TECHNOLOGY Snubbing workover operations in deep sour gas wells a success

Mike R. Konopczynski, Mike R. Milligan
Shell Canada Ltd.
Calgary

Several deep, sour-gas wells underwent conversions from dual to single completions, using a snubbing unit and service rig, to improve gas deliverability.

In 1994, Shell Canada Ltd. conducted workovers to commingle sour gas production from the Devonian and Mississippian formations in the Limestone field. Most of the Limestone wells are concentric dual-tubing completions with the Mississippian gas produced up the concentric annulus and the deeper Devonian gas produced up the inner tubing string.

A few wells were commingled by opening sliding sleeves or perforating the inner string, but an opportunity was identified in many wells to enhance deliverability and accelerate reserves production by removing the inner concentric tubing string, allowing the commingled production to flow up the larger outer tubing string alone.

To prevent formation damage from conventional well-control procedures, snubbing was identified as a preferred method to execute these operations.

The Limestone gas field is located in the Rocky Mountain foothills of central Alberta. Shell Canada Ltd. discovered the field in 1974 and began production from 10 wells in 1980.

Today, there are 19 wells producing approximately 3.75 million cu m/day of raw gas from dolomite formations of Mississippian and Devonian age.

The raw gas is produced from five carbonate formations: the Mississippian Turner Valley (Mt), the Mississippian Pekisko (Mp), the Devonian Wabamun (Dwa), the Devonian Nisku (Dn), and the Devonian Reef (Dr). All these formations contain sour gas.

The hydrogen sulfide content is approximately 6 mole % for the Mississippian gas and ranges from 22 to 29 mole % for the Devonian gas.

The majority of the wells drilled in the Limestone penetrated productive reservoirs in both the Mississippian and Devonian formations. Initially, the gas production from the Devonian pools was segregated from the gas production from the Mississippian pools in accordance with Energy Resources Conservation Board (ERCB) regulations. This was accomplished by installing dual completions in these wells.

Most of the wells have been completed with dual concentric strings; the Devonian gas flows up the 73-mm inner production tubing string, while the Mississippian gas flows up the annulus between the inner 73-mm string and the outer 127-mm string (Fig. 1 [66859 bytes]).

In the spring of 1994, the ERCB granted Shell permission to commingle the production from the segregated Mississippian and Devonian gas streams. Well productivity was declining because of reservoir depletion; thus, this commingling resulted in an opportunity to improve the deliverability of a number of wells by the removal of the inner 73-mm production string (Fig. 2 [62268 bytes]).

Snubbing operations

Snubbing and stripping are processes by which pipe is removed from or installed in a well when surface pressure in a well exceeds atmospheric pressure.1 These operations are commonly done by pulling the pipe through a flexible elastomeric element which creates a pressure seal around the pipe.

If the hydraulic force on the pipe created by the well pressure acting on the cross sectional area of the pipe is greater than the weight of the pipe such that, unrestrained, the pipe would be ejected from the well, the process is called snubbing.

If the weight of the pipe is greater than the hydraulic force such that, unrestrained, the pipe would fall into the well, the process of moving the pipe is called stripping.

Both snubbing and stripping may be done with a snubbing unit. Thus, when both processes are involved, the total operation is generally referred to as snubbing.

Objectives

After the Limestone field came on stream, well control during workover operations was achieved by loading the well with water-based fluids. Unfortunately, the hydrostatic head of water was greater than the reservoir pressure, so large volumes of fluid were lost, especially to the Mississippian formation.

The fluid losses were somewhat alleviated by the use of aqueous gels and acid-soluble lost circulation materials such as calcium carbonate, but fluid loss was still high, resulting in productivity impairment.

In addition, fluid lost to the formation had to be produced back, often leading to difficulties unloading the well during start up. This was a major problem for low-pressure gas wells. Some wells responded quickly, while others experienced long-term or permanent formation damage.

With production, the Devonian and Mississippian reservoirs have been depleted, and the formations' pressures have dropped greatly over time. In some cases, the pressure has been depleted by more than 60%, especially for the higher permeability and more productive Mississippian formation.

In considering the commingling work, it was apparent from previous workover experience that standard well control techniques would result in massive losses of workover fluids and that the associated impairment would result in productivity losses which could far outweigh the potential gains from the commingling.

Snubbing is conducted without introducing damaging fluids into the well bore and without creating an overbalance which would force fluids into the formation. As a result, no formation impairment or damage occurs. In addition, because heavy liquids are not placed in the well, the unloading process is avoided.

