Two cases illustrate acid gas/water injection scheme

At the David installation, produced water from the oil battery inlet is the cooling medium. Shown is the compressor inlet scrubber (Fig. 1).

• The compressor building at Thompson Lake accommodates regular monitoring of the compressor operation without requiring the operator to enter the sour-gas equipment area (Fig. 2 [11,892 bytes]).
• The acid gas, at the David installation, is introduced to the produced water at the booster pump discharge prior to the mixer. Shown is the water header mix system (Fig. 3 [13,523 bytes]).
• The Thompson Lake high-pressure, produced-water mixing header is made of Schedule 40 Inconel 625 material (Fig. 4 [13,111 bytes]).
• The acid-gas injection well at Thompson Lake is the same as PanCanadian's standard oil field water injection well (Fig. 5 [13,111 bytes]).

Two field installations in Canada illustrate the facilities required for injecting low-volume acid gases mixed with water.

The first installation, near Provost, Alta., is at the PanCanadian Ltd. David Battery No. 3 and the second is at the PanCanadian Thompson Lake facility near Hardisty, Alta.

This is the concluding article in a two-part series that began in OGJ Aug. 3, 1998, p. 33.

Reservoir considerations

In the David area, the producing pool has two main zones that consist of multiple stacked channel sands. The upper zone is the 1-10 ft thick regional Cummings sandstone. A tight shale layer separates this member from the lower channel Cummings sandstone with an oil pay of up to 40 ft. An extensive and active aquifer underlies this oil accumulation.

The two Cummings sandstones have excellent reservoir qualities with an average 30% porosity and up to several Darcy permeability.

PanCanadian operates the larger portion of this pool. Well spacing is 5-10 acre/well. The area has about 160 producing wells and 5 disposal wells. October 1997 production was about 4,090 bo/d and 114,000 bw/d with about 58,000 b/d of acid gas-laden water being disposed of into the Cummings aquifer with two of the five injection wells.

Re-injection to the producing formation raised concerns about acid-gas recycling. Acid-gas cycling to surface would place increased and undue load on the gas processing facilities. But because of the aquifer's strength and the injection perforation separation from the oil/water contact, it was expected that no cycling effect would be noticed.

PanCanadian's operations in the Thompson Lake area produce about 34,000 b/d of sour water that is re-injected through one well into a non-hydrocarbon bearing reservoir in the Upper Leduc formation. This formation lies below most of the producing horizons.

In this area, the upper Leduc is a dolomitized shelf carbonate that has a large areal extent, covering most of southwestern Alberta. It is capped throughout the region by the lower Ireton shale that is regionally flat and dips 20 ft/mile to the southwest.

Local structures are difficult to identify because of a lack of well control. Generally, the targeted disposal zone has about a 131-ft reservoir thickness and 22% dolomitic porosity.

This single injection well was selected because it was an available unsuccessful exploration well and it was located close to the battery. This permitted a short injection line.

Surface facilities

Both the David and Thompson Lake facilities are designed to produce zero daily sulfur emissions. Oil production needs to be reduced when the acid-gas disposal facilities are not functional. This provides significant incentive to design a reliable system.

The David installation has an oil-injected screw compressor (Frick 163L) driven by a 150-hp electric motor. The compressor unit is made of conventional carbon steel metallurgy with instrumentation to NACE sour requirements.

A single-seal assembly was provided on the compressor. The unit discharges at a pressure of 190 psig and has a turndown ratio of 10:1 using a variable sliding suction valve.

This compressor design offers the advantage of a high compression ratio without the expense of interstage coolers and scrubbers. This service is thought to be the most sour wet-gas application for this compressor type in the world. As a result, all compressor components were reviewed at length before committing to this application.

A significant design consideration was to maintain a safety factor of a 30° F. margin over the predicted water dew point throughout the compression cycle. This ensures that water in the inlet gas stream would not condense and contaminate the oil, reducing lubrication properties and possibly causing corrosion.

The compressor logic system has a high suction temperature shutdown of 110° F. and a low discharge temperature shutdown of 220° F.

