Gels, monomer solutions fix pinhole casing leaks

Prentice Creel
Halliburton Energy Services Inc.
Odessa, Tex.

Ron Crook
Halliburton Energy Services Inc.
Duncan, Okla.

Sodium silicate gel and in situ polymerizing monomer (IPM) solutions have had nearly 100% success in repairing pinhole casing leaks.

These methods are an alternative to small-particle cement squeeze jobs and can be used in both producing and injection wells. The particles in small-particle or find-grind cement average 5 microns in diameter compared to the 50 micron particles in Portland cement.

Repairs not only help satisfy regulatory requirements but also reduce possible related casing repair costs such as during drillouts, repeated cement squeezes, and workovers.

If casing leaks in injection wells are unsuccessfully squeezed and fail regulatory testing, the operator may be fined and the wells may have to be plugged and abandoned.

Casing leak repair

Casing leaks can occur in designated freshwater zones, across intervals with poor original primary cement jobs, or in intervals with a high water influx. Unwanted water influx can cause formation damage, production loss, and increase tubular and surface equipment corrosion.

These leaks are often too small for small-particle cement to be placed outside the casing; therefore, small-particle cement cannot provide a barrier to the water influx or allow zonal isolation.

The occurrence of small pressure drops (?50-150 psi/hr) presents additional difficulties in placing fine-grind cements.

Filtrate from fine-grind cements is squeezed through the leaks, causing a node of cement particles to build up on the casing face where the leaks occur. Upon drillout, pressure tests may fail and the leaks may reoccur.

Conventional cement slurries have proven less than 10% effective in squeezing pinhole leaks and generally require casing perforations for slurry entry.¹ Fine-grind cement jobs can be successful if casing leaks are large enough to allow sufficient slurry to enter the annulus.

If the casing leaks are small, the cementitious material is not protected from dissolution and deterioration caused by water influx. Also, the success of conventional slurries depends largely on the severity of the casing leak, as indicated by pressure leakoff rates, and the maximum injection rate achievable below maximum pressure restrictions.

If these conditions are outside the capabilities of conventional cement slurries, different methods, such as sodium silicate gels or in situ polymerizing monomers, may be necessary to squeeze off the leaks.

In a solution, sodium silicate gels form particulate solids when in contact with divalent ions, such as calcium (an internal-activating catalyst) or cement.² When the water phase is squeezed into the solution, these particulate solids cause a paste-like material to build up, and it continues building during the squeeze process until it forms a permanent solid.

The strength of this newly formed solid is equal to the final squeeze pressure applied.

In situ polymerizing monomer (IPM) solutions also offer a unique capability for repairing casing pinhole leaks.

When injected, IPM solutions form a right-angle set polymer that allows the solution to generate an extremely resilient material capable of resisting high extrusion pressures.

Sodium silicate

Sodium silicate treatments are now considered an effective means for repairing casing leaks that range from 15 to 500 psi/hr. Because of insufficient pump-in rate, particulate material cannot be placed in such leaks.

Sodium silicate systems have been used in the petroleum industry for over 30 years to modify well profiles, shut-off water coning, and perform other various near well bore and deep-formation treatments.³

In squeezes, sodium silicate particulate accumulates when the material enters a reactive medium (Fig. 1a [108,060 bytes]).

Because of high-pressure leakoff rates, some state regulatory agencies require that only a cement product be used across certain depths for repairing casing leaks. However, some wells offer only a marginal possibility of success for repairing leaks with cement slurries.

Sodium silicate treatments improve the chances for success in wells where cement squeezes have a low success rate.

In these treatments, an internal activator is added to the sodium silicate solution when the solution is injected into a leak in which no external reactions will occur naturally. This internal activator causes the solution to form a particulate at the set time.

When external reactions occur naturally, they will cause the sodium silicate to automatically form a particulate.

A gelled sodium silicate solution loses its water phase when squeezed, forming a paste in the restricted leaking channels (Fig. 1b). When squeezed in a confined area, the sodium silicate component can have extremely high resistance to extrusion pressures.⁴

Sodium silicate squeezes

The sodium silicate squeezes (Table 1 [113,304 bytes]) have maintained pressures from 500 to 2,500 psi on all jobs. These jobs have a 90% first-attempt success rate. Temperatures in the wells ranged from 85 to 190° F. and well depths ranged from 1,300 to 12,900 ft, with pressure falloff of the leaks ranging from 15 to 500 psi/hr.

Operators first spotted the intervals to be squeezed with 250-500 gal of sodium silicate solution. Placement-time parameters determined the solutions' internal set times of 2-4 hr.

High leakoff rates resulted in a successful second attempt on 10% of the wells tested. Typically, 1/4-5 bbl of solution was placed outside the casing. The jobs used between 250 and 1,000 gal of squeeze material.

Injection well repair

In an injection well, three conventional cementing squeezes failed to seal a leak in a critical zone. A state regulatory group authorized one sodium silicate solution squeeze on the well because the solution was intended to be placed permanently.

Regulations required stopping a leak within its critical interval, 400-800 ft, which was believed to be a freshwater zone.

The freshwater zone was considered to be from ground level to 1,250 ft and had a pressure falloff rate of 450 psi/hr from a starting pressure of 500 psi, indicating a leak.

The regulatory requirement stipulated that the operator perform a pressure test in 12 months. If successful, another pressure test should be performed within 2 years with follow-up tests every 3 years thereafter.

