during the hours of darkness if the conditions laid out in section 1060, paragraph 5, have been satisfied.
In multiple DSTs on the same well the second zone perforated may be brought on during hours of darkness following consultation with the DS and SPE.
d All nonessential personnel must keep clear of the rig floor and well test area for the duration of the flow period.
e No crane movements over any of the well test equipment or flow lines.
1.3 Select the burner to ensure that the flare is blown away from the rig.
1.4 Sometimes during clean-up slugging or wind conditions make it difficult to keep the flare lit and to burn all the produced gas. Uncombusted gas is a serious hazard to helicopters.
In such a circumstance the rule is:
If you can't burn the gas, you can't land the helicopter, unless the well is closed in.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 4040
SUBJECT INITIAL FLOW AND CLEANUP
REVISION 1
DATE 01/11/94
1.6 Pressure surges can occur with a change in fluid passing through the choke. To safely control gas surge the following must be adopted:
- If WHFP exceeds 2000 psi bean back to a fixed choke size that will restrict the gas flowrate to less than 6 mmscf/d.
- After first gas the choke size may be increased as required.
2. PREPARATION
2.1 Prior to opening up the well the following must be
- The separator is by-passed and the well is lined up to the burners. (oil wells may be flowed to the gauge/surge until the first half of the cushion has been produced)
- The pilot to the relevant burner is lit, the water screen is in operation, and a well test operator is stationed near the burner.
- The steam generator is fully fired up.
- That the adjustable choke has been correctly zeroed.
- That a suitably sized fixed choke (usually 20/64th) is installed on the fixed side of the choke.
- The work permit has been re-endorsed for the testing phase of operations.
- That the Radio Operator has notified the Coastguard that the rig is about to
commence flaring and notified the standby boat and any helicopters of the intention to open up the well
- All personnel involved in the test operation are at their respective stations.
2.2 Make a tannoy announcement to inform rig personnel that the well is about to be opened up.
3.1 Make a final check on the wind direction, that the helideck is clear and that there are no boats adjacent to the rig.
3.2 Pressure up the annulus to open the tester valve and allow the wellhead pressure to stabilise.
3.3 Check the position of the tester valve and cycle to a fail safe position, ie not locked open.
3.4 With the adjustable choke set on 16/64" choke, open the front valve on the choke manifold.
Monitor the downstream choke pressure. This should be kept below 1000 psi. If the pressure rises quickly towards this figure then the well should be shut in and the problem investigated.
3.5 Bean up well in 4/64" stages as instructed by the Petroleum Engineer.
3.6 Take two samples of the cushion at the choke manifold.
3.7 Monitor annulus pressure and bleed off as required (annulus pressure will rise as the well heats up)
3.8 Monitor wellhead pressure. If WHP increases above 2000 psi switch to a fixed choke size that would restrict the gas flowrate through the choke to less than 6 mmscf/d.
3.9 When hydrocarbons reach the surface, monitor for H2S and CO2 at the choke manifold at 10 minute intervals until levels have stabilised, and at half hour intervals thereafter.
3.10 The well will be considered clean BS&W has been constant over 2 hours.
The solids content is < 1%.
The wellhead pressure is constant or declining as a log function of time.
3.11 When the well is cleaned up. Divert the well through a fixed choke.
4.1 Do not conduct the initial flow period with the tester valve in a locked open position.
Always cycle the valve to a fail safe position.
4.2 Never use adjustable chokes that have the choke tip braised to the shaft. All choke tips must be integral or screwed and pinned to the shaft. A choke tip that comes off will slam into the choke seat resulting in a sudden increase in well head pressure.
4.3 On low rate wells it can be advantageous to switch to a fixed choke if the adjustable choke is plugging with debris. If a fixed choke is used for the clean up flow it could become damaged or partly plugged and must therefore be inspected or changed out for the main flow period.
4.4 For gas wells the flow must initially be directed to the burners. Only if the well does not appear to be flowing may the well be diverted to the surge tank for a short period of time to confirm if the well is dead.
4.5 For oil wells no more than half the cushion is to be flowed to the surge tank, the flow is then be diverted to the burners.
4.6 If the well is producing solids at least one string volume should be produced between choke changes.
4.7 During clean-up the cushion should not be back produced at more than 10,000 bbl/d.
4.8 During clean-up it is not necessary to maintain critical flow across a choke if so doing would compromise the complete removal of mud/brine from the casing. When the well is clean critical flow can be re-established by beaning down the choke as required.
4.9 The Data Acquisition Manual details the parameters that should be recorded and the recording frequency.
4.10 Clean up is most easily detected from looking back at the process trends (WHP, WHT, BS&W) and is easier to spot in hind sight than as it happens.
