TWO-STAGE TREATMENT REDUCES WATER/OIL RATIO

Frank Wood, Dwyann Dalrymple
Halliburton Services
Duncan, Okla.

Kenneth McKown
Halliburton Services
Hays, Kan.

Bruce Matthews
Halliburton Services
Wichita, Kan.

A treatment of amphoteric polymer followed by chrome-complexed anionic polyacrylamide has successfully decreased the water/oil (WOR) ratio of wells producing from the Arbuckle dolomite formation in central Kansas.

This technique, the fractured-matrix, water-control (FMWC) treatment, is designed to alter both primary and secondary permeability to water production. In 10 treated wells, the average WOR was reduced by a factor of five (Table 1).

WATER PRODUCTION

The Arbuckle dolomite formation in Kansas is a very prolific oil producer in the lower Ordovician series of the Paleozoic era. As an oilbearing formation, the Arbuckle has good primary (matrix) permeability with excellent secondary permeability in the form of natural fractures.

This secondary permeability, in combination with a strong bottom-water drive mechanism, normally causes significant volumes of water to be produced along with the oil. WORs of 200 or greater are not uncommon. Initial completions that begin with low WORs are usually soon followed by encroachment of strong coning water from below.

Expensive handling problems are frequently associated with the production of large volumes of Arbuckle water. Electricity expenses for pump operations alone can take a significant bite out of production revenue.

Most Arbuckle reservoirs, especially those in older fields, have either naturally occurring or induced contamination by sulfate-reducing bacteria. The resultant generation of H2S gas and iron sulfide scale in the well bore can cause early replacement or repairs of pump, rod, tubing, and casing. Storage, transportation, and disposition of the water are also of concern.

CONTROLLING WATER

Both primary and secondary permeability to water production are altered with the FMWC treatment that combines chemical water shutoff and placement techniques.

CHEMICAL

Stage 1 of the chemical portion of the treatment consists of an amphoteric polymer used to coat pore throat surfaces to reduce the effective matrix permeability of the rock to water. The bond of the polymer to the rock surface is permanent and not affected by subsequent water flow.

Stage 2 consists of a chrome-complexed anionic polyacrylamide (CCAP) to plug natural fractures.

An ionic chemical interaction occurs between Stages 1 and 2.

This locks the anionic polyacrylamide into the high permeability fractures and helps limit the returned polymer treatment that might otherwise be produced with later water production.

Note that the lack of polymer production does not mean that corrosion inhibitors and biocides can be eliminated after the job. Any posttreatment water produced should still be considered corrosive.

PHYSICAL PLACEMENT

A typical treatment technique would include these steps:

• Pull rods and tubing.

• Analyze water sample.

• Run in tubing and set packer.

• If water sample indicates iron scale, acidize the well with a system containing iron control additives or, if iron sulfide is present, an acid system designed for sour-gas wells.

  The acid should be produced back before continuing with the treatment.

• If sulfate-reducing bacteria (SRB) are a concern, the addition of a bactericide specific for SRB should be included in all fluid treatments following the acidizing stage.

• Pump preflush of 1,500-4,000 gal of dilute amphoteric polymer solution.

• Pump CCAP with diversion material as dictated by treatment pressure response. On occasions, when the well is not responding with an acceptable pressure increase, the diversion material may be added in small stages throughout the treatment.

• Flush tubing with lease crude and 1-2 bbl overflush.

• Shut in well for 4 days.

During the placement of the CCAP, it is necessary to perform a Hall plot analysis, which indicates "skin effects" of the polymer treatment, and monitor the surface pressure.1

Job success is a function of a correlation that exists between the combination of chemical water shutoff and placement techniques.

Any changes in the permeability near the well bore can be expressed as skin damage. The skin factor can be estimated from the change in the slope of the Hall plot.

[SEE FORMULA]

where:

S = Skin factor

K = Permeability, md

h Thickness of zone, ft

m Viscosity of fluid being injected, cp

MH = Slope from Hall plot (_ sum delta (psi)/_ cumulative injected volume, bbl)

_ sum delta (psi) change in cumulative pressure

EXAMPLE

In the Hall plot (Fig. 1) the final skin factor is calculated to be 5.70,

where:

Permeability = 230 md

Thickness of zone = 10 ft

Treatment fluid viscosity 10 cp

S2 = 3.75 + (10 (230)/(141.12) 10) ((350-230)/(700-600)) = 5.70

Values from the Hall plot are listed in Table 2.

Pretreatment water production and net thickness zone are used to establish the initial treatment volume. Subsequent Hall plot analyses aid in fine tuning treatment size and rates to improve results.

When analyzing a Hall plot, it is necessary to keep several points in mind:

• In Arbuckle dolomite, a skin factor of six appears to give the best WOR reduction without losing oil production. A different skin factor may be needed for other formations with different parameters.

• Attempt to achieve a steep Hall plot slope without fracturing or diverting (Fig. 1). Diversion or fracturing is indicated by breaks in the Hall plot or stair stepping with decreases in Hall plot slope (Fig. 2).

• A Hall plot is necessary to determine a correlation among pressure, rate, and skin.

FIELD RESULTS

Ten wells treated using the FMWC treatment had an average cost of approximately $7,000/well. Reduction of WOR was approximately 80% (Table 1).

Another important benefit is the minimal production of polymer following this treatment. Typically, polymer production after other treatments ranges from 50 to 100 ppm. But, after an FMWC treatment, polymer production normally has fallen to less then 10 ppm within 3-4 weeks (Fig. 3).

These low levels are desirable because polymer produced after the treatment can react with corrosion inhibitor and increase the chances of corrosion problems. The FMWC treatment has minimal long-term post-treatment polymer production; however, upon returning the well to production, application of corrosion inhibitors and biocides at levels congruent with the level of returned polymer should still be considered necessary.

REFERENCE

1. Earlougher, Robert C., Jr., Advances in Well Test Analysis, Monograph Series, SPE, Dallas, 1977, pp. 85-87.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.