Latest Oil and Gas News Russia

Hamish McArdle,
Special Counsel, Baker Botts (UK) LLP

Mark Rowley,
Partner, Baker Botts (UK) LLP

In this two-part Article "Turkmen Gas - Export Strategy and Trans-Caspian Opportunities" Turkmenistan's historic and current gas export strategies are examined, and the opportunities for Trans-Caspian gas exports to Europe are considered. Part One of this Article provides an overview and assessment of Turkmenistan's current gas export strategy, and considers some of the competing claims for Turkmen gas.

Recent diplomatic events involving Turkmenistan and Russia, and to a lesser degree Azerbaijan and the European Union, when taken together with recent statements of Turkmen President Berdymukhamedov, suggest a sea-change in Turkmenistan's energy export strategy. Is Turkmenistan finally ready to commit to gas exports to the European market, or are we once more seeing Turkmenistan successfully playing off competing interests for its natural resources?

Whilst Azerbaijan, with the support of the US, was successful in securing a non-Russian alternative export route for its oil and gas through the Baku-Tbilisi-Ceyhan (BTC) Pipeline, and the South Caucasus Pipeline (SCP) respectively, the export of Turkmen gas through a proposed Trans-Caspian link foundered in the late 1990s. Now, however, there are renewed signs that Turkmenistan may be serious about committing to diversify its gas export options.

Turkmenistan has traditionally been a net exporter of gas. Since independence from the Soviet Union in 1991, it has, together with Caspian neighbours Kazakhstan and Azerbaijan, been the focus of sustained US and EU attention in a bid to counterbalance European dependence on Russian gas supplies. Indeed, Turkmenistan is seen by some as a potential keystone supplier of gas to Europe. Various factors have, however, conspired to maintain the gas export status quo. These factors include the proactive geopolitical and energy strategy pursued by Russia and Gazprom, failure to agree the littoral boundaries of the Caspian Sea states, continued uncertainty as to Turkmenistan’s actual recoverable gas reserves, and the difficult environment for foreign investment in Turkmenistan as a result of the idiosyncratic policies of former President Niyazov - the self-styled "Turkmenbashi" (or "Leader of Turkmens").

Limited Options versus Abundant Opportunities
Considering the historic importance of the Caspian region for hydrocarbon production, and the unconfirmed estimates of significant oil and gas reserves in Turkmenistan, Azerbaijan and Kazakhstan, the Caspian region generally (and Turkmenistan in particular) remains relatively under-explored. The principal causes of the relatively poor state of Turkmenistan's oil and gas industry, and its limited options for development, are (i) the political and economic relationship between Turkmenistan and Russia (historic and current), and (ii) at least with respect to gas, the difficulty in finding an accessible market, caused by Turkmenistan’s geographic location. It should be noted that Turkmenistan's position is not entirely unique and that these circumstances are largely also experienced by Kazakhstan and, to a lesser extent, Azerbaijan.

The Turkmen Government's own (unverified) reserves' estimates are 12 billion barrels of oil and 20 trillion cubic metres of gas, which would equate to Turkmenistan having around the fifth largest gas reserves in the world. There are two main gas producing regions in Turkmenistan: in the Eastern/Southeastern Uzbekistan and Afghan/Iran border regions, and in the West/
Caspian offshore area (see Diagram).

Hydrocarbon production is by means of Licences for Exploration and Production, and by Production Sharing Agreement (PSA). All hydrocarbon exploration and production involving foreign company participation is currently undertaken through PSAs. There are currently a small but growing number of foreign investors operating oil and gas concessions in Turkmenistan, including Dragon Oil, Petronas, Eni and CNPC. The list of foreign companies currently seeking to become involved in Turkmenistan is growing almost daily.

Exports to Russia
Currently, around two-thirds of Turkmenistan's gas is sold to Gazprom, and is exported to Russia via the Central Asia Centre Pipeline (CACP) (see Diagram). The CACP has a capacity of approximately 80 billion cubic metres (bcm) per annum, and has been constructed on a piecemeal basis from 1974. 90% of gas exported from Turkmenistan to Russia travels via the eastern branch of the CACP through Uzbekistan and Kazakhstan, where it meets with the western branch taking gas from the Caspian region north through Kazakhstan. The CACP generally, and particularly the western section, is understood to require significant modernisation, and recently suffered an explosion claimed by the Russians to be the result of the "dilapidation of the gas pipeline system". The generally poor state of these main export pipelines, together with capacity constraints in the Kazakhstan sections of the CACP, restricts Turkmenistan's current gas export opportunities to Russia.

