Good wells don't count if oil and gas can't reach the market.

Flow assurance is a critical issue in offshore wells, and it becomes more and more critical as tieback distances and water depths increase. The right decisions are imperative because an operator will have to live with them through the life of a well or field or submit to expensive new solutions for a project already in place.

"We normally like to be involved at the start of acquisition (of fluid samples)," said Keith Stevens, flow assurance team leader for Shell E&P. Collection and analysis of high-integrity fluid samples from a well test - particularly on wildcats and appraisal wells - are the first major step in establishing flow assurance challenges and determining options for mitigation.

It's also important to collect a full range of samples from each zone that is planned for development, he added. The first sample might demand a pigging system to assure a clean flow line, while the other samples could determine pigging isn't necessary; a major investment difference in the field.

Feasibility

The flow-assurance parameters go into the overall field development plan as one factor in determining the feasibility of a project, Stevens said. If the field passes that feasibility test, the team moves into selection of a development concept. That requires an evaluation of flow assurance options from the viewpoint of both costs and risks.

For example, one subsea layout might be better than others for flow assurance, but flow assurance is not the only value that counts in the field layout, he added. The team is responsible for finding the concept that adds the highest value to the entire project, even if that concept involves a higher-cost flow assurance program.

There are no rules of thumb predicting flow assurance. Reservoirs don't all show up under the drill bit with uniform pressures at uniform depths. Shell uses a variety of software programs to help with flow assurance solutions. These include HYSYS, PipeSim, OLGA, a transient pressure simulator and a proprietary in-house transient simulator.



Additional help

Stevens started work for Shell 22 years ago and spent 8 to 10 years of that time working in flow assurance in the North Sea, the Gulf of Mexico, West Africa and the Far East. That experience also helps with flow assurance decisions on projects, but it's important to use all the tools available. For example, often the best guidelines come from other nearby wells, even if they aren't in the same field. Fluid parameters tend to be similar throughout a basin.

As an additional aid, Shell has accumulated databases of temperatures, pressures and fluid types from reservoirs around the world, and those databases offer clues to fluid flow behavior on a new project.

Hydrates

Hydrate formation has been a continuing concern to oil and gas production. "They tend to be present all the time during start-up and shutdown. You have to deal with them," Stevens said.

Other considerations include pour point, wax, asphaltene, napthanates, heavy oil, scale and, more recently, low-temperature and low-pressure reservoirs. They each pose their own challenges.

Most offshore fields produce associated gas, and that's a warning sign for hydrate formation, particularly during startup or shutdown, and these conditions can often define the hydrate strategy.

Anticipating a shutdown situation, for example, Shell might install an insulated flow line. That could give the company 8 to 12 hours of cool-down time under normal flowing conditions. This would allow time to react to the shutdown and restart before any further action is required to stabilize the system for a long-term shut-in. This level of insulation would keep the flow lines out of the hydrate formation window at lower flow rates at the expense of reduced cool-down times, he said.

Low points on a flow line pose a particular challenge. They are natural collection points for liquids, and if water exists in the flow, the hydrate risk increases. In situations where it may not be possible to depressure the flow line, the operator needs an alternative to a blowdown to clear the line.

One such situation occurred as Shell built the Na Kika complex, which consisted of the Na Kika platform at a central location fed by fields that were both upslope and downslope in the Gulf of Mexico.

Blowdown was effective for the uphill flow lines on the south side of the platform, but the downhill sloping flow lines on the north side could not be blown down effectively, and the company had to go to an oil-circulation system as an alternative flow assurance strategy.

Considerations

From a cost and reliability point of view, Stevens leans toward passive solutions whenever possible. They cost less and they don't need maintenance. That means the first option in dealing with flow assurance will be external insulation, burial or pipe-in-pipe equipment.

Only when those can't do the job will the company turn to more active solutions such as electric heating of the flow lines.

Most of the time chemicals are readily available to treat waxes, scale and asphaltenes, although there are many drivers for finding flow assurance solutions that reduce the overall chemical usage. This includes reduction in the cost of storage and delivery systems, reduction in chemical cost, and impact of chemicals on the environment

So far, Shell has been able to handle the majority of its tiebacks without electric heating. But that answer is in the toolbox. As the tieback distances get longer and the water deeper and colder, it may be needed continuously in the future. For the present, it is used to assure the restart of a system following a shutdown.

Asked if he could pick out the most challenging area of the world for flow assurance, Stevens said each area has its own set of problems. "None is better or worse. Hydrates can get more challenging with greater distances" (when the product flowing through the lines is colder, longer).

Experience can be a great help. Shell's experience with deep water and a large number of tiebacks in the Gulf of Mexico has given it a significant advantage in dealing with the problems of getting production to platforms.

New solutions

More and better solutions for flow assurance challenges are on the way. High on that list are subsea separation and pumping. Statoil, Norsk Hydro and Petrobras are testing subsea separation systems that allow them to separate oil, water and gas on the seafloor. They can then pump the water into a subsea disposal well and use electric pumps to move the oil to platforms with significantly lower lifting costs. Normal reservoir pressures will move the gas from new fields, but at some point subsea compression (also in the pilot stages) will keep gas flowing.

Industry advances in fluid evaluation and understanding also will make flow assurance more transparent, Stevens said. Techniques are becoming available to better analyze wax and asphaltene and determine where it will precipitate and deposit in a flow line. That analysis can lower the cost and time of intervention.

The greater challenges will come from ultradeep water as well as marginal fields. He said, "We've found a lot of the big fields." No single flow assurance solution is the best in every case. The more options available, the better chance there is of making a particular project viable. With the many challenges, it will take a combination of flow assurance management and remediation techniques to ensure fields of different sizes and in different locations can be brought on line and kept in production.

The additional experience and analysis leads to better risk-based decisions.