Homer G. Smith
Homco International Inc.
Houston
After repeated cement squeeze failures, casing patches were successfully used to stop casing leaks in a well operated by Mainland Resources (O.S.) Ltd. in Indonesia.
The Bunyu field, discovered in 1922, has 123 wells drilled with one dry hole in a complex series of channel sands interspersed with shales and coals. About 91 zones have been produced to date. Cumulative production is approximately 80 million bbl of oil. Although most wells produce with high water cuts, pressure maintenance and improving the sweep efficiencies across the channels by careful placement of injection points can substantially improve recovery.
Mainland Resources (O.S.) Ltd. is a secondary recovery contractor that obtained the rights of evaluating, installing, and operating the waterflood project in the Bunyu field. The field is on the relatively isolated Bunyu Island off the east coast of Kalimantan in Indonesia. Initial pilot installation work commenced in July 1987 in several zones.
Well B-49, drilled in 1973, was proposed as a producer well for the 0-95 zone water flood pilot. This well was chosen because of its location within the desired pilot area, and because the drill stem tests, in July 1985, showed the well as a desirable producer for secondary recovery.
The well had been abandoned in the zone at uneconomic primary rates.
This testing was on natural flow, and the well was originally completed to produce in this manner. To save early production cost, installation of artificial lift was planned for a later date.
Water cuts were expected to rise to 90% and above sometime after production started, due to the injection already initiated into this reservoir. But high initial water ratios during production testing reduced the well's capacity to produce on natural flow sooner than expected.
Because large volumes of water would be produced to maintain economic oil rates and with other considerations, including the capacity limitations of the existing gas lift system, electric submersible pumps (ESP) were chosen as the preferred lift method.
The ESP was installed without difficulty, and the well was placed on production. Similar to most oil wells in Bunyu, many zones in well B49 had been perforated previously for production, and cement squeezed when the zones were abandoned. In general, good primary cementing in Bunyu is very difficult to obtain and is generally poor, especially in the old wells such as B-49.
Apparently because of the combination of poor primary cement and "incompetent" (unconsolidated) sandstones, breakdown of primary cement and shallow squeezes occur when subjected to pressure drawdowns of ESP'S.
The previous testing in 1985 needed difficult squeeze work to prepare the well. Those jobs were examined closely in an effort to improve upon the methods used. Although great care was taken to ensure good squeeze jobs, including testing various cement mixtures and placement techniques (different methods of hesitation squeezing, pump rates, etc.), some squeezes still required multiple jobs with increasing costs to obtain the required casing test results.
Much was learned regarding the formation competence and problems associated with utilizing the old wells.
REPAIR ALTERNATIVES
Additional pump testing resulted in additional breakdowns, finally requiring temporary abandonment for safety reasons. It was apparent that additional squeezing of these perforations would most likely be unsuccessful and not cost-effective. An evaluation was made to determine the optimum method of repair to bring the well back on production.
Alternatives included:
- A complete resqueezing program with a special epoxy-based resin cement which needed to be designed and ordered from the U.S.
- Setting approximately 160 ft of casing patches, which also at the time needed to be ordered with setting tools and a serviceman stationed in Indonesia
- Isolating the bad section of pipe with a special packer, complete with electrical feed-through and individual vent line to surface,
- The possibility of setting a 4 1/2-in. liner (5 1/2-in. pipe was not available) through the bad casing sections, which would then require a different lift mechanism, as submersible pumps were not available small enough to fit this size casing,
- Drilling and completing a completely new twin well on location, a rather expensive prospect.
After evaluating all factors, such as cost, logistics, reliability, and production rates required, the casing patch alternative looked best. Although these were new in Indonesia, the one other operator with experience with the casing patch had been very satisfied with the cost effectiveness service, and results.
Patch materials on hand could also be used in the other pilots that were being installed, thereby reducing future workover and ultimate project costs.
Casing patches will not improve zone isolation behind the pipe. But it was felt that if the differential pressure across a cement squeeze into the casing could be borne by the patch, the cement could maintain zonal isolation behind pipe (casing-formation annulus) with a much lower vertical (formation-to-formation) pressure differential than horizontally (formation-to-casing) across the old perforations.
The patch materials and setting tool were ordered and preparations made to perform a nine-patch casing repair operation.
SETTING PATCHES
The patches were set using the setting tool, circulating break-out sub and drill pipe system. A marker sub was located above the setting tool to position the first and lowest patch accurately over the perforations. Marker sub depth was located with a wire line gamma ray and CCL.
The deepest patch was set first. The first 5 ft were hydraulically set using 2,500 psi and then the remaining length set by straight rig pull of 50,000 to 60,000 lbs. A bar was dropped to break the circulating sub plugs and the tool was pulled out of the hole.
The second patch was rigged up and lowered into the hole and the first patch tagged. It was then pulled up hole until it was located opposite the second set of perforations to be patched. The wire line gamma ray and CCL was run again to verify the location. The second patch was then set using the same procedures as the first.
In the same manner, the remaining seven patches were set. The overall time to set the nine patches was 104 hr.
