well: As we have discussed, exploration well prospects are generated by exploration geologists; while development wells locations and objectives are generated by development geologists. Once the surface locations and well objectives are known, the geologists work with the drilling engineers to develop the detail drilling proposals. In addition, all permits (environmental, safety, regulatory, etc.) are acquired during the final stages of the planning process when a solid well proposal is developed.
2. Perform Shallow Gas Survey: To ensure there are no shallow gas hazards which may result in a kick or blow out, a shallow gas survey is performed to identify the locations and depths of any potential shallow gas hazards. Preliminary surface locations and well trajectories may be altered from the original well proposal to avoid these shallow gas hazards.
3. Prepare the Wellsite: The site preparation involves building clearing land for use by the rig, building access roads to the well site or well pad, construct infrastructure for water, water disposal, and electricity, dig and line all mud pits to prevent ground water or water table contamination, dig reserve pits for cutting storage (for eventual disposal), and drill the holes which will eventually become the rat hole and the mousehole. The site preparation may involve multiple contractors and companies to perform all of the required work. As we discussed in earlier lessons, a lot of site-preparation time and the environmental footprint can be minimized if multi-well pads are used in the field development.
4. Set the Conductor Casing: Prior to the arrival of the drilling rig, an Auger Unit (in hard rock regions) will drill a large diameter hole capable of accommodating 18 in. to 36 in. conductor casing (see Figure 9.16). In soft rock regions or at offshore locations, a diesel hammer may be used to hammer the conductor casing into place. The conduct casing may go to depths of 40 to 300 ft depending on the location. The conductor casing is typically set through the top soil and loose rocks to the bed rock. The objective of the conductor casing is to isolate the wellbore from the top soil to ensure that loose debris does not enter the well during early drilling operations. The conductor casing is then cemented into place.
5. Move-In and Rig Up (MIRU): Once the wellsite is prepared and the conductor casing is in-place, the rig is brought on location. Most land rigs, particularly those in North America, are transported on multiple trucks. Once on the well site or well pad, the rigging-up process begins. Rigging up the well consists of taking the rig modules from the trucks and assembling the rig. Included in the rigging up process is setting-up all of the rig systems and testing these systems. Here is a YouTube video, "Rigging up Land Drilling Rig" (3:35), showing the Rigging Up process of the derrick:

   Source: Industrial3D Inc | I3D

   Pioneer Drilling 60 Series Rig-up Animation | Drilling Animation | Land Rig Animation | Oil & Gas. This video contains only background music with no words.

   
   Transporting and assembling the rig may take 50-75 workers (two crews), 35 &#; 40 vehicles, and take up to four days. If a multi-well pad is used, once the rig is rigged-up for the first well, then the rig can simply be skidded over to the next location without having to dig-down.

6. Spud the Well: After the rig has been inspected and all of the systems tested the well can be Spudded. Spudding a Well refers to starting the rotary drilling operations for that well.
7. Drill Down to the Surface Casing Depth: The first section of the well to be drilled is the section that goes down to the pre-determined surface casing depth (Casing Point). Obviously, for this section of the wellbore, the drill bit diameter must be smaller than the ID (inner diameter) of the conductor casing. In this shallow section of the wellbore, fresh water aquifers (both for personal and municipal use) exist. As discussed earlier, shallow gas hazards may also exit. The objectives of drilling this first section of the well is to allow the setting and cementing of the surface casing to:
   1. protect the fresh water aquifers by placing a steel and concrete barrier to isolate the water table from the well;
   2. protect the well from the aquifer (cutting of the drilling fluids with fresh water);
   3. protect the well from shallow gas hazards.
   This section of the well is drilled through the most environmentally sensitive depths. Consequently, when this section of the hole is drilled, it is typically drilled with the most environmentally friendly drilling fluid (possibly either air or fresh water) and cased and cemented as soon as possible to alleviate any potential of contaminating fresh water aquifers. By running the surface casing string, we are putting the environmentally sensitive water table behind pipe and protecting it from future well (drilling and production) activities.
8. Run and Cement the Surface Casing: Once the surface casing point is reached, the surface casing is run into the wellbore and cemented into place. This process is performed by:
   1. Pulling Out of Hole (POOH): Tripping out of the hole with the drill pipe to remove it from the wellbore during cementing operations;
   2. running the surface casing;
   3. pumping a cement slurry down the interior of the casing;
   4. chasing the cement with drilling fluid to displace the cement up into the annular space between the casing string and the wellbore (rock);
   5. allowing time for the cement to Cure (harden).
   Cementing is a common activity planned and implemented by drilling engineers, and you will learn a lot more of the details in your future drilling courses. The following YouTube video, "Running Casing" (7:01), shows the cementing process (note: this is a commercial video for Frank&#;s International):
    

