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Monday, 29 March 2010

The ROGTEC Interview: Ken Gardiner from Seismic Micro-Technology Europe, Ltd

What is your position in the company and how long have you held this?
I manage the Seismic Micro-Technology Europe Ltd. operations based in Croydon, U.K. and am the Vice President European, African and Russian Operations. I joined SMT just over 7 years ago to open up our first international office and we have been aggressively growing the business since then.

How long have you been in business in Russia and the Caspian?
We have covered business opportunities in Russia for more than 15 years. In Fourth Quarter 2005 the Croydon office took on board Pavel Morozov to cover sales in Russia and the former Soviet Union Countries. The success of this business led us to open a full sales and support office in Russia, based in Moscow. This was opened in mid-2008 with Nikolay Kutsenko as Country Manager and ably supported by several staff members.

What companies have you worked with in the Region?
We have worked with quite a number of different sized companies both based in Russia and operating in the CIS region, additionally having good relationships with a number of companies in Kazakhstan. These include such companies as the Rosneft group of companies, the KazmunaiGaz Group, Lukoil Overseas, PGS, CGG and Fugro. In total, there are more than 70 we have worked with in the region.

What is your most recent success in the market?
SMT has enjoyed continued business success with Gazprom companies, working on both Russian and International projects, and Rosneft and developed business opportunities with Zarubezhneft and AGIP KCO as well as Block N Operating Company.

Have you and any recent product launches for the region?
We have had a number of releases that offer new functionality that is critical for this region. For example, we released a new product line called KINGDOM Advanced that is specifically tailored for the types of organizational needs in this region. And with our upcoming release, we plan to have Russian language support for our geoscience solutions.

What is your favourite band and track?
My current favourite band and track of the moment has to be driving music such as Chris Rea and "The Road to Hell" so I can enjoy getting out in a Nissan GTR which I just bought 6-weeks ago. And yes it’s a great car to drive.

Where in the world would you most like to visit and why?
I enjoy travel, but as I am always on the move for business, the place(s) I most like to visit are holiday destinations such as the South Luangwa Valley in Zambia for safaris and great, but infrequent, spotting of leopards.

What is your favourite sport, and what team do you support?
My favourite sport is both a leisure activity, and as everyone will appreciate, a frustrating game, golf. I am a member of Banstead Downs Golf Club in Surrey. As regards a team sport I enjoy football and watching Manchester United play.

What are your thoughts on the Russian oil and gas market through to the end of this year and beyond?
The steadying of the world's economies and the steady rise in the price of oil to a reasonable but sustainable level has benefited all countries where oil exploration and development is carried out. Particularly in Russia where there are large un-tapped areas to be explored. The current economic climate in Russia makes it feasible to carry out oil exploration and bring new projects online and will definitely benefit the Russian oil and gas market through 2010 and beyond.
posted by The Rogtec Team @ 16:12  0 Comments

Issue 20 News

The Mobius Group launch "PowerTec Russia & CIS"
The Mobius Group of companies, renowned marketing and print media specialist - launched their second regional title at the recent Russia Power exhibition in Moscow.

Leaders in printed marketing within the Russian and Caspian upstream O&G sector, The Mobius Group is proud to announce its push into the Russian power generation and distribution sector, with its new title "PowerTec Russia & CIS".

PowerTec will cover the latest news, projects, investments, case studies, technology reviews & corporate interviews across the regions power generation sector.

Distributed initially on a bi-annual basis, with bi-lingual language format, PowerTec will be an important source of vital information to the regions exciting and quickly developing power generation sector.

For more information link to www.powertecrussia.com

Russia to spend RUB 40 bn for shelf exploration
Russia will spend about RUB 40 bn on exploration works at the country's ocean shelf by year 2020, Minister of Natural Resources Yuri Trutnev announced.

In 2009, shelf exploration dropped following the financial crisis. Commenting on the more than RUB 9 tn, which the Natural Resources Ministry believes is necessary to invest shelf development in the period, the minister said this money will have to be "collected from all over the world".

Russia in 2008 spent a total of RUB 1.2 bn on shelf exploration. In 2009, the sum dropped significantly following the financial crisis.

TNK-BP Advocates Flexible Approach to APG Utilization for Greenfields
TNK-BP finds it expedient to make associated petroleum gas (APG) utilization requirements more flexible for greenfields.

German Khan, TNK-BP Executive Director, said to the media that greenfield subsurface specificities and development conditions frequently make greenfield APG utilization uneconomic.

"The law that obliges to bring APG utilization to 95% by 2012 does not consider greenfield structures. It is not always economically viable to set up an APG utilization infrastructure at the initial stage of operation of such fields due to their process and subsurface specificities", he said.

"The state should exhibit some flexibility in this aspect", Khan added.

He emphasized that there is no need to change the general deadlines for bringing APG utilization to 95%. What is needed is an amendment to the law with regard to greenfields only.

The APG utilization issue and energy efficiency were discussed at a meeting in Belozernyi GPP that was attended by Deputy Prime Minister Sechin

Gazprom bags Bulgaria block
A Gazprom-led consortium has been awarded the Provadia block in eastern Bulgaria.

The consortium consisting of Overgas, a Gazprom joint venture, JKX and Balkan Explorers will operate the 1787-square-kilometre onshore block, which is partially carved out from the 2007 B-Golitza and B1-Golitza licences.

Overgas will operate the onshore block with a 64% stake. Balkan Explorers, a wholly owned subsidiary of Aurelian Oil and Gas, and JKX each will own 18%

'Kovykta reclaim will be fair'
Russia's top energy official Deputy Prime Minister Igor Sechin recently anounced that any decision to strip TNK-BP of its licence for the Kovykta gas field in Siberia should be "fair" and that costs should be compensated.

Sechin sought to reassure TNK-BP, holder of the licence for the Kovykta gas field in East Siberia, that any decision to strip the company of the licence would be fair and that any costs incurred would be taken into account.

"There's no talk of any blatant expropriation. I think we will find a solution to this issue," he said.

TNK-BP, half-owned by BP, is involved in a decade-old dispute over Kovykta, which escalated last month when environmental watchdog RosPrirodNadzor recommended the company be stripped the licence.

"I don’t think the issue is so acute," Sechin said. "The expenses incurred must be taken into account."

Some Russian officials have said TNK-BP failed to follow obligations outlined in its license for Kovykta, including the launch of full-scale production.

Russian Billionaires are Number one in Europe
Russia has the largest number of billionaires among the European countries, Forbes magazine has said. According to the Forbes' annual list of world's richest people, the number of billionaires in Russia has risen to 62 from 32 last year. The list of Russian billionaires widened due to 28 returnees who had fallen off last year's list amid a meltdown in commodities, Forbes said.

Vladimir Lisin, the owner of the Russian steel giant Novolipetsk Steel, is Russia's richest person with a fortune of $15.8 billion, according to Forbes. The tycoon occupies the 32nd position in the magazine’s list of world's richest people. Mikhail Prokhorov, the president of Onexim Group who topped last year's rankings, is second in the 2010 list of richest Russians with an estimated wealth of $13.4 billion. TNK-BP interim CEO Mikhail Fridman is Russia's third richest person, with a $12.7- billion wealth.

RWE Group Signs MoU for Exploration Activities in Azerbaijan
The RWE Group and the State Oil Company of the Republic of Azerbaijan (SOCAR) have signed a memorandum of understanding to draw up an agreement for the hydrocarbon exploration and development for the Nakhichevan perspective structure in the Azerbaijan sector of the Caspian Sea.

The memorandum of understanding was signed in Baku by the President of SOCAR, Rovnag Abdullayev, and Dr. Jürgen Großmann, Chairman of the Board of Management of RWE AG. As a result, RWE will also be able to grow in the upstream sector. The agreement relates to the Nakhichevan structure in the Caspian Sea, about 50 kilometers off the coast of Azerbaijan

China Oil demands jumps "astonishing 28%"
China's demand for oil jumped by an "astonishing" 28% in January compared with the same month a year earlier, the International Energy Agency (IEA) says. The body added that demand for oil in 2010 would be underpinned by rising demand from emerging markets, with half of all growth coming from Asia. But the IEA predicted demand in developed countries would fall by 0.3%. The IEA has increased its global oil demand forecast for 2010 by 1.8% to 86.6 million barrels a day. Russia is building new transport infrastructure linking the promising fields of Eastern Siberia to China to satisfy China's energy thirst.
posted by The Rogtec Team @ 16:03  0 Comments

Cold Production in Western Canada: A Step Forward in Primary Recovery

Ron Sawatzky, Marlene Huerta, Mike London and Brigida Meza
Alberta Research Council*

*Now part of Alberta Innovates - Technology Futures

Canadian Heavy Oil and Bitumen Production
Canada's heavy oil and bitumen resources are extensive. They are located in the northern portion of the Western Canadian Sedimentary Basin (WCSB). The WCSB contains an estimated 1.7 trillion bbl of bitumen in place, primarily in three deposits - Athabasca, Cold Lake and Peace River. Canada's current production of bitumen exceeds 1.2 million bbl/d. The choice of technology for recovering bitumen is delineated by the depth of the sand. For deposits less than 50 m from the surface, open pit mining operations are used to recover the oil sands and then the bitumen is recovered from the mined sand; for deeper deposits, in situ recovery technologies that reduce oil viscosity and enable oil to flow must be used. Steam-assisted gravity drainage (SAGD) is in an early commercial phase of implementation. Other in situ recovery technologies are at an early pilot stage or laboratory stage. Approximately 60% of Canada's bitumen production is from surface mining operations, although it is estimated that less than 10% of Canada's bitumen resource is recoverable by surface mining.

Included among Canada's heavy oil and bitumen resources is approximately 25 billion bbl of conventional heavy oil. The majority of this resource lies in the general Lloydminster region straddling the Saskatchewan-Alberta border. Although this heavy oil resource is insignificant compared with Canada's bitumen resources, it continues to contribute significantly to western Canadian heavy oil and bitumen production. Canada's current heavy oil production is estimated to be approximately 500,000 bbl/d, only slightly less than in situ bitumen production.