One proposal was for a new Caspian Sea border pipeline linking Turkmenistan with Russia via Kazakhstan (the "Caspian Gas Pipeline", also known as "Prikaspiiski") to be constructed alongside the existing 10 bcm per annum onshore pipeline (the western section of CACP) which would increase export capacity on this route by an initially planned 12 bcm per annum, (see Diagram). The Prikaspiiski project was agreed between Russia, Kazakhstan and Turkmenistan in 2007, and was intended to be operational in 2010, however construction has yet to commence. Arguably, the delay can be attributed to the increased diplomatic tensions surrounding the Nabucco project, and potential Trans-Caspian export options, (to be discussed in Part Two of this Article) and may reflect a desire by Turkmenistan not to commit wholly to Russia's gas import embrace.

Turkmenistan's recent decision to open to international tender for the construction of the internal East-West gas pipeline, connecting Turkmenistan's Eastern and Caspian region gas fields caused further strain to the Turkmen-Russian relationship, and to the historic influence of Russia in the key gas development and export decisions of its neighbour. The original plan had been for Gazprom to build this pipeline and for it to tie-in to the Prikaspiiski pipeline to facilitate additional gas deliveries to Russia.

How Russia Took Control of the Gas
Western interest in Turkmen gas was relatively short-lived following the country's independence, largely as a result of Russia's ability, through national champions Gazprom, Rosneft and LUKoil, to maintain its traditional influence in the region.

Gazprom, Rosneft and LUKoil have been strong and successful players in the competition for the control of strategic oil and gas assets within the Russian zone of influence. In controlling the main gas export infrastructure, Russia's strategy has been to prevent Turkmenistan from selling its gas directly to the European market. The export relationship is chequered, including a significant transit price dispute in 1998, which resulted in gas exports to Russia being suspended. Over time the commercial terms on which Turkmenistan has been able to directly trade its own gas have changed, so that now Gazprom purchases all Turkmen gas exported via Russia at the border.

The failure of Turkmenistan and Azerbaijan to progress a Trans-Caspian Pipeline, initially proposed in 1996, is substantially attributable to Russian political opposition, as well as the unresolved status of the Caspian littoral state's offshore boundaries, a circumstance used by Russia to its advantage. It is also worth noting that the Trans-Caspian pipeline was not, at the time, in Azerbaijan's economic interests either - it being keen to ensure the viability of its own gas export project to Turkey (SCP) ahead of any project to export competing Turkmen gas.

Faced with the circumstances described above, it is unsurprising that Turkmenistan has progressed gas export projects geographically to the east and south, towards China, Iran and Pakistan, and away from the zone of Russian influence in the Caspian, Caucasus and Black Sea. Russian geopolitical influence is weaker in these alternative markets, although Gazprom at one time did seek involvement in the India/Pakistan export project, ultimately pulling out for financing reasons.

The New Challengers
Iranian Exports
The first non-Russian post Soviet-era gas exports by Turkmenistan were to Iran. Operational since 1997, the 150km pipeline from the Korpedji Field in Western Turkmenistan to Kurt Kui in Iran has an 8 bcm per annum capacity. A second 1 bcm per annum gas pipeline was put into operation in 2000 (see Diagram).



Although Iran has the world's second largest gas reserves, it is a net importer of gas and is keen to increase imports of Turkmen gas for domestic supply to its northern regions. Iran considers itself to be a natural route for Turkmenistan's gas to the European market, and continues to lobby Ashgabat for new export commitments and co-operation. Turkmen gas could be supplied to Turkey via the Iran-Turkey Pipeline (although prone to stoppage and interruption, particularly in winter months), and theoretically then onwards to Europe. Unsurprisingly, the Iranian export route is politically a high-risk option given the internal instability of that country, US and EU sanctions against Iran, and the associated pressure brought to bear on Turkey, Turkmenistan and Azerbaijan against a deepening of their energy dealings with Iran.

