RESIN SALVAGES GRAVEL PACK IN OFFSHORE WELL

C. Patrick McInturff
Ryder Scott Co.
Houston

Richard Rowe
Nerco Oil & Gas Inc.
Houston

Travis Cavender
Otis Engineering Corp.
Houston

Joe Murphey
Halliburton Services
Duncan, Okla.

A failed gravel pack in an offshore well was salvaged by applying furan resin for near-well bore sand consolidation. This treatment avoided a $1.3 million workover to regravel pack the well.

The application differed from traditional sand consolidation in that:

• The gravel-pack screen annulus was consolidated in place.

• A relatively long interval was successfully treated by reciprocating coiled tubing throughout the treatment.

Union Texas Petroleum Corp.'s well Vermilion 237 No. A-2 was originally completed as a single completion with a selective alternate, or "stack pack." Two reservoirs were gravel packed individually with the upper sand being blanked off with an isolation string (Fig. 1).

The lower zone watered out in April 1990 and was shut off by setting a plug in a landing nipple in the isolation string (Fig. 2a). The upper zone was accessed with a wire line tubing punch to perforate the isolation string.

Gas production following the June 1990 workover was more than 14 MMcfd. But after an acid stimulation treatment, the well began to produce sand. Flow rates were reduced to 2.5 MMcfd to avoid excessive sand production.

After the resin repair in November 1990, the well flowed 13 MMcfd with no sand production. Table 1 lists significant well data.

THE FIELD

The Vermilion 226/237 field is located approximately 70 miles south of the Louisiana coast in 122 ft of water. Five of 6 wells drilled were completed on Block 226, and 7 of 10 wells were completed on Block 237. The average production for 1990 was 120 MMcfd and 632 bbl of condensate/day from 12 completions.

Union Texas operated in a 5,000-acre joint development area encompassing this field, with a 34.92% working interest. In May 1991, Nerco Oil & Gas Inc. purchased this and other Gulf of Mexico properties from Union Texas.

The two primary Pliocene pay sands in this field consist of the Buliminella 1 at approximately 11,500 ft and the Basal Nebraskan at approximately 10,000 ft. Blocks 226 and 237 are productive in both reservoirs, which are structural closures upthrown against a regional fault system.

OPERATIONS

Once sand production began, a remedial operation to replace the gravel-pack screen was estimated at $1.3 million or 15 times the estimates for repair by resin. The excessive cost for a rig workover and the fact that additional completions existed in the same reservoir made sand consolidation the logical choice.

A 200-ft class liftboat with coiled tubing and nitrogen units aboard was preloaded and moved into position. The outline of the planned procedure was:

• Rig up nitrogen (N2) and 1-in. coiled tubing.

• Test all surface equipment to 5,000 psi.

• Pickle coiled tubing with 250-gal 15% hydrochloric (HCl) acid plus acid inhibitor and displace with 12 bbl 2% potassium chloride (KCl) containing 35 lb pH neutralizer.

• Run coiled tubing in hole and wash down to plugged-back TD at 11,499 ft. Use filtered 2% KCl water throughout washing operations. Foam, if necessary.

• With end of coiled tubing positioned across perforated interval, spot and squeeze away at 1/4-1/2 bbl/min the treatment consisting of 2,750 gal of 15% sodium chloride (NaCl) water containing 0.25% surfactant and 600 scf/bbl N2; 1,060 gal externally catalyzed furan resin containing 600 scf/bbl N2; 1,000 gal of 15% NaCl water containing 0.25% surfactant and 600 scf/bbl N2; and 3,500 gal of 10% HCl with catalyst mixed in NaCl water containing 0.25% surfactant, 0.3% acid inhibitor, and 600 scf/bbl N2

• Displace coiled tubing with filtered 2% KCl water (12 bbl).

• Shut in well for 8-12 hr while resin cures.

• Resume production at 4 MMcfd until load water is recovered.

However, the coiled tubing (furnished by a third party vendor) parted after placement of the resin.

The well was killed with brine and the parted tubing was fished from the well. Since the resin used was externally catalyzed, the 40-hr delay resulting from the fishing job had no effect on the resin.

When operations resumed, the catalyst was overflushed through the gravel pack and consolidation occurred as planned. The actual job was as follows:

• Day 1: Preloaded jack up rig arrived on location. Rig jacked up in place. Coiled tubing rigged up. Started pressure test.

• Day 2: Pressure tested to 5,000 psi. Ran in hole to 9,810 ft. Stripper on injection head blew out. Stripper replaced, continued in hole. Pumped 2,750 gal 15% NaCl water with 0.25% surfactant and 600 scf/bbl N2. Pumped 1,060 gal resin containing 600 scf/bbl N2. Followed with 1,000 gal NaCl water with 0.25% surfactant and 600 scf/bbl N2. Pulled up off bottom. Discovered coiled tubing had parted. Went in hole and found the tubing below the stripper.