To guarantee this inlet temperature, a secondary shell-and-tube water cooler is employed in the summer months to further cool the amine regenerator overhead vapor. The discharge temperature shutdown set point actually floats with suction temperature based on water dew point criteria contained in the program. Produced water from the oil battery inlet is the cooling medium (Fig. 1 [14,488 bytes]).

As a safety precaution, the compressor control room is isolated from the compressor building to accommodate regular monitoring of the compressor operation without the operator having to enter the sour gas equipment area. This room has its own HVAC (heating, ventilating, and air conditioning), H₂S detection, and outside access (Fig. 2 [11,892 bytes]).

The discharge gas passes through the lube oil separator and from this point on, 304L stainless steel (SS) pipe is used. The gas is introduced to the produced water at the booster pump discharge prior to the mixer (Fig. 3 [13,523 bytes]).

The mixer is an inline multi-element static mixer (Koch model SMVL) made of 316L SS. The mixed fluid stream enters the horizontal multistage centrifugal charge pump (Sulzer Bingham model 6x8x11D MSD-5). The pump metallurgy is conventional 316L SS impellers and 316L SS casing. The metallurgy was unchanged from its original use with the produced water containing 50,000-ppm chlorides.

Slight configuration changes were made in the ancillary piping to provide increased containment of the acid gas-laden fluid. All the water piping is internally thin-film plastic coated.

The Thompson Lake installation uses a four throw, four-stage reciprocating compressor (Dresser Rand model HOS), that is heavy duty (60,000-psi rod load) and has double-distance pieces. The compressor is driven by a variable frequency 800-hp TEFV (totally enclosed forced ventilated) motor drive that provides a 4.5:1 speed reduction. Auxiliary oil pumps are activated at low motor speeds.

Table 1 [107,322 bytes] lists the design operating pressures, temperatures, and metallurgy.

The dual distance piece system prevents sour gas migration into the compressor crankcase. The outboard distance piece vents are piped to the suction of the oil-battery vapor recovery unit to ensure zero emissions.

The inboard vents are held at 8-psig static pressure with fuel gas and will only vent on complete rod packing failure.

Variable volume clearance pockets were not provided, to avoid the possibility of acid-gas leakage. Fixed clearance volumes are provided for future volume adjustments. Flanged connections were preferred over screwed to avoid leakage and corrosion.

Because no dehydration is involved in the design, all process vessels, coolers, piping, valving, and instrumentation are 316L SS to resist wet CO₂ corrosion, vibration-induced cracking, etc. This metallurgy was selected for process systems with high operating temperatures where condensation of corrosive sour water could collect in pocketed piping (such as in the discharge piping to the cooler) during equipment shutdown and ambient cooling.

Similar to the David facility, the local compressor control panel was housed in its own attached building, with its own exterior access, HVAC, gas detection, and a window to the compressor room to allow visual monitoring. Access to the compressor area is only allowed if breathing apparatus is worn.

Acid gas from the amine reflux drum is routed to the first-stage compression at 5 psig, and the suction pressure is controlled by compressor speed adjustment and/or machine recycle. The gas stream is compressed through four stages to the desired pressure.

A vertical aerial cooler that also cools the glycol/water cylinder coolant and frame lubricating oil coolant provides interstage cooling.

Water collected from each intercooling step is level controlled back to the preceding suction scrubber to avoid possible hydrate formation on pressure reduction. The resultant liquids accumulate in the first-stage suction scrubber and are recycled back to the amine unit or water skim tank with a pump.

The outlet piping from the compressor cooler is 2-in. 316L SS. A final-stage back pressure controller exists prior to gas release to the 6-in., Schedule 40 Inconel 625 high-pressure, produced-water mixing header (Fig. 4 [13,111 bytes]).

The acid-gas stream mixes with the water and then flows to the dedicated injection well through a 758-ft long, above ground, insulated and electrically heat-traced 6 in. carbon steel line. The line was kept above grade for inspection purposes.