A number of methods are used to recover Canada's heavy oil, including conventional primary production, water flooding, unconventional primary production (cold production) and to a lesser degree, various thermal in situ recovery techniques similar to those used for deeper bitumen resources. Cold production is a recovery technique developed for the Lloydminster block in which a substantial quantity of sand is produced deliberately along with oil, water and gas. Cold production has become the recovery technology of choice for most heavy oil fields in the Lloydminster block, accounting for nearly half of western Canadian heavy oil production.


Heavy Oil
Production of heavy oil in western Canada dates back to at least the 1940s in the Lloydminster block. Initially, primary production methods were used. Primary production continues to be an important form of recovery for the shallow, thin regional sands that predominantly characterize the heavy oil resource in the WCSB. Water flooding is another conventional recovery technology that continues to be employed successfully for heavy oil production in western Canada. An unconventional form of primary production, involving the co-production of sand, has been developed in the Lloydminster block as a commercial recovery technology. Over the past fifteen years this technology, known locally as cold production, has emerged as the dominant heavy oil production method in the WCSB. Thermal recovery technologies have been tested to a limited extent in some of the thicker channel sands that are interspersed among the thin regional sands. These technologies include steam flooding and CSS, in situ combustion, and SAGD. While a combination of steam flooding and gravity drainage has proved successful in some locations (e.g. Pikes Peak), and SAGD has been operated successfully in others, thermal recovery methods remain only of marginal importance for the heavy oil resources in the WCSB due to the relative scarcity of sufficiently thick sands in which to employ them.

Until the emergence of cold production in the 1990s, primary production was the dominant heavy oil recovery technology in western Canada. In its conventional form, it was implemented with vertical wells and rod pumps. Oil production rates typically fell in the range 1 - 5 m3/d, with recovery factors typically in the range of 3-5% OOIP; low operating costs allowed the production rates to be viable commercially. Conventional primary production continues to be practised in the Lloydminster block, mainly in thin sands in which the initiation of sand production is known to be difficult or in mature cold production wells where sand production has ceased.

Horizontal wells offer an alternative technology for performing primary production. This technology has been implemented successfully in western Canada in sands that tend not to present sand control issues. Generally, these sands are weakly or patchily consolidated. A relatively low oil viscosity (< style="font-weight: bold; color: rgb(255, 0, 0);">


Cold Production
Cold production is an unconventional primary recovery process in which sand is produced deliberately along with oil, water and gas. It is implemented in vertical, slant, or deviated wells with a progressive cavity (PC) pump. Production rates are improved substantially over conventional primary production, by as much as a factor of ten. Recovery factors tend to be higher as well, typically in the range of 8-15% OOIP. Cold production has become the recovery technology of choice for most heavy oil fields in the Lloydminster block. It currently accounts for nearly half of western Canadian heavy oil production, at approximately 230,000 bbl/d.

There is considerable evidence to indicate that sand production causes long channels of increased permeability (wormholes) to grow out from the well into the reservoir, for distances of 200 m or more. A central feature of the process is the formation and flow of foamy oil into wormholes, as they grow into the reservoir. The wormholes provide improved access to the reservoir. Among the advantages of cold production is its success in very thin sands, for zones with a net pay as low as 2m.


The development of cold production as a successful commercial heavy oil recovery technology in the WCSB has been field-driven from the outset. Field experience has lead to an optimal operating strategy for a wide variety of field conditions: a fairly rapid initial draw down (over a period of several weeks to a few months) followed by maintenance of very low bottom hole pressures (preferably less than 5 joints of fluid).


Since the cold production process depends on the continuous transport of sand along the entire length of a wormhole, from its tip to the well bore, it should not be surprising that cold production wells are not long-lived. Some last for 8-10 years or more, but many do not live nearly that long. The principal cause of failure is watering out (very high water cut) generated by water influx. Once water has infiltrated a wormhole network, it can be transported rapidly to the associated well and subsequently to interconnected offset wells. A secondary cause of failure is lack of inflow, likely caused by a blockage near the well or farther out in the wormhole network and/or by a lack of drive. Efforts are continuing to develop technologies for the remediation and stimulation of cold production wells, but successful results have been few and far between.


International Adoption of Cold Production
Although cold production was established as a successful commercial technology for heavy oil recovery in western Canada, it did not start there. Deliberate and aggressive sand production was practised in California heavy oil reservoirs (e.g. Midway, Sunset, Cat Canyon) prior to the First World War. Pays were generally much thicker than in Canadian reservoirs, in the 30-100 m range. Even without PC pump technology, individual wells reportedly produced several thousand cubic metres of sand over a 40-year life.

Producers whose assets include thin heavy oil reservoirs elsewhere in the world are viewing the success of cold production in the WCSB with interest. The key reservoir conditions that appear to be necessary for the cold production process to succeed in western Canadian reservoirs include: unconsolidated, clean sands (very low fines content); a minimum oil viscosity; mobile oil; and, a minimum initial gas-oil ratio (GOR). These conditions may also be found in reservoirs outside of Canada (e.g. in Alaska, Albania, California, Colombia, Kazakhstan, Kuwait, Oman, Russia, Venezuela). Currently, few of these reservoirs are being exploited commercially through cold production. In order to accelerate the screening of prospective international reservoirs for cold production, a technical examination of the feasibility of the process would likely need to be undertaken on a case-by-case basis, in combination with field trials.
posted by The Rogtec Team @ 15:44  0 Comments

ROGTEC Talks Drilling Technology for the Verkhnechonskoye Field with Schlumberger D&M


Referring back to the VCNG article; What do you feel were the key factors for success when working with VCNG?

I feel some of the key factors contributing to this successful deployment would be having a systematic approach to the project. We fully employed the Schlumberger D&M Management System, this included training and planning the personnel (Field Operations and Maintenance). We also had a very methodical approach towards BHA design, BHA selection and ultimately we delivered on our promises with the system. Finally we had great communication with the client over the entire course of the project.

All of this has resulted in a step change in the overall drilling performance of TNK-BP VCNG. Alongside this we also had great success with the launch of the PowerDrive675 in the Vankorskoe field for Smith Production Technology and Rosneft in 2007.

Roughly how long has the tool been in use in Russia?

The first PowerDrive job we did in Russia was for Shell, on an offshore field in Sakhalin, in 2005. PowerDrive is now a core service for Schlumberger D&M in the whole of Russia. We have all the components in Russia to execute this service successfully. We have working tools across the whole region with local Russian expertise capable of executing these jobs. We also have local maintenance facilities set up to service the tools, even remotely. We also have a centralized Operations Support Center to monitor all jobs in real time. This is extremely important for our clients as it translates into better service quality and less cost. With regard to total meters drilled, we have drilled more than 350,000 meters with PowerDrive in Russia alone. Globally, the tool was first launched back in 2001.

What would you say are the key advantages that PowerDrive brings to operators who deploy it?

Three of the key advantages are:

The time savings that the tool brings. You get improved ROP and there is no lost time through sliding plus there are multiple benefits through drilling efficiencies.

Improved well bore conditions where you have smoother wellbores with less tortuosity. This also simplifies wellbore cleanout and reduces completion costs.

Finally there is generally a reduced risk with the well bore and you can also minimize the risk of stuck pipe. PowerDrive is a unique RSS tool that has a fully rotating system, this helps reduce the stuck pipe risk. It is part of a flexible system that can combine with MWD/LWD sensors. With Real Time measurements close to the bit, you can enable processes, as discussed in the VCNG article, which greatly improve well placement and improve trajectory control. For the operator this results in minimizing drilling cost and maximizing production through a step change in drilling performance and horizontal well placement.

What other regions in Russia or regional formation types would most benefit from this system?

PowerDrive has been used by the following operators:

  • Rosneft on the Vankor Project
  • Rosneft on the SMNG Project
  • TNK-BP on the VCNG and Samatlor Projects
  • Lukoil on the Korchagina Project
  • Lukoil on the Usinskoe SAGD Project
  • NMNG on the Yuzhno-Khalchuyu, Yareyu and Toravey Projects
  • Total on the Kharyaga Project
  • SEIC in Sakhalin
  • ENL in Sakhalin

There are also several smaller projects in West Siberia that are benefiting from the PowerDrive Service. It is formation independent and will bring significant benefits to all potential clients, not only Oil Companies but also General/Drilling Contractors.

You briefly mention the benefits of the Real Time solutions in the article. Could you expand on this?

The Real Time capability of PowerDrive has the biggest impact in improved Real Time decision making. This enables better Well Placement resulting in increased reservoir contact (increased NTG). Within the drilling parameters, optimization enables better drilling performance (increased ROP). So the client has a higher quality well bore, delivered in less time with increased contact with the payzone.

General speaking and not referring to the case study, what level of cost saving can the tool bring to an operator?

Operators are mainly interested in two key points which we focus on to the highest level: decreasing cost per meter and increasing production. We are decreasing the cost per meter by increasing the commercial ROP, which effectively means reducing the AFE by saving days.
This can be done in multiple ways; increasing the ROP during drilling. Reducing the flat times (better planning and better wellbore conditions). Reducing unplanned events like stuck pipe through technology applications like PowerDrive and the application of DCS Domains like GeoMechanics.

The level of saving could be different depending on the type of project and the complexity of the formations or reservoirs. However, based on our worldwide experiences, we have successfully delivered results in drilling performance and cost saving that exceeded our customers' expectations.

An example of this would be in deepwater or arctic offshore projects, where a single day of saving could means a significant dollar saving due to extremely high rig rates. The other major benefit to the client is increased production. By bringing a field on stream earlier the operator benefits from this production.

The production is also increased through more efficient well placement.

What is the next step forward for you on the technology side?

The next step in further drilling optimization for our clients in Russia is the introduction of the PowerDrive Vortex in several locations. PowerDrive Vortex is a service that combines PowerDrive with a high power motor (A700GT) to provide extra drilling energy to the system for another step change in drilling performance. PowerDrive Vortex is designed to drastically reduce and eliminate the stick and slip effect thereby improving the efficiency of energy transfer to the drilling bit. The combination of Vortex with the latest MWD tools and telemetry support (Orion compression) allows for faster downlink of steering commands and directional surveys transmission, making the PowerDrive services more effective than ever.

