Norsk Hydro, which last year success fully tested a downhole oil and water separator, is now preparing to carry out a field test early in 2001. The tech nology holds the promise of remov ing water, a major bane of oil production, virtually at source, and has been described as representing a quantum leap in reducing production costs. - Set-up for test of H-Sep downhole separation system at Norsk Hydro's Porsgrunn research facility.
Hydro has developed its own patented separation process known as H-Sep. The system is straightforward, involving a gravity separator and a pump to inject the separated water back into the formation. The company has enlisted the assistance of Weir Pumps on the pump side and Kværner Oilfield Products (KOP) on the separator side.
The process employs the horizontal section of the wellbore, where conditions are ideal for separation, as the separation vessel. Tests carried out at Hydro's Porsgrunn research facility in simulated downhole conditions produced sales quality oil with a water content of less than 0.5%, and clean water with less than 500 ppm oil. "We have shown that the separator meets expectations and that it can produce top quality oil and water," commented Per Almdahl, Hydro's manager for the downhole separator program.
Initial consideration was given to using a cyclone separator, but a gravity separator was preferred as it provides a simpler process and achieves better results. Another advantage is that while cyclone separation is only suitable for larger water cuts, gravity separation works through virtually the whole range of water cuts.
Demo 2000 funds
Schematic lay-out of H-Sep system.
Through KOP, the project has now received NKr 7.4 million in funding from the Norwegian government's Demo 2000 technology demonstration program, out of a total project budget of NKr 29.4 million, to qualify key components. The planned field trial will be carried out on a well on Hydro's Brage Field off Norway. Weir and KOP currently are performing the main study for this trial.
"This study involves a full technical evaluation of all aspects of the technology in the light of the trial well and its data," says Bjarne Olsen, general manager of Weir Norge. "When it is finished, we will have a complete technical evaluation of all key components, a cost-benefit analysis, and risk analysis."
"The beauty of the concept is its simplicity," says KOP's project manager Gunder Homstvedt. "Hydro's initial research with bottom-hole samples of formation fluid showed that in the higher pressure and temperature downhole, the gas remains dissolved in the oil, thus reducing the density and viscosity of the oil. So, the density difference between the water and the oil is greater downhole, and the gravity field can be used to separate the oil and the water in a more efficient way than topside. Moreover, as there is little pressure drop, the gas is not encouraged to break out before separation has taken place."
When the wellstream in its entirety is taken topsides for separation, these pressure/ temperature advantages are lost. Achieving the same efficiency of separation also takes much longer. So, with the exception of the fact that space is limited, downhole is without doubt the best place to perform separation, Homstvedt says.
Seabed separation also presents advantages over topsides separation, as Hydro itself hopes to demonstrate on the Troll Field when it brings a subsea processing system developed by ABB into operation this spring. Here too, the downhole pressure/temperature advantages are lost, and the process requires a comparatively bulky separation unit, higher energy consumption, and a dedicated well for water disposal.
With regard to the H-Sep system, the downhole gravity separator is built into the well casing - for the Brage trial it will form part of the 10 3/4-in casing section.
"One of the challenges for the field trial is installing the separator in the well while fitting in with drilling constraints, safety barriers, and so on," says Homstvedt. Once the technology is proved, however, this problem will only arise when the system is retrofitted in existing wells. In the case of new wells, as the process is suitable for the whole range of water cuts, it will make sense to install the system as part of the original well completion and use it from startup.
On the pump side, the biggest challenge is the requirement to boost the pressure of the separated water stream up to 250 bar to ensure injection into the formation. "The hydraulic submersible pump (HSP) we have developed is unique in its ability as a downhole pump to achieve this," says Bjarne Olsen. It can generate 1 MW of energy, enough to inject up to 20,000 b/d of water into the formation. The pump can be placed horizontally or vertically, and does not need to be located next to the separator. It is powered by fluid pressurized by a charge pump, which can be located either topsides or on the seabed. Depending on the casing size, neither the pump nor separator need to be removed to allow well intervention or logging operations to take place.
The HSP is derived from the downhole multiphase pump developed by Weir and Texaco for the latter's heavy-oil Captain Field in the UK sector. "This is a very reliable pump, and we foresee having to do workovers on it every five years," says Olsen. "It underwent a 2,000-hour downhole test on Captain in which conditions were much worse than we had expected, and was still in prime condition when it was retrieved."
The HSP to be used in the H-Sep field test will be 5 meters long and weigh 950 kg. If a main tenance need arises, it can be pulled separately, either by wireline or coiled tubing. On Captain, it took one day to pull the pump and one day to run it. But as with the Captain pump, Olsen expects that intervention will only be required at lengthy intervals. The pump will be built of materials with optimal wear-resistance, such as the cobalt-based alloy stellite 6 and ceramics such as tungsten carbide.
In principle, the technology represents an important step towards solving the problem of produced water. On a worldwide basis, the volume of oil produced is exceeded by about three to one by the volume of water production. As the water cut reaches large proportions, water handling and disposal can account for more than three quarters of the total operating costs on a field. Removing and disposing of the water downhole will greatly reduce the burden placed on topsides facilities with a concomitant reduction in costs.
But, downhole separation could also be set to reshape the industry's whole way of thinking about field development. It raises the question of whether topsides facilities will be needed - if what emerges from the wellhead is an oil/gas stream or separate oil and gas streams. The more economic solution may prove to be simply transporting these streams directly to shore, or to some distant gathering facility, if necessary, with the aid of multiphase boosting.
And, in some cases, the cost reduction the technology offers could make it possible to develop marginal fields that would otherwise be uneconomic, not least in the case of deepwater discoveries, where the water depth itself poses additional problems and costs in bringing oil and gas to the surface.