Drilling/Production

With the proliferation of high-angle and horizontal wells that expose longs sections of producing formation to the bit, has come increased concern over near-wellbore damage. The issue has garnered sufficient industry concern to give rise to a new category of cleaner drilling muds called "drill-in" fluids. Typically, at the point the bit is to enter the productive zones, the fluids system is switched from traditional bentonite-laden muds to ones that use polymers to gain cuttings-carrying

Cleaning up "clean" fluids

With the proliferation of high-angle and horizontal wells that expose longs sections of producing formation to the bit, has come increased concern over near-wellbore damage. The issue has garnered sufficient industry concern to give rise to a new category of cleaner drilling muds called "drill-in" fluids. Typically, at the point the bit is to enter the productive zones, the fluids system is switched from traditional bentonite-laden muds to ones that use polymers to gain cuttings-carrying viscosity and salts for fluid loss control.

The problem, according to researchers at BJ Services' laboratories in Tomball, Texas, is that while these drill-in fluids are "cleaner" and therefore less damaging than traditional fluids, operators are still settling for less permeability (or more permeability reduction) than is necessary. Polymer residue, left behind by traditional acid and oxidizer clean-up procedures, they say, inhibits production almost as badly as does traditional filter cakes. Their laboratory results indicate acid and oxidizer washes restore cores damaged by polymer-based drill-in fluids to only about one third its original permeability.

The solution, according to BJ biotechnology section leader, Robert Tjon-Joe-Pin, is polymer linkage specific enzymes (PLSE) - enzymes whose nature restricts them to reaction with only key linkage sites within one type of polymer. PLSEs are designer enzymes that match themselves to a specific polymer, breaking it and reducing the polymer to soluble sugars. When the correct match is made between enzyme and target polymer, lab results show a nearly 100% restoration of permeability.

The key, say the scientists, lies in enzyme specificity. Standard oxidizers and acids react at whatever site they first contact, including tubulars and other downhole hardware, spending themselves before they can break the polymers bonds. The effectiveness of acids can also be severely reduced when it creates channels, or wormholes, in the filter cake through which the acid drains, bypassing most of the filter cake it was meant to treat.

Critics point to debatable success using enzymes as breakers in fracture fluids. But, Tjon-Joe-Pin argues, others have been using random assortments of enzymes without matching a specific enzyme to the polymer residue and as a result were only partially successful.

MI Drilling Fluid's technology manager, Jim Bruton, said that while his company is looking at, and has used, enzymes for certain cleanup situations, several factors must be considered when viewing PLSE or any enzyme success story.

Among what might be called mitigating circumstances, he said, particularly when transferring technology from lab to field, are placement, temperature, and the reality of damage itself. "Typically when you are dealing with damage issues you are in a gray area," Bruton said. "What is clean-up and formation damage? How do we know lab tests are applicable to the field? We ran some (lab) tests and at two different times there was a 30% difference in the results. That is not within appropriate experimental error."

But the evidence, said Tjon-Joe-Pin is not confined to laboratory work. "BJ built upon its experience with breaking polymers in more than 20,0000 frac jobs when it embarked upon and patented its treatments for drill-in fluid clean-up."

And significantly higher production rates from PLSE clean-ups on a series of wells in the middle east, done in conjunction with offset control wells without the enzymes, appear to justify Tjon-Joe-Pin's enthusiasm. Should the industry become convinced of the results, a new category of treatment fluids will undoubtedly soon join the category of drilling fluids.

Composite CT soon commercial

Non-metallic (composite) coiled tubing appears ready to enter the market. US-based Fiberspar is close to realization of a joint interest project it proposed to the oil industry in Houston last October to qualify non-metallic bonded tubular products (composite coiled tubing) for offshore use. Applications development manager, Bill Stringfellow, said it will be funded by the end of May with firm commitments from Conoco, Exxon, Halliburton, Shell, and the Massachusetts Institute of Technology. Others still considering the proposal include Texaco, Mobil, Chevron, and BHP.

The company has supplied a 2 1/8-in. composite, continuous, coiled tubing flowline to Arco on Alaska's North Slope, will deliver a 2 7/8-in. flowline to Mobil in Utah, and install two vertical strings in May and June. Halliburton has ordered 15,000-ft each of 1 1/2-in. and 2 3/8-in. reeled strings. Several papers on the matter are scheduled for the 1997 Offshore Technology Conference in Houston.

Meanwhile another player has entered the field. NIST (National Institute of Standards and Technology), has provided about half the $5 million necessary for a five-year research program to develop methods to manufacture 10,000- to 30,000-ft sections of spoolable composite tubing. Private sector participants include Hydril, Amoco, Mobil E&P, Shell, Phillips, Dow Chemical, Schlumberger, Elf, and the University of Houston.

Fiberspar and Halliburton have formed a development company to commercialize several composite reeled tubing applications, including flowline cleanouts, completions, and workovers by the end of the second quarter 1997. The NIST project has reportedly completed some test pieces but the timing of commercial applications have not been publicly predicted.

Radoil/Deepstar test loop ready

Radoil in Houston has completed its Deepstar project test loop and is ready for any vendors seeking to prove pipeline paraffin blockage removal tools. The loop, designed to simulate five miles of Gulf of Mexico flowline has been fitted with a 15-degree paraffin ramp that leads into the actual 15-ft long blockage. Vendors presenting blockage removal ideas or tools to be tested will be first screened by project leaders at Radoil. Those deemed reasonable possibilities will then be recommended to Deepstar for testing funds.

The standardized paraffin is comprised of 70% from tank bottoms from a Utah refinery and 30% Gulf of Mexico crude. It has a 31-degree API gravity and a 168-degree F drop melt point.

The original program included hydrate blockage remediation. But since it is very difficult to create a long hydrate block and far easier to remove one than to remove paraffin, it has been decided that testing paraffin removal ability would suffice for both problems.

The payoff and risk for any vendor seeking to showcase a solution at the test loop is immediate exposure to the project's 18 sponsoring oil companies. While Deepstar officials assured vendors that apparent failures would be viewed by the sponsors and Deepstar in the best possible light, Radoil has also offered vendors unsure of their tool's readiness an opportunity to use the loop outside the Deepstar project until they are confident enough to go public.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

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