Production optimization is the holy grail. Only problem is, no one knows what a grail looks like.

Ask many of the exhibitors lining the aisles of the 2003 Offshore Technology Conference and they'll tell you, "We do production optimization." Well, maybe they do and maybe they don't. Nowadays, the term "production optimization" has come to mean many things to many people. It's sort of like the adjective "unique." In school, we learned that it is incorrect grammar to try to qualify the word unique, because after all, the word means one of a kind. Still, one sees items described as, "The most unique..." or, "More unique than..."

So it is with production optimization. After all, optimum means perfect for the situation, and therein lies the problem. What's perfect for one situation may not work at all for another. Here's an example. One operator may want to get every economical drop of oil out of his reservoir, so for him optimization may involve taking steps to maximize recovery factor. Another, whose concession is about to expire, sees optimization in an entirely different light. He wants the highest possible rate of production for the remaining time he has left in his PSA. Which is true optimization? Both are.

Service companies who profess to offer production optimization solutions almost invariably have an entirely different definition in mind. They focus on a single aspect of production and try to position their product or service as the best approach for optimizing that particular aspect. But without knowing the overlying drivers, how can they be sure their approach is indeed optimal? The answer is, they can't, nor do they care.

To be fair, a few recent consortia of service and supply companies have tackled the daunting task of developing integrated production solutions working in concert with the operators. These come closest to meeting the definition of production optimization, because the operator defines the term at the time in context with his present situation. Even so, a change in supply, demand or market price may cause him to re-evaluate his position.

The fact that there are so few true production optimization plays in the world is largely due to a lack of agreement on how to measure success. How much data is enough? How much accuracy is needed? How is an operator going to balance the value of optimized production against the cost of achieving it?
Some operators are trying to identify, qualify and integrate the very best technology into their solutions, regardless of the source. On the face of it, this seems a highly desirable goal. Others say that for them a solid chain of responsibility assures better long-term reliability. They prefer hiring an integrated solutions provider they can hold responsible for overall results. They have had unpleasant experiences where the train goes off the track and all the suppliers point fingers at each other.

On the supplier side, business runs the gamut from a straight retail sale, to in-depth collaboration, where the supplier shoulders a fair amount of up-front risk in return for a share of the reward. Which one is right? The best answer is, "It depends." The risk/reward strategy has had marked success in some Brownfield projects, where the operator was happy to get any incremental added production as long as he did so at a profit. Greenfields however, are a different matter. It is hard to get any operator to agree to share production profits with a supplier, no matter how influential the supplier's product or service has been to the success of the overall project. One operator said, "It's like the old tale where the king promises his first-born son to any knight who could slay the dragon, only to have second thoughts when it came time to pay up."

But the industry is getting closer to a solution. Smart wells provide the type of measurements needed to quantify results, and moreover, the ability to make the adjustments necessary to keep wells producing at peak efficiency. Production engineers are using robust computer models to analyze thousands of measurements, both from the reservoir and from surface facilities, to fine tune the entire asset to near optimum operating condition. And they can do it every day.

New high-tech sensors are able to measure much more than pressure and temperature. They can measure multiphase flow, phase composition, sanding, corrosion, distributed temperature, pressure and seismic. They can accomplish this with robust sensors that have no electronics, no moving parts, no drift and extremely long lives. And they can transmit their data at the speed of light on a glass fiber slightly thicker than a cat's whisker.

With such measurements, operators will be able to track the movement of fluid through the reservoir and accurately predict drainage patterns. In fact, fluid movement can be monitored wherever it occurs, inside or outside tubing, casing or behind the sand screen. Water or gas can be anticipated before breakthrough and remedial action taken to delay their incursion as long as possible. And through the use of microseismics, fracture treatments can be monitored in real time. But there's a problem.

The digital oil field of the future is within our grasp, but with few exceptions, the infrastructure is not ready to accept it. People don't feel comfortable enough in quantifying the risk and estimating the profitability to justify the up-front investment. And already one hears grumbling, "It's too expensive." Cost is a relative term that can be justified with profits, but no one wants to go out on a limb and guess at profits of a long-term investment in a commodity whose price cycles are legendary.
The prize will go to whomever solves this problem. Will it be you?

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