TOLOMATIC SERVOCHOKE® TEST REPORT

Louisiana State University PERTT Lab

2017

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Contents Introduction 1

Procedures 1

Test Loop Description 1

Choke Description 2

Choke Step Response Test 2

Pump Rate Step Response Test 2

Two Phase Pressure Control Test 3

Results and Discussion 4

Choke Step Response Test 4

Pump Rate Step Response Test 8

Two Phase Pressure Control Test 9

Conclusion 11

Appendix 1 – Well 1 (Goldking) Schematic 12

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List of Figures

Figure 1 - Cortec CXE-II Flow Efficiency Curve 2

Figure 2 - Choke Step Response Through Surface Pipe (Pressure & Rate) 4

Figure 3 - Choke Step Response Through Surface Pipe (Pressure & Position) 5

Figure 4 - Choke Step #4 from Figure 3 (Pressure & Position) 5

Figure 5 - Choke Step Response Through Surface Pipe (Position & Current) 6

Figure 6 - Choke Step Response Through Well (Rate & Pressure) 7

Figure 7 - Choke Step Response Through Well (Position & Pressure) 7

Figure 8 - Pump Rate Step Response Test (Pressure & Flow) 8

Figure 9 - Pump Rate Step Response Test (Pressure & Position) 9

Figure 10 - Two Phase Pressure Control Test (Pressure & Rate) 10

Figure 11 - Two Phase Pressure Control Test (Pressure & Position) 10

Figure 12 - Two Phase Pressure Control Test (Pressure & Volume) 11

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Introduction

Tolomatic’s ServoChoke® actuator was tested at Louisiana State University’s Petroleum Engineering

Research and Technology Transfer (PERTT) Lab. The test was performed with the actuator mounted to a

Cortec CXE-II choke. This test was performed to evaluate the actuators performance for pressure control

during drilling operations, as used in managed pressure drilling. The objectives of these tests were to:

evaluate the actuators performance to while making choke position adjustments of various sizes,

determine the actuators ability to hold steady back pressure under changing pump rates, and evaluate the

actuators ability to maintain pressure during two phase flow.

Procedures

Test Loop Description

PERTT Lab’s field scale test loop was used for this test. Surface pipe for this test was 2-inch XXH and 2-

inch 1502 iron. Tests were performed either through surface pipe only or through Well-1. Designations

are made on a test-by-test basis in the following procedures. A detailed wellbore schematic for Well-1 can

be found in Appendix 1. Casing pressure during the test was limited to 2200-psi. Flow rate was limited

during the test to 300-gpm by the size of the surface pipe and tubing in Well-1. This test was performed

with water as the liquid and nitrogen for the gas during the two phase test.

Casing pressure was measured using an IFM PX9110 pressure transducer from a pressure tap

approximately 2-feet upstream of the test choke. Standpipe pressure was measured using a Pason 1502

5000-psi pressure transducer approximately 40-feet upstream of Well 1. Pump Flow rate was taken from a

Foxboro mag meter between the charge pump and triplex pump. The choke position and electrical current

were recorded from the servo amplifier. Choke position is representative of the actual actuator position as

a percent within the physical travel of the choke and current is a raw value stated in amps.

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Choke Description

The choke used in this test was a Cortec CXE-II. It was a 4-1/16-inch 5M body with 3-inch trim. The

flow efficiency curve for this choke is shown below in

Figure 1 - Cortec CXE-II Flow Efficiency Curve

Choke Step Response Test

A choke step response test was performed to evaluate the actuator’s performance while stepping through

different choke position set points, producing different casing pressures. During this test, the actuator was

electrically commanded to its set point via manual position inputs through a touch screen interface. Choke

positions were arbitrarily chosen for the actuator to adjust the choke to hit. After a new choke position

was selected and casing pressure was allowed to stabilize, a neutral point was returned to prior to

beginning the next step. This test was performed through surface pipe and Well-1 to see the performance

on systems with different compressibilities. For both these tests, the actuator’s velocity and acceleration

rates were set to their maximum values.

