In observance of the 4th of July Holiday, the Railroad Commission of Texas will be closed Monday, July 3 and Tuesday, July 4. The agency will reopen for business on Wednesday, July 5.
Use of Downhole Hydrocyclone Oil-Water Separators in Simultaneous Injection and Production Wells in Texas
The use of Downhole Oil-Water Separators (DOWS) provides a unique opportunity to reduce the risk of pollution, reduce operating costs, and enhance production by extending the economic viability of marginal high water-cut operations.
Standard injection well operations pose a significant but manageable risk of environmental pollution. The highest risk occurs due to surface spills during separation, and reinjection of the separated brine. By reducing the volume of produced brine brought to surface and reinjected, the principal environmental risks associated with injection wells can be reduced.
The permitting of an injection well using the DOWS equipment provides an ideal opportunity to apply risk-based environmental permitting.
The nature of the DOWS injection well requires modification of the standard permit requirements for mechanical integrity testing and injected fluid monitoring to meet the regulatory requirements of groundwater protection and confinement of injected fluids.
The following guidelines for permitting DOWS injection wells was adopted by the Commission on July 16, 1997. The procedure reduces the testing and monitoring requirements and associated compliance costs to a level consistent with the lower risk posed by these wells, while still providing information necessary to demonstrate proper operation.
DOWS injection wells can be divided into two basic configurations. Each configuration has two distinct variations requiring slightly different regulatory approaches.
One configuration has the well producing from a shallower zone and injecting into a deeper zone.
This configuration has two cases depending on whether injection is into the same formation.
The second configuration has the well producing from a deeper zone and injecting into a shallower zone.
This configuration has two cases depending on whether surface casing protection extends through the entire zone of usable quality groundwater.
Permit Application Considerations
In addition to the standard attachments, the application for an injection permit should include:
a wellbore sketch showing the wellbore construction and DOWS configuration;
the current fluid level or current "bottom hole" formation pressure of the proposed injection/disposal zone;
the proposed water/oil ratio of the produced fluids raised to ground surface to be maintained by the DOWS equipment. This would not be required in the case where injection is into the same reservoir.
the proposed "bottom hole injection pressure" (BHIP) of the proposed DOWS completion.
Areas in common with both configurations:
Monitoring and reporting of injection volumes and pressures:
The standard permit conditions on monitoring and reporting the injection volume and injection pressure will apply.
The average and maximum monthly injection pressures and monthly injection volumes will be determined from downhole transducer readings and reported annually on the annual monitoring report (Form H-10.)
Pressures and volumes will be estimated if a transducer fails.
The Commission will have no way to know if downhole pressure and volume information is unavailable unless notified of transducer failure.
Accordingly, the operator will be required to report the failure of a downhole transducer within 24 hours and take corrective action within 3 months of transducer failure.
Maximum bottom hole injection pressure - In order to ensure that injected fluids are confined in the authorized injection interval, the Commission requires that the maximum bottom hole injection pressure may not exceed the formation fracture pressure at the uppermost perforation. The formation fracture gradient is generally assumed to be around 1.0 psi/ft. Standard injection well permits stipulate a maximum surface injection pressure to simplify compliance inspections. The permit for a DOWS injection well will specify the maximum authorized bottomhole injection pressure.
Changes in well configuration - As with any injection well permit, any significant change in the well's configuration will necessitate changes in the permit conditions. Accordingly a permit amendment application will be required, for any significant modification of the wellbore configuration, such as conversion to conventional injection through tubing and packer arrangement.
Minimum water/oil ratio - The DOWS system should be designed so that some water is produced with the oil. Since the hydrocyclone separator is not 100% efficient, it is more desirable to produce some water to the surface than to try to fine tune the system and run the risk that some oil is lost to the injection zone. This approach was taken to avoid the need for hearings to evaluate "waste of natural resources" considerations for individual well permits. Economics will probably dictate that DOWS systems be installed primarily in high water-cut wells. The manufacturer recommended a 50% water content in the production stream to prevent significant loss of produced oil in the injection stream. The permit will stipulate a minimum water/oil ratio of 1:1 for a single stage hydrocyclone. The permit will also require that the water/oil ratio be monitored monthly and reported annually as an attachment to Form H-10. This would not be required if the injection is into the same reservoir from which the well is producing, since the oil is ultimately recoverable by the same well.
Initial Mechanical Integrity Test - As with every injection well, the mechanical integrity of the wellbore must be demonstrated prior to injection because the environmental risk of a DOWS well is lower than a conventional injection well due to its mode of operation.
For the Production Above Injection configuration: The initial mechanical integrity test will be a conventional pressure test at the minimum test pressure required by Commission rules (200 psi). The test may be either a test with the packer set within 100 feet of the top of the perforations, OR a fluid level depression (Ada) test above the production perforations.
For the Injection Above Production configuration: The initial mechanical integrity test will be a conventional pressure test at the minimum test pressure required by Commission rules (200 psi).
Subsequent Testing and Monitoring -Commission rules require that whenever a loss of integrity or malfunction is indicated, the well should be shut in and tested, then corrective action taken, if necessary.
For the Production Above Injection configuration: The mechanical integrity of the packer and lower DOWS assembly will be demonstrated by a combination of quarterly fluid level monitoring and pressure testing after each workover but at least once every 10 years. A mechanical integrity failure of the packer or lower DOWS assembly will either result in:
a rise in the fluid level in the tubing-casing annulus (when the pressure differential between the injection zone and the production zone is low) or ;
a decline in oil production and increased water production due to water recirculation (when the productive zone is underpressured relative to the injection zone)
For the Injection Above Production configuration: The risk to ground water for these wells will ordinarily be low because the produced water will be at a pressure sufficient only to move it into the disposal zone and that permitted "down-hole" injection pressure may not be sufficient to raise fluids to the ground water zones. In other cases, however, the formation pressure of the disposal zone may be high enough to require an injection pressure equivalent to that of surface injection operations, or at least sufficient to raise fluids to the ground water zones. In the event of a tubing or packer leak, the produced water may move under pump pressure into the tubing-casing annulus. As with conventional injection wells, the mechanical integrity frequency and monitoring requirements for DOWS wells hinge on whether the well has full surface casing protection for the entire groundwater zone:
For wells with full surface casing protection of groundwater, subsequent pressure tests will be required every five years. In addition, the tubing-casing annulus pressure will be monitored monthly for wells that have a permitted downhole injection pressure sufficient to reach ground water zones.
For wells without full surface casing protection of groundwater, subsequent pressure tests will be required every three years. In addition, the tubing-casing annulus pressure will be monitored weekly.