   The BOP is then installed on the surface casing string.

9. Continue this Process to Drill to the Next Casing Point: This drilling process is continued to the next pre-determined casing point. The selection of these intermediate-string casing points is beyond the scope of the class, but the criteria are based on the mud weight, the Fracture Pressure of the formations to be drilled (the pressure that causes the formation to fracture), the locations of any Lost Circulation Zones, and the locations of any High Pressure Zones. As we discussed earlier, any of these situations may result in a kick and a potential blowout. The objectives of the intermediate casing strings are:
   1. isolate unstable hole sections behind pipe;
   2. isolate lost circulation zones behind pipe;
   3. isolate under-pressured zones behind pipe (prevent lost circulation);
   4. isolate over-pressured zones behind pipe (prevent a kick);
   5. isolate multiple producing zones
10. Continue this Process to Drill to each Casing Point: This process is repeated for each of the planned casing points. Obviously, as successive casing strings are run and cemented into place, smaller diameter tools and drill bits must be used for continued drilling operations. As we discussed earlier, the two most important drilling parameters within the Driller&#;s control to maximize the Rate of Penetration (ROP) of the drill bit are the weight-on-bit and the rotational speed of the rotary system in Revolutions per Minute (RPM).
11. Continue this Process to Drill to Total Depth (TD): Once the final intermediate casing string is run and cemented, the drilling process is continued until the well reaches the TD (Total Depth) of the well. At this point, the well is said to be TD&#;ed.
12. Log the Well with Open-Hole Logs: At this point, the sand face is exposed to the well and Open-Hole Logging Tools can be run in the well. Open-hole logs are used to measure certain properties of the subsurface formation that are of interest to the geologists and engineers working on the well and the reservoir.
13. Run and Cement the Production Casing String or Liner: If a production casing string or production liner is to be used in the completion, then they are run and cemented at this time.
14. Compete the Well: Install the well completion as discussed in earlier lessons:
    1. tubing
    2. gravel packs
    3. packers
    4. sliding sleeves
    5. stimulation
       1. acidize the well
       2. hydraulically fracture the well
    6. artificial lift
15. Rig Down and Move Out

Figure 9.16: Typical Hydrocarbon Production Well with Multiple Casing Strings including two Intermediate Casing Strings

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0

Finally, here is a YouTube video, "Drilling Animation" (5:58), showing the entire drilling process. This animation is from Chesapeake Energy, and it discusses the drilling process for a Marcellus Shale well:
 

By analyzing cuttings, drilling mud, and drilling parameters for hydrocarbon-associated phenomena, we can develop a great deal of information and understanding concerning the physical properties of a well from the surface to final depth. A critical function in data analysis is familiarity with the different sensors used for gathering surface data. The primary types of surface data sensors are discussed in this page.

Depth-tracking sensors

Current depth-tracking sensors digitally count the amount of rotational movement as the draw-works drum turns when the drilling line moves up or down. Each count represents a fixed amount of distance traveled, which can be related directly to depth movement (increasing or decreasing depth). Moreover, the amount of movement also can be tied into a time-based counter, which will give either an instantaneous or an average rate of penetration (ROP).