Having started out as a Field Engineer in Abu Dhabi and Iran, Chin Seung Way has worked for Schlumberger in Egypt, China and Houston. Since 2009, he has been Operations Manager for Drilling & Measurements, Eastern Siberia, managing business of over $120M and one of the most challenging operations of Schlumberger in Russia.
posted by The Rogtec Team @ 15:21  0 Comments

Bearing the Risk and Taking the Reward : Verkhnechonskoye


Kevin Wilson:
Drilling Director, VCNG

Back in 2007, Verkhnechonskoye (VC) project was considered uneconomic, yet today there's no doubt about the commercial potential of the field. First and foremost this is thanks to CAPEX optimization in drilling and infrastructure.

VCNG continues its drilling effort building the most complex wells in TNK-BP Geosteering to meet the unique geological challenges of the field. The company has recently achieved a record of 18 days per well thus reducing its initial drilling rate more than thrice! Kevin Wilson, VCNG Drilling Director, talks about the technological advances and work optimization approaches that ensured this remarkable acceleration.

The complexity of subsurface structure in Verkhnechonskoye (VC) field is unique and most of those complexities present challenges on drilling viewpoint.

To start with, the reservoir is very shallow (1,650 m deep), the productive horizon is less than 10 m. The reservoir is heterogeneous with areas of different permeability due to the mineral salt depositions. Therefore, the net pay zone in the 10-meter thin section is even smaller reaching about 3m.

These challenges impose the need for some front-end technology to ensure cost-effective drilling in VC field.

Hitting the Sweet Spot
When VCNG began drilling back in 2005, only vertical wells were built at the time. Considering the thin net pay of VC formation those wells did not show great productivity. Later, the drilling plan was thoroughly revised with a view to the geological structure of the reservoir. The project subsurface team proposed a development plan based on directional and horizontal wells rather than vertical wells. This helped halve the initially planned number of wells while maintaining overall productivity. However, due to the heterogeneous nature of VC formation some horizontal wells happened to be drilled in areas with poor permeability and had low flow rates.

The solution to boost the initial flow rates was found in 2009. The use of rotary steerable systems by Schlumberger while allowed the drilling bit to stay inside the sweet spot of the reservoir avoiding the salt depositions and poor permeability areas. The LWD technology ('logging while drilling') provides for the installation of sensors at the drilling bit that analyze the rock geophysics and identify the areas of best permeability to continue drilling. Thus, wells with a measured depth of 3,600 m and true vertical depth of mere 1,650 m are now being drilled in VC field.

Chin Seong Way, Operations Manager East Siberia, for Schlumberger Drilling and Measurement commented:
"In this field, PowerDrive was used in combination with the advanced LWD tools to enable optimum horizontal well placement. By utlising the systems high speed, real time data transfer system, experts within Schlumberger's DCS team could provide us updates and adjustments to allow the trajectory of the well to be optimized within the sweet spots for maximum reservoir contact. All of this was achieved with out compromising the ROP."

"Overall this has reduced the drilling costs and increased the oil production for our client."

The use of LWD geosteering increased the amount of oil produced from each well. The flow rates reach 200 tpd to 250 tpd per well as compared to the average flow rate of 100 tpd of the previously drilled wells. Obviously, the new technology proves cost-effective and helps pay back the investment much quicker.

Continuous Improvement
Yet another VC challenge facing the drilling engineers is the hard rock characteristic of Irkutsk Region. The hardest rock is in the surface sections due to the presence of chirts.

To increase the rate of penetration and thus reduce the number of days per well VCNG drilling engineers use high-torque slow-speed motors and put a lot of effort into the drilling bit design.

Originally VCNG used roller-cutter bits that were appropriate in the other areas of Russia where the rock is softer. Soon it was clear that those bits did not meet the challenge and harder bits were sought for. Success came with the use of PDC bits and since then VCNG drilling engineers have been refining the PDC design. Exact charts for each bit performance are developed to identify the areas for further improvement in bit run life, rate of penetration and rate of penetration gain versus cost of bit. So far the improvements are remarkable. A well section used to be drilled with four or five bits while now only one bit is used to drill a similar section.

However the fantastic success with PDC bits refers to the lower sections only. The next challenge for VCNG drilling team is efficient application of PDC technology in the upper portions of the hole where the rock is extremely hard.


Time-Based Approach
The use of high-torque slow-speed motors and PDC bits improves the rate of penetration and thus reduces the number of days per well. Introducing the innovative technology to VCNG required a new contractual business model that in itself is a huge factor that helped boost the drilling rate over the last several years.

Traditionally, the drilling contracts in Russia have a turn-key basis. Similar approach was used in VCNG to drill vertical wells back in 2005. The average drilling time was 150 days. The responsibility for drilling a well was entirely on the contractors, so the companies preferred to play on the safe side and follow Russian norms rather than take risk to introduce front-end international solutions. There was no real incentive for the contractor to optimize the drilling rate and productivity. This is where the day-work contracts come in.

Today VCNG takes all the risks of drilling decisions and engineering and the contractor is paid for the rental of its equipment and crew only. This concerns contractors working in all areas related to drilling, e.g. directional drilling, muds, cementing. The contractor's objective is to provide VCNG with a 100-percent working equipment (a rig, a mud pump, tools, etc.) to the required specification and follow the instructions exactly. If this objective is met the contractor is paid the rent no matter whether VCNG drilling decisions have been taken or the crew has to wait and whether these decisions prove efficient or not. If the work is done ahead of plan the contractor is paid a bonus. However there is a list of penalties for the contractor in case he fails to provide all the necessary equipment.

Today VCNG takes all the responsibility for drilling a well and reaps the reward of the innovative decisions taken. The company obtains the opportunity to use the equipment provided by the contractor to its full advantage and thus identify the most efficient approaches to reduce the drilling days.

Thus, in 2007 the drilling time in VCNG was reduced to less than 60 days and today an average well is drilled for about 24 days with a drilling record of 18 days achieved by KCA Deutag. However, VCNG drilling staff is continually revaluating the technical limit for the wells; they believe it is technically possible to drill even faster!

The day-work contracts serve yet another purpose, i.e. reducing the cost of construction per well. Following this new approach the contract cost is identified based on the number of working days rather than the number of wells. Therefore, the faster the wells are drilled, the more wells are built in a period of time, the cheaper each well is. The average cost per well today has nearly halved and is getting in the $3 mln range.

The use of innovative technology and the new approach to contractor management helped reduce the drilling time more than thrice over the last four years. The outstanding result provided for the update of 2009 drilling plan. Initially, 32 wells were planned to be built this year, yet the increased drilling rate made it possible to drill 10 more wells in 2009.

At the same time, VCNG drilling engineers have no doubt that there still remains areas for technical improvement that will bring about new success in the future.


POINT OF VIEW
Yaroslav Gordeev,
Subsurface Director, VCNG

Verkhnechonskoye (VC) is a field of a complex geology. It is acknowledged to be unique not only by the shareholders, TNK-BP and Rosneft, but also by the statutory authorities. The oil-bearing formations have areas of various productivity and there are sections with salt deposition.

Reservoir uncertainty is very high; a well may be very much unlike its neighbors.

Practice shows that while drilling in such complex environment half of a well bore may go outside the net pay.

Geosteering significantly improves drilling efficiency in the high reservoir uncertainty thanks to timely adjustment of the designed well trajectory. Geosteering equipment consists of two logging devices installed next to a bit and transmitting data to the surface. They measure resistivity, density and porosity and other geophysical parameters of the rock and thus identify the reservoir heterogeneity and assess productivity of the section drilled. If drilling is outside the net pay then a real-time decision can be made as to changing the well trajectory and going into a better reservoir.

Therefore, geosteering helps increase the length of the bore in the net pay, thus improving initial flow rates, reducing well construction payback period and improving the project’s overall economics.

Currently, there are six wells drilled in VC field using geosteering: well 1174 was drilled in 2008 and the other five wells - in 2009. Specialists say that geosteering increases the effective length of a wellbore and initial flow rates by 10 percent to 15 percent on average as compared to drilling 'blindly'. At the same time, analysis shows that this technology in good reservoirs is inefficient, while in reservoirs with high uncertainty it proves useful. One of the commissioned wells was drilled in good reservoir and had an insignificant flow rate increase, a little more than 8 percent, while a risky well had an increase of almost 40 percent.
posted by The Rogtec Team @ 14:51  1 Comments

Coiled Tubing Applications for Exploration Drilling at Salym


In 2009, Salym Petroleum Development & Schlumberger assessed the Bazhenov formation - ROGTEC overviews the project and speaks with SPD Well Manager Fred van Nieuwenhuizen about the advantages of coiled tubing.

In Q1 2009 Salym Petroleum Development N.V. (SPD) jointly with Schlumberger Logelco Inc. did an assesment of presense of oil and gas content in Bazhenov formation deposits (JS-0 formation). That is unique geological horizon with unconventional indications of hydrocarbons and reservoirs.

Hydrocarbon reservoirs of Bazhenov formation in most of the cases are represented by shales, enriched with organic content, siliceous deposits and cavernous fractured carbonate rock. One of the most important tasks of Bazhenov exploration is to locate the prospective oil zones using different techniques and strategy. As a part of this effort thee wells were to be drilled in prospective oil zones. One of them characterized by anomalous high temperature >135 degrees centigrade and anticipated formation pressure up to 600 atm.

Possessing necessary expertise, qualified personnel and equipment, Schlumberger Well Services were involved for the project execution and coordination. Initially the well was drilled and cased conventionally by the rig placing section TD into the Upper Bazhenov Member (JS-0). With tubing installed and packer set, the well was handed over to Coiled Tubing for non directional well deepening into underlaying Middle and Lower Bazhenov. Drilling of this section was performed in underbalanced condition in order to in order to appraise the long term unimpaired productivity of the formation. The survey section of the well was tested and then logged by means of wireline. At the final stage, the section was abandoned by setting the cement plug through the coiled tubing in accordance with approved procedures and standards.

The survey section of the well with undefined formation pressure was drilled underbalanced by Coiled Tubing with no danger to people and environment. Collected reservoir characteristics with skin effect eliminated in drilling and during the well test stage. The most complete possible suite of logs was acquired in openhole by wireline. Experience in coiled tubing and ability to adapt this technology for well testing and exploration drilling needs, let Schlumberger to successfully perform this operation.