Pakistani and Indian Exports
The proposed 1,700 km, 27 bcm per annum Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline has been long in planning and is supported by the Asian Development Bank (ADB). The project proposes that Afghanistan would off-take 2 bcm per annum with the remainder shared equally between Pakistan and India. Construction was originally scheduled to commence in 2010 with the pipeline projected to be operational by 2014; however it is unclear whether all parts of the project will be built, and to what timetable. The TAPI pipeline is supported by the US as an alternative to exports to Pakistan and India from Iran. Turkmen gas exports via TAPI would compete with Iranian and Qatari gas transported via the proposed Iran-Pakistan-India pipeline (IPI). It is hoped that TAPI and IPI would together form the core of a Southern Region Gas System.

Chinese Exports
The 7,000km Trans-Asia Gas Pipeline from Turkmenistan to China via Uzbekistan and Kazakhstan is currently nearing completion, and will eventually reach Shanghai. From 2010 Turkmenistan will export 30 bcm per annum of gas to China for thirty years, with a further 10 bcm per annum committed for export to China by Kazakhstan. By offering "near-European" gas prices and assisting Turkmenistan to finance gas field development, China is aggressively consolidating its position as a credible gas export partner, and building a sphere of influence in the Caspian region energy market in direct competition with both Russia and the European Union. China's pragmatic and decisive approach, and its deep pockets, have found favour in Turkmenistan, and as the relationship has flourished the countries have agreed a suite of co-operation agreements on energy matters, gas production and gas purchasing.

Part Two of this Article reviews the current, and changing, state of the Turkmen-Russian relationship, and assesses the likelihood of Turkmenistan committing to a Trans-Caspian gas export link to Europe

Labels: baker botts, oil gas, pipeline, Turkmenistan

posted by The Rogtec Team @ 11:02  0 Comments

David Sullivan - Managing Director of Geotrace Data Integration Services Ltd

Alexander Yakovlev - Product Manager, RISC/UNIX servers and storage, Fujitsu Technology Services

Vladimir Zykov - Product Sales Specialist StorageWorks Division, HP Russia

Thomas N. Keller - President of Iron Mountain in Russia



What is the current condition of the data storage and retrieval sector in Russia? What changes are required?

David Sullivan: The storage and retrieval sector in Russia is still characterised by warehouse style storage spread across this vast nation. Over time, some organisations have transcribed the original format data into more modern and durable media (3590, 3592, LTO-4 etc.) and scanned sections and film to produce digital archives. Other organisations have created automated near-line and on-line data management systems. Russia, like its competitors, needs to move to contemporary data storage and retrieval sector focused on smaller data centres, using modern media, on-line storage and with the focus on quality and availability. More controversially, once the data is converted to the new systems and quality assured the original format data should be destroyed.

Alexander Yakovlev: Due to significant IT budget cuts and restrictions, the sales of large solutions and high-end class disk arrays dropped down in the first quarter. Resources were reallocated and some projects that initially were planned as high-end projects were downgraded to middle class systems. Data growth rates have remained the same as before the downturn, and as such sales of disk arrays in the middle class segment did not change much, and indeed even grew in SMB sector. This can be explained one hand by budget cuts, and on the other hand by significant performance and functionality enhancements of SMB disk arrays. For example, in our recently announced entry-level disk storage there are a number of hardware solutions that were previously available only in middle - and high-end segments.

Vladimir Zykov: For the most part Oil & Gas companies buy Low-end and Mid-range systems. There are some transitions to higher level Mid-Range and Hi-end models in some of the regional centers and large research facilities, accompanied by new technologies, specialized storage systems and hierarchical storage. All in all O&G is pretty much in line with current trends in storage industry.

Thomas N. Keller: Present conditions of oil and gas energy data storage are very fragmented and de centralized. There are significant amounts of energy data (with huge replacement cost and valuable commercial application) which is improperly stored, poorly catalogued, and has no back up or replacement. In short, most major energy companies do not have a centralized policy for storage of key data and an authorization system for its retrieval. It's mostly held with subcontractors and contracted providers.

The region is seeing exponential data growth across all sectors, is there a risk that future valuable data assets will be lost because of inadequate storage capacity?

