August 30, 2008
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Home / Issue Archive / 2006 / September #9 / ENI Answers the Kashagan Challenge

№ 9 (September 2006)

ENI Answers the Kashagan Challenge

In the Top 10 list of “world-class” offshore development projects presently underway, one of the main contenders for the No.1 spot lies in Kazakhstan’s northern portion of the Caspian Sea.

By Mark Thomas

The Kashagan field, lying in the North Caspian Sea PSA contract area, is located about 80 km from Atyrau and covers an area of approximately 75 km by 45 km.

It is not only the sheer scale of this frontier project that puts it at the top of almost anyone’s list – it is one of the largest oil fields discovered in the last 30 years – but its extreme technological complexity.

Operator ENI of Italy, via its subsidiary Agip Kazakhstan North Caspian Operating Company N.V., is tackling the development of a field that presents one of the greatest challenges of the petroleum industry, given the following characteristics: a deep, high-pressure reservoir; high (16-20 percent) sulphur content with associated production of poisonous and extremely corrosive hydrogen sulphide (H2S); shallow waters that range from 3 to 4 m in depth and freeze from November to March and sea-level fluctuation during the rest of the year; wide surface temperature variations from -30 C to +40 C; several logistical challenges due to the remote location; and a surrounding environment considered to be possibly the most sensitive you could wish (or not wish) for, with a variety of internationally protected species of fauna and flora.

This does not make for pleasant reading if you are one of those tasked with developing such a field. However, one thing we all know for sure is that the oil industry likes a challenge.

And ENI, holding as it does an 18.52 percent stake in the field, is proving to be well up for that challenge.

The company itself says the development is “advancing as planned”, with more than 46 percent of work already completed and first oil expected by the end of 2008. Eventual plateau production in the full development phase is targeted at more than 1.2 m b/d, although initial output in the “Experimental Program” phase will be a more modest 75,000 b/d rising to around 450,000 b/d at the end of the phase. A second phase will raise that output to a predicted 900,000 b/d and to the 1.2 m b/d figure by the end of the third full development phase.

This comes from a recoverable reserve base currently estimated at about 13 bln bbl, if and when partial gas injection is applied.

So far the project has been anything but easy, bearing in mind first oil was originally planned for mid-2005 and then shifted back to its current 2008 date.

With a cost review currently underway due to several aspects including the weakening of the US dollar, increased costs for materials and services, and essentially a lack of a benchmark for similar offshore projects, there was growing belief as Oil & Gas Eurasia went to press that the current onstream date may again find itself being shifted back further to possibly late 2009 or even into 2010. This could be due to an increasing perception that there is a need for further artificial islands and field facilities in order to ensure the safety of the field’s workers and minimize the technological risks.

However many observers would say that this was always going to be a “mega-project” that would throw up severe challenges.

With total gross capital expenditure estimated at US $29 bln, the development entails the drilling of 280 wells and the initial construction of platforms and three artificial islands (hubs), which in turn will collect production from “satellite” islands.

Oil and non-reinjected gas will be treated in the hubs and delivered, through two separate lines, to onshore treatment plants (located at Eskene West, near Atyrau). The oil will be further stabilized and purified; natural gas will be treated for the removal of hydrogen sulphide and will be mostly used as fuel for the production plants. The remaining amounts will be marketed.

The biggest problems center of course around dealing with the field’s high pressures and the significant presence of hydrogen sulphide.

All those involved in the project say though that it is the combination of challenges that makes Kashagan so unique.

It is the first time that oil companies have had to deal with such a high concentration of hydrogen sulphide on such a large scale as that found in Kashagan’s oil (up to 19 percent), along with the uncharacteristically high reservoir pressure so far encountered, the absolute need to resolve completely the gas and sulfur utilization problems, and the sheer distance from global markets.

Add to this the shallow water depths and the unpredictable movement of the ice in winter further complicating the delivery of cargo to and from offshore structures, and the problems appear to be overwhelming.

But it is the H2S that has been most taxing.

There is another Kazakh field with almost the same situation, Tengiz, where H2S makes up 17 percent of the reservoir. Onstream for more than a decade, this is a project where mountains of sulphur have been visibly growing in the public eye, a by-product from treating the field’s sour gas. These tips now reportedly total more than 9 mln tons.

A third field in the country, Karachaganak, has been producing for more than 20 years but only has around half the concentration of sulphur as the other two projects.

Oil companies do of course have experience of dealing with sulphur elsewhere in the world at levels equivalent to Kashagan, such as in Alberta in Canada.

But the added complexity at Kashagan comes with its extremely high reservoir pressures.

An ideal way, and usually the industry’s weapon of choice, to solve the sulphur problem at any field producing sour oil and gas is to re-inject the H2S after it has been separated out, also helping to improve ultimate oil recovery by maintaining reservoir pressure over a longer period of time.

Geological arguments do exist, however, especially as in the early stages of field life – when natural pressure is high – the formation might be easily damaged. The commercial costs of drilling a large number of re-injection wells is also a major factor, accentuated by the exotic and therefore expensive steels needed to carry the corrosive H2S.

Producing and selling sulphur is an option but the market for this product remains far from buoyant, with the volumes that would be produced at Kashagan likely to be much more than the market needs.

Karachaganak has lead the way on the re-injection front, with one of the world’s highest pressure sour gas injection schemes completed there in 2003, pumping at around 8,000 psi. So far nearly 7 bcm of gas a year is being injected using this method.

Tengiz has its own sour gas injection program that will operate at an even higher pressure of 9,000 psi.

ENI and its partners have watched and learned some important lessons from these other fields.

When Kashagan eventually comes onstream, facilities at the onshore terminal will be ready to deal with all incoming H2S until production rates have grown to 150,000 b/d of oil. The sulphur produced will go to a buffer storage zone with the emphasis to be on selling it.

Re-injection is then an option to be used possibly within the first year, depending on how the field’s wells behave individually. The sour gas injection program for the field is likely to be at around 11,000 psi.

Even this, however, will not remove all the sulphur produced, and so the operator is still weighing up other alternatives including disposing of it in old open-pit mines or perhaps in permanently covered storage below ground.

Long term, the solution remains to find a n ew technology breakthrough allowing the field’s gas to be sweetened offshore and the produced H2S to be pumped right back below ground immediately afterwards.

So although further delays are unlikely to be officially welcome, any added time would further serve to allow the participants to optimize the development not only of Kashagan but also of other fields in the North Caspian PSA area. These fields, Kashagan South West, Kalamkas (two wells are planned for drilling between now and 2008), Aktote (undergoing appraisal studies) and Kairan (the Kairan-2 well is in progress), are all being separately appraised as we speak.

But adopting a “wait and see” strategy is likely to serve ENI well, especially as the very real environmental concerns have caused the Kazakh Energy Ministry to kick off a new study to assess the impact of both existing and future offshore oil and gas developments on the fragile environment of the shallow northern portion of the Caspian Sea.

Conducting any pioneering mega-development in a frontier offshore area always produces several false starts and dummy runs. That has happened around the world throughout previous decades with large scale/large expenditure projects, from the North Sea’s Brent field to Qatar’s North Field and several currently coming or recently come to fruition in deepwater off West Africa.

But when Kashagan eventually starts to flow – which it surely will – then Kazakhstan’s offshore sector will suddenly be transformed from a provincial backwater into an offshore powerhouse.

Copyright © 2007 Eurasia Press, Inc. (USA). All rights reserved.
Copyright © 2007 Eurasia Press (www.eurasiapress.com)