Schedule 160 pipe with 0.490-in. corrosion allowance was installed at nominal extra cost over the required wall thickness (Schedule 40). This line can also serve for the total solution-gas injection scheme using the plant inlet and sales gas compressor. This would provide backup to guarantee oil production when the acid-gas injection scheme is down. Otherwise production would have to be curtailed for the facility to meet zero sulfur emissions.

Table 2 [155,219 bytes] displays the comparative capital costs for small acid gas-handling schemes. The data were obtained from installed facilities, and the cost comparison is difficult because acid-gas capacity and process schemes vary significantly.

One can conclude by scaling the equipment costs based on capacity to the power of seven-tenths that the low-pressure screw compressor with an intermediate mixing pressure with water is significantly less costly than the other schemes shown.

Injection equipment

The Thompson Lake injection well ( Fig. 5 [11,908 bytes]) is PanCanadian's standard oil field water injection well. The 7-in. well casing is standard material with two stainless steel joints above the injection zone where the packer is set. The tubing string is 4.5-in. diameter, J55 with internal coating.

Casing pressure is monitored on a routine basis. No backup well is provided. Monthly reports are submitted to the Alberta Energy Utilities Board.

Future flow rate turndown can be accomplished by installing smaller tubing in the well. This will raise the tubing system differential pressure, thereby raising the wellhead pressure and assuring the rotating equipment has sufficient back pressure.

Operations experience

The David injection facility was commissioned in February 1995. Acid-gas/water injection was accomplished immediately with no difficulties. Shortly thereafter, the screw compressor experienced a mechanical seal failure. The seal was replaced and the system was brought back on line.

Following several seal failures, a new type of seal was selected. The original seal was a pusher type, with a rotating seat. The seat material was Ni-resist, while the seal face was carbon. This seal was replaced with a balanced pusher-type rotating face design. Both the seat and face materials are silicon carbide.

No seal failures have been experienced since the new seal was installed.

With the exception of the seal failures, the system ran virtually trouble free. At this time, there appears to be no effect of the acid-gas injection on component or overall system reliability.

The compressor unit is relatively straightforward to operate. It is not significantly different from a similar screw-type compressor in natural gas booster service with the exception of hazardous-area considerations and water dew point concern.

This level of simplicity is achieved with local logic control for start/stop/purge warm-up, etc.

The acid-gas injection pump was installed in February 1995. In June 1996, this pump was removed from service. It was dismantled and inspected to evaluate the effects of the acid-gas injection as compared to the effects of only produced water.

In general, the pump condition was very good. The casing and impellers were found to be in very good condition, with no apparent effects from the acid-gas service. The impeller and casing wear rings were washed from erosion/corrosion. The washing of the eye rings and hub rings was typical for this type of pump in this service.

The throttle and center sleeve/bushings were washed more significantly than is typical for produced water service. In addition, some discoloration of unknown origin was observed. It is suspected that the acid gas had some effect in these high-velocity/high-differential pressure zones within the pump. The mechanical seals have been sent to the seal manufacturer.

Some stainless parts showed some discoloration, but wear was normal for this service.

In May of 1996, a consolidation of gas plants in the area resulted in the closure of the David gas plant. Over 1 year of operating experience proved the viability of this disposal scheme. The on stream factor for the compressor was 99.3% excluding downtime due to the original seal failures.

The Thompson Lake compressor was commissioned in June 1995. The unit was put on line with no significant difficulties. Since that time, the unit has run relatively trouble-free. The supplier, due to several springs breaking, has changed compressor valve spring material during the 500-hr routine inspection.

A major modification to the distance-piece packing system was carried out to improve the purging/sealing reliability. The compressor on stream factor for the 10-month period from August 1995 to May 1996 was 99.5%, excluding the downtime related to packing failure. The gas plant on stream factor was 98.0%.

Electrical interruptions and upstream amine plant upsets individually exceeded the acid-gas compressor system downtime. The 1997 maintenance experience has been normal and cylinder valve life has exceeded expectations.