RESULTS
No downtime due to squeeze breakdown or indications of casing leaks occurred during the first 7 months on continuous production. The well pumped a stabilized 2,250 bbl of fluid/day, almost one-third higher than the rates that previously caused breakdowns.
The patches were exposed to differential pressures of up to 700 psi.
Although some of the rig work prior to patching would have been required for various reasons including pump testing, it is estimated that 65% of the rig and associated cementing costs were solely attributable to repair of the cement breakdowns.
Fortunately, even though the ESP was exposed to gas slugging, repeated low amperage shutdowns, cement, and formation sand, the ESP did not require changing out; otherwise the cost of the cement breakdowns would have been even higher.
The total cost of the patch work was approximately $70,000, including rig time and reflecting the high logistics costs involved in this remote area. This well was an exceptional case due to the many old perforations, and the fact that this was the first producer completed.
However, eliminating similar completion problems on future wells by utilizing casing patches is expected to provide savings of up to $60,000 per producer. Savings are based on rig work, with workover time reduced by approximately 4 days.
The casing patch has become a standard item in Mainland's completion programs, significantly reducing the risk associated with remedial cementing in high drawdown applications.
HOW THE PATCH WORKS
The patch is set in the casing over perforations or other type leaks. It forms a thin wall cylinder in the casing, reducing the internal diameter by only 0.31 in., thus allowing packers or other remedia-type operations to pass through and perform other necessary functions. The patch seals off the leaks and is strong enough to withstand both internal and external pressures.
The patch is composed of a long, thin metal tube, corrugated in an 8 or 10 pointed star shape (Fig. 3). This shape reduces the outside diameter so it can be run downhole.
The outside is covered with a layer of glass cloth or other material depending on the application.
As the patch is lowered into the casing, a layer of special epoxy coating is applied.
The coating has a gel life of 608 hr before it hardens.
They epoxy and glass cloth form a permanent seal between the casing and patch when it hardens. The patch length is designed to cover the leaking area and extend approximately 8 ft on each end into good casing.
The patch is held in place by compressive stresses. The setting operation forces the patch to conform to the casing ID and puts the patch in compression. After the first 3 to 4 ft are set, the patch is firmly anchored to the casing and will not move up or down hole.
SETTING TOOL
The setting tool is a series of hydraulic cylinders actuated by pump pressure (Fig. 3). The cylinder rod extends below the setting tool in the opened position.
Attached to the rod are extension rods long enough to accommodate the length of the patch.
To these are attached a solid cone wedge and a powerful flexible collet (Fig. 4). The patch is installed over the extension rods and between the cone at bottom and a liner stop at the top.
On top of the hydraulic cylinders various tools are attached, determined by the type operation. Combinations of tools can be holddown, bumper sub, slide valve and tubing or breakout plug-type circulating valve, and drill pipe.
SETTING OPERATIONS
The procedures and operations to set a standard patch are as follows. The leak depth is located using packers or other type tools. A casing scraper is run to clean the scale, cement, etc. out of the section of casing to be patched.
A gauge ring is run to verify that the casing is not undersized. The setting tools and patch are assembled and positioned above the well bore.
A two part epoxy is mixed and as the assembled tool is lowered it is applied to the fiber glass cloth on the patch. The assembly is then run downhole and centered over the leak. The slide valve allows the tubing to fill up going down hole, or if the circulating break off plug sub is used the pipe is filled up every two or three stands.
When positioned over the leak, the slide valve is closed and pump pressure is applied. This activates the hydraulic cylinders which then pull the cone and collet into the bottom of the patch and sets the bottom 5 ft.
As this happens the star shaped patch is forced to conform to casing ID. The epoxy forms a cylindrical seal between the casing and patch and is also squeezed into the defects and leaks occurring in the casing.
After the first 5 ft of patch is set, the pump pressure is released and the working string raised 5 ft. This strokes the tool open, and it is ready to set an additional 5-ft hydraulically.
A second method of setting the remaining patch is a straight pull on the working string. The patch is anchored to the casing after the first 5 ft are set so either method can be used. Either system allows the working string to drain while coming out of the hole.
Additional patches can then be run or other operations begun. If the patch is to be pressure tested, it can be done after the epoxy hardens, 24 hr from the time it was mixed.
GENERAL INFORMATION
Patches have been set worldwide from the Bradenhead to 13,000 ft. They have been used to patch perforations, splits, collar leaks, cementing valves, corrosion, parted casing and holes caused by milling or drilling. Various types of oil, gas, storage, disposal, water, and low fluid level wells have all been patched.
Pressure ratings depend on the type of leak, size of hole, and size of casing. The internal pressure rating over perforations is equal to the maximum casing pressure limit.
Large holes, splits, and parted casing have a lower rating depending on the size of the hole and casing size.
External pressure ratings of 3,500 psi are obtainable using heavy duty materials. The standard temperature rating is 325 F. Special coatings are available to 630 F.
Patches have been set in one continuous piece 150 ft long. Special metals are being used for highly corrosive wells.
ACKNOWLEDGMENT
The author wishes to thank Steve Jacobs, Mainland Resources (O.S.) Ltd. and Scott Davis, A-1 Bit & Tool Co. for their input and cooperation in writing this article.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