Fine-grind cement had failed to seal the leak at this depth in the past, and because of the potential associated costs of further failure, the operator chose a sodium silicate solution.

A 600-psi pressure level was held by the sodium silicate solution because of the compressive strength of the formation surrounding the well at 400-ft. Because of rapid pressure drop, the sodium silicate squeeze was done in two attempts of 750 gal each.

The first attempt caused the pressure to fall from 450 to 150 psi/hr, and pressure did not drop below 350 psi. A 1,000-psi squeeze was reached on the second attempt with a holding pressure of 600 psi, which is higher than the 500 psi required by the 12-hr regulatory test.

Production casing leaks

Sodium silicate solutions successfully stopped leaks in production wells in which pinhole leaks formed because of corrosion and other mechanisms.

Produced water influx through pinhole casing leaks can cause formation damage, loss of production potential, and greatly increase tubular corrosion in wells and on surface equipment. Many of these leaks are so small that even small-particle cement cannot be placed outside of the casing to build a barrier to the water influx or to obtain squeeze integrity.

For economic or practical reasons, such as hydrostatic limitations, many producing wells have exposed intervals above the primary cement top. Once a casing leak develops in these wells, production is typically lost and problems such as water invasion into the producing interval occur.

The casing condition is usually poor because of exposure that caused pitting by forces such as ionic changes.

Placement of a sodium silicate treatment in the annulus is easily achieved even when leaking intervals are difficult to inject into. Previously, operators located the leaks, set retrievable bridge plugs to protect the production zones, and cement-squeezed the leaking interval using cement retainers. When possible, cement was circulated up to the surface to help eliminate future problems.

With this method, casing integrity tended to suffer, annulus sections were heaved-in, and exposed formations experienced hydrostatic restrictions. These problems typically are associated with wells where water crossflow from a shallower zone goes down the annulus into a porous interval that accepts fluid because the hydrostatic pressure is greater than the reservoir pressure.

In the subject wells, most of the casing was old, and damage could occur during drillouts or tool settings. In these wells, sodium silicate solutions successfully stopped leaks and eliminated costly drillouts associated with cementing.

Once placed and after a squeeze attempt, the remaining solution inside the casing is circulated out with the tubing used to spot the solution. Usually, sodium silicate solution squeeze jobs do not require squeeze packers or retainers if casing integrity above the leak is satisfactory.

This helps eliminate the potential for retainer slippage, which can cause holes in the old casings.

Silicate flour

Sodium silicate solutions with either fine sodium silicate flour or course sodium silicate flour added to create a slurry can also squeeze off casing leaks in which a greater test pressure drop-vs.-time is encountered. Statistics are being gathered to allow engineers to gauge the pressure-drop ranges where variations in amounts of silica flour (slurry density) and sizes (fine vs. coarse) may be selected for squeezing off leaks.

Because silica flour is not a factor in set-time development, its use gives additional leakoff blockage by providing surface area on which the squeezed particulate can develop.

IPM treatments

Development of in situ polymerizing monomer for plugging pinhole leaks was based on the tendency of monomers to transform right-angle sets into crosslinked polymers (Fig. 2 [43,066 bytes]). This effect caused engineers to encounter very low injectivity in some wells when injecting formation-sweep modification material. The engineers noted a very high resistance to the extrusion of these set polymers and failure to clear the tubulars of the material plug.

Pressure applied to tubulars with as little as 30 ft of polymer remaining withstood a pressure drop of 6,000 psi without causing polymer extrusion. The method of injecting monomers into the channels, fissures, or other elements causing the pressure reduction provides a right-angle set that leaves a material that can withstand internal and external high-pressure drops (Fig. 1b [108,060 bytes]).

In one example, attempts to repair casing leaks in a CO2-flooded field were ongoing. Usually as many as six attempts were needed to accomplish a pressure test. In one case, the casing still yielded a very slight leakoff (25 psi/hr), and operators attempted to seal the leaks with an IPM.

The IPM was designed to have an internal initiator that would cause the solution to react based on thermally timed conditions. Once a portion of the material was squeezed into the leaks, the well was pressure-tested and squeezed to a holding pressure satisfactory to the operator. The IPM was chosen based on its resistance to CO2, bacterial growth, and acid.

IPM has demonstrated high performance and reliability in a number of projects (Table 2 [117,778 bytes]).

The IPM solution squeeze method has been nearly 100% successful on workovers. The amount of IPM solution placed outside the casings is typically 5-20 bbl of solution with between 5 and 25 bbl of material used. The volume used on the jobs was determined based on the interval length to be squeezed, the leak severity, and the need for the solution to enter the adjacent formation.

Use of these materials to repair pinhole casing leaks can eliminate the need for costly drillouts and repeated cement squeezes, and the reduction in workover time can reduce casing repair cost

References

1. Shryock, S.H., and Slagle, K.A., "Problems Related to Squeeze Cementing," JPT, August 1968, pp. 801-07.
2. Cole, C., and Lindstrom, K., "Well Integrity Maintenance Using Pumpable Sealants," Underground Injection Practices Council International Symposium, New Orleans, May 1987.
3. Dalrymple, D., Sutton, D., and Creel, P.G., "Conformance Control in Oil Recovery," Southwestern Petroleum Short Course, Lubbock, Tex., Apr. 24-25, 1985.
4. Smith, C.W., Pugh, T.D., and Mody, B., "A Special Sealant Process for Subsurface Water," Southwestern Petroleum Short Course, Lubbock, Tex., Apr. 20-21, 1978

The Authors