• Day 3: Mixed and pumped 65 bbl of NaCl water at 1/4 bbl/min and 200 psi down coiled tubing to kill well. After well was dead, went in hole and caught fish at 28 ft. Removed injector head and made cut. Well came in, everything secure. Pulled out of hole. Pulled coiled tubing out of head and swapped out reels. Rigged up new coil. Went in hole to pump acid.

• Day 4: Pressure tested new coiled tubing. Ran coiled tubing in hole to bottom. Pumped 3,500 gal 10% HCl with catalyst. Displaced with 2% KCl water. Pulled out of hole. Rigged down.

Fig. 2 shows the stages of the treatment. N2 was commingled with all the injected fluids in this treatment. Nonreactive and immiscible with the other fluids, the addition of N2 leads to the formation of a short-lived, volume-expanding foam.

The foam acts as a diverter to enhance uniform placement of the treating fluid. In Fig. 2b, the saltwater preflush has entered the screen and exited casing perforations to contact formation sand. In Fig. 2c, resin has been pumped and is coating the sand. The coiled tubing has been reciprocated across the screen interval to direct the fluid at the borehole wall (on longer intervals, a special nozzle can be attached to the end of the coiled tubing to optimize fluid flow direction).

The saltwater spacer slug and the catalyst have been pumped in Fig. 2d, hardening the resin-coated gravel pack and forming a permeable but solid sand filter. A final brine flush is injected to enhance displacement of the acid catalyst. Typically, such sand packs have 85-90% of the original permeability.

The set resin is resistant to acids, except hydrofluoric (HF), brines, alkalies, and other common well treating fluids. Laboratory tests on the durability of sand-consolidation resin systems show that furan resins demonstrate stability and retain high strength when subjected to damaging fluids.

Brine, considered to be more damaging than oil to the stability of resin-consolidated sand, was selected as the test fluid. Field experience with furan resin overflush treatments shows no indication of resin consolidation impairment where brine has been produced. 1

THE RESIN

The resin system used in the screen repair was a water-compatible, furan resin catalyzed by overflushing with acid. Long noted for high-temperature stability, the furan resins have been widely used as foundry core resin binders. 2

As described in the placement procedure, NaCl water is placed ahead of the resin and pumped between the resin and catalyst. The leading load of salt water helps prepare sand surfaces to provide a site for chemical reaction needed for the resin to absorb on the sand.

A notable benefit of externally catalyzed resin in sand-packing treatments is that it has been possible to reverse circulate excess coated sand from the well bore and then repack the well before injecting the catalyst because the resin does not set until contacted by acid. 2

That particular element proved especially fortunate in the Union Texas well where the fishing job required a 40-hr delay before catalyzing. The tail-in load of salt water (the spacer) separates resin from catalyst so that no partial reaction is started until resin is properly placed. The salt water also begins removal of excess resin from pore spaces, flushing the resin further into the formation.

Traditionally, furan resin has been used in sand-control treatments both to consolidate formation sand in situ and to precoat sand at the surface before pumping downhole. Extra resin has normally been injected after washing out the excess pack sand and before pumping the catalyst to consolidate a portion of the formation sand adjacent to the pack sand.

This particular treatment was unusual in that large-grained pack sand covering a 32-ft perforated interval was treated in place. An average radius of over 3 ft may be expected from in situ consolidations of this kind. 1 2

A similar resin system has been used by Union Texas to repair a failed gravel pack screen in an oil reservoir. That well was a dual completion in which two reservoirs were gravel packed individually and produced simultaneously through separate production strings.

That particular resin system used an oil-based preflush, spacer, and catalyst to activate the resin. The zone treated was the short-string gravel pack which has the long-string isolation tubing extending through the failed screen. For that reason, coiled tubing could not be reciprocated across the interval during the treating procedure and was left stationary at the end of the short-string. That well also continues to produce sand free.

Sand production through gravel-pack screens has become a common problem in the oil and gas industry. The use of resin gives an economical option to rectify sand problems while maintaining a full-open screen assembly. Candidates for this procedure include wells with excessive sand production problems with the following conditions:

• Minimal well bore ID across the affected area (small through-tubing screen assemblies can effectively correct screen failures; however, they also create very high pressure drops).

• Between 60 and 400 F. static bottomhole temperature.

• Bottomhole pressure gradient of less than 11.6 ppg. (Calcium chloride is the heaviest compatible brine.)

ACKNOWLEDGMENT

The authors thank the management of Nerco Oil & Gas Inc., Otis Engineering Corp., and Halliburton Services for permission to publish this work.

REFERENCES

1. Rensvold, R.F., "Sand Consolidation Resins--Their Stability in Hot Brine," Paper No. SPE 10653, Formation Damage Control Symposium, Lafayette, La., 1982.

   Murphey, J.R., Bila, V.J., and Totty, K., "Sand Consolidation Systems Placed with Water," Paper No. SPE 5031, SPE/AIME Annual Fall Meeting, Houston, Oct. 6-9, 1974.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.