William Furlow
Editor-in-Chief
The technology is in place. The economics of deepwater are screaming for it. So what's holding subsea separation back? It is often said that the oil industry doesn't drill for oil, it drills for water because most of what existing wells produce is water. Water with some oil, water with some gas, water with oil and gas and a little sand. Water in the production tubing, the flow lines, and the topside separators chokes the production system and causes huge transportation issues. Water must be processed topside, then thoroughly cleaned so it can be returned to the ocean or sent back downhole into a specially drilled injection well. In short, the water and water-handling equipment take up weight and space that could be dedicated to producing and processing oil and gas. With new, larger deepwater production platforms coming on line and existing facilities being expanded to handle more and more tiebacks, the time seems right to take water out of the equation.
Subsea separation
A handful of basic components are involved in subsea separation, according to Ian Ball, subsea system development advisor for Shell Interna-tional Exploration & Production Inc. The heart of this system is the pump and separator. Ball said the operating stresses on a subsea pump are much less than those on an electrical submersible pump (ESP). An ESP is designed to go into the well. That means it is exposed to high temperatures and pressures, as well as a corrosive environment. Being inside the well, it requires a costly re-entry to remove or replace it.
In the seabed environment, Ball said, the pump is situated in a relatively benign environment and can be made easily accessible from the back of a workboat. The pump and separator components could be replaced using an A-frame off the back of a workboat in benign weather regions. This procedure not only eliminates many of the component failure concerns, but also allows the equipment to be tailored and reconfigured to match the evolving volume and composition of the well flow.
The production profile of a well is a moving target, changing over time. An oil well with a high gas-to-oil ratio, for example, would require a different type pump than one producing with a high water cut. A well producing heavy oil would require a different system. With the ability to change out these components, an operator can tailor the design to match flow composition from the well. This flexibility is especially helpful in a situation where the flow composition is changing rapidly over time, such as in an early production scenario or late-in-life field.
"(A modular subsea boosting system) gives you tremendous flexibility, for negligible pre-investment without knowing for sure if you will need it or not," Ball said.
A custom-designed injection well sends water separated from the oil and gas back into the formation. This system not only eliminates the need to transport and process produced water at the surface, but it also can help maintain downhole pressure and the natural energy of the formation.
Ball said these subsea boosting systems can be powerful enough to rapidly draw hydrocarbons out of the reservoir. While this puts additional pressure on the completions design, it can maximize early production on new fields, something that is becoming increasingly critical in high-dollar, high-volume deepwater projects. Many deepwater sands have relatively high permeability and can produce at higher rates than natural flow delivers alone without damaging the formation.
Moving from pilot to profit
While there are at least two pilot programs in place to test the practicality of subsea separation (ABB's Subsys, on Norsk Hydro's Troll A field in the North Sea and the Cameron-built VASPS system in Petrobras' Campos basin offshore Brazil) Ball says that these pilot projects just scrape the surface of the technology's potential. Good reservoirs can become great reservoirs with some extra energy addition, Ball said. Fields expected to produce a lot of water would benefit most from the ability to re-inject this produced water locally to the production wellheads and keep it out of the production stream. Considering that the system would be designed so that, if there were a catastrophic failure in the subsea processing facility, it could easily be completely by-passed and production handled, as it is traditionally, at the surface.
"That puts you, at worst, back where you were before, without the subsea boosting," Ball said.
The type of high-powered pumps required for this work have an excellent track record. A great performance history is emerging for this equipment in an increasing variety of offshore fields in ever-increasing water depths, Ball said.
One remaining challenge is providing deepwater tiebacks with enough secure electric power to run the pumps. Ball estimates typical power needs to be in the range of 1-2 MW per multi-phase pump, but significantly less if subsea separation is also used to allow more efficient single-phase pumping to be applied. This would require a large and costly umbilical cable system. In applications where the system is retrofitted onto a turreted FPSO, for instance, the "feed-throughs" required for such a large umbilical could cause a serious feasibility issue and a serious bottleneck in the swivel, Ball said. The problem is circumvented in the more benign weather regions, where a spread-moored FPSO can be used.
There is also the question of resistive power loss en route to the wellhead. Much of the power is lost through heating the umbilical. Ball said that AC power is a real problem subsea because it only uses the outer periphery of the copper conductor. There are a number of novel solutions in place to address this problem, such as a small, unmanned power buoys that would be placed over the tieback location.
Another option might be to combine a power umbilical with a continuous power line feeding into an electrically heated flowline. This could alleviate flow assurance problems while delivering the required power to the separation pumps.
Ball points out that this separation at the seabed need only be designed to achieve a coarse first stage since we are only aiming at present to improve flow performance en-route to the host processing facility. The oil and gas would need to be further treated and conditioned at the surface to get them up to sales grade. The goal is to have a compact system that could be installed and maintained from the back of a workboat.
The biggest problem the industry faces is convincing the user the technology is mature. Getting this message across has taken a long time. And, it is likely that more pilot demonstrators in by-passable situations will be required before there is full acceptance across the industry that this technology has made the grade.
Each offshore basin attracts an appropriate fleet of service vessels, Ball said. If the subsea processing kit is designed in standard modular fashion, models can be run easily in any region by a fleet tailored for that region, and can be quickly interchangeable between regions. That has to be the future of the business one day, Ball said.
