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Russia s oil production growth has slowed in recent years, from double digits in 2003 to just 2% last year. The ‘boom’ came mainly from reinvigorating the West Siberia area, first discovered and developed in the Soviet era. Application of more advanced technology allowed production profiles to be increased but West Siberian growth is now slowing.

If Russian production levels are to be maintained, of course one option for Russia is to open, explore and develop new areas, for example by extending West Siberian success to both the north and the south (Yamal and Uvat) or building on early successes in East Siberia.

However, an additional option for West Siberian fields is to recognize the distinction between the recent application of those technologies which have successfully transformed production rate, and the use of "Know How" which could still lead to an increase in reserves and hence, at least potentially, to a transformation in production capacity.

By and large, the application of technology, in the form of for example:

Well Construction, especially Directional and/or Underbalanced Drilling
Coiled Tubing Operations
Completion
Mechanical Operations
Stimulation, Fracturing, Chemicals etc
Artificial Lift

leads simply to existing reserves being produced earlier than otherwise would be the case. Indeed, over-vigorous “pulling” on existing reserves can ultimately lead to damage to a field, for example to premature water breakthrough, and hence to a reduction in field reserves. Saudi Arabian examples illustrate these points (Simmons, Twilight in the Desert, 2005).

In contrast, reviewing studies where increases in reserves are demonstrated, the application of "Know How" seems to be key. I illustrate this with 3 SPE papers:

Back in 1993, BP and Arco (Szabo & Meyers, SPE Western Region Meeting, 1993) described the "Development History and Future Potential" of the Prudhoe Bay Field, the largest producing field in North America, then expected to yield at least 25% more reserves than estimated at start up. Their paper briefly described the history of the field and some of the key developments that had taken place which had contributed to improved recovery efficiency. These incremental developments resulted from a process of continuous surveillance, interpretation of field performance, management of multiple reservoir mechanisms, efficient utilization of the gas resource, and exploitation of the existing field infrastructure.

Four dominant recovery processes were at work in Prudhoe Bay: Gas Cap Expansion/Gravity Drainage, Waterflood, Miscible Flood, and Gas Cycling. Continuous management of these processes and analysis of field performance had led to identification of attractive targets for further development.

Even in 1993, Prudhoe Bay was seen by many as a mature oil field on an inevitable and irreversible decline. However, the major Owners (who included Exxon) in Prudhoe Bay had continued to pursue incremental developments to mitigate decline and supplement proved reserves. Unit technical studies were (and are) typically done in multi-company, multi-disciplinary work teams. The pooling of resources, experience and knowledge in this manner enabled efficiency gains and promoted the sharing of ideas and best practices.

In 2004, ExxonMobil (Wilkinson and others, SPE International Conference, 2004) described "Lessons Learned from Mature Carbonates…." based on three long-life fields in the USA (the Jay, Salt Creek and Means Fields), exemplifying the benefits achieved by a continuous process of data collection, studies, and systematic application of available technologies. The example fields "will achieve a range of incremental increases in the recovery factor of between 8 and 20% OOIP…….." A systematic and integrated approach to reservoir management has been employed to understand the basic rock and fluid physics of each reservoir and the key parameters that impact reservoir performance.
……..ExxonMobil has established a large knowledge base of secondary and tertiary project experience at the laboratory, pilot-test and field implementation stages."

In 2005, several SPE authors (Moulds and others, Offshore Europe, 2005) described reservoir management issues associated with the North Sea Magnus Field. Magnus is a high productivity field from which oil was first produced in 1983 and for which the production plateau of 150mstbod ended in 1995. Post-plateau, a variety of reservoir management techniques has been used to arrest decline and by 2005, through exploitation of a gas injection EOR opportunity, the oil rate was again rising and looking ahead, additional drilling to access more reservoir was anticipated to maintain significant oil production ‘beyond the next decade’. In this opportunity-rich field, prioritisation of drilling targets was seen as key, with EOR wells vying with infill waterflood targets and extended reach wells to the (untapped) field periphery. The particular challenge described (and met) by the authors is that, due to non-uniqueness, a conventional full field reservoir simulator history model cannot sufficiently reduce uncertainty on drilling locations and facilities decision: in fact, future reservoir processes and performance may be sensitive to aspects of reservoir description that have little influence on the history match.

