Sensitive carbonates sometimes defy an operator's best efforts to flow gas and liquids at their highest potential. But, in general, the operator with fewer obstructions in the wellbore is going to get better production.

Traditionally, when a carbonate zone flows at rates lower than its potential, operators use hydrochloric acid to stimulate the well's production. If the zones are long and diversion is needed, then, often, they have used a polymer additive to add viscosity. If they still can't treat all the zones they need to reach, they may call for a coiled-tubing unit to provide individual treatments for each area capable of production or injection. However, this often adds expense.

A year-old technology called viscoelastic diverting acid (VDA) offers a new solution in treating this old problem, and the treatments conducted to date have been positive. The formula is relatively simple. It is hydrochloric acid and a patented surfactant in combination.

"We have pumped about 120 treatments, so far, with not one failure. VDA is surfactant and acid, and the chance to fail is slim," said Schlumberger Stimulation Business Development Manager for Middle East and Asia, Dr. Mathew Samuel.

"We have cases that increased oil production from zero to 4,000 bbl and cases from 500 (b/d before treatment) to 8,000 b/d of oil," he said.

A Middle East operator asked for the treatment for one gas well. The well initially produced 44 MMcf/d of gas and the companies expected to raise that to 66 MMcf/d using the traditional polymer-acid treatment. It delivered 80 MMcf/d the next day, after a matrix stimulation treatment with the acid-surfactant combination.

After that well, the operator asked for the treatment on two more wells. One of the two wells produced results similar to the first well. The other has posted an initial production rate of 49 MMcf/d. This well delivered 75 MMcf/d with the new treatment. Production logs are planned for the three wells to observe the production distribution and to further confirm the effectiveness of these treatments.

Based on the success of the treatment, the operator is now considering the use of VES (viscoelastic surfactant) technology in a 15- to 30-well campaign for acid fracturing.

The reasons for the improvement are easy to understand. Independent studies by Stim Lab, Frac Tech, Saudi Aramco and other companies have shown - and the results have been published in Society of Petroleum Engineer papers - that the polymers used in conventional acid systems plug wormholes and damage the formation. Similar damaging of proppant pack by polymer fluids in hydrolytic fracturing was also reported.

Some polymer fluids, whether they are crosslinked on the surface or in the formation, use crosslinkers and breakers that are sensitive to acid levels. Metal crosslinkers can precipitate out of the fluid as hydroxides or, if hydrogen sulfide is present, as sulfides. Both can damage the formation.
If a breaker breaks the fluid system prematurely, the treatment does not give the operator effective diversion. The system that consists of surfactant and hydrochloric acid doesn't have to deal with that potential problem. Once viscosified, the viscosity will not reduce until it is diluted by formation water or contacted by hydrocarbon (or a mutual solvent that is sometimes used in the post flush).

High temperatures often cause instability in traditional polymer systems. The VES-acid system maintains stability to 350°F (176°C).

Traditional acid treatments frequently do not give an operator full coverage of all the zones it wants to treat. Sometimes zonal coverage was as small as 10% of the desired area with acid alone with diversion and often led to face dissolution that affected the wellbore integrity. Polymer fluids, when used for diversion, could lead to formation-damage from deposits left by polymers and create a roadblock to efficient production. The acid-surfactant combination goes into the interval and covers the full zone.
All of the major service companies have competent research programs, and they probably will come up with treatments that yield similar results, even if they don't work the same way.

Coiled tubing applications can reach the areas of incomplete coverage, but this can be an expensive mechanical option. The acid-surfactant system can be used with coiled tubing or it can be bullheaded. The Kuwait Oil Co. picked the system specifically because it could be bullheaded against pressure. It had been using dual completions in many of their wells and had concerns with the coiled tubing getting stuck should it be used to treat the upper zone.

In some of the longer extended-reach wells in Saudi Arabia, the coiled tubing simply could not reach the end of longer holes.

So far, 90% of the jobs with the relatively new matrix stimulation treatment have been in the Middle East and Asia. Wells have been treated in Saudi Arabia, Kuwait, Pakistan, Egypt, India, Indonesia, Europe, North Africa, Thailand, Mexico and more recently in the United States. The big carbonate wells are in the Middle East, and the company introduced it there first.

Many of those big fields also don't face the water problem that an aging West Texas carbonate well might have to manage. If a treatment opens a formation to oil or gas flow, it also would be expected to increase the flow of produced water.

