ACID TREATMENT REMOVES ZINC SULFIDE SCALE RESTRICTION

Kim Biggs
Kerr McGee Corp.
Lafayette, La.

Dave Allison
Otis Engineering Corp.
Lafayette, La.

William G.F. Ford
Halliburton Services
Duncan, Okla.

Removal of zinc sulfide (ZnS) scale with acid restored an offshore Louisiana well's production to original rates.

The zinc sulfide scale was determined to be in the near well bore area. The selected acid had been proven to control iron sulfide (FeS) scales in sour wells without causing harm to surface production equipment, tubing, and other downhole hardware.

The successful removal of the blockage re-established previous production rates with a 105% increase in flowing tubing pressure.

BACKGROUND

On production for a number of months, a high rate, high pressure offshore well was experiencing unusually rapid pressure and rate declines.

The well produces from a middle Miocene sand and is located in the Main Pass area, offshore Louisiana.

Investigative wire line work, in early March 1991, determined that a restriction was present at 11,032 ft where a 2 1/16-in. gravel-pack screen and 2 3/8-in. blank tubing were connected (Fig. 1). The restriction was such that a 1/4 in. tool string was unsuccessful in passing the reduced cross section.

A small sample of the restrictive material was obtained during the wire line operations. The well was subsequently shut in while a laboratory analysis determined that zinc sulfide was the major component of the obstruction.

The presence of zinc sulfide is explained by the occasional production of up to 2 ppm of hydrogen sulfide (H2S) gas, and the loss of over 500 bbl of 17.2 ppg zinc bromide completion fluid to the reservoir.

CONSIDERATIONS

Considerations for the remedial treatment included the following:

Perform treatment in safest manner
Avoid damage to well bore hardware and surface facilities
Avoid damage to the reservoir
Use readily available products.

The selected acid was originally developed to remove iron sulfide scales from sour gas wells while protecting downhole hardware.1 2 The treatment consists of 15% HC1 (hydrochloric acid), NTA (nitrilotriacetic acid), Egmbe (ethylene glycol monobutyl ether), sulfide modifier, and surfactant-suspending agent. A high quality corrosion inhibitor should be included.

This combination allows for the control of both iron and elemental sulfur precipitation in a sour environment.

Caution must be exercised when attempting to remove sulfide scales with HC1 acid. The mechanical properties of all metals exposed to the acid and resulting byproducts, such as H2S, must be scrutinized.

Many materials used in a producing environment are susceptible to chloride stress cracking as well as sulfide stress cracking. Conventional coiled tubing and high alloy stainless steels can be severely damaged by H2S and chloride attack as documented in previously published works.1 2

Using a high quality corrosion inhibitor will mitigate some detrimental effects of the acid.

SULFIDE SCALE

H2S combines with formation waters containing metals such as iron, zinc, and lead to form sulfide scale. Additionally, sulfide scale can be created when H2S reacts with the iron compounds in the well bore's hardware. The resulting scale can be deposited in the near well bore area, or within perforations, tubulars, and surface equipment.

The iron scale is usually soluble in a hydrochloric acid solution. The reaction equation is as follows:

2HC1 + FeSH2S + FeC12

This reaction will reverse itself as the pH rises and exceeds 1.9. If the reaction is not complete (as a result of dissolved ferric iron), elemental sulfur will precipitate and be deposited with the reformed sulfide scale.

As mentioned, the Main Pass well had zinc sulfide rather than iron sulfide scale. The chemistry and associated problems remain the same for ZnS scale as was noted for FeS scale. The reaction equation is as follows:

2HC1+ZnSH2S+ZnC12

DESIGN

The key to a successful treatment is complete and effective contact of the treating acid with the zinc sulfide scale. A number of refinements were included to avoid operational problems while simultaneously providing for an effective treatment.

Coiled tubing was considered for placement of the treating acid. The tubing permits spotting fluids to the bottom of the well and lets the fluids be washed down through the screen assembly. However, if the perforations contain significant volumes of scale deposits, coiled tubing could limit the injection pressure to 5,000 psi (the normal working limitation of the tubing).