The following performance indicators were achieved: survey section was successfully drilled with 44mm coiled tubing grade HS-90, 54mm downhole motor and 70mm PDC bit. There were 76 meters of openhole section with clean and stable formation walls penetrating all JS-0 formation. Maximum rate of penetration was 7.2 m / hour. Drilling was done from the top of the formation with azimuth and deviation set by conventional drilling rig. No devices were used for directional control. Dogleg severity was not higher than 2.75 degrees / 30 m. Upon the end of well test and logging, the survey section was abandoned by placing the cement plug through the coiled tubing.

Despite of the fact that oil is produced out of the sandstones in the Lower Cretaceous Cherkashin (AS-11) in this and most of the cases, assessment of presence of oil and gas content in underlying Bazhenov formation deposits (JS-0 formation) is also essential part of license commitment for the company. Peephole underbalanced coiled tubing drilling done by workover department is an example of cost effective solution that delivers on commitment to explore the high-pressure Bazhenov in licensed area without up-scaling the well.

To discuss this project in more depth, ROGTEC talks with SPD Well Manager Fred van Nieuwenhuizen

What advantages did CT have over other possible drilling technology types?

With CT the well could be drilled under balance (otherwise the drilling mud would have damaged the sensitive formation) with water using one pipe size (the coil) which can be "stripped" out of the well under pressure) opposite drilling with tubular joints which have connections of bigger diameter then the pipe which does not have the optionally of circulating while pulling out of hole for the entire length of pipe under full "closed in" condition. (ability to contain the pressure). Actually the standard CT package was designed initially to work underbalanced with surface well control equipment up to 15000 psi. Otherwise the conventional well control stack is designed for 5000psi. Therefore if we want to bring to the rig 15000 psi it will be dramatically expensive for such type exploration projects

Underbalanced drilling has a number of advantages, particularly in our situation using coil tubing drilling. Because there is no mud weight as there would be in conventional drilling, it allows an increased rate of penetration by the drill bit; there is less uncontrolled loss of drilling fluid into the formation strata and there is less potential for the drill tubing to stick to the wall of the well. The potential productivity of the well is minimally affected. In this specific case, the added advantage would be to assess the flow capacity of intersected fractures in the formation whilst drilling, in case a medium (gas/oil/water) would be present in the rock.

It should be mentioned that standard CT package was designed initially to work underbalanced with surface well control equipment up to 15000 psi. Therefore it's possible to find it anywhere worldwide. When the conventional drilling well control stack is designed for 5000 psi surface (in Western Siberia). Therefore if we want to bring the Rig up to 15,000 psi well control equipment it will increase the cost several times.

For the potentially dangerous 600bar formation, how much under-balance were they at on surface?

250 bar under balance in case there would be 600 bar at bottom

How did CT affect the project costs?

Although there is an advantage that the coil tubing unit is a stand-alone unit so no Rig cost, the total set-up with the testing equipment makes it a expensive part of the total well-cost.

In this particular case, that there was insufficient hydrocarbon to justify production, the overall cost of the well was significantly lower than if we had used conventional drilling. The test separator, an integrated element of the set-up, was provided by SPD, as we have this unit in our well services team for general well testing and flow rate calibration on the normal producing assets

Does CT offer additional safety or environmental benefits over standard drilling technologies?

Yes as mentioned the full control over the pressures at all times is a major safety advantage. It's designed to work underbalanced with standard well control surface stack 15000 psi.

Exactly how was danger at surface avoided?

By lowering and pulling the pipe (coil) through a stripper (rubber ring that closes around the pipe) so keeping the fluids and pressure contained. CT is a technique which was designed initially to work underbalanced on any well services operation.

What pressure control stack components (BOPs) were used?

These are special coil tubing BOP's with stripper rubbers and emergency cutting devices, so ability to hold pressure with coil in the well, ability to cut the coil and ability to hold pressure without coil in the well.

How did the penetration rates with CT compare to standard drilling technologies?

Would consider it normal for this depth but very good for the fact that the bit was very small 2.3/4" (70mm) and the well was deep. It could be compared with conventional drilling with a bigger drill-bit (in general the smaller the bit the lower the ROP (rate of penetration) ROP was 2 m/hr (SAV-45 152 mm wellbore)

Will your experience on this field alter your future practices or usage of CT?

Unfortunately was there no presence of oil otherwise SPD would definitely continued with this technology to develop the reservoir. But it should be marked that Shell is promoting a balanced risk-versus reward approach to field exploration efforts, in an overall move to optimize cost and well delivery. To support this, the peephole concept has been promoted globally throughout Shell's global exploration portfolio and been received with great enthusiasm as an additional tool.

Fred van Nieuwenhuizen
Dutch national who obtained a Bsc. in Mechanical Engineering in 1982. He joined Shell the same year and after his initial development in Holland with NAM moved to Oman (PDO), followed by working in Nigeria (NLNG project). He followed that by working in Scotland managing an offshore installation and returned to Holland to become the Well Engineering Course director for the global Shell skillpool. Became the Well Engineering Project Manager for the initial preparation phase of the Kazakhstan Caspian project "Pearls now CMOC" and holds currently the position of Well Engineering manager for SPD (4 Rigs, 7 hoists, heavy transport, fraccing & CTU Ops.)
posted by The Rogtec Team @ 14:35  0 Comments

ROGTEC talks Exclusively with Tom Blades, CEO for Oil & Gas at Siemens


Tom Blades
Energy Sector, CEO Oil & Gas Division

Having previously held senior positions at Schlumberger and Halliburton, Tom Blades has taken the reigns at Siemens Oil & Gas during turbulent times. ROGTEC caught up with him to discuss his strategy.

1. You started your position at Siemens in what was undoubtedly a tough year financially across the globe for most. "In at the deep end" comes to mind, so how was your first year at the company?

The last fiscal year which ended September 30th, 2009 was a record year for the division both top line and bottom line performance. The healthy backlog we had built prior to the downturn has enabled us to maintain momentum even in these difficult times. I am particularly pleased with our 1.1 book to bill ratio and even more so when I compare this to our main competitors' achievements.

2. Having previously held top positions within Schlumberger and Halliburton who have great industry reputation and market positioning, what made you decide to join Siemens - who although a huge company, do not have the same positioning within the O&G sector?

During the first 30 years of my career I was serving the oil and gas industry from inside. Although I never was in direct contact with Siemens products I became acquainted with the line of products used by the oil & gas industry, such as gas and steam turbines, electric motors, compressors, controls etc. I am familiar with their application in upstream, midstream and downstream processes, the technical issues faced in the oil & gas industry and the expectations and challenges the operators demand of the manufacturers.

Given the current direction that the oil & gas industry is moving in I see tremendous opportunity for Siemens to move up from a tier 2 supplier to a tier 1 'partner' for our customers. Getting us there is the strategic challenge that attracted me to my present position.

3. What major changes have been implemented since your arrival and how have they benefited both Siemens and the client?

Traditionally, Siemens has been a component supplier. However, nowadays customers are no longer looking to us for components, but solutions to problems. So we had to grow from a pure component supplier to solution provider, reorganizing our internal structure to accomplish the transition. This is a general trend encountered by other Siemens business units, but it is particularly exacerbated in the oil & gas industry. We are entering into a partner type relationship with our customers, providing them with solutions to their current application problems but also with innovative ideas that our experts are jointly developing in anticipation of future market needs.

Within Siemens, we have an array of products and services that allow us to develop packaged solutions where all the core components are provided in house. A single supplier source has always had a special appeal to customers as it de-risks their projects and accelerates completion times.

4. It has been a pleasure for the ROGTEC team to have partnered with Siemens and to have met your teams at many events throughout Russia and the Caspian over the last 5 years. But how successful is the region for you at the moment and do you have any plans to expand this area?

We are very successful in Russia and in the Caspian Region. For instance, we received an order from Rosneft for the supply of gas turbines as power plant solutions for the Tuapse refinery to accommodate its expansion following the order for the gas turbine power plant power plant at Priobskoy oil field in 2008.

We expect that the two megaprojects in the region - the Kashagan oil field in the Caspian Sea and the Shtokman gas field - will be a good business opportunity for Siemens.

As I already mentioned our aim is to complete the migration form product supplier to true solution partner. Our aim is to enter into dialogue with our customers on long-term oil & gas projects development as early as the Pre-FEED / FEED phase so that we can coordinate the total Siemens portfolio in order to leverage our technical capabilities as single-source partner the across the board from power generation and distribution to automation and turbo-machinery. We already have about 1,200 engineering employees in place around the world and we will further strengthen our regional presence in key areas like Russia.

We have already established local offices in all federal districts in Russia. i.e for the Caspian pipeline we use our service centre in the south to provide our customer with latest service offering on our installed turbines.

Additional we are also active in the countries around the Caspian sea with several projects in the total energy conversion chain.

5. As I understand it, Siemens is stronger within the pipeline and downstream sector than upstream. What are your upstream offerings to Russia and the Caspian and how are you looking to compete in this arena?

You have analyzed the competitive situation very well. Unfortunately we were not in the upstream focus as much as we could be, because we can offer a wide range of solutions especially for energy efficient solutions and clean energy.

6. The low cost of oil seen at the start of the year and the financial situation put many projects on hold, and in many areas, market confidence was low. We all agree some confidence is coming back - but what are your thoughts on current market conditions and what do you forecast
for 2010?

I agree with you on the financial situation. Due to the strong decrease of the oil and gas prices and additionally the ruble devaluation in November last year some projects in Russia have been postponed for 1-2 years. Currently we expect a small increase in 2010 and 2011. The main positive impact for the oil and gas sector we expect from the mega-projects and also from the new energy efficiency law in Russia. This will support huge investments in the next years. I am convinced that with our solutions oriented approach we have the right answer to these challenges.

7. We read many stories relating to "Peak Oil" and the need to look towards alternative energy. I understand Siemens have a strong renewable division - but what is your view on "peak oil" and where will the world's oil be found in the coming decades.

The Oil price hit a rock-bottom low, but in the mid-term and long-term perspectives nothing has changed essentially. Energy demand will continue to grow in the years to come. It is anticipated that it will nearly double by the year 2050. The share of renewable energy will increase significantly but nevertheless fossil fuels are and will be the backbone of the energy supply. But we do have to accept that "easy oil is over" - and this is the point where Siemens can step in because we have the right portfolio and cutting-edge technology. Depletion of resources is the main driver of our business. Technologies such as steam or water injection, gas compression and advanced subsea systems are all areas which are becoming economically viable as oil prices increase and are all technologies in which Siemens is active and can provide solutions, both now and for the future.