David Sullivan: Russia has always placed great emphasis on the national interest value of exploration and production data. However, here, as in all other oil provinces, valuable data assets are regularly lost because of inadequate storage capacity (and techniques). The near exponential growth of E&P data in the Russian Federation will mean that more modern storage conditions, together with more technically advanced and effective data management techniques, will be mandated. Availability of appropriate quality assured data to the exploration community will be a key factor for success in the ongoing development of the Russian oil and gas business. Certainly, modern 3D surveys create much more data by volume. But these surveys use advanced, more durable media. The cost of the survey means that the client tends to take care of this valuable purchase (at least in post stack form). However, most of our knowledge of the world's hydrocarbon bearing rocks, by area and most of our understanding of the history of our oil and gas fields comes from 2D seismic surveys, traditional well data, maps and historical reports. This will be the case for many years. These are the invaluable data sources whose value is constantly denuded by inadequate data management - both in terms of the physical condition of the media and availability of the data.

Alexander Yakovlev: Even with a cut in IT budgets, a skilful management should be able to avoid the loss of critical data. On the one hand, a number of solutions for information life-cycle management and managed services, and on the other the use of cutting edge storage technologies that allow the user to store substantial volumes of information a cheaper cost. A good example of this are Nearline SAS (NL-SAS) hard drives, that give big advantages in performance and reliability of SAS interfaces and in the near future will have a capacity of 2 TB.

Vladimir Zykov: If the storage systems implementation lifecycle in companies is reduced from the current 10-12 months to 5-6 months, taking into account the arrival of new storage technologies along with bigger disk drive capacities there should be no such risks. HP already provides several storage solutions to the Russian market which combine low cost with high performance and storage volumes. Also, implementation of the Hi-End storage systems will allow for capacity reserves for some of the customers tasks.

Thomas N. Keller: Yes there is a large risk of this but we feel many of the companies are beginning to realize this and develop solutions to handle this. However, most companies have yet to make the key distinction between key "live" data and important historical data (the key difference being access speeds, and authorization levels). In many cases they are over engineering solutions which are costly and unnecessary

With large legacy systems existing in Russia, is there an urgency to modernise the solutions the operators are using?

David Sullivan: At first glance, it is much less expensive and requires far fewer resources just to preserve the status quo. To progress we need to adapt and to innovate. The large legacy systems need to be consolidated into small units with modern media and high levels of accessibility. Unfortunately, data management is often regarded as an expense rather than an opportunity. Conventional accounting techniques show only what we have spent on the storage, rent, utilities, transport etc. No account is taken of the opportunity cost of the delay in producing hydrocarbons resulting from inadequate data management. Replacing a traditional warehouse-based system with a modern and effective data management regime provides oil and gas companies with an effective, strategic tool at the core of their business. Therefore, there is a compelling and urgent need to modernise the solutions in use by Russian operators.

Alexander Yakovlev: If we compare, for example, with western markets, Russia does not have so many inherited systems. It gives us a number of advantages - customers are ready to implement modern technologies much more actively that allow a significant rise in efficency. Thanks to the virtualization of tape media we offer increased speed and performance of the back up and copy process to the tapes in very diverse environment, including back up copying from mainframes to modern LTO-4 devices.

Vladimir Zykov: There is no need to modernize such legacy systems; the system will have to be replaced instead. Legacy systems usually have no means for integration between themselves and a new IT system. Small vendors that initially provided these solutions often do not exist anymore and system support is provided by the companies own IT staff. However, many of the old systems are still in line. New systems are being bought for the new tasks. In some companies old systems are being transferred to the branch offices that do not require high storage capacities or performance, so as to maximize efficiency. Later these systems are being utilized, according with companies hardware lifecycle policies. So there is no urgency as such.

Thomas N. Keller: Not really. There is a large need to inventory the key data and categorize it according to its creation, usefulness, and access levels. Operators then have to upgrade legacy systems, as needed, rather then "across the board". Selective protection (using proper data vaults and so forth) can eliminate the need for large-scale modernization of legacy formats. Data can then be used "on demand" which results in significant cost savings. Note however that much of the older seismic data needs urgent categorization, quality control, and modernization to new formats.

What is the level of accessibility to archived data within the regions oil companies?