Clean up is a function of both time and volume produced. On an average well a constant BS&W for two hours will represent 1 - 2 string volumes. On a low rate well two hours may represent less than half a string volume and it may be necessary to extend the clean
Bringing a well on and choosing how to bean up the choke relies very much on experience. The following discussion and flow chart (figure 1) can be useful in many
- Sufficient flowrate to lift the cushion fluid in the tubing. (This is a function of the slip velocity of oil in water or gas in diesel or water. For an oil well with 4-1/2"
tubing the surface flowrate should be > 600 bbl/d. For a gas well with 4-1/2" tubing the surface flowrate should be > 1800 bbl/d flowrates for other tubing sizes can be calculated using Equation 2)
- Be able to safely handle the gas surge pressure.
- Maintain BHP above bubble point (If this is a well objective) Predicting Bottom Hole and Surface Pressures
On first opening up a well the pressure will fall firstly because of the drawdown applied to the formation to make it flow, and secondly because mud/brine is being displaced from the casing into the minor string and increasing the hydrostatic head. As oil/gas enters the minor sting the hydrostatic head will decrease and WHP will rise. Later as gas nears surface the rate of gas expansion becomes significant and the rate of increase in WHP
minimum the WHFP might fall to, or how much further the pressure may rise as the cushion is produced.
Clean-up of Cushion and Drilling fluids
At low flow rates the flow regime will be that of bubbles of the lighter phase rising through the continuous heavier phase. As the flowrate increases the light phase becomes continuous and the droplets of the heavy phase (water/brine/mud) fall back through the oil/gas.
With bubble flow the bulk of the cushion will remain in place and the hydrostatic head will still be high.
To remove the bulk of the cushion from the tubing/casing the well must be flowed at a rate sufficient to make oil/gas the continuous phase. To achieve the transition from
SG = The specific gravity of the fluid in the droplet (water = 1) P = The well bore pressure at the point under consideration, psia
The flow rate required for removal of mud/cushion from the tubing/casing in a gas well is highly sensitive to gas pressure. Ideally all the mud between the gauges and top
perforation should be removed during clean-up. A plot of the flowrate required for mud removal versus estimated BHFP will help determine if this has been achieved.
In general, unless the bottom set of perforations are the main point of influx then it is unlikely that all the mud will be removed from opposite all the perforations.
Gas Surge Pressure
The effect of first gas at surface largely depends on if the WHP is high or low.
At low WHP first gas will cause a rapid increase in WHP as the gas restricts the flow area available to the liquid phase.
At high WHP first gas will cause a sudden increase in choke downstream pressure as the volume of gas that can pass through a choke at high pressure far exceeds the volume of diesel or water that previously passed through the choke.
flowing diesel to flowing oil and gas through the choke when the well has a low WHFP.
Assume the well is back producing a diesel cushion on a 28/64th choke with a WHFP of 100 psi. This would give a surface flowrate of 1600 bbl/d (Eqn 8).
If the flow of diesel through the choke were replaced by oil with a GOR of 1000 scf/stb and Bo of 1.6, then the flowrate through the choke would be reduced to 125 bbl/d (Eqn 9). The marked reduction in flowrate that results from the transition from diesel to oil and gas causes a rapid increase in WHFP. In this example, were the well to continue flowing at 1600 Rb/d the WHFP would to increase from 100 to 800 psi (Eqn 9).
The following example gives an indication of the effect on downstream choke pressure of the transition from flowing diesel to flowing gas through the choke when the well has a high WHFP.
Assume a well is back producing a diesel cushion on a 24/64th choke with a WHP of 3000 psi and a downstream choke pressure of 400 psi.
The surface flowrate would be approx 6000 bbl/d.
If the diesel cleaned up to dry gas, then the flow of gas through the choke would be approx 9.3 mmscf/d.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 4040
SUBJECT INITIAL FLOW AND CLEANUP
REVISION 1
DATE 01/11/94
At down stream conditions (400 psi) 9.3 mmscf/d of gas occupies a volume equivalent to 45,000 bbl/d. The pressure down stream of the choke would rise within 1-2 seconds to over 2000 psi as the diesel accelerated and the gas downstream of the choke was re-compressed. Rupture of the low pressure lines (1440 psi Working pressure) and serious injury are likely results of an uncontrolled gas surge.
Gas surge is reduced if the choke setting is kept small as this reduces the flowrate to which the diesel is accelerated.
To safely control gas surge the following must be adopted:
- If WHFP exceeds 2000 psi bean back to a fixed choke size that will restrict the gas flowrate to less than 6 mmscf/d.
- After first gas the choke size may be increased as required.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 4050
SUBJECT MAIN FLOW PERIOD
REVISION 0
DATE 01/10/92