In the worst case scenario, injection pressures were expected to approach 10,000 psi or higher. Therefore, coiled tubing was not acceptable. Instead, the treatment was pumped directly down the production tubing as follows:

Stage A: 500 gal 3% ammonium chloride (NHC1)
Stage B: 500 gal 15% HC1 (containing 5% enhanced Egmbe, 1% corrosion inhibitor, and 0.5% surfactant suspending agent)
Stage C: 2,000 gal 15% sour well-treating acid (containing 5% enhanced Egmbe, 1% corrosion inhibitor, 0.5% surfactant-suspending agent, sulfide modifier, and NTA)
Stage D: 3,500 gal 3% ammonium chloride displacement fluid

STAGE DESCRIPTION

Stage A's goals were to:

Permit the surface equipment and wellhead to be pressure tested to 10,000 psi
Determine whether or not the well bore gas could be compressed and forced back into the reservoir, that is, whether some perforations were unrestricted.

If higher than anticipated pressures were encountered, a wellhead isolation tool would enable treatment pressures up to 15,000 psi.

Stage B was to remove any accumulated scale deposits in the tubing above the known restriction. This stage made available the full volume of treating acid for reacting with the zinc sulfide scale at the reservoir and gravel-pack assembly.

Stage C was the treatment, based on a volume of 100 gal/ft of interval.

Stage D displaced the treatment. No overflush was planned because of the risk for carrying the treating fluid, now laden with reacted products, deep into the reservoir.

TREATMENT

The treatment was performed from a lift boat that was positioned upwind next to the offshore structure.

While the treating lines were assembled and connected to the well, a safety meeting ensured that the crews were fully aware of:

Location and usage of safety equipment
Potential hazards associated with high-pressure pumping
Potential for high H2S levels in the treatment flow back
Safe handling of stimulation fluids.

After pressure testing the treating lines, the well was opened with 7,300 psi on surface. The decisive first stage, Stage A, was pumped with no indications that the perforations were completely plugged. It was decided to continue with the treatment, and Stages B, C, and D were then bullheaded into the well.

The hydrostatic pressure of the fluids helped lower the required pump-in pressure.

When the calculated volume for placing Stage B at the perforations was reached, the pump-in rate was reduced to 0.5 bbl/min. This reduced rate permitted longer contact time between the treating acid and the zinc sulfide scale and increased the efficiency of the treating acid.

A 600 psi reduction in the injection pressure was observed at the surface. This indicated that the restriction was being removed.

The difference in hydrostatic pressure between the tubing full of treating fluids and the tubing full of displacement fluid (3% NHC1) was 260 psi.

Taking this difference into account, the actual total pressure reduction was closer to 860 psi.

After completing the pumping schedule, the well was temporarily shut in. The treating lines were removed and the jack up boat was lowered and moved off location before production commenced.

RESULTS

The well readily unloaded when opened to production. The initial production tests indicated that the rates and flowing tubing pressures had returned to the previous "undamaged" levels. The maximum H2S level recorded during initial cleanup was 10 ppm. This was easily handled within the production system.

Long-term production rates will be monitored for evidence of a return of the zinc sulfide scale.

After successful removal of the restriction, we concluded that the sour well acid treatment effectively removed the zinc sulfide scale. To date, no adverse reactions to the treatment have been noted.

ACKNOWLEDGMENTS

We thank Kerr McGee Corp., Otis Engineering Corp., and Halliburton Services for permission to publish this article.

REFERENCES

Walker, M., Dill, W., and Besler, M., "Iron-Control Additives Improve Acidizing," OGJ, July 24, 1989, pp. 53 56.
WaLker, M.L., Dill, W. R., and McFatridge, D.G., "Iron Control in West Texas Sour Gas Wells Provides Sustained Production Increase," Paper No. SPE 20122, Permian Basin Oil and Gas Recovery Conference, Midland, Tex., Mar. 8-9, 1990.