For example, Siemens will invest a lot of money in Subsea technology in the coming years. We are thinking a long way ahead and are trying to picture a future where no more platforms are needed and all of the oil production will be done Subsea with onshore control. It is a big challenge to keep the oil production at the same level as it is today. New technology must be developed for better exploration of all the different oil and gas fields. Subsea technology and solution are not only environmentally friendly but with this technology fields can be reached that previously were unreachable. Subsea equipment is more expensive but the processes and maintenance will be far cheaper for a period of 30 years. We will supply solutions down to a water depths of 3000 meters. Our goal in Siemens is to be number 1 in specific Subsea technologies and solutions by 2017. As per today we have no competition with the same technology and we are working hard on joint industry programs to co-operate and involve large oil companies in the development of our solutions.

And I would like to mention another example: One third of natural gas reserves are wet or sour gas, there is a need for high reliability and availability for the equipment with, long average maintenance intervals. We developed the compressor for sour gas applications and have reduced the number of required components and auxiliary for compression systems to a minimum. Our solution is the STC-Eco which integrates a high-speed induction motor and a multi-stage centrifugal compressor on a single shaft in a single casing. No need for seal gas system, lube oil system, gear box etc.

8. In a highly competitive marketplace - what makes Siemens stand out from the crowd?

Siemens Oil and Gas Division has a broader portfolio than any of its other competitors and the Siemens brand enjoys an extremely positive recognition. We are part of the Siemens Energy Sector and backed by the Siemens AG building together this big company which is present in some 190 countries. In Russia, Siemens is doing business for more than 150 years now. We have excellent people in place and as mentioned before, a single supplier source has always had a special appeal to customers as it de-risks their projects and accelerates completion times.

Tom Blades
Energy Sector, CEO Oil & Gas Division
Born on September 17, 1956 in Hamburg, Germany

Education:
Electrical Engineering in Salford (UK) and Lyon (F)

Career:
1978 Schlumberger, 1993 - 1996 Vice President and General Manager Schlumberger/Geco-Prakla
1996 NUMAR Corporation, COO
& Executive Vice President
1997 Halliburton, Executive Vice President
1998 SPECTRO, President & CEO
2004 CHOREN Industries, President & CEO
Since 01/2009 Siemens Energy Sector,
CEO Oil & Gas Division
http://www.siemens.com/energy/oil-gas

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posted by The Rogtec Team @ 14:18  0 Comments

Exploration Hardware: Advances for Harsh Environments


Vladimir Boreyko
General Representative in Russia & CIS


Robert Heath
Global Technical Marketing Manager

In an economic downturn, the exploration sector can sometimes bear the brunt of companies cost cutting. How did this affect your business in Russia last year and what are your forecast for 2010 and beyond?

Vladimir Boreyko: 2009 has indeed been a tough year for the exploration industry and our clients in Russia. Though our sales were nearly halved, our presence and the adequacy of our equipment to the Russian market is allowing us to remain optimistic on the long term and particularly to maintain our human capital in Russia. Having said that, we estimate that 2010 will not be much better than 2009, as our customers have had to reduce their margins, and thus will have less cash to invest in equipment.

Robert Heath: iSeis is new to Russia (although its parent is not) and iSeis marketing activities only started in Russia in late 2009. However, given the advantages of the technology we have on offer (we have the world’s only Second Generation Cableless Land Seismic Acquisition System, called "Sigma"), and the difficulties of operating in the Russian environment (where 2nd generation cableless gear is ideal) we are most confident of success. We have already established a well known agent and plan Sigma system demonstrations.

Many unexplored areas of Russia are found in extremely harsh environments. With the cost of oil seemingly stabilizing. What opportunities do you see in areas such as Eastern Siberia and the Arctic? Have the recent tax incentives spurred activity in the region?

Vladimir Boreyko: Seismic exploration is the first activity to arrive in unexplored areas just after the geologist so we are indeed at the forefront of these trends. We do deliver more and more equipment to these regions, with configurations that are getting bigger and bigger.

Robert Heath: The tougher the environment, the more it suits Sigma. This is because operators will have tended to avoid these locations knowing the limitations of existing technology. They will find it a relief that new technology now solves their problems, effectively safely opening up new frontiers for seismic exploration.

What advancements have you made to your hardware to survive and thrive in these arctic areas?

Vladimir Boreyko: Sercel equipment has been operated in areas such as Siberia, the Komi republic, Yakutia, Canada and Alaska for several decades, so we have a significant experience of work in arctic conditions. This experience covers the whole scope of our equipment, from special connectors on our geophone strings to power management on our acquisition systems or vibrator design.

In cold weather, the battery management is critical. Our Data Acquisition systems have been designed to optimize power consumption and to reduce the number of batteries in the field (single channel configuration; power through the line). As an example, our 428XL land acquisition system typically uses five times fewer batteries than a competitor’s system.

Our experience can also be witnessed on our vibrators, on -50 degrees centigrade reinforced winterization, or on the design of the tracks.

Robert Heath: Power supply is a major issue as temperature drops. We do not rely on power-hungry power transmission along cables, thus our power loss is much less and we can make use of the latest hi-tech batteries with high power densities and low temperature characteristics.

In a previous issue of ROGTEC (issue 18), we discussed the need for a cost effective solution for operators to enable real time 3D and 4D seismic on producing fields across Russia and the CIS. What hardware solutions can you provide to improve their effectiveness in the DOF arena?

Vladimir Boreyko: It is well known that high-density seismic is a proven tool for improving the signal-to-noise ratio as well as the vertical resolution of the data. To shoot a high-density survey (high CMP fold and small bin), the seismic contractor should possess a high-channel count recording system with the number of active channels exceeding 10,000 and modern high-productivity field techniques like multi-fleet vibroseis. We are glad to report that the first high-density survey in CIS was successfully acquired in Kazakhstan in 2009 with the aid of our recording equipment and our vibrator electronics.

The weight and power consumption of field equipment are gradually decreasing, thus allowing the seismic contractors to shoot more productive and less expensive 3D seismic surveys.

Robert Heath: It is not clear what is meant by "real time 3D and 4D". Sigma is the only 2nd generation cableless system which has real time data monitoring capabilities. However, it also has many other modes, both in stand-alone operation and to augment existing cable-based hardware. It has by far the best level of source control integration of any system on the market (because its parent company is the world's leader is development of source controllers). This provides additional levels of flexibility for any 3D operation.

As regards 4D, cableless systems are what makes 4D viable on a larger scale. We have made significant sales into this market already and new types of 4D (such as "Rapid Deployment 4D") are planned around the advantages of Sigma.

How can seismic contractors improve the data quality of the survey through the hardware that they use?

Vladimir Boreyko: We have brought many innovations to the market, that bring improved data quality. Our latest geophone has an extremely low distortion and is less sensitive to tilt, our digital sensors are not sensitive to crosstalk and have a response that is independent from the frequency. We have increased the bandwidth of our vibrators towards low frequencies, and we are currently introducing heavy vibrators into the Russian market.

Last, but not least, quality control is of essence on a seismic project. We have comprehensive quality control software allowing the observer to ensure, in real-time, that the data being recorded is OK. With our remote access option, the quality results can be made available in real-time anywhere in the world (e.g. at the head office of the contractor). This option is currently being widely used in Russia.

Robert Heath: This is very difficult question because it depends on how they currently operate their crews. However, generally speaking, data quality has been a compromise with such things as data productivity, operational costs and HSE exposure. Almost all cablefree/cableless systems offer increases in productivity compared to cable-based systems. However, the shoot-blind cableless systems can put data quality at risk as they have no means to monitor even basic QC functions. Thus, cableless systems with monitoring capability can increase productivity and reduce operational cost without risk, which can be used to augment data quality (e.g by better citing of receivers, optimising fold etc). Sticking with cable-based acquisition hardware virtually guarantees little data quality improvement because these systems are perfected almost as much as they can be. This will be hard pill to swallow for some operators as it also requires a change in attitude to exploration, but it is the only way forward.

What do you see as the next big technological step in exploration hardware?

Vladimir Boreyko: Reducing the cost of acquiring seismic data through productivity gains will be the key driver. While the market is pushing for more and more data to obtain a clearer image, the cost cannot go up proportionally. As the clear market leader in land acquisition, our 428XL system is continuously improving to maintain industry leading productivity. As an example, a record of more than 75000 live channels has been achieved recently in Colorado which utilized the vibrator controller VE464. Another record of more than 17000 Vibration points per day has been achieved in Oman. More productivity records are expected in the near future.

Robert Heath: There are two next big steps. One relates to sources and source control. The other relates to recording systems. In terms of sources and source control, there will be improvements in understanding how vibrators work so we can better estimate the far field signature and build control systems to allow for earth effects, we will also have more simultaneous impulsive sources. Both these require significant improvement in terms of how we develop source control systems. In terms of acquisition/recording systems, the main area of development will be in terms of getting more channels back over hi-tec radio systems, probably using mesh radio.

How can contractors minimise the environment impact of the survey through their choice of hardware?

Vladimir Boreyko: One interesting track is the use of heliportable crews. Bringing the equipment on site by helicopter and not vehicles, significantly reduces the environmental footprint of the seismic project, the cost of operation of the helicopter being counterbalanced by reduced tree cutting and increased productivity. To achieve this, the overall weight (weight by itself and reduced number of batteries) and the volume of the equipment is critical. Our acquisition system, which by its design and its reduced power consumption weight and volume, allows such operations in Canada and more recently in Russia.

Robert Heath: Immediately stop using cable-based acquisition systems. They are heavy and unreliable.

It has been a pleasure speaking with you - do you have any final comments.

Vladimir Boreyko: Yes. We want to mention that producing high-performance hardware in the industry is not enough. The technical support we offer to our customers is a key driver and it is a matter of daily attention to us.

We have developed our customer support in a network of several locations in the CIS in order to be as reactive and as close to our customers as possible, hence helping them to maximize the benefits of their investment in our equipment.