Pump Rate Step Response Test

A pump rate step response test was performed to test the actuators ability to hold casing pressure constant

while pump rate was changed. This test was performed in a manner which models a pump start-up and

shut-down, like that in most well control procedures. During this test, the actuator was in pressure control

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mode with a proportional control loop (PLC) taking feedback from a casing pressure transducer.

Tolomatic’s method of pressure control was a rudimentary PLC that commanded the actuator to move

once a predefined window of pressure change had occurred. No drilling or pressure control software was

utilized during these pressure and flow tests. The PLC program would command the actuator to make a

pressure control adjustment once the pressure exceeded a preset window (+/- 4 PSI). This test was

performed through the well. The test started with the pump in neutral and 1,000-psi trapped casing

pressure. The pump was placed into gear and brought up to a selected rate. During the second start-

up/shut-down procedure the rate was increased and decreased at different rates to continually test the

actuators ability to hold constant casing pressure. The pump’s idle flow rate is approximately 25-gpm.

The program controlling the actuator in pressure control mode had a safety protocol which slowed the

actuation rate and reduce force of the actuator to the seat when approaching full close to prevent damage.

This safety feature also made actuations from 2% to 0% open even slower to avoid damaging the choke

valve This did not allow the choke to hold pressure when the pump instantaneously changed 25-gpm

going in and out of neutral. It also did not allow the actuator to come off of the seat automatically.

During pump start-up the test the actuator was switched into manual control mode and manually moved

until the window was wide enough to switch to automatic mode and avoid re-seating the choke. During

pump shut-down the actuator was switched to manual control mode and set to close as the pump was

switched into neutral. Going from neutral to idle with the pump, and vise versa, were the only portions of

this test which the actuator was in manual control mode.

Two Phase Pressure Control Test

The two phase test was performed to evaluate the actuators ability to control pressure during liquid and

gas flow through the choke. During this test the actuator was in pressure control mode with a PLC taking

feedback from a casing pressure transducer. This test was performed through the well. This test was

performed with a pump rate of 135-gpm and the choke programed to maintain 800-psi casing pressure.

During the circulation, a nitrogen gas kick was injected down the intermediate annulus of Well-1. The

volume of the kick during circulation was monitored through the liquid volume in the surface tanks. The

software running the choke for this test was only able to use casing pressure as an input, so a driller’s

method procedure was not followed while circulating the kick out. Instead the casing pressure was held

constant while the standpipe pressure was allowed to decrease.

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Results and Discussion

Choke Step Response Test

The first portion of this test was performed through surface pipe. A base pump rate of 150-gpm was used.

Due to the low system volume and speed of the pressure build, the pump throttle was left constant and the

flow rate was allowed to be restricted. The choke position steps ranged from 3.49-9.45% for the surface

pipe portion of this test. Figures 2, 3, 4, & 5 show graphs of casing pressure, flow rate, choke position and

electrical current drawn by the actuator.

Figure 2 - Choke Step Response Through Surface Pipe (Pressure & Rate)

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Figure 3 - Choke Step Response Through Surface Pipe (Pressure & Position)

Figure 4 - Choke Step #4 from Figure 3 (Pressure & Position)

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Figure 5 - Choke Step Response Through Surface Pipe (Position & Current)

The results of this test show the repeatability and speed of the actuator. A neutral choke position, which

generated 600-psi casing pressure at 150-gpm, was used during the surface pipe portion of this test.

Between each step the choke was returned to the neutral point. Each time the choke position returned to

the original choke position, causing the original stabilized casing pressure. Even in a surface piping

system with a very small volume and compressibility, the actuator was able to stay well ahead of the

pressure stabilization. Figure 4 shows an expanded time scale for the fourth choke step in Figure 3. The

actuator is able to make a 9.45% choke step in 1.05-seconds. The resulting pressure spike takes

approximately seven times that to stabilize. Table 1 below shows the actuator step sizes and time for

stabilization of choke position and casing pressure for the four steps seen in Figure 3. This test was

performed at full actuator speed to show that this actuator can run at any speed, up to the rated maximum

of 19.6-mm/sec, with the same performance. This demonstrates the actuator’s ability to be controlled at

very high speeds, well above any system requirements, with repeatability and precision.