Although this fluid breaks on contact with oil, it does not break with water. For the operator, this means the wormhole growth is slower in the water zones than in the oil or gas zones and post-treatment the water cut can be lower. Of course, the service company also would try to keep the fluids in the oil and gas zones and avoid the water zones wherever possible. Another technology based on the use of surfactant fluids is used to the selective stimulation hydrocarbon zones in wells with high water cut.

Uses

An operator can use the VES fluid in a variety of ways. An acid frac normally offers better results than an acid wash or matrix stimulation, but the acid-surfactant combination has been used in small volumes and as foam in an acid wash for long horizontal wells.

The cleanup time is faster than traditional polymer-acid treatments as well. Matrix treatments that previously took a day to cleanup now take only a few hours. The fracturing job that typically cleans up in 5 days with a polymer treatment might clean up in 12 to 15 hours with the new surfactant system.
There is a tradeoff for the higher performance. The surfactant treatment can be more expensive than a polymer blend on the same job; however, results have shown that the better performance more than offsets the additional cost. The service company explains that this is a patented surfactant that works up to 350°F and viscosifies when the acid has been spent. Typical surfactants used in the oilfield application are either not compatible with acid or will not viscosify the fluid under downhole conditions. With the new system, the amount of surfactant and the concentration of HCl used controls the viscosity of the system downhole. The typical HCl concentrations range from 15% to 28%, though 3% and 5% HCl were used in some treatments.

Surfactants have two parts, a head and a tail, Samuel said, The head in the acid-surfactant fluid is larger and the tail is much longer compared to regular surfactants. That gives the compound its favorable working qualities. And, he added, the cost per gallon of fluid may be higher than conventional fluids but the cost per barrel of oil returned is lower.

In some cases, production improvements compare with a traditional frac job, but the cost of the surfactant matrix stimulation is about a fourth of the cost of a frac job. In addition, it's not always easy to get a battery of frac trucks, a sand chief, mixing equipment and support equipment to remote locations.
A matrix stimulation with acid-surfactant requires a lot less equipment than a traditional hydraulic fracturing or an acid-frac treatment.

An acid-surfactant treatment can be performed anywhere a traditional acid-polymer treatment is used. There are no restrictions in vertical wells, horizontal or deviated wells, oil wells, gas wells or water wells or mature wells that aren't producing. The results from the Middle East operator show the success of the system in gas wells.

It has been successful in more than 150 oil wells, however, some surfactants can form emulsions with some oils and condensate. For that reason, it is always advisable to test the formation fluids for emulsions prior to treating an oil zone. At the same time, the patented acid-surfactant mix has a lower tendency to emulsify than standard surfactants. If an emulsion tendency is observed, specific de-emulsifing agents can be used in the treating fluid or as a pre-flush system to overcome the emulsion tendencies.

Advantages

"The acid-surfactant combination can be batch mixed or mixed on the fly from the surface. Traditional polymer mixes must be batch mixed. The new fluid also leaves no tank bottoms. It is not adhesive like poly-acrylamide polymer systems and the mixing tanks can be cleaned out with a simple water flush", said, Hisham Abou El Azm, the Schlumberger Well Services manager in Bahrain.
It can be used equally as well in Saudi Arabia's high-volume wells and Indonesia's lower-volume wells.
Acceptance is rapidly growing in the United States and the rest of the world, as well. A US independent company pumped its first job, on a long horizontal well in January, another in February and four or five in March. That's an extremely high growth rate in an industry that took 5 years to accept frac packs.
Common sense suggests that, if the cleanup is better, it should last longer; the time between treatments should be longer and this is being proven with results. During its year in the field, the company tried the acid-surfactant treatment on wells in Egypt that went into decline in as little as one week. After treatment, wells in the same area were still producing at consistent rates after six months.

It also tried the treatment on water injection wells. In some of those wells the injection rate is triple the rate of injection in non-treated wells. After nine months, they continue to accept injection rates even after 12 million bbl of water has been injected, while conventionally treated wells in the same area start showing declines after pumping 2 million to 3 million bbl of water.
Kuwait's oil company used the acid-surfactant combination to treat some of the flank wells, wells with very heavy oil, that hadn't produced for 6 to 10 years even after several stimulation treatments. The wells started producing again and allowed Kuwait to recalculate its recoverable reserves.
The company has proved the acid-viscoelastic surfactant treatment speeds up recovery, and because it covers more of the producing zones than traditional treatments, it should recover more oil and gas. The treatment has been in the field for only a year, and it's too early to try and predict what additional percentage of hydrocarbons in place might be recoverable.



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