David Sullivan: Accessibility is entirely dependent on the system in use by the company. Generally, if the data is managed using a legacy warehouse type-environment, where original media is requested, both response times and accessibility are generally poor. This is exacerbated where the data needs extensive QC, improvement and format conversion before it is workstation ready. There are a great many data sets throughout Russia that could be regarded as highly inaccessible. Where the data owner has implemented a digitisation and re-mastering project, accessibility is improved, particularly if the system has a near- line or on-line component. Integrated digital data management systems, either in-house or using a reputable third-party system, improve matters further.

Alexander Yakovlev: At the same time with complex multilevel content storage todays market offers WORM technology (Write Once Read Many) that allows the creation of an archive on special LTO standard tapes. Therefore we have the possibility to create a tape with an unchangeable archive copy of the data in a small tape library. If we have, for example, two writing devices in the tape library we have the possibility to create one ordinary tape and one WORM tape for long-term archive. This technology has enabled the access of archived data not only from the headquarters, but also in branch offices.

Vladimir Zykov: Not every company can allow itself to store a few years of archive data online on the disk storage system. And the accessibility level for archive data is not very high. Data archiving systems are not implemented in lots of cases. It might be impossible to restore data from the archive, because there is often no archive copy at all. Usually this happens because there is no archiving process in place, or if it is present, is poorly implemented, not automated and prone to human errors.

Thomas N. Keller: In our experience it's poor or non-existent. Often the original source data resides not with the owner of the data but a sub contractor. The subcontractor does not inventory the data and has no real incentive or systems to catalogue it for its client. The real end user, the oil field specialist, often has no access or idea what resources are available to him/her. This is where the real money is made or lost.

Data protection has always been a concern - what can the operators and data centres do to ensure data security and their legal requirements?

David Sullivan: By storing data in remote physical stores and distributing interpretations across systems spread right across this vast country, we often create an environment that is susceptible to security breaches When we were designing our own system, we recognised the need to produce a system that would give data owners ultimate security over their valuable data asset, yet provide controlled and convenient access to authorised users. In addition to secure, convenient access ,it is also extremely important to automatically monitor the use of the data asset - both to ensure that there are no security breaches and to add to the knowledge of the data's provenance. The Ministry of Natural Resources, tax authorities, regional administrations and a host of others mandate regular filings relating to a wide variety of exploration activities across the entire asset life cycle. Once again, the concept of a warehouse-based store or archive is entirely inappropriate for this purpose. By migrating to an integrated digital data management system, we can produce a more effective and less expensive statutory reporting system. Digital data integration systems, not only enhance security and make short work of complying with statutory reporting obligations, they enable the data owner to manage their assets in real-time. Thus the latest digital oilfield techniques, usually only used on the most capital intensive of fields can be applied to the smallest, remotest asset, at minimum cost.

Alexander Yakovlev: As with any complex goal, the problem of data integrity and security must have complte solution on both soft and hardware level, and, probably the most importantly on organizational level. Competent use of modern entry and middle class solutions allows the user to decrease the possibility of hardware data loss to very low level. For example, in our recently announced entry level disk arrays, ETERNUS DX60/80, along with snapshots, it is possible to create full clones, internal and remote data replication. I would like to emphasize that all these functions are embedded into the entry level systems. So, if the process of back up copying and information life cycle management are organized properly, and in conjunction with modern storage functionality it is possible to build a highly reliable configuration even when using entry level systems.

Vladimir Zykov: Actually, I would class this question is a continuation of the previous one. Of course there have to be means for data backup and archiving in the company's data center. Also, IT departments have to have a data protection strategy and have to work according to the SLAs for the different types of data: operational, archives, backup, etc. At HP we can help here by providing an integrated solution for all types of customer data, along with the monitoring and management tools for the data itself and for the storage infrastructure as well.

Thomas N. Keller: There is a fine line between security and paranoia. Our strong suggestion is to benchmark with others in the industry.

In today's climate with operators looking to cut cost across all sectors of operations - describe the solutions you can offer to help them achieve this goal, especially as data management can be viewed as a spiralling cost for the owner.