Table 1 – Surface Pipe Step Test Stabilization Rates

Step Number 1 2 3 4

Step Size (% Open) 3.47 5.47 8.45 9.45

Choke Position Stabilization (Seconds) 0.65 0.77 0.91 1.05

Casing Pressure Stabilization (Seconds) 7.17 8.48 7.63 7.27

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The portion of this test ran through Well-1 was performed at flow rates of 150-gpm and 200-gpm.

Multiple choke position steps were made ranging from 1.01 to 9.95%. The choke position was held until

casing pressure began to stabilize. Figures 5 & 6 show flow rate and choke position in comparison to

casing pressure.

Figure 6 - Choke Step Response Through Well (Rate & Pressure)

Figure 7 - Choke Step Response Through Well (Position & Pressure)

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The data collected through the well shows the same actuation speed with prolonged pressure builds due to

increased system compressibility. Since the actuator is far faster than the system’s pressure reaction, the

software running the actuator could intentionally over shoot a position, decreasing the pressure build time,

and still have enough time to return to the appropriate choke position for steady state flow. Or, the

actuator can run at slower speeds to generate a smoother pressure response. Fast choke position

adjustments of this nature may also serve operational purposes other than pressure control. Quick moves

may allow for rapid bleed-off of pressure to augment a PRV or provide a dual purpose as a throttling

pressure relief valve. Quick adjustments may also prevent dead heading when switching flow from the

bell nipple to the choke line with a fast actuating annular preventer.

Pump Rate Step Response Test

The pump rate step response test ran through two complete pump start-up and shut-down procedures. The

second procedure included three different circulating rates. Figures 8 and 9 shows the casing pressure,

flow rate, and choke position throughout the test.

Figure 8 - Pump Rate Step Response Test (Pressure & Flow)

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Figure 9 - Pump Rate Step Response Test (Pressure & Position)

During the test the actuator was able to keep the pressure within a 179-psi window. Most of the deviation

from the control pressure is seen when the pump was switched from neutral to first gear. This

instantaneous jump in rate was not able to be compensated for in the simple software used to control the

choke during these tests. The pressure data set, as a whole, has an average of 997-psi with a standard

deviation of 20-psi. The second start up shut down procedure shows tighter pressure control during the

two pump rate changes of 30 and 75-gpm that occur between the start-up and shut-down. This portion of

the data set (550 to 1,070 seconds) has an average of 998-psi and a standard deviation of 8-psi. With more

adaptive software this actuator would have the ability to account for instantaneous changes in pump rate,

as seen when putting a pump in and out of gear. This would improve the performance of pressure control

during pump large rate changes in short time spans.

Two Phase Pressure Control Test

The two phase test showed the actuators ability to hold steady back pressure while gas is present in the

circulation fluid. Figures 10, 11, & 12 show the standpipe pressure, casing pressure, flow rate, choke

position, and surface fluid level.

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Figure 10 - Two Phase Pressure Control Test (Pressure & Rate)

Figure 11 - Two Phase Pressure Control Test (Pressure & Position)

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Figure 12 - Two Phase Pressure Control Test (Pressure & Volume)

The increase in surface fluid volume during the first portion of the test shows the volume of gas being

circulated expanding as it comes to surface. This is a result of the decreasing standpipe pressure. The

inflection of the liquid volume curve shows the point that gas reaches surface. After 720-seconds there is

two phase flow going through the choke. Figure 11 shows a much faster rate of choke position change

after this point, as it is accounting for the lower density fluid in the choke. While this choke adjustment

speed is quicker than the initial portion of this test, the actuator is able to keep up with a minimal increase

in the error band around the target pressure.

Conclusion

The Tolomatic ServoChoke® SVC07 actuator is a very quick, very precise electric choke operator. The

servo aspect of the design ensures that speed and position control will be properly executed regardless of

the flow conditions through the choke as demonstrated by the two different step response tests. When

paired with drilling or pressure control software, it would not appear that the ServoChoke® actuator would

have any difficulty executing the commanded pressure control positions at any programmed speed, up to

the rated maximum of 19.6-mm/sec, in a precise manner.

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Appendix 1 – Well 1 (Goldking) Schematic

WELL #1 (GOLDKING)

056 07S 01W SERIAL: 159200