Planning process

After the first three candidates for commingling were identified, a general review of snubbing operations and procedures was conducted by a review of industry literature, applicable ERCB well servicing regulations, and Alberta Recommended Practices and by discussions with service companies.2 3

Conducting snubbing operations on sour gas wells defined as critical by the ERCB requires special considerations to address safety and operational concerns. A set of general operating procedures recommended for use in snubbing operations on sour gas wells was then prepared. These procedures addressed issues such as equipment requirements, personnel qualifications, blowout preventer (BOP) requirements, design factors for avoiding pipe buckling, contingency procedures, and emergency response planning.

Based on these general operating procedures, well-specific workover programs were prepared and subjected to an internal technical review process. The ERCB was consulted, and an application for Critical Sour Well servicing operations approval was submitted in accordance with their regulations. Service companies and equipment vendors were selected for the supply of rig services, snubbing and safety services, and specific downhole equipment required for the operations.

Prior to executing the snubbing programs, a hazard pre-operations review meeting was conducted for each well operation. The Hazop/PreOp meeting involved key personnel from the service rig, snubbers, safety services, BOP suppliers, and the Shell workover operations manager, foremen, production engineers, and safety representatives.

The Hazop/PreOp meeting was used to ensure that all personnel involved were familiar with the objectives of the operations, the history and condition of the well, the operations planned, and the area safety and emergency response procedures. In addition, the servicing program was reviewed in detail, step-by-step, to detect any potential hazards or problems or identify opportunities to make the operation safer and more efficient.

Safety measures

One concept which Shell Canada adopted for the sour snubbing operations was the dual-barrier concept. Well control during snubbing was available from at least one of two tested barriers.

The barriers external to the pipe consisted of the snubbing unit BOPs and the service rig BOPs. Internally, downhole well control was provided by back-pressure valves, slick-line-set profile plugs, or wire-line-set permanent bridge plugs set in the tubing.

At least two plugs were set in the tubing (Fig. 3 [65353 bytes]). In addition, one or more stabbing valves sized for the pipe were available on the snubbing platform at all times.

During snubbing operations, the pipe to be snubbed from the well under pressure can be subject to high compressive axial loads which can result in buckling of the unsupported pipe above the BOPs.

Buckling may result in pipe string failure and loss of pressure integrity at surface. Before commencing snubbing operations, the pipe is pressure tested to confirm pressure integrity and to evaluate the competency of the pipe body strength for buckling calculations. The buckling calculations give an indication of the safe amount of stroke that can be used when removing or installing the pipe under snubbing conditions.4

Operations at Limestone were conducted during daylight hours as per Alberta Recommended Practices. In addition to the standard BOP drills, "man-down" drills were conducted to practice evacuation of an incapacitated operator from the snubbing platform basket.

Nitrogen gas blanket

An additional safety measure incorporated in the Limestone snubbing operations was the use of a nitrogen gas blanket in both the 73-mm tubing and the annular area between the 127 mm and 73-mm tubing. The 73-mm tubing was purged with two tubing volumes of nitrogen prior to setting the internal plugs. Similarly, the annular space was purged with two hole volumes prior to commencing snubbing operations.

The nitrogen blanket has two purposes:
• It acts as a buffer against the release of small amounts of sour gas due to "weeping" past the stripping BOPs as the pipe is snubbed from the well.

• It provides a measure of reaction time (2-5 min for this operation) in the event of catastrophic failure of the sealing elements while the nitrogen is displaced from the well and before sour gas surfaces. This time allows the crew to ensure their own safety and implement contingency procedures to secure and control the well.

Monitoring H2S buildup

Shortly after the purge and periodically as the snubbing operations were conducted, the purge gas in both the tubing and the annulus area were sampled for the presence of hydrogen sulfide. This sampling was intended to confirm the effectiveness of the purge gas and to see if hydrogen sulfide would migrate to surface through agitation, diffusion, or release from scale on downhole tubulars.

As expected, the hydrogen sulfide content of the purge gas was "too small to measure" using conventional H2S detection equipment immediately after the nitrogen purge. During the next 24 hr, the hydrogen sulfide content in the annular purge gas built to 120 ppm, then declined to amounts too small to measure over the next few days.

The hydrogen sulfide content remained too small to measure throughout the remainder of the operations. The same pattern was experienced in all three operations conducted at Limestone.

It is suspected that the source of the hydrogen sulfide noticed after the purge was in the wellhead valve bodies and bonnets and other wellhead cavities not swept clean by the nitrogen purge.

This gas was probably vented during gas sampling, resulting in lower subsequent measurements of hydrogen sulfide.