David Sullivan: Silo-based data archiving belongs in the dark ages, exploration data is the very stuff hydrocarbon discoveries are made of and it is high time we recognised its importance. In fact, such projects not only assist the exploration process, the scanning, digitisation, re-mastering and re-cataloguing activities associated with their implementation drive down traditional data administration costs. Storage area is vastly reduced, outmoded media can be discarded and transport costs virtually eliminated. Also, given that traditional storage costs are annually recurring the project will go on saving money for many years to come.

Alexander Yakovlev: One of the ways of cost reduction during constant growth of stored data is the concept of managed storage services. We offer "Managed server" and "Managed storage". These solutions allow the creation of private "cloud" storage which allows the user to utilize the advantages of storage and computing supported by the cloud computing technologies, and at the same time to avoid a number of vulnerabilities inherent to this concept. Managed services will take into account all the specifics of the customer's IT infrastructure, will meet customer's business needs and will allow the system to be scalable and flexible depending on the situation.

The necessary conditions for successful integration of the managed DDC are clear definitions and service level agreements. It also important for optimization, because both a lack, or indeed excess of services can cause the system to be ineffective. Consequently, the first step is to analyze the demands and their requirement of service level agreement (SLA) including goals, roles, reaction and restore time limits. Such agreements are the basis of cooperation between the service provider and the customer's IT department. For example, SLAs of Fujitsu Technology Solutions define the components of operation (e.g. storage devices, mail servers and print servers), processes of back up copying and restoration, and the management of all IT services for the centralized network and system management platform. These clear interfaces allow the management of DDC operation fully or partly, and the customer does not lose the general understanding of the levels of quality and cost of the managed services. IT departments do not need well paid professionals in their headcount. The goal is to use the resources when they are necessary and not to pay when they are not neccesary. As a service provider we can offer a high level of flexibility to give additional advantages to our customers. Thus, a managed DDC of Fujitsu Technology Solutions gives the choice between our customers own activities and placement of DDC outside of the company providing the necessary services.

Vladimir Zykov: These are the solutions, specially developed by HP to provide high user value with low TCO. We are continuing to improve our midrange systems such as the HP StorageWorks EVA x400 series, which are, according to the Edison Group whitepaper the easiest to manage among similar class storage systems. At the beginning of this year we announced a new storage appliance, HP StorageWorks ExDS 9100, which provides exceptional storage density per sq.m. of data center floor, combined with low cost per TB of data and highly scalable performance, and delivers access to different types of data, i.e. geological, via many file access protocols: NFS, CIFS, FTP, HTTP, etc. For the remote offices and regional branches we promote inexpensive HP LeftHand P4000 SAN solutions, which are based on the iSCSI and do not require costly FC SAN implementation and staff training. As for the storage backup solutions we provide traditional tape libraries along with virtual libraries such as HP StorageWorks VLS, that allow the user to store vast amounts of data with high speed access, thanks to new deduplication technology.

Thomas N. Keller: Iron Mountain (IM) is the global leader in the storage and protection of energy data. It's all we do around the world. We are able to assess problems and outline solutions which are safe, secure, redundant, allow access control, and cost effective. We have industry specific software (and solutions), which allows companies to move data from a spiraling cost to a productive asset.

How do you see the future of the storage and retrieval sector in Russia and the CIS?

David Sullivan: Russia has always regarded exploration and production data as being important to the national interest. Consequently, it understands very well the need for secure, strategic management of these assets. As such, I expect that Russian organisations will wish to exploit the opportunities that the new technologies afford. Specifically, I see a trend for removing data from remote warehouse locations, re-mastering to modern formats and relocating to state-of-the-art integrated digital data management systems. The reduction in bulk means that these centres can often be located at the company's headquarters with a security copy stored at another secure location. Where the company is involved in operations around the world, these integrated digital data management systems can be distributed, allowing access to the data in the partner country as if it were in Moscow. In addition, I see a trend towards integrating the integrated digital data management with the wider exploration lifecycle. These modern systems need to be able to communicate with modern workstation formats and supply data to them and receive data from them rather like an automated digital librarian, recording the transaction and maintaining an audit trail of how these data have been used. These systems will also be integrated with the regulatory authorities, meeting the statutory reporting obligations of the oil and gas company.

Vladimir Zykov: Russia and CIS companies are moving in the same direction as the rest of the world. We can expect to see rapid development of SAS technologies, continuation of the FC and iSCSI SANs development. Oil & Gas companies will continue to mlargely purchase Mid-range systems that will be based more and more on the industry standard components. Hi end systems will be implemented for specific "heavy" tasks like SAP and the like.