Robert Heath: The world is running short of easy-to-find hydrocarbons. The technology we used to find large fields in easy places will no more be the correct technology to use for the new era, than would propeller-driven planes be the answer to supersonic travel of aircraft able to carry 600 passengers. The philosophy of design of equipment needs to change to "fully independent hardware", where the hardware itself comes with no built-in restrictions in how it can be used - such limitations are definitely the case with most equipment used today. Independent equipment is the only way to go if we expect be find hydrocarbons in frontier basins, or the last oil in mature basins. Otherwise it will simply be too expensive to explore, too risky, too high HSE exposure. The great advantage of such new technologies is that they are not only much easier to buy, they are lower in cost to use.

Robert Heath has been involved in land seismic acquisition techniques, engineering and marketing since 1976 and written a large number of articles and papers on modern land acquisition. He has been involved in the start up of large number of new seismic instrumentation companies, and is at the forefront of bringing new technologies to improve land seismic.
posted by The Rogtec Team @ 13:58  0 Comments

New Standards: SEG-D 3.0 and the SEG Technical Standards Committee

Jill Lewis, Troika International Stewart A. Levin, Halliburton Drilling, Evaluation & Digital Solutions, Rune Hagelund, WesternGeco, Barry D. Barrs, ExxonMobil

Summary
The SEG Technical Standards Committee has recently undertaken a revision of the SEG-D Field Tape Standard designed to accommodate the needs of current and anticipated future acquisition systems. This includes not just field acquisition support for arbitrary sample rates, continuous passive recording, multicomponent sources and receivers, and sophisticated field filters, but also things like area / line /crew /client /job information, source and receiver co-odinates and their reference system, and capture of processing such as trace edits in the field system.

Introduction
A field systems engineer, an acquisition bird dog, a seismic processor, a seismic interpreter, a geoscience researcher and a software developer were having refreshments at an SEG International Exposition and Annual Meeting while discussing the state of SEG field and interchange standards.

"We generate essential quality control information in our field systems, but our customers never seem to pass it on to their clients. I really wish there were a standard place in the SEG-D format we can automatically record it. Right now we have to put in extra SEG-D headers in our own proprietary format." said the field systems engineer.

The bird dog agreed. "Yes, I couldn't do my job properly without your system's QC displays. Picking out trace edits is almost painless. It's a shame, though, that I end up putting this with the observation sheets on a separate CD or a USB stick and not directly on the SEG-D tape."

The seismic processor chimes in: "Speaking of observation sheets, I seem to spend half my time chasing them down. And don’t even get me started on geometry! Our navigation folks are so busy merging and QC'ing coordinates that none of them could even spare the time to come to this convention."

The seismic interpreter recalled that just last week she was trying to tie two different vintages of spec data over a prospect. "Something was clearly wrong with the header coordinates of one or both of the surveys, but no one was ever able to locate the navigation data to check on differences in datum or local zones. I ended up stretching and squeezing the two until they more or less fit. What an ignominious epitaph for hundreds of hours of TLC seismic data processing. And all because we couldn't get the nav."

The geoscience researcher, finally resting after running back and forth as much as half a mile shuttling between 10 simultaneous technical sessions, pulled out his pipe, put it back after noticing the no smoking sign, and sighed. "You know that by the time an SEG standard is published, it is practically obsolete. Our company has been monitoring producing fields with 9 C, 4 D seismic, both active and passive, for some years. But lacking any standard for formatting and transmitting it to contractors, we waste inordinate amounts of time and money getting it processed properly so I can get on with my research program of jointly analyzing these data with CSEM acquired at the same time."

The software developer harrumphed, took another swig of high caffeine double nonfat latte, and interjected "Wait just a minute, there. Do we really want a new version of the SEG-D standard upgraded to include the kitchen sink? The existing standard already has plenty of problems with ambiguities, mistakes and inconsistencies and you want to make it even more complex? Let's assume by some miracle this SEG-D on steroids is actually promulgated before I retire. Now I've got to spend the next year rewriting all the tens of thousands of lines old Fortran dating from the '70s for reading SEG-D. And just because there is more information in the new SEG-D, doesn't mean there's a place for it to be transferred into in the existing seismic processing and interpretation system. Add another two man years of development. And at least half my time after that maintaining and upgrading it to work around one vendor glitch after another. I'll welcome early retirement after that!"

SEG-D Rev 3.0 goals
As the previous imaginary conversation indicates in its tongue-in-cheek way, there is a clear need for standardization of additional seismic data and metadata in SEG-D to capture information that is automatically captured or generated in the field. Continuing the status quo of many vendor-specific extensions greatly increases the risk that that extra information will be indecipherable a decade from now.

Some features that the SEG-D upgrade to SEGD 3.0 now includes:

  • General survey information such as client, area, prospect, field crew or vessel,
  • Source type(s), strength, timing, status, layout, and field conditions,
  • Receiver type(s), orientation, sensitivity, status, layout and field conditions,
  • Support for IEEE 8 byte samples, code 8080,
  • Support for sample rate steps of 1 microsecond,
  • Four and a half years of recording data at one second interval to provide support for passive recording,
  • Support for CSEM and EM recording,
  • Common Time Stamp GPS Epoch, starting 6th January, 1980,
  • Clarification of method for writing data to disk,
  • Coordinates and their EPSG reference system in line with OGP (International Oil and Gas Producers Association),
  • UoM (Units of Measurements) Table in common with Energistics,

They are represented by:

  • Completeness: If implemented and populated the survey could be constructed later from the SEG-D.
  • Compatibility: Where reasonable, the format is compatible with earlier versions, both in layout and methods of extension.
  • Coordination: Where new (or old) information is in another technical standard? So that the information can be exported to or imported from the other standard without pain or degradation.
  • Clarity: We have avoided ambiguities by means of explanatory notes and examples. And don't specify the same information in two different places, a failing of the current SEG-D Rev 2.1 standard and its predecessors.
  • Simplicity: Adopt a set of consistently followed practices in laying out information in the new SEG-D revision. Make each block or block grouping self-contained, irrespective of any master table of contents.
  • Do no harm: Seriously consider how new SEG-D data might be misused or misinterpreted down the road. For example, how might preplan coordinates for source and receiver be mishandled?
  • Recoverability: Provide internal clues and make formatting choices that limit the loss of information should the medium on which SEG-D is recorded becomes corrupted.
  • Cleanup: Option to provide a precise count of samples per trace in milliseconds rather than ambiguously back calculating it from other fields in the headers.
  • Extensibility: Have a clearly defined compatible approach to future updates that can be quickly drafted, approved and deployed without revisiting all aspects of the existing standard.

The SEG is now working very closely with the OGP (International Oil and Gas Producers Association, ogp.org) who represent approximately 80% of the Oil and Gas producers from around the world. This association is the custodians of all the positioning formats with the SEG handing over the SEGP formats early in 2009. The OGP is currently updating the range of the positioning formats.

The OGP also hosts the EPSG (European Positioning and Survey Group) database which is freely available from their web-site providing geodetic parameters for the world.

The SEG and the OGP are some of the most valuable resources that are available free of charge to the upstream oil and gas industry. We are nothing without data and the more comprehensive the recording the better use we can make of that data. An enormous effort has gone into the work represented here over the last six years. By utilizing this work it is estimated that you are receiving in excess of four million dollars of free consultancy. If we included the EPSG database then this figure would more than quadruple.

This is a wonderful and free resource that will improve and save money in many departments including Acquisition; Data Management and Processing.

References
Note: All SEG technical standards are published on the website http://www.seg.org/publications/tech-stand/.

Allen, R., Crews, G., Guyton, W., McLemore, C.A., Peterson, B., Rapp, C.S., Walker, L., Whigham, L.R., White, D.A. and Wood, G., 1994, Digital field tape format standards - SEG-D, REVISION 1, Geophysics 59,
668-684.

Cavers, D.A., Carroll, P.E., Meiners, E.P., Racer, C.W., Siems, L.E., Sojourner, M.G., Twombly, J.L., and Faichney, Norris, Hiscox, Hovde, Bingham, Stigant, Racer, Reynolds, Hares, 2001, SEG-UKOOA Ancillary Data Standard - Metafile Format Description: Geophysics 66, 1961-1998.

Weigand, J.A., 1980, SEG-D—Digital field tape format standards, in Digital Tape Standards, Society of Exploration Geophysicists, 31-65.

SEG Technical Standards Committee, 1997, Digital field tape format standards (SEG-D Revisions 1 and 2), Society of Exploration Geophysicists, 46 p, ISBN 1-56080-046-1.

SEG Technical Standards Committee, 2002, SEG Y Data Exchange Format Revision 1, Society of Exploration Geophysicists, 45 p, ISBN 1-56080-123-9.

SEG Technical Standards Committee, 2004, Digital Tape Standards (SEG-A, SEG-B, SEG-X, SEG-C, SEG-Y, SEG-Y Revision 1, SEG-D, and SEG-D Revisions 1 and 2 formats), Society of Exploration Geophysicists, 112 p, ISBN 0-93183-015-X.
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Caspian Sea: Morphometrics & Stochastic Modelling

Many reservoir models rely on populating reservoir zones with objects whose dimensions are taken from statistical databases of analogue sandbodies. While this attributes may be sufficient to characterise single channels, they do not adequately describe branching networks such as deltaic distributary channels.

This study examines morphometrics of deltaic distributary channels using satellite image data from the modern Volga Delta, Russia.

The Volga delta is an extreme example of a fluvial-dominated delta that is characterised by extraordinary pronounced distributary branching. Several reservoir intervals are deposited by the palaeo-Volga Delta in the Pliocene Productive Series reservoirs of the offshore Caspian Sea.

A quantitative database of key geometrical measurements the length, width and sinuosity was collected from the branching network of channels on the satellite image of the Volga delta. The channel segments were assigned hierarchies using an ordering classification system.

Various statistical analyses were carried out to obtain the mean, standard deviation, Inter-quartile range and coefficient of skewness of the length, width and sinuosity of the Volga Delta channels. Also, various cross plots of length, width, sinuosity and hierarchy were made and their R2 values obtained to reveal the associations between these variables.

The statistical analyses reveal that there are no relationships between these variables; length, sinuosity, width and hierarchy.

This implies that these variables can be treated as independent and can be placed as separate entities in object-based reservoir modelling of the Pliocene Productive series reservoirs of the offshore Caspian Sea.

The results enables us to define shapes and dimensions of channel objects for models of the Pliocene Productive Series reservoirs of the offshore Caspian Sea, such as the Pereriv Suite in BP's giant ACG field.