Snubbing equipment

For the Limestone snubbing, Shell used a rig-assist hydraulic snubbing unit. The snubbing unit had its own BOP stack to provide the seal around the pipe during snubbing or stripping and to allow staging of irregular objects such as packers or tubing hangers in or out of the well.

The latter procedure required "equalizing loops" and a bleed off line to allow the pressure in the snubbing BOP stack to be switched between well pressure and atmospheric pressure.

In addition, the snubbing unit incorporates two sets of opposed slips to hold the pipe against upward (hydraulic) forces or downward (gravity) forces. One set of slips, the stationary slips, are fixed to the top of the BOP stack and hold the pipe when not in motion. The second set of slips, the traveling slips, are anchored to a movable yoke to hold the pipe when in motion.

The yoke is attached to hydraulic power cylinders or rams which produce the force necessary to push the pipe into the well or to extract the pipe from the well in a controlled manner when subject to pressure from the well.

A conventional service rig was used for the operation and provided the means of moving the pipe in and out of the well during stripping operations. The service rig also expedited the handling of the pipe during pick up and lay down and provided a primary set of BOPs for well control.

BOP equipment

The BOP stack for the snubbing operations at Limestone was composed of both the rig BOP stack and the snubbing unit BOP stack (Fig. 5 [73528 bytes]). The stack was arranged as follows, from top to bottom:

• Snubbers: Annular BOP, spool, QRC pipe rams, spool and equalization valves, QRC pipe rams, and spool

• Rig BOP: Annular BOP, pipe rams, blind rams, spool, and blind/shear rams.

  The snubber's BOP stack was powered from a separate power and accumulator system from the rig BOPs. The snubber's BOPs are the "working" BOPs, with elements designed to resist the wear of the pipe being stripped through them under pressure.

  All components in the BOP stack conformed to NACE MR0175 sour service certification.

General snubbing
procedure

Because all the operations conducted at Limestone were similar, the procedures used in each were common. The snubbing operations were conducted according to the following procedure:

• A slick-line-set plug was set in the 73-mm tubing.

• The tubing was pressure tested with nitrogen to ensure pressure and strength integrity.

• The plug was retrieved, the tubing was purged with nitrogen, and a check valve-type plug was set in the tubing.

• The service rig and snubbing equipment were rigged up on the well. The BOP stack was installed and pressure tested.

• The annulus between the 73-mm tubing and the 127-mm tubing was purged with nitrogen.

• A stabbing joint was installed in the tubing hanger. The tubing was released either by pulling the seal assembly from the production packer or by coming off an "on-off" tool above the packer.

• A second check valve-type plug was installed in the tubing to provide the second interior barrier.

• The 73-mm tubing was stripped and snubbed out of the well until the bottom hole assembly with the plugs reached the surface.

• Water was pumped through the 73-mm tubing and check valve-type plugs to purge any gas from the tubing and bottom hole assembly.

• The bottom hole assembly (plugs, on-off tool, and seal assembly) was staged out of the snubbing BOP stack. During this operation, the snubbing crew and driller were masked up.

• A slick-line-set plug was set in the 127-mm tubing, and the tubing was pressure tested with nitrogen.

• The snubbing and rig BOP stack were removed, and a new 127-mm wellhead and christmas tree were installed.

• The rig was released, the 127-mm tubing plug was retrieved, and the well was returned to production.

Examples

For the first snubbing program, three wells were selected from the Limestone producers which appeared to have the most potential for incremental deliverability by removal of the 73-mm Devonian string.

Limestone 22

Limestone 22 was the first sour well on which Shell Canada conducted these snubbing operations. The well was selected because it was recently completed, and the operation was the least complex. The potential degree of tubing corrosion was believed to be small, and hence the risk of operational problems from pipe degradation would be minimal.

The Limestone 22 completion incorporated an on-off tool one joint above the locator seal assembly in the 73-mm tubing string (Fig. 6 [37546 bytes]). After pressure testing, purging the tubing, and rigging up, the next operation was to attempt to release the 73-mm tubing by pulling the locator seal assembly from the packer seal bore with 24,000 daN of overpull.

The seals did not release, so the TKX check valve was moved up one profile, and the tubing was successfully released by unlatching the on-off tool. The tubing was snubbed out of the well according to the program.

Little-to-no corrosion was found on the 73-mm tubing despite 3 years of service.

Limestone 2

The operation on Limestone 2 had a few more complications than Limestone 22.

First, the completion was much older (9 years). Second, no on-off tool was incorporated into the design. Third and most important, an underdrift crossover had been accidentally installed in the tubing string, precluding the use of profile-type plugs unless the crossover could be reamed to full drift (Fig. 7 [33297 bytes]).

