Drilling Automation Saves Rig Time and Safeguards Against Human Error
This paper shows how automation reduces invisible lost time and allows drillers to focus on other activities while repetitive tasks are controlled by software.
This paper shows how automation reduces invisible lost time and allows drillers to focus on other activities while repetitive tasks are controlled by software. An automated drilling-control system using advanced modeling of well conditions in the North Sea helped the rig save up to 10% of rig time per well through safeguarding and optimizing manual operations and automating repetitive activities such as tripping, pipe filling, connections, and pump startup.
To explain why the real-time model-based automated system deployed on the rig was capable of saving up to 10% of rig time, the following factors must be considered:
- The effect that time and temperature have on drilling-fluid properties and thereby why conventional operations must be kept at a conservative level compared with automated operations tuned to current downhole conditions
- The reduction of invisible lost time and the realization of faster, smoother drilling operations with fewer unplanned drilling events, obtained through shorter connection times, automated pump startups and shutdowns, automated friction tests, and active (automated) safeguards and safety triggers that assist drillers during manual operations
- The human factors and team efforts to optimize operations further wherever possible
Some of the main functions of the drilling fluid are to cool the drill bit; transport drill cuttings out of the wellbore; and maintain downhole pressures to avoid fluid influx or formation collapse, prevent fluid losses, and avoid formation fracturing.
Weighting material is added to the drilling fluid to adjust its density and thereby control downhole hydrostatic pressure. In order to keep the weighting materials and drill cuttings suspended in the drilling fluid whenever fluid circulation is stopped, drilling fluids also incorporate polymers or gelling materials. The drilling fluid is formulated to turn into a gel state within only a few seconds of fluid circulation stopping, after which the gel structure strengthens with time. When restarting the pumps, the fluid gel structure resists circulation and must be sheared (broken) carefully with a low pump rate to avoid excessive downhole pressure, which could create an unwanted fracture or losses into the formation.
It takes some time after the pumps are started and the drilling fluid is being pumped down through the drillstring before fluid returns begin to appear at surface. When fluid does appear, the initial return flow is high as compressed fluid is released through the (breaking) gel structure. A stable fluid return flow indicates that the initial gel has been broken and the circulation rate can be ramped up in steps to the required drilling flow rate.
Downhole temperature and pressure not only affect the fluid density but also change its viscosity. Extended laboratory testing can be conducted to determine the fluid rheology at different pressures and temperatures, but these tests are not commonly available to the drilling team.
As the gel strengthens with time and rheology changes with pressure and temperature, the optimal pump-startup procedure also changes with time and temperature. In practical drilling operations, however, no one actually measures the current gel time since last circulation and then adjusts the pump-startup procedure for each connection according to the gel time, current bit depth, downhole temperature, and calculated equivalent circulating density vs. current fracturing pressure margin at the worst-case openhole depth. Changing the manual pump-startup procedures on the basis of time, temperature, and bit depth simply would be too difficult and confusing for the driller. Consequently, the practical manual procedures usually are made uniform (and often conservative) in order to prevent accidental formation fracture.
The automated pump-startup procedure described in this paper makes use of real-time calibrated models of the current downhole conditions, including distributed fluid temperature at all depths, the current gel state (time since circulation), the current estimated cuttings loading and location in the annulus, the fluid rheology vs. downhole pressure and temperature, and more. This allows the system to calculate the optimized pump startup accurately on a second-by-second basis, keeping the resulting downhole pressure close to, but not exceeding, the geopressure boundaries with a higher confidence factor than is possible with purely manual operations.
Experience from wellsite operations shows that the function was used more or less at every connection during drilling. On average, a savings of 70 seconds per startup was observed for the 17½-, 12¼-, and 8½-in. sections. This corresponds to saving nearly 3 hours for a 4000-m-long well for pump startup alone.