So “Know How” is about integrated, multi-disciplinary teams, building knowledge, dealing with great uncertainties, learning from their mistakes: it is acquired by having explored for, developed, managed and produced hydrocarbons around the globe and thus is the preserve of IOCs.

It is not generally available from oilfield service contractors who may well own some technologies but do not know how as defined above. In addition, contractors do not participate independent from their technology – indeed being paid premium prices for its deployment is part of the business model which induces them to invest in technology development in the first place.

Provinces such as Alaska (for BP and Arco), USA Gulf Coast (for Exxon) and California (for Shell and Exxon), North Sea (for Shell and BP) have honed company and individuals’ skills. Another way of saying this is that the oil & gas industry is knowledge-based, that is, dependent on people and not simply on technology. And all the signs are that in the short to medium term there will be a shortage of appropriately educated and trained or trainable staff. As I’ve discussed elsewhere, I believe that a “scramble” for this resource is under way.

This argument does not of course dismiss the important impact of technology.

In simple terms, IOCs apply technology to developments and producing fields to:

a) Image what’s there
b) Reach what’s there
c) Extract what’s there.

The last ten years have seen dramatic developments in the use of seismic technology, specifically "time-lapse" 3D, otherwise know as 4D, to Image fluids within reservoirs.
This technology – involving conventional surface-towed sources and streamers – has transformed reservoir management from its previous situation where the main approach to understanding reservoir dynamics was to build a 2D or preferably 3D simulation model based on relatively long-term production history (oftentimes an epic labour of love somewhat akin to the building of the Grand Mosque* in Cordoba!).

The North Sea has been greatly impacted by 4D technology but perhaps an even greater impact will come in deep-water fields where wells are very expensive and thus any increase in certainty as to fluid movement is exceptionally valuable.

This said, it would be facile to assume that what is done today represents the limit of what is achievable with geophysical technology, whether in acquisition, processing or analysis. Indeed, it is widely envisaged that The Instrumented Oil Field lies in the (near) future with down-hole
sensors recording seismic and electro-magnetic waves, and perhaps potential fields (gravity and magnetic), and seismic and electro-magnetic sources complementing conventional surface (and sea-bed) sources and sensors.

Globally, the most significant problems associated with this vision are:

Developing sensors and sources that are reliable down-hole,
Delivering said equipment to the reservoir, without interrupting production, and
Analysing the data to deliver a usable Image.

However, the issue in Russia is this:

By an accident of history, Russian geophysical contractors are focused onshore, somewhat regional, have relatively weak technical quality assurance and HSE standards, no experience of 4D, and little understanding of working as an integrated part of a multi-disciplinary (reservoir management) team.

Western geophysical contractors have global onshore and offshore experience, good technical quality assurance and HSE standards, significant 4D experience, and are used to working with multi-disciplinary teams. However, with the exception of WesternGeco via its relationship with PetroAlliance, they have shown little appetite for, or commitment to, working in Russia.

There seems therefore to be both a pressing need and a clear opportunity for a multi-national service company to bring new geophysical ideas to the development and production of Russia’s onshore and offshore resources. A merger between a Russian contractor and a Western one seems to be called for.



*The Grand Mosque in Cordoba:

Cordoba fell to the Moors in 711AD:
Late 8th C AD, the original Mosque was built
833-852 AD, first extension
961-966 AD, second extension
987 AD, final extension.

Following the re-conquest of Cordoba in 1236 AD:
1254 AD, Chapel of San Clemente added
1258 AD, Capilla Real added
Late 15th C AD, Chapel of Villaviciosa added.

Labels: artificial lift, oil gas russia, rogtec, Siberia, Well Construction, Western Siberia

posted by The Rogtec Team @ 17:41 

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