The first step in this operation was to attempt to mill out the undersized crossover with a 59.6-mm mill powered by a 52.4-mm downhole motor run on 38.1-mm coiled tubing.

After several motor and mill combinations were tried with little success over several days, and facing escalating costs and mounting loss of fluid to the Devonian formation, it was decided to proceed with an alternate plan.

The 73-mm tubing was cut with a chemical cutter at 2,820 m, just inside the 127-mm tubing. This depth was chosen to maintain the ability to fish the 73-mm tubing in the future and to avoid potential liquid loading problems with Devonian gas.

The tubing was purged, two wire-line-set permanent bridge plugs were installed in the tubing, and it was snubbed out of the well.

Limestone 12

Limestone 12 presented the greatest challenge to the snubbing operation because its complex history presented a major obstacle.

In an attempt to alleviate problems associated with deposition of elemental sulfur precipitating from solution in the sour Devonian gas, the Devonian formation was completed with internally plastic-coated, 73-mm tubing. An on-off tool was not included in the completion (Fig. 8 [33277 bytes]).

Shortly after production was commenced from the Devonian pool, several wire line tools were lost in the lower section of the tubing. Fishing operations were complicated by failure of the internal plastic coating, resulting in additional tools lost downhole, complete plugging of the tubing, and total loss of gas production from the Devonian pool in Limestone 12.

Production from the Mississippian pool continued for several years, depleting that reservoir while the Devonian remained near original conditions.

For the snubbing operation, a wire-line-set bridge plug was set immediately above the fish, and the tubing was pressure tested. A hole was then punched in the joint above the bridge plug so that the tubing could be purged with nitrogen. Two more wire-line-set bridge plugs were set above the perforation (Fig. 9 [79183 bytes]).

Fortunately, the large pressure differential between the Devonian and Mississippian formations provided an hydraulic force which assisted in pulling the locator seal assembly from the packer. The tubing was then snubbed from the well.

Once the tubing, locator seal assembly, and tail pipe containing the wire line tools reached surface, a 150-ton crane with a 50-m reach was brought to the location. The well was killed with water, and the remaining 82 m of tubing and equipment were pulled from the well in two sections with the crane.

During this procedure, the entire crew, including the crane operator, were masked up in preparation for potential hydrogen sulfide release. Less than one hole volume of water was used to control the well during this operation.

The tubing was laid down by the crane in a remote location on the lease. The tubing was then hot tapped and broken apart.

Snubbing operation results

All operations were completed under budget. Gas production was resumed from each well immediately after operations were completed, without start up problems.

The potential deliverability rate of Limestone 22 increased by 110,000 cu m/day of raw gas, or 75,000 cu m/day of sales gas. The potential deliverability rate of Limestone 2 increased by 90,000 cu m/day of raw gas, or 78,000 cu m/day of sales gas.

With the regained access to the Devonian formation, the potential deliverability rate of Limestone 12 increased by 1.195 million cu m/day of raw gas, or 720,000 cu m/day of sales gas. Since the initial production, which paid out the cost of this operation in less than 1 month, sulfur precipitation and deposition have complicated the ongoing production of this well.

Overall, considering back-out of gas production from other wells in the field, these three operations have contributed a gain of approximately 350,000 cu m/day of sales gas.

Snubbing operations on sour gas wells can be used to realize additional commingling opportunities in Limestone and other Shell Canada properties. Snubbing has also been used in the completion of a number of Shell Canada's horizontal oil wells and may be used in the future in conjunction with underbalanced drilling to complete horizontal sour gas wells.

In summary, snubbing operations on sour gas wells can be conducted safely with adequate planning, training, and attention to safety issues.

Snubbing operations on low-pressure sour gas wells can permit certain workover activities, such as commingling, without formation impairment or difficulties returning the well to production associated with conventional well control techniques.

The use of a nitrogen purge and blanket in the well during snubbing operations contributed to the safety of the operation and the confidence of the crews.

Acknowledgment

The authors would like to thank Shell Canada Ltd. for permission to publish this article. The authors extend a special thanks to the crews at VC Pressure Control, Drive Well Servicing, and Standard Safety who made this work possible.

References

1. "Equipment Requirements for Safer Snubbing," World Oil, December 1988.

2. "ID 90-1: Completion and Servicing of Sour Wells," Energy Resources Conservation Board, Calgary, June 1990.

3. "Completing and Servicing Critical Sour Wells," Alberta Recommended Practices, Vol. 2, April 1989.

4. "Safer Snubbing Depends on Proper Prejob Calculations," World Oil, October 1988.

The Authors