Upon initial commissioning, the injection pressure was 755 psig, with 27,000 b/d of produced water. The wellhead injection pressure has stabilized at about 435 psig, with 28,300 bw/d and 888 Mscfd acid gas. This reduced discharge pressure in conjunction with the lower gas flow rates (888 Mscfd vs. design of 2,660 Mscfd) resulted in the unit operating with a significant amount of compressor recycle even with variable-speed drive.

To reduce operating costs, the head end of the first stage was unloaded. A back pressure control valve in the discharge line, before the injection point into the water stream, maintains a minimum discharge pressure. This ensures adequate load on the fourth stage, maintaining temperatures out of the aftercooler above the hydrate point in the winter.

The unit is relatively straight forward to operate through the use of local programmable logic controllers (PLCs); therefore, the installation does not require significant additional operational effort.

The installation has not encountered any sulfur deposition problems, no specialty chemicals are required, and maintenance has been minimal, due in part to the electric driver.

At the David facility, corrosion is not a major concern because the acid-gas laden produced water is injected through the existing internally coated injection pipelines. Corrosion monitoring has been focused on the Thompson Lake facility where the project schedule required the installation of a high pressure, temporary, internally bare, carbon steel, stress-relieved injection line with a high corrosion allowance.

The corrosion monitoring program at Thompson Lake consists of ultrasonic inspection, corrosion coupons, and visual inspection of removed piping. Ultrasonic testing was conducted monthly from start-up until October 1995 with maximum corrosion pitting rates in the order of 20-30 mills/year (mpy).

Corrosion coupons removed from the injection line in late September 1995 indicated a general 2-3 mpy corrosion rate and a maximum 25.3 mpy corrosion-pitting rate.

During late September, a piping spool was removed from the injection line near the injection well for visual inspection. The spool was sectioned and split longitudinally to expose the interior surface for detailed examination.

Pit depth measurements taken from a representative piping section confirmed corrosion pitting rates in the order of 20-30 mpy. Frequency of surveys was increased to every 6 months.

Results from the December 1997 ultrasonic survey at Thompson Lake indicate slowing in corrosion and minor metal loss to date throughout the system. The lowest remaining life expectancy of the bare carbon steel injection line is a minimum of 56 years based on 2 years of monitoring. Highest corrosion rate found on the last survey is 8 mpy.

Although this line was to be upgraded to a more resistant material when available, upgrading the metallurgy has been deemed unnecessary at this time. Corrosion surveys will continue on a semiannual basis. No corrosion of compressor equipment has been observed.

Both David and Thompson Lake schemes seem to be relatively cost effective and PanCanadian operations have been comfortable with the reliability and safety of both acid-gas injection facilities. The facilities also provide zero sulfur emissions.

Reservoir response

The David disposal scheme started in February 1995 with a total sour-water disposal rate of about 44,000 b/d. Generally, well injectivities have improved with some decrease in wellhead-injection pressures. This response is reflected in the changed slopes on Hall plots (Fig. 6 [126,318 bytes]).

One probable reason for the increased injectivity is the formation stimulation provided by the injection of mildly acidic water.

The upper Leduc formation used in the Thompson Lake scheme has excellent reservoir qualities, and no injectivity problems have been encountered in the disposal well. From the start, injection pressures have been low and the average water injection rate is 26,400 b/d.

The Hall plot in Fig. 6c shows some improvement in the injectivity performance. As in the David scheme, some acidizing effects can be expected, and more data will help confirm any significant change in injectivity.

The Thompson Lake injection well performance (Fig. 7 [79,662 bytes]) indicates the reduced injection pressure after initial solution gas injection, and the sensitivity of wellhead pressure to water flow rates. Overall, there is no indication of well bore plugging, and injectivity is improving which confirms that a back-up well is not currently necessary.

Acknowledgments

The authors wish to thank the PanCanadian Petroleum Ltd. and DPH Engineering Inc. managements for allowing publication of this article. We would also like to thank D. Carley, J. Herauf, R. Lutzer, R. Hartzler, and others for their support and contributions to the article.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.