Effective produced-water control revives returns.

Handling produced water in mature fields eats income potential and often forces the early shut-down of fields with years of potential production. New techniques can postpone the day when economics close the field.
Water handling represented a major challenge for producers worldwide as they produced more than 25.3 billion bbl of water with hydrocarbons in 2000. Since operators must do something with that water, the figure doubles to more than 50.5 billion bbl of water handled during the year, said Dwyann Dalrymple, scientific advisor to Halliburton, during a talk at the Hart Energy Publishing "Brownfields: Optimizing Mature Assets" (BOMA) conference in Denver.
That water, conservatively, costs between a dime and 50 cents a barrel to process, he said, for a cost between US $5 billion and $25 billion a year. In the United States, that compares with cementing, fracturing, acidizing and sand-control costs that amounted to $4 billion in 2001. Most companies just count that money as a cost of doing business, he said.
US operators typically don't spend money on upfront diagnostics for water production problems, but they would be money ahead if they did take that closer initial look.
Among the near-wellbore and reservoir performance problems they might learn about are casing leaks, channels behind casing, completion out of zone, stimulation out of zone, poor areal sweep, gravity segregated layering, coning, interwell channeling and high-permeability streaks, Dalrymple said.
An operator can learn a lot about the reservoir by examining historical data of problems in the area and running injection profiles. It can use tracers, conduct multirate injectivity analysis with profiles and analyze logs to define the problems. Production testing and production log analysis can help, and the operator can develop a reservoir model.
Tools and testing equipment can provide information. A "Xero" analysis of existing data from expert experience is a technique with a success rate of more than 80%, he added.
Among diagnostic techniques, examining historical data has an 84.6% success rate, or economic return; multirate injectivity analysis offers a 93% return; and logging analysis yields a 92% return.
Among solutions that work, he
listed internally or externally catalyzed silicates, in-situ polymers, metal-crosslinked polymers, relative permeability modifiers, diesel oil cement or slurries, cement
squeezes, re-cements, foam cements
or combinations of solutions.
In a survey of 889 wells, he said, a combination of diagnostics, analysis and treatment gave operators a $703 return for each $1 spent.
An operator must understand the reservoir, completions and optimization choices. Dalrymple said, "You need to understand why before you choose how to treat the problem."
Hydrophobically modified polymer adsorption is one water-management technique with high potential, he said. The water-soluble polymer from water-soluble alkyl chains remains about the same consistency of water, and it permanently absorbs to rock surfaces downhole.
It reduces permeability to water seven to 10 times more than it reduces permeability to hydrocarbons. Since the water is absorbed in the formation, the operator has lower water disposal costs. It allows hydrocarbons to pass to the well bore while holding onto the water and extends the economic life of the well.
The technique can be used as a water reduction system. In one sandstone field trial, it reduced the water-oil ratio from 120 to 48.
It also can reduce water in fracture treatments when fractures might reach into a water zone. In a test for a customer, a well that produced 90 b/d of fluids with 70% water improved to 220 b/d of fluids with 40% water.
It also can be used as a diversion stage for acid treatments. In about 40 acid diversion treatments, it increased oil production 34% and reduced water cut from 21% to 17%.
In the same program, Gordon Graves, independent consultant, said operators need the right answers to water management to:
• Justify a sale or purchase price;
• Identify proper individual well workover programs;
• Extend well life;
• Reduce lifting, maintenance, treatment and disposal costs; and
• Resolve environmental issues.
The right answers increase reserves and profits and improve the environment, Graves said.
The main reasons for failure to properly manage water include poor, or no, diagnosis; poor candidate well selection; poor treatment selection; and poor application of techniques.
The best answer for water problems, he added, is to "Do it right the first time." That means the right primary cement job, the right completion strategy, and the right reservoir analysis for water-oil contact. The worst solution is looking for a magic bullet. No solution gives the operator all oil and no water.
Graves offered a conservative look at the severity of the produced water problem. A 1999 Environmental Protection Agency analysis estimate said average US wells had a 7.1 water-to-oil ratio, or 81% water cut. A 2004 study by Halliburton put the US number at a 9.6 water-to-oil ratio, or a 91% water cut. An OFR review indicated that average world production water-to-oil ratio was around 3, or a water cut of 75%. Graves said that his own estimate of average world production water-to-oil ratio was closer to 10, or a water cut of 90+%.
If the annual water handling cost in the United States is 20 cents a barrel, then the total US cost is $4 billion. At the same rate, the world cost is $14 billion with a 75% water cut.
Costs include lifting the water, separating it from the oil, treating it to some required specification, disposing of the water and workover costs related to water production.
In trying to figure out what to do about that produced water, Graves recommended using the simple tools first. Log-log plots of the water-oil ratio over time and injection data can give an operator a feel for whether water comes from coning or channeling.
He recommended immediately running a cased-hole log in a newly completed well to determine where the cement is and how well it is working. If it's not working properly, the log will tell the operator where the cement squeeze should go.
In a mature well, a new log compared with the log of the newly completed well will give an operator valuable information about formation evaluation, well integrity and fluid movement.
Combination tool logs can show potential for water entry. Temperature measurements could indicate water incursion. A downhole video camera can identify a host of problems, including water spray through pinhole leaks, he said.
Before attempting any solution, an operator should build a model using tools for reservoir development and predictions, to verify data and assumptions, to evaluate well tests and workovers, and to train field people. The model doesn't have to be particularly complicated.
When the time comes to apply a solution, the operator has a variety of chemical options: cements, resins and hard-set chemicals, gels, swelling chemicals and materials, and relative permeability modifiers, or a combination.
An operator must know how to properly use the selected technique. For example, if gels aren't mixed properly, they may not set, or they may set too quickly.
On the mechanical side, the operator might choose to pull and repair damaged casing sections; install liners, patches or expandables; or install packers, sliding sleeves or bridge plugs.
Graves also asked whether operators could handle the water in ways less expensive than surface separation, treatment and disposal. For example, solutions might include separation of oil and water in the pump, in the casing, in the reservoir or on the sea floor. In those cases, the operator would have to deal with a lot less water at the surface, and in some cases might eliminate water at the surface.
A two-pump system such as the one developed by Texaco in the 1990s uses one pump to bring oil and small amounts of water to the surface, while the other pump re-injects most of the water in a downhole zone. A study of 11 wells that used that system showed a 75% reduction in water production with no reduction in oil produced.
Another option, hydrocyclones, was made commercially available, but the ESP version of these pumps had so many technical and economic problems that suppliers are now reluctant to even discuss their availability.
Responding to a question from the audience, Gordon said, before any water management job begins, the operator and the service company should meet and agree upon job objectives and expectations. That helps provide a basis for good communication about expected job results and keeps the focus on the real objectives by all involved.

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