Gordon RJ Mackenzie
Baker Oil Tools
Two recent well intervention projects in two sectors of the North Sea used the flexibility of an inflatable-style packing element. Both jobs also benefited from a new, patent-pending fluid separation device to address two very different challenges.
Inflatable packing element technology has been used in the global oil and gas industry for over seven decades. The main differentiator between inflatable and more traditional packing element technology is the ability of the inflatable element to expand to as much as 300% of its original run-in outer diameter. This expansion ability allows inflatable packing elements to pass through wellbore restrictions and still provide a seal in the larger inner diameter below these restrictions. The restrictions may be planned, as with a seating nipple in the production completion above the pipe in which the intervention application is required, or unplanned, such as collapsed tubing or pipe.
The main differentiator between inflatable and more traditional packing element technology is the ability of the inflatable element to expand to as much as 300% of its original run-in outer diameter.
The other main application where inflatable technology has offered an attractive alternative is in open-hole conditions where the unique sealing characteristics of the inflatable packing element can out-perform more traditional elements.
The smaller through-tubing style inflatable elements, first pioneered in the mid 1980s, were used in both of these wells. These smaller elements allow the operator to perform standard workover operations in the production casing or liner without having to pull the completion from the wellbore and make it possible to workover the well in a "live" condition.
Oil to gas conversion
The first of these interventions was conducted in the Dutch sector of the North Sea for Nederlandse Aardolie Maatschappij, a 50/50 Shell-operated joint venture with ExxonMobil, in February and was planned and operated out of Ijmuiden, Holland. The well originally had been completed as an oil producer with 4.50-in., 12.6-lb/ft tubing above a 7-in., 32-lb/ft liner. The well began producing with a very high watercut and a high gas/oil ratio.
Production became increasingly difficult to maintain due to the level of water being produced with the hydrocarbons. Finding it impossible to bring the well back on line following a plant shutdown, NAM decided to re-enter the well and perforate the upper gas layer above the oil-bearing zone. Similar problems, however, occurred following another plant shutdown, with only a small amount of gas production and slugging of fluids. At this point, the operator decided to shut off the lower oil-producing zone and convert to a full gas-producing well.
The original completion had a "bottleneck" type of configuration, with its minimum restriction of 3.688 in. being a 4.50-in. landing nipple above a 6.094-in.-inside diameter liner. This configuration precluded using tools with conventional type packing ele- ments to provide a bridge plug. NAM decided to attempt a solution using a bridge plug with an inflatable packing element. A ret-rievable rather than perma- nent bridge plug was chosen to provide the option of re-positioning in the heel of the well should the desired results not be achieved.
Coiled tubing (CT) was selected as the conveyance method to prevent having to kill the well. The deviation of the well at up to 90° negated the option of conveying and setting inflatable bridge plugs on electric wireline.
The final consideration was the methodology for setting the inflatable retrievable bridge plug. Because it is a differentially set, high-expansion tool, a controlled fluid setting must be used to expand and pressurize the inflatable element. In this particular well, a low bottom-hole pressure (2,248 psi) at setting depth would result in an overbalance of 1,675 psi at the plug at the time of setting if CT was used with a full column of water. This type of overbalance posed a risk of leading to an uncontrolled initial inflation of the bridge plug and what is referred to as a "soft-set."
The workover team deployed a new patent-pending reservoir system for running CT-set inflatable devices in such underbalanced conditions. The reservoir system allows for a pre-determined volume of suitable element inflation fluid (glycol/water) to be pre-loaded at surface and then transported to depth along with the retrievable bridge plug. Once at setting depth, nitrogen (N2) is used in the CT as the medium to create the differential pressure required to set the bridge plug. However, with the fluid separator reservoir in place, the N2 is used to "push" the reservoir fluid into the inflatable element.
