Øivind Reinertsen is the President of StatoilHydro USA & Mexico. Even before the merger of Statoil with Norsk Hydro’s oil and gas activities in 2007, the two companies were actively pursuing development opportunities in the US Gulf of Mexico. Now StatoilHydro is one of the largest leaseholders in the deepwater GOM, applying technology developed in the harsh North Sea environment to develop its reserves. The company is also expanding into the US onshore shale gas sector.
Question: What is StatoilHydro’s upstream strategy for the Gulf of Mexico?
Answer: In 2004, we looked at different places in the world with the most remaining resource yet to be found, and where such resource could be accessible for oil companies like us, and the Gulf of Mexico was one of the areas we selected because of the huge amount of remaining resource and also based on the fact that the deep water is very immature.
We also had a view that the experience and technology we had developed in the North Sea could be a leverage for us, by qualifying this equipment for the water depth in the Gulf of Mexico.
We decided at the time that we should enter into the Gulf of Mexico by acquisitions and farm-ins with existing companies, mainly to learn, and also to acquire a lease portfolio in the deep water. At Statoil, we did the farm-in with Chevron, we did the farm-in with ExxonMobil, we acquired the EnCana portfolio, and we acquired some Anadarko leases. Hydro did the same thing with ConocoPhillips, and they acquired Spinnaker.
That has given us the portfolio we have today, consisting of some 400 leases, which makes us the fourth-largest leaseholder in the deepwater Gulf of Mexico, and we are the operator on about 200 of them. Today we have a portfolio of producing fields, we have field discoveries that are under construction and development, and we have discoveries that are being evaluated for development.
And we have a lot of exploration acreage that we are about to start drilling on with the two drilling rigs that we are getting into the Gulf of Mexico this year. By June/July, we will get the first one, which is a newbuild coming out of Singapore operated by Maersk, and probably in September we will get the second one, a drillship operated by Transocean. We have an exploration program for the next year of some 18 exploration wells that we will drill with the two rigs.
Q: What differences were there between the Statoil and Hydro strategies for the Gulf of Mexico, and how were they reconciled in the merger?
A: The Statoil strategy at that time was more focused toward the deep water only, while Hydro was looking at the Gulf of Mexico as an area. When they merged, we divested immediately all the shelf activities that were coming through the Hydro portfolio, to go back to the original [Statoil] strategy of being focused only on the deep water.
Q: What technology developed for use in the North Sea is StatoilHydro now planning to use in the Gulf?
A: Mainly equipment that could give us increased recovery and also reduce costs. If you look at a typical field in the harsh Norwegian environment, we’re talking about recoveries of more than 50%, and we have fields that have recoveries today of more than 70% of the entire resource. Comparing that with the deepwater Gulf of Mexico, you probably today don’t find any fields with expected recoveries more than 50%, most of them probably in the range of 10 to 20%.
In Norway we developed new technology that can reduce drilling costs, and we are able to access much more of the reservoir from one well by drilling long horizontal sections. In addition, we have developed quite a lot of subsea equipment, like subsea separators, which means that you are separating the water out of the oil on the sea bottom and pumping the oil up to the platform. This saves a lot of energy, which you can use to move the oil in the reservoir instead, increasing the recovery.
And also, we are using a lot of subsea pumping equipment that can move the oil longer distances on the sea bottom, and also to lift the oil from the sea bottom up to the platform.
Q: StatoilHydro is becoming active in North American shale gas development—an unusual move for a company largely defined by its offshore activities. Where is the company finding the expertise for this very different kind of production activity?
A: A couple of years ago, Statoil started looking at all the possibilities here in the US, and especially onshore. The main reason for doing that was to get hold of resource that could be sustainable over a long period of time. We saw that we do not have the expertise to do this [with shale gas] ourselves, because this is very different from deep water.
We immediately saw that if we were going to enter into this kind of operation, we needed to do that with somebody who has the experience and the knowledge. We were able to partner with Chesapeake in the Marcellus Shale. Chesapeake is a big operator; they are the biggest gas producer onshore in the US, and they operate 100 rigs onshore, so obviously they have the competence.
We are putting people into their organization to learn, and we also have an agreement with them to look at similar plays elsewhere in the world, together, in which we can utilize their competence in the subsurface, and maybe add our competence and knowledge of the gas market elsewhere in the world.
Q: How does the recent drop in the prices of oil and gas affect StatoilHydro’s plans for North America?
A: Generally, we have stated to the capital markets that our strategy is firm. We may implement at a different pace; we may take a longer time, but we are in this for the long term. In the US, there is not much we can do because a lot of what we’re doing is under [a Standard Operating Practice] agreement that we have with the Minerals Management Service, to develop fields at a certain pace.
We also have developments that are coming on production this year, and we don’t have any plans to slow down exploration activities due to the fact that we have the rigs, which are on four- and five-year commitments, and of course we have to utilize them.
Q: How do you see Norway’s oil and gas production trending in the next one to three years?
A: As a company, we are operating more than about 80% of the fields in Norway. Our goal is to keep Norwegian production at today’s level through 2015. And we have to do that by being very active in exploring smaller fields in the close vicinity of existing infrastructure. Then we can utilize the infrastructure in place to immediately produce smaller new discoveries. At the same time, we will then have enough volume to maintain the production on the main field to increase the recovery.
A lot of new technologies have enabled this. We have done this successfully in the southern part of the North Sea, where we have the mature fields like Gullfaks coming up to 75% recovery. We are now moving further north into the Haltenbanken area, where we have fields like Kristin, like Åsgard, where we are really exploring the surrounding area, because we start getting spare capacity on the infrastructure. That, we think, will make it possible for us to maintain the kind of production level we have today.
The Dompap oil find near Norne Field is a good example, and we can immediately tie it back to Norne Field. And these types of developments also will be applicable in the deepwater Gulf of Mexico when we start getting infrastructure in the area. To justify the infrastructure, you really need huge discoveries, but once you have the infrastructure, and you can have a hub in place, then you can start exploring for smaller accumulations, because you don’t need the same huge discovery to justify development when you already have infrastructure in place.
Q: What important projects have come online in the last couple of years for StatoilHydro, and what is their current status?
A: We have SnØhvit, which is a major gas field combined with an energy plant in the northern part of Norway, and we have the huge Ormen Lange Field, in the middle part of [the Norwegian North Sea], flowing gas to be treated onshore and then being sent to both the UK and to the continent via pipelines.
At SnØhvit there is no infrastructure offshore, so the whole development is subsea, and it’s in an Arctic environment. We are up to about 80% production there.
[Back in the Gulf of Mexico] we are working on Tahiti with Chevron, and that is coming on production this year, and we are also working on Jack/St. Malo with Chevron, which is the first major development in the Walker Ridge area. And on both of these fields, it seems that some of the technology that we have experience with from Norway will be implemented, like subsea pumping and water injection. 
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THE AUTHOR
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Øivind Reinertsen moved to Texas in the fall of 2005 to open Statoil’s office in Houston. After the merger with Norsk Hydro in 2007, he took his current position as President of StatoilHydro USA & Mexico. Mr. Reinertsen has a long career with Statoil and has been involved in developing large projects off the coast of Norway. He was responsible for the operation of Sleipner and Gulfaks Fields, and worked offshore as Platform Manager for Sleipner Field. He came to Houston from his previous position as Senior Vice President with responsibility for all operations and activities in the Tampen area, one of the main areas of production for StatoilHydro on the Norwegian Continental Shelf. Outside of Norway, Mr. Reinertsen has managed the Statoil office in the Netherlands. He earned his degree in petroleum engineering from the University of Stavanger in 1976.
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