Latest Oil and Gas News Russia

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

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

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

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

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

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

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

Labels: siemens

posted by The Rogtec Team @ 14:18  0 Comments