Some companies still use a pressurized depth-tracking/ROP sensor. The pressurized ROP system works on the principle of the change in hydrostatic pressure in a column of water as the height of that column is varied. This change can then be indirectly related to a depth measurement. Again, a time-based counter is used to calculate an instantaneous or average ROP.

Accurate depth measurement on offshore rigs such as semisubmersibles, submersibles, and drill ships is affected by both lateral (tidal movement) and axial (the up-and-down motion of the rig, also called &#;rig heave&#;) effects. To properly compensate for this, most of these rigs have a rig-compensator system installed on their traveling block. As the rig moves up, the compensator opens, thereby allowing the bit to stay on bottom. Similarly, as the rig moves down, the compensator must shut to keep the same relative bit position and weight on the bit.

The same digital sensors are attached to the compensators so that any change in movement can be taken into account, allowing accurate depth measurement (Fig. 1).

• Fig. 1&#;Example of a typical depth-tracking system.

Flow-in tracking sensors

Flow-tracking sensors are used to monitor fluid-flow rate being applied downhole as well as the pump strokes required to achieve this flow rate. Data gathered from these sensors are essential inputs to calculating drilling-fluid hydraulics, well control, and cuttings lag. Monitoring changes in trends may also indicate potential downhole problems such as kicks or loss of circulation.

Two commonly used types are proximity and/or whisker switches. A proximity switch, activated either by an electromagnet (coil) or a permanent magnet, acts as a digital relay switch when it incorporates electrical continuity. A whisker switch is a microswitch that is activated only when an external rod (called a whisker) forces a piston to raise a ball bearing to initiate contact against it (Fig. 2). Both types are digital counters; an increase in counts will correspond to a specific increase in both flow rate and pump rate.

• Fig. 2&#;Example of proximity and whisker switch.

Pressure-tracking sensors

Pressure-tracking sensors are used mainly to monitor surface pressure being applied downhole. Data gathered from these sensors are used either to validate calculated values or to confirm potential downhole problems such as washouts, kicks, or loss of circulation.

Two types of sensors are available, and both monitor pressure from a high-pressure diaphragm unit (knock-on head) located on either the standpipe or the pump manifold. The first sensor type derives its physical input from mud pressure expanding a rubber (or viton when high temperature is involved) diaphragm within the knock-on head. This expansion proportionally increases the pressure in the hydraulic-oil-filled system and, in doing so, relays the mud pressure to the appropriate transducer. The second sensor type makes a direct connection with the standpipe manifold itself (i.e., the transducer face is in contact with the mud; see Fig. 3).

• Fig. 3&#;Example of pressure transducers.

Flow-out tracking sensor

Commonly called a &#;flow paddle,&#; this sensor measures flow rate coming out of the annulus using a strain-gauge analog transducer (Fig. 4). Changes in resistance values are directly related to either an increase or a decrease in mud-flow rate. This sensor provides an early warning of either a kick condition (sudden increase in flow rate) or a loss of circulation (sudden decrease in flow rate).

• Fig. 4&#;Schematic of a flow-paddle sensor.

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Drill-monitor sensors

Drill-monitor sensors monitor surface revolutions-per-minute (RPM) values, rotary torque, and hook load. The torque sensor is a clamp (Fig. 5) that sits around the main power cable to the top-drive system (TDS). It works on the principle of the deformation of Hall-effect chips by the magnetic field produced around the cable owing to the current being drawn through it (i.e., the greater the torque being produced as the pipe rotates, the greater the current drawn by the TDS and therefore the greater the Hall effect). (Note: the Hall effect is a transverse voltage caused by electric current flow in a magnetic field.) Torque changes can then be related to either formation lithology or downhole drilling problems such as pipe stick/slip or motor stalling.

• Fig. 5&#;Example of a torque (left) and an RPM sensor (right).