The main value of the friction test is to ensure that the up and down weights are measured correctly when sliding the drillstring and that the free rotating torque and free rotating weight are measured when rotating the string off-bottom. An abnormal increasing trend in friction needs to be detected and addressed to avoid future problems.
When the driller performs a sliding friction test, the procedure is to measure the hookload while lifting and lowering the drillstring slowly at a low flow rate. When this is performed manually, variations may occur in velocity, acceleration, and lift height. It is very difficult, if not impossible, to perform two identical sliding friction tests manually, even by the same driller.
With automated friction tests, any variations in velocity, acceleration, and lift height are greatly minimized. The driller predefines how the friction test shall be performed, and the automatic sliding friction test calculates and adds the length required to start sliding the bit (elongation of the string). With automated friction tests, the block is moved a constant distance after the string has been elongated. Because of the elongation of the string, the hoisting distance is expected to increase with increasing bit depth. The automatic function will take an equal measurement each time while keeping the resulting downhole pressure within the geopressure boundaries. The results from the test, the up and down weights, the free rotation weight and torque, and the corresponding friction values are presented to the driller automatically.
Operational experience showed that the drilling team opted to measure free rotating weight and free rotating torque after each connection rather than before connection before the friction test. The automatic sliding friction test function was used, however, at almost every connection once the system had been activated. Furthermore, feedback from the drillers was very positive, highlighting the work-flow benefits of this function.
During manual filling of casing, the driller must calculate and keep track of the volume to fill and count the number of pump strokes. As a result, the driller has to be very cautious not to overfill the casing and cause mud to spill on the rig floor. Automatic casing filling calculates the required fill volume on the basis of a detailed casing tally and keeps control of the volume level inside the casing and the pump rate. The automatic function, therefore, can fill the casing at a much higher rate. The benefits of this are twofold: In addition to improving consistency, the time spent on filling the casing is reduced significantly. In this case, the filling time was reduced from 100 to 40 seconds per casing joint, offering a savings of 60 seconds per joint. For a well of 4000 m, this corresponds to a savings of approximately 16 hours.
Safeguarding the Well
It is possible to enable automatic sequences in open hole provided that the sequences are safeguarded by technology that accounts for the downhole conditions. The technology presented in this paper also provides safe working envelopes during manual operations, assisting the driller in avoiding or limiting the effects of drilling incidents otherwise caused by excessive string accelerations, overpulls, set-down weight, pump accelerations, pump pressure, or excessive flow rates.
The system assists the manual drilling operation by
- Limiting the drillstring axial velocity to prevent swab and surge
- Limiting the flow rate to prevent formation fracturing
- Limiting pump acceleration and deceleration to prevent over- and underpressure transients
- Reacting automatically to overpulls/set-down weights, preventing excessive pull/push force into a tight spot or cuttings bed to avoid stuck pipe
- Reacting automatically to overtorques to avoid pipe damage
- Reacting to abnormal pump-pressure increases, to avoid formation fracture in a packoff situation
- Automating the mud-pump startup
- Automating friction tests
- Automating reciprocation
It is difficult sometimes to prove that drilling incidents or drilling problems considered normal would have occurred without the assistance of the system. But the kinds of incidents that automated assistance can mitigate are more likely to occur in the deeper, deviated, and more-complex well sections than in simpler vertical well sections. Thus, the time savings realized on a horizontal 8½-in. section drilled with automation assistance proved to be a strong indicator. When compared with five previous 8½‑in. sections drilled in the same field without automation assistance, a significant amount of invisible lost time was avoided by use of automation assistance. When normalizing the drilling times for the previous nonassisted wells to the same distance drilled with automation assistance, their average drilling time was 67.1 hours. With automation assistance, the same distance was drilled in only 40.8 hours.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177825, “Breakthrough in Drilling Automation Saves Rig Time and Safeguards Against Human Error,” by Egill Abrahamsen, SPE, and Ronny Bergerud, Sekal, and Roald Kluge and Matthew King, Statoil, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.