The reservoir system incorporates a separator device that creates a physical barrier between the preloaded inflation fluid and the displacing fluid (N2). This separator device is highly effective when running in highly deviated to horizontal wellbores because it does not allow for the inflation fluid to separate on the low side and leave a channel for the nitrogen to reach the inflatable element itself. Once the inflatable tool has been set and disconnected from the reservoir system, further pumping displaces any excess inflation fluid (a 25% excess is used). An observed increase in pressure confirms that the fluid has been displaced. Increasing surface pressure at this point activates a circulating valve, which enables any further CT operations such as cementing to be conducted.
A 3-in.-outside diameter (OD) element was used for this application. Pre-job engineering was performed to select the optimum operating requirements of the plug for the anticipated well conditions after isolating of the lower zone. Once set, the inflatable plug would be capable of supporting a 4,517-psi applied differential pressure or up to a 2,917 psi draw-down or pressure reduction across the bridge plug.
The inflatable bridge plug was run into the hole with a standard CT bottom-hole assembly (BHA). A nipple profile locator was used to correlate the CT to a known depth on the 4.5-in. landing nipple at 9,035 ft. The retrievable bridge plug was positioned and set at 10,335 ft MD. The job proceeded with a time frame of 25 hours between making up the CT connector prior to running the job and removing the CT connector after retrieving the setting BHA from the well.
After installing the inflatable bridge plug above the lower oil zone, all the fluids (water and oil) were shut off. The well was put back on production at a maximum plant fill capacity of 7.608 MMcf/d.
The second application of an inflatable retrievable bridge plug with this system took place in the UK sector of the North Sea in April. Shell Expro planned to sidetrack an existing wellbore using through-tubing rotary drilling methodology. Before setting the through-tubing whipstock for the sidetrack, however, they needed to permanently isolate the existing main bore of the well.
The well had been completed for production with 5.5-in., 17-lb/ft L-80 tubing above a 7-in. 29-lb/ft liner. This completion included a minimum restriction through a 4.313-in. landing nipple. The operator decided to plug back the existing 7-in. wellbore using an inflatable retrievable bridge plug.
The objective was to use a 3.375-in. through-tubing inflatable retrievable bridge plug, conveyed on 2.875-in. Hydril 533 tubing. The plug was to be set at 10,200 ft MD (8,500 ft TVD) in 6.184-in. ID. The 3.375-in. OD plug would support an applied differential pressure of 5,934 psi and a reduction in pressure across the plug of up to 4,384 psi.
Minimizing debris problems
The system was selected as part of the tubing BHA. The reason was not to control the staging of element inflation pressure, but rather to minimize the risk of fouling the inflation mechanics from debris in the running string. On previous occasions when running small OD inflatables on threaded tubulars, problems had been encountered from debris generated by dropping a setting ball to actuate the setting processes. Similar debris problems had arisen from the tubing filling with wellbore fluid while tripping in the hole.
In this application, the fluid separator reservoir assembly was used to positively separate the tubing and wellbore fluids from one another. The BHA incorporated a ball-operated hydraulic release tool, a pressure-operated circulating valve, an inflation valve, the reservoir system and the plug and hydraulic disconnect running tool. The system was run in the hole with depth control correlation controlled by the tubing tally. The plug was positioned at a setting depth of 10,200 ft MD and a deviation greater than 90°. The tubing running string was allowed to fill while tripping into the hole by means of the inflation valve. To set the plug, a 0.50-in. setting ball was dropped to its seat in the inflation valve, and further applied surface tubing pressure acted on top of the separator system within the fluid reservoir. This in turn forced the clean, pre-loaded fluid (4.92 gal including a 25% excess) to fill, pressurize, and disconnect from the bridge plug. Once disconnected, surface pumping was continued until the excess fluid was displaced and the pressure-operated sleeve valve opened, allowing for further fluid circulation and preventing a "wet" pipe trip on the way out of the hole.
The isolation procedure from picking up the BHA to breaking it down at surface was completed within 36 hours. With the main bore of the well isolated, Shell Expro was able to continue with sidetracking the well through tubing.