The Railroad Commission of Texas will be closed Wednesday, Nov. 22 through Friday, Nov. 24 in observance of Thanksgiving. The RRC will reopen for regular business Monday morning, Nov. 27. We wish everyone a safe and happy holiday.
Form H-10 Instructions
1. Items 1 through 11--Identification
These items are computer generated from the current Commission database. Note changes by crossing through incorrect information and writing the correct information above it.
Lists the months and year for which monitoring data must be provided.
3. Item 13--Operating injection pressures
Both average and maximum pressures must be provided.
Technical staff will review the operation if any reported pressure exceeds the authorized pressure.
Significant noncompliance will result in a violation notice.
Commission procedure limits the maximum injection pressure to 1/2 psig per foot of depth to the top of the injection zone. Higher pressures may be authorized if the results of a step-rate test indicate that fracturing will not occur.
4. Item 14--Injected volumes
Injection volume must be the total volume injected for that month.
Injection volume must be reported in barrels of liquid or thousand cubic feet (MCF) of gas.
5. Item 15--Annulus pressure monitoring
Monitoring of the tubing-casing annulus pressure is required by many permits. If not required, it is an option that may be accepted in lieu of a pressure test if it demonstrates ongoing mechanical integrity.
Annulus pressure monitoring will only be accepted in lieu of a test that is required once every five years and for wells that are operating in compliance with their injection permit. Note that annulus pressure monitoring is limited to a maximum of 10 years between pressure tests.
Annulus pressure monitoring is not an alternative to:
initial test on newly permitted or amended well;
annual test required by permit; and
test after workover.
Conditions for acceptance as demonstration of mechanical integrity.
There must be a sufficient pressure differential between the tubing pressure and the tubing-casing annulus pressure.
A minimum differential of 50 psig is required at low injection pressures (less than 500 psig.).
Differential can be positive or negative.
There should be no significant variances in annulus pressures over the 12-month period.
Send an attachment explaining all pressure anomalies.
If an anomaly cannot be explained satisfactorily, then annulus monitoring will not be accepted as a demonstration of mechanical integrity.
If annulus pressure monitoring indicates a leak in the tubing, packer or casing, the district office will inspect the well and require any testing necessary to demonstrate mechanical integrity.
Beginning April 1, 2010, a wellhead inspection will also be required to verify credible monitoring.
Common reporting problems:
Injection pressures are sometimes erroneously reported as annulus pressures. This type of error is significant because identical injection pressures (Item 13) and annulus pressures (Item 15) indicate a tubing or packer leak.
Number of readings taken is not reported.
6. Item 16--Current injection interval
Report the currently completed interval, which may differ from the permitted interval.
Make necessary corrections of computer-generated data.
7. Item 17--Packer depth
Unless an exception has been granted, the packer must be set as follows:
For disposal wells permitted under Rule 9, the packer must be set within 100 feet of the permitted zone.
For injection/disposal wells permitted under Rule 46, the packer must be set no higher than 200 feet below the known top of cement behind the production casing and at least 150 feet below the base of usable quality water. Note: If the packer is moved uphole from the setting depth proposed in the permit application, an amendment to the permitted injection interval may be an option.
will result in a violation notice and
will eliminate annulus monitoring as an option to the 5-year pressure test requirement.
8. Item 18--Other operators' fluids.
Indicate if fluids from sources other than the operator's are being injected by checking the box.
require that fluids be trucked to the well site and a fee is charged to dispose of the fluids
require a commercial permit with special surface facility provisions
9. Item 19--Injection method.
Indicate the current injection method.
Note that any pipe (regardless of size) that is cemented in place, is defined by Rule to be casing and does not meet the requirement that injection be through tubing set on a mechanical packer.
10. Item 20--Fluids injected during cycle year.
Check the appropriate box for all fluids injected during reporting cycle.
The category "other" includes fluids such as nitrogen, steam, surfactants and hydrogen sulfide (H2S) gas.