Introduction
This study, 'morphometrics of deltaic distributary channels for object based reservoir modelling' was undertaken as a three month project in Imperial College as the final individual project for the Imperial College Msc in Petroleum Geoscience.

The aim of the project is to collect a quantitative database of key geometrical measurements of a network of deltaic distributary channels with its case study from the Volga Delta, Russia.

The requirements of the project are as follows:

  • To measure key geometrical/morphometric data for a connected distributary channel network;
  • To compare this dataset to standard statistical databases used to condition object-based models of deltaic reservoirs; and
  • To define shapes and dimensions of channel objects for models of reservoir analogous to the modern Volga Delta (Productive Series reservoirs, Caspian Sea)

Many reservoir models rely on populating reservoir zones with objects whose dimensions are taken from statistical databases of analogue sandbodies. This approach requires: (1) robust matching of the subsurface reservoir interval to an analogue (e.g. ancient systems at outcrops, modern system), and (2) measurements of the key geometrical attributes of analogue sandbodies. Typically, the geometrical attributes of channels in such databases are width/depth ratio and sinuosity. While these attributes may be sufficient to characterise single channels, they do not adequately describe branching channel networks such as deltaic distributary channels. This project will characterise the morphometrics of such network in the Volga delta, an extreme example of a fluvial-dominated delta that is characterised by extraordinary pronounced distributary branching. The results have several applications to several intervals deposited by the palaeo-Volga Delta in the Pliocene Productive Series reservoirs of the offshore Caspian Sea, where the channel dimensions, geometry and connectivity are key unknowns that may have large impact on reservoir behaviour.

Morphometric Techniques
Morphometry can be defined as the measurement of the shape, whereby measurements are then manipulated statistically or mathematically to discover inherent properties. Morphometric techniques aim at developing methods or a set of tools that measures both general and specific geomorphometric features.

In the field of hydrology, morphometric studies were first initiated by R.E. Horton and A.E. Strahler in the 1940s and 1950s. The main purpose of their work was to discover holistic stream properties from measurement of various stream attributes.

The attributes to be first quantified was the hierarchy of stream segments according to an ordering classification system as illustrated in Figure 2.1.


In this system, channel segments were ordered numerically from the stream’s headwaters (i.e. the upper portion of stream's drainage system) to a point somewhere down stream. Numerical ordering begins with the tributaries at the stream’s headwaters being assigned the value of 1. A stream segment resulted from the joining of two 1st order segments was given an order of 2. Two 2nd streams formed a 3rd order stream and this went on. The analysis of the data generated revealed some interesting relationships (Pidwirny, 2005).

R.E Horton applied morphometrics analysis to a variety of stream attributes and from his studies a number of laws of drainage composition were proposed. Horton’s law of stream strengths suggested that a geometric relationship existed between numbers of stream segments in successive stream orders. The law of basin areas indicated that the mean basin area of successive ordered systems formed a linear relationship when plotted on a graph.

These results and studies of other natural branching networks have revealed patterns similar to the stream order model. In morphometry the geomorphological significance of the Hortonian stream-order relationship is limited.

The stream numbering technique used by Horton is quite similar to the technique applied during this study to number and assign hierarchy to channel segments of the Volga delta. In this study, the channel segments were first of all numbered randomly from the first segment to the last seen on a map view of the delta. The ordering of the stream segments according to their hierarchy was then assigned the number '1', from the Volga River, at the apex of the delta.

In a situation whereby a single channel is assigned the value of 1 in the first order in the hierarchy, when it splits or bifurcates into two or three channel segments, they are assigned the value '2' in the second order of the hierarchy. If two of the channel segments converge, the channel segment that results from this is assigned the hierarchy number of the previous single channel that bifurcated. In this way, the ordering according to hierarchy goes on until the last channel segment has drained into the Caspian basin.

Object-based reservoir modelling
Reservoir models are essential tools used during the exploration of hydrocarbon reserves. According to Bryant and Flint, 1993, the general methodology for building a geological reservoir model is to;

  • Define the space occupied by reservoir interval
  • Identify the geological/genetic units within this space
  • Assign realistic shapes and geometries to these geological/genetic units
  • Arrange these units within the defined space (i.e. determine the reservoir’s internal geometry or 'architecture'); use either deterministic or stochastic (object-based) methods
  • Assign reservoir properties to the genetic units (use deterministic, stochastic and/or other geostatistical methods)

The concept of object-based modelling techniques (also termed 'marked point processes) follows naturally from the concept of genetic reservoir units. An object-based is defined as a 3-D geometric shape which can represent a genetic reservoir unit, or shale, or any other reservoir or non reservoir interval which can be defined in space and which has clearly distinguishable boundaries.

An object-based model is a model that simulates the distribution of objects defined by specific geometries, in 3D space, with simulations usually constrained by well data.

A reservoir will typically contain many objects of a certain type (e.g. channels), which have a similar geometry but which differ in size (e.g. different thickness, width and length), location and orientation. If the location of the objects are 'conditioned' to well data (objects have been identified in the wells and the realisation must honour this) then the well data is modelled before the inter well volume.

Object-based modelling uses the stochastic method of approach in building probabilistic models on a particular object with various modelling software such as IRAP and Petrel. These types of modelling have variable input parameters, commonly derived from probability-density functions (pdfs), and therefore have multiple outcomes; as a consequence model runs must be repeated many times and subsequently averaged.

The goal of object-based modelling in sedimentary geology is to predict sedimentary architecture and stratigraphy. Uncertainties associated with object-based modelling include; limited data available about reservoir dimensions and architecture, Complex spatial disposition of reservoir building blocks or facies, and spatial heterogeneity of rock properties. (Bryant and Flint, 1993).

According to Bryant and Flint, 1993, the stochastic reservoir modelling provides improved integration of geoscientific information, uncertainty quantification by generation of many plausible relations, reservoir characterisation during exploration, appraisal and production stage and convenience, and speed of stochastic methods.

Object-based modelling is commonly applied to fluvial reservoirs.

The method employed for stochastic reservoir modelling of fluvial channel sand bodies includes:

  • Conditioning data
  • Honoring well data: whereby sand bodies are randomly located to coincide with sands in the well. This ensures that the channel positions are controlled.
  • Inter well bodies: Here random bodies conflict with the well and must be dropped or moved
  • Final realisation: Sand is added until net-to-gross ratio reaches desired level.

Problems can arise with object based techniques when there are objects present in the well which cannot be matched because the stop criteria has been reached too soon, there are too many conflicts, or the objects being drawn into the reservoir volumes have an inappropriate geometry. Problems are also associated with objects that are very large (It is easier to fit a group of small objects together than large ones). Other problems occur when the wells are closely spaced to the size of the objects; this is ironic as more wells yield better constrained models. The methodology can distort the statistics, whereby larger object are placed near the well and smaller objects between wells.


Dataset
Data used is as follows:

  • Publicly available satellite imagery of the modern Volga delta
  • Enlarged section of the delta with better resolution showing more pronounced distributary channel patterns.
  • Cartoon map of the Volga showing the area covered by the satellite image.


Methodology and Data Collection
The channel segments were traced-out from the satellite image map of the Volga delta using sheets of tracing paper, & the channel segments numbered from 1 to 270

Measurements of length along the stream (L), horizontal length (H) & width of channels were obtained; using a ruler and a long string, and the sinuosity (L/H) was calculated.

The channel segments were assigned a hierarchy with numbering starting from 'one', from the Volga River, at the apex of the delta through the network of branched and converging stream channels to the region represented on a traced-out, satellite image of the Volga delta. The numbering of the channel hierarchy continued from there, through the drainage system to where the stream channel drains into the Caspian Sea. Some channels close to the sand dunes and deserts were observed and measured.

A section of the delta showing a pronounced branching pattern was looked at and measured as above.

The Sinuosity for each channel segment was calculated by dividing the channel length along a floodplain stream (L) by the horizontal channel length (H).

All the records of measurements were properly labelled and tabulated on an Excel work sheet.

Statistical analysis; mean, standard deviation, frequency & cumulative frequency were obtained from the dataset collected via Excel worksheet.





Part 2 of this article with the findings and conclusions will be published the June issue of ROGTEC Magazine.
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Blackbourn Reports: Western Siberia

Following on from his previous article for ROGTEC, Graham Blackbourn looks at the Potential of this exciting frontier

The West Siberian Basin (WSB) occupies an area of approximately 3.5 million km2, including the offshore South Kara Basin in the north and the western part of the Yenisei-Khatanga Trough in the northeast (Figs. I.1.1 & Enclosure 1). The basin is bounded in the west and northwest by the Ural and Novaya Zemlya ridges, in the south and southeast by the North Kazakh and Altai-Sayan uplands, in the east and northeast by the Central Siberian plateau and Taimyr uplift and in the north by the North Siberian Sill. As is evident from the depth to top-Jurassic map (Enclosure 1), the Basin is deepest in the offshore area to the north; the thickness of the Phanerozoic sedimentary cover ranges from approximately 3-5 km in central parts of the basin onshore in Siberia, but reaches 8-12 km or more below the South Kara Sea in the north. The Mesozoic and Tertiary basinfill has been estimated as having a total volume of around with 16 million km3, ranging in thickness from 3-4 km in the central area to 8-10 km or more in the north (this asymmetry is clearly reflected at top-Jurassic level). The Mesozoic-Cenozoic cover is less than 1 km thick along the North Siberian Sill, which comprises a basement high of Mesozoic age extending between the northern end of Novaya Zemlya and the northwestern part of the Taimyr uplift. The basin is connected with the Ustyurt and Aral basins of Kazakhstan to the south through the narrow Turgai valley, which runs between the southern Ural Mountains and the North Kazakh uplands (Fig. I.1.1). During the latest Cretaceous and early Tertiary the West Siberian Sea was connected through this channel with the Tethys Ocean. Apart from the Kara Sea which covers its northern part, the Western Siberian Basin now lies almost wholly beneath the vast, low-lying West Siberian Plain. The plain is drained by the Ob (in the west) and Yenisei (in the east) rivers, which flow northwards into the Kara Sea, and it exhibits little topography, containing vast tracts of swampland. It is the world's largest unbroken area of flat terrain, and elevations remain less than 100 m above sea level 1000 km upstream on the River Ob. Taiga (swampy forest) vegetation and landforms cover much of the Plain owing to the largely sub-Arctic conditions, with tundra in the Arctic regions in the north, and a cool continental climate over the southern steppe, which rises southwards towards the Kazakhstan uplands and Altai-Sayan. The entire Plain lies within Russia, apart from its southern rim which is part of Northern Kazakhstan.