A digital rotary sensor is similar to a proximity sensor used in a pump. It is shaped differently but acts on the same principle. RPM changes are used to drill the well efficiently and minimize downhole vibration effects.

The combined weight of the bit, bottomhole assembly (BHA), drillpipe, etc., is called the string weight (SW). The block weight (BW) is the weight of the lines and blocks (including top drive or kelly). When the bit is on bottom (i.e., drilling), the hook load is seen to reduce. The amount of weight suspended by the bottom of the hole is the amount of weight on bit (WOB), as shown below:

This hook-load sensor uses the same transducer type as in a pressure-tracking sensor. As the deadline experiences strain, the reservoir has load applied across it, which pressures the hydraulic fluid. This pressure increase is translated to a measurement value (Fig. 6). These measurement values are then correlated to potential downhole problems such as kicks or stuck pipe.

• Fig. 6&#;Example of a hook-load sensor.

Pit-monitor sensor

Most pit-monitor sensors use ultrasonic transit time to measure mud level. The sensor is mounted over the pit above the maximum mud level, and sends a sonic wave that is reflected back to the receiver (Fig. 7). The transit-time measurement is then directly transformed to a volume measurement. This critical measurement is actively used to monitor potential kicks (rapid increase in pit volume) or loss of circulation (rapid decrease in pit volume).

• Fig. 7&#;Example of a sonic pit-volume sensor.

Gas-detection sensors

The gas-detection sensors consist mainly of a gas trap, a pneumatic line linking the gas trap to the gas-detection equipment (which is found inside a mud-logging unit), and the gas-detection instruments (chromatograph and total-gas detectors).

The gas trap is basically a floating chamber with a rotating &#;agitator&#; inside. It works on the principle that mud flowing through the gas trap is agitated, thereby releasing the vast majority of any gases contained within the mud. This gas is then extracted from the trap through the unit sample line to be analyzed in the unit (Fig. 8).

• Fig. 8&#;Example of a gas trap.

The principle behind gas chromatography is simple. The gas from an oil well consists of several hydrocarbon components, ranging from light gases (methane) to oil. A gas chromatograph then takes a sample of gas and separates out some of these components for individual analysis. Typically, methane (C1) through pentane (C5) are the gases of interest. These can be plotted individually, or they may be used in gas-ratio analysis for reservoir characterization.

Most logging companies currently use a flame ionization detector (FID) gas chromatograph and total-gas detector (Fig. 9). The FID responds primarily to hydrocarbons and has the widest linear range of any detector in common use. The output signal is linear for a given component when concentrations vary from less than one part per million (ppm) to percent levels, and with care, resolution can be obtained in the low part-per-billion (ppb) range. The total-gas detector samples gas in a manner similar to that of a chromatograph, the only difference being that there is no column in the detector and, hence, no separation of components (i.e., it burns the &#;total&#; hydrocarbon gas sample as one). This also means that there is no injection time and, therefore, the gas is being sampled continuously (Fig. 8).

• Fig. 9&#;Example of an FID chromatograph and a total-gas detector.

Additional sensors

In addition, exploration and production companies may require specialized services such as formation-pressure monitoring and drilling optimization. To effectively support these services, additional sensors may be required such as fluid temperature, density, and conductivity. In areas of high H2S or CO2 gas, corresponding sensors that exclusively monitor these gases may be required as well.

References

See also

PEH:Drilling-Data_Acquisition

Noteworthy papers in OnePetro

Bill Lesso, Maja Ignova et al. . Testing the Combination of High Frequency Surface and Downhole Drilling Mechanics and Dynamics Data Under a Variety of Drilling Conditions, SPE/IADC Drilling Conference and Exhibition, 1-3 March. -MS. http://dx.doi.org/10./-MS.

Elliott, L.R., Barolak, J.G., Coope, D.F . Recording Downhole Formation Data While Drilling, Journal of Petroleum Technology, Volume 37, Number 7. -PA. http://dx.doi.org/10./-PA

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