Latest Oil and Gas News Russia

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  0 Comments

T.N. Nasr, Alberta Research Council

Russia has always been known as a major force for hydrocarbon production; indeed there have been times when it has bested Saudi Arabia as the globes top. It has been a market in transition recently; the pumps at the giant Soviet era fields have started to wain over the last few years and the years of underinvestment in exploration have started to take there toll. Production has fallen steadily and only recently have the exploration boundaries been pushed further in Siberia and the Russian Arctic.

With some experts predicting peak oil as early as 2030, there is more and more interest in so called "unconventional resources" such as heavy oil and bitumen. Technology in the recovery of such reserves is advancing rapidly and suddenly this huge country with depleted hydrocarbon reserves has an opportunity for the future.

So, what percentage of Russia's oil can realistically be recovered? The best sources available are from BP and the Oil and Gas Journal, but they differ by some 13 billion barrels.


The graph above makes no distinction between conventional or unconventional oil; however the USGS has speculated that the Russian Federation has roughly 13.4 billion barrels of technilcally recoverable heavy oil and 33.7 billion barrels of technically recoverable barrels of bitumen. The most promising technology being used in the heavy oil capital of the world, Canada, is Steam Assisted Gravity Drainage (SAGD)


Canadian Bitumen Resource
The Canadian bitumen deposits are almost entirely located in the province of Alberta. Three major deposits are defined as Athabasca, Cold Lake and Peace River. The average depths of the deposits are 300, 400 and 500 m, respectively. The total initial volume-in-place of bitumen is estimated to be 259.1 billion m3. This estimate could ultimately reach 400 billion m3 by the time all exploratory developments are completed. This shows that Canada has the world's largest bitumen deposits. Out of the total volume, 24 billion m3 are available for surface mining techniques. Athabasca deposit is the only deposit with surface mineable reserves. About 376 billion m3 lie too deep to be surface-mined and are exploitable by in-situ technologies. However, approximately 12%, or - 50 billion m3 of the total volume-in-place is estimated to be ultimately recovered by existing technologies. That percentage is expected to increase as more advances in recovery technologies are made. Most recently, advances made in directional drilling and measuring while drilling (MWD) technologies have facilitated development of new in-situ production technologies such as the steam assisted gravity drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD) that have significantly improved well-bore reservoir contact, sweep efficiencies, produced oil rates and reduced production costs.

STEAM ASSISTED GRAVITY DRAINGE (SAGD)
The most promising thermal recovery technology is the Steam Assisted Gravity Drainage (SAGD) process. In this process, two horizontal wells separated by a vertical distance are placed near the bottom of the formation. The top horizontal well is used to inject steam, which rises forming a large steam chamber above the well, and the bottom well is used to collect the produced liquids (formation water, condensate, and oil). The rising steam condenses on the boundary of the chamber, heating and entraining the oil to the production well. The process leads to a high recovery and high oil rate at economic oil-to-steam ratios (OSR). Butler developed an empirical correlation for determining the oil rate from the SAGD process as a function of reservoir and oil properties. This correlation is given by the following:


The Underground Test Facility (UTF-Phase A) at Fort McMurray, Alberta, Canada was constructed in 1985 by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and industry partners to test the SAGD technology. The process was tested from December 1987 to mid 1990. The UTF-Phase A project was the first successful field demonstration of the SAGD process. In addition to proving the concept of SAGD, it also provided operational know-how, which is critical to its successful commercial application.


Shafts and tunnels are used for underground access of the reservoir

Following the success of the UTF Phase A project, 500 m long horizontal wells have been used in subsequent phases to further test the commercial viability of the SAGD process. In addition, a number of field pilots are in progress in other heavy oil reservoirs in western Canada (Alberta and Saskatchewan), and around the world. These pilots tested the use of surface accessed horizontal wells and extended SAGD applications to problem reservoirs. These reservoirs often have lower permeabilities, are deeper, have bottom water transition zones, with initial gas-saturated "live" oil and top water / gas caps. In Alberta, the success of these pilots has led to a number of commercial SAGD projects that are currently underway.


Surface accessed SAGD horizontal wells

Current developments of the SAGD process are aimed at improving oil rates, OSR, reducing energy and minimizing water disposal requirements. In addition to SAGD, progress has been made in the development of combined steam-solvent injection processes, a novel approach for combining the benefits of steam and solvents in the recovery of heavy oil and bitumen. A newly patented Expanding Solvent-SAGD "ES-SAGD" process has been successfully field-tested recently and has resulted in improved oil rates, OSR and lower energy and water requirements as compared to SAGD.

THE ES-SAGD PROCESS
In the ES-SAGD concept, a hydrocarbon additive at low concentration is co-injected with steam in a gravity-dominated process, similar to the SAGD process. The hydrocarbon additive is selected in such a way that it would evaporate and condense at the same conditions as the water phase. By selecting the hydrocarbon solvent in this manner, the solvent would condense, with condensed steam, at the boundary of the steam chamber. Condensed solvent around the interface of the steam chamber dilutes the oil and in conjunction with heat, reduces its viscosity.


The ES-SAGD concept

In the example shown below, as the carbon number of the solvent additive increases, the vaporization temperature increases. Hexane has the closest vaporization temperature to the injected steam temperature (215 C at the operating pressure of 2.1 MPa) and resulted in a higher oil drainage rate. On the other hand, C8 has a vaporization temperature that exceeded the injected steam temperature and a decline in oil drainage rate is noticed as compared to Hexane.


Impact of solvent type on oil drainage

EnCana Corporation of Canada has piloted the SAGD-solvent process at its Senlac Thermal project in 2002 for heavy oil and has tested and still operating this process at its Christina Lake SAGD project for bitumen. At the Christian Lake project, conventional SAGD was operated for about 5 months followed by introduction of the SAGD-solvent for about half a year till February 2005. A significant improvement of oil production rate and SOR were observed within this short time interval. A major improvement in produced oil quality was also observed. Suncor Energy, and other oil companies, are currently testing, or planning to test, the SAGD-solvent process in the field.

Labels: ES-SAGD, Heavy oil recovery, hydrocarbon reduction, oil gas, Russian Arctic, SAGD, Siberia

posted by The Rogtec Team @ 16:15  0 Comments