Siberia is notorious for the length and severity of its winters: temperatures below -50 C are not uncommon in winter. Transport across the region is mostly by air, with many roads passable only in winter when the ground is frozen. The presence of permanently frozen ground - permafrost - causes particular difficulties both for surface construction, and for drilling. Permafrost in northern Siberia extends down to depths of 500 m or more (Fig. I.1.2). The structure of permafrost zones both laterally and vertically can be complex, with interfingering of frozen and thawed ground. Three main permafrost zones are recognised within the West Siberian Plain: northern, central and southern.


The northern zone lies to the north of a line of latitude running approximately through the centre of the Medvezh'e and Urengoi gas fields (i.e. about 66-67 N). The permafrost here is continuous both vertically and laterally, apart from below the channels of major rivers and deep lakes. The thickness of the permafrost increases from east to west along the 65 N line from 300 m to 500 m, and on the north coast it reaches 500 m to 600 m. The central permafrost zone has two separate permafrost layers, apart from below a few treeless ridges where the permafrost is vertically continuous. Elsewhere in the central zone there are upper and lower permafrost layers, separated by a layer of melting. The upper layer results from freezing in recent times, whereas the lower layer is a "fossil" relic which was not wholly melted during the most recent Holocene warm period. The thickness of the relict layer in the west is 250-300 m, reaching 300-400 m in the east. The upper permafrost layer is 30-80 m thick, and varies significantly laterally.

The intervening melted layer provides a supply of fresh water throughout the year; those working in the northern zone have no such supply of groundwater, and have to obtain water by melting snow or ice.

The melted layer has also acted as a fluid conduit on occasions when wells drilling below it have unexpectedly encountered pockets of gas. The gas may reach the surface at a considerable distance from the well. For example, such a situation arose on one occasion while drilling on the Urengoi field, when gas was observed to be emitted from the bed of a fluvial floodplain and from lakes up to 1500 m from the well (Medvedskii, 1987). Only the relict frozen layer occurs in the southern zone. This is observed both to the north and south of the east-west-trending section of the River Ob, where it typically lies at depths between 150-300 m (e.g. in the Ust-Balyksk, Pravdinsk and Mamontovsk areas), although its upper surface is occasionally encountered at depths as shallow as 80 m. Its thickness varies considerably, however, depending on surface conditions. For example, it is 150 m thick in the Chernogorsk area, whereas in the Samotlor area, immediately to the northeast, it is considerably reduced owing to the large number of surface lakes and swamps here.

The relict layer in the southern zone does not cause any particular problems for drilling. It can, however, cause problems in the interpretation of seismic surveys owing to its very variable thickness.


No permafrost has been encountered at latitudes south of about 59-60 N (Fig. I.1.2). The permafrost below the West Siberian Plain incorporates considerable volumes of gas hydrates. Environmentalists have expressed concern that global warming could release huge volumes of the bound methane into the atmosphere. Methane is a potent "greenhouse gas", and its release could engender further warming. Russian occupation of Siberia began in 1581, when a Cossack expedition overthrew the small khanate of Sibir, which gave its name to the entire region. During the late 16th and 17th centuries, Russian fur trappers and traders and Cossack explorers penetrated all of Siberia, reaching a border treaty with china in 1689 (although they advanced further east, into the Amur basin, in contravention of the treaty, in the 1860s). Although a place of exile for criminals and political prisoners, Russian settlements were of little significance until the building of the Trans-Siberian railway across the southern part of the West Siberian Plain in 1891-1905. Industrial growth along the railway and in the Kuznetsk Basin coalfield was considerable after the first Soviet Five-Year Plan (1928-32).

The population began to fall again during the 1960s. The discovery of hydrocarbons in 1953, and especially that of the giant Samotlor oil field in 1965, however, was the major impetus for a redevelopment of the area, especially its northern regions, which reached a peak during the 1980s. Figure I.1.3 illustrates the average size of oil discoveries in Western Siberia from the 1970s, compared with those from Russia as a whole. It is clear that the average field size in the WSB has consistently been significantly higher than that of Russia as a whole, but that discovery sizes in both areas have fallen steadily and dramatically. Nonetheless, although Western Siberia is now a mature province, it covers an immense area, and there is plenty of scope for further discoveries, even if no "supergiants" remain, in addition to development and rehabilitation of existing fields. Some of the latter hold very considerable remaining reserves. The early years of the 21st century, with steadily increasing oil and gas prices, have seen a significant increase in the levels of activity.


I.1.3 Brief Historical Review of the Hydrocarbon Industry of Western Siberia, and a Short Introduction to the Petroleum Geology of the West Siberian Basin.
The first field to be discovered in Western Siberia was the Berezov gas field in 1953, in the northern Pre-Urals area on the western margin of the Basin (Enclosure II.1). Owing to the remote location and the absence of infrastructure to the field, which has a Jurassic reservoir, it was not brought on-stream until 1963. In the meantime, the Megion oil field in the Middle Ob Region was discovered in 1961, followed by the giant Samotlor field in 1965. Samotlor was one of the largest oil fields in the world: ultimately recoverable oil has been estimated as 24.7 billion barrels, and it immediately drew the attention of Soviet planners to the West Siberian Basin, and drew investment away from almost all other hydrocarbon provinces in the FSU. The Samotlor field was brought on-stream in 1964. Reservoirs vary in age from Late Jurassic to Cenomanian, but the large majority of the oil lay within Neocomian marine sandstones, which have proved to be the most prolific oil reservoir in the entire West Siberian province.

Further development of oil fields within central parts of the West Siberian Basin during the 1970s was followed by the development during the 1980s of massive gas fields in the north, mostly within Cenomanian reservoirs, first discovered in the 1960s. Oil production in the basin has however declined since 1988, and gas production since 1991, and recent production has exceeded the reserve replacement rate.

Most of the known and potential hydrocarbons in the basin lie within the Mesozoic succession. The Palaeozoic and older basement was formed by a complex array of microplates and continental fragments brought together by ocean closure and strike-slip faulting during the mid- to late Palaeozoic (Section I.2.1). Following Triassic rifting and igneous activity, the basin as a whole began to subside in the Early Jurassic and to fill with sediments sourced from the surrounding uplands, lying primarily to the southeast and northeast. Once the erosional topography had been blanketed, deposition occurred across a very extensive platformal area. Owing primarily to the vast extent of the basin, sediment input did not keep pace with subsidence, and the western half of the basin in particular was at times sediment-starved, leading to the deposition of up to 2500-3000 m of dark marine shales, commonly rich in organic matter, being deposited there between the Middle Jurassic and early Tertiary, with the latest-Jurassic Bazhenov Suite being of particular importance as a source rock. During most of the Early Cretaceous the transition between deltaic and open-marine deposition lay approximately mid-way across the basin. Repeated transgressive-regressive cycles in this environment provided optimum conditions for the reworking and winnowing of feldspathic deltaic and interdeltaic sands, leading to an improvement in their reservoir potential. Shelf deposits prograded westwards and northwestwards across the basin during regressive phases, creating clinoformal structures with distinct sand accumulations in the upper, shelf, environments, on the slope, and at the base-of-slope. During transgressive phases the clinoforms were draped by marine sapropelic muds of excellent source-rock quality, which encased the sand-rich clinoformal structures and these, together with the underlying Bazhenov Suite source, created a remarkably efficient source rock - reservoir - seal relationship.

A delicate balance between sediment input, sea-level fluctuations and basin-floor subsidence provided a combination of circumstances in which this interfingering of reservoir sands and source rocks continued to form throughout the Early Cretaceous over the extensive central-southern area of the basin, in particular within the Nizhnevartov, Surgut, Urengoi, Yamburg, and other regions (Enclosure II.1). The high concentrations of organic matter within the basin may have been related partly to its palaeogeography, and especially to its restricted connection over the North Siberian Sill with the Arctic basin to the north. Southward circulation of cooler nutrient-rich marine waters across the North Siberian Sill into the warmer epicontinental basin may have stimulated the production and accumulation of planktonic organic matter to an unusually large extent. The oil-prone marine source-rocks did not extend over the substantial eastern and northeastern areas of the basin, and other parts of the basin margins, which had become the sites mainly of fluvio-deltaic and lacustrine deposition. Significant coals accumulated within these environments, however, which constitute a substantial gas source. This is the main reason for a general transition from oil fields within central and southern parts of the WSB, to gas in the north and east, and along its western margin (Enclosure II.1).

Another factor which makes the WSB such a prolific hydrocarbon province is that there has been very little tectonic activity within the area since hydrocarbon emplacement, so that early accumulations of hydrocarbons have been preserved within structural and stratigraphic traps which have remained relatively undisturbed.

Over the past 30 years or more, the WSB, particularly its central-southern part (either side of the Ob-river where it runs in an approximately east-west direction before turning northward in the Khanty-Mansi area - the Russians call this the "latitudinal Ob" region (Fig. I.1.1) has been quite thoroughly explored. However, parts of the basin remain under-explored, particularly the South Kara Sea and the Yenisei-Khatanga Trough. Both of these areas appear prospective, especially for natural gas and possibly for oil. The major Jurassic and Cretaceous source-rock facies are thought to extend northwards into both these regions: the gas-prone source may become more extensive, although the oilprone Bazhenov Suite may well extend into the South Kara Basin. The Taimyr uplift, and probably Novaya Zemlya, were sources of clastic material during most of the Mesozoic, and could have provided good-quality reservoirs.

The West Siberian Basin is of enormous extent, and the Russian-language geoscience literature uses a variety of systems for sub-dividing it into geographic regions. One of the most common subdivisions is illustrated on Enclosure I.1 (after e.g. Maximov, 1987). The ten regions depicted are somewhat arbitrary, apparently being defined on the basis of a variety of geological, geographic and administrative criteria. These regions differ from the purely administrative divisions, illustrated in Fig. I.1.1. A pragmatic approach is adopted in this report, switching between the different terminologies according to what is most appropriate to the discussion in hand.

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