Thomas N. Keller: Clearly the key data will be created and stored near the energy production. Therefore we will have to move our vaults, people and expertise to the regions and keep working with our customers to save them money and increase the security of their data. Further in Russia there is a strong assumption that data needs to be in house to be compliant with Russian law and internal company regulations. This is simply not true. We see this changing but it will take time and experience for companies to try and fail to manage data themselves. We see many of our clients now outsourcing "trial" parts of its data storage to IM so they can verify the process and manage costs.

What are the key issues for data storage and accessibility, in terms of workf low optimisation and maximising E&P decision making? What can you offer to overcome these issues?

David Sullivan: Accessibility is key. If explorers are unable to access data when required, the value of that data is lost. Modern exploration and production specialists need high quality, workstation-ready data on demand. The challenge is to meet this need in a cost effective manner, while ensuring the company's precious data asset remains secure. We believe passionately that the effective use of exploration and production data is at the very heart of the exploration task. We can create a real time, integrated digital management system that enables companies to make the very most of every data acquisition Rouble.

Our approach can streamline the exploration process, and deliver incredible efficiency savings. Regulators, including government and national oil companies, can ensure their data is managed strategically, ensuring that the national interest is properly served. All stakeholders can have a much more informed view of the potential of their hydrocarbon assets. We have created a suite of state-of-the-art products supported by the best people to make this happen. Our team is based in Tyumen at the heart of the Russian oil and gas business and has vast experience of this type of project.

Vladimir Zykov: Currently storage systems are used not only in the context of traditional IT infrastructure - for database data, financial systems data, but also as a storage for industrial process automation solutions such as SCADA, exploration, geological data and so on. On this base of data silos corporate data warehouses are being built that allow the user to analyze, forecast and get additional value from stored data. No company in O&G sector in Russia currently has such a solution implemented in full scale. However, everyone is moving in this direction, with different rates of success. Difficulties that occur are more administrative, such as problems in communication between departments of merged company. It may also be a technical problem because of the different and incompatible data formats. To solve this HP provides specialized solutions for the O&G industry together with our partners: Schlumberger, ROXAR, Landmark, SGG, SAP.

Thomas N. Keller: In our opinion, this means making sure the key energy data is used by the people who need it most. We so often see that data storage is a black hole where nothing ever comes out. Our solutions put data at the desktop where field people who need the access can have in within seconds. This is a complete process of identification of key data assets, storage and digitizing of key assets, and setting proper access levels for usage.

Any final comments?

David Sullivan: We encourage you to consider how this approach could benefit your organisation. Please visit us www.geotrace.com/products/tigress.html (Russian & English) or mail sales@geotrace.com for more information.

Thomas N. Keller: In addition to state of the art data vaults and data migration from older formats, we offer a multilanguage asset management system called "eSearch" which was designed with today's large-scale energy company in mind. It manages data in terms of location, description, access control, and allows full track and trace of all assets. It's scaleable and working in a number of major Russian energy companies to manage large amounts of key data. From the archive to the desktop! Find more on eSearch at: http://www.ironmountain-esearch.com/

Labels: data accessibility, Data storage, Fujitsu Technology Services, Geotrace, HP Russia, Iron Mountain in Russia, oil gas

posted by The Rogtec Team @ 15:37  1 Comments

By: J F Lea, PLTech LLC, David L. Divine, P.E. Wood Group ESP, & Lynn Rowlan, Echometer Co.

Introduction:
The electrical submersible pump system has been developed over the years by Engineers and scientists involved in metallurgy, hydraulics, electronics, heat transfer, plastics, many aspects of mechanical engineering, and other disciplines. It is not practical to outline all of the many aspects of the system in the short introduction section. Instead, the major components are introduced.



Overview:
The pump assembly is hung on the tubing with the electric cable banded to the outside of the tubing from surface to pump. The equipment is arranged from top to bottom with the pump first, with the gas separator below, then the seal section, followed by the motor. If a downhole pressure sensor is used, it is hung at the bottom of the motor. ESP's are thought of as high volume lift perhaps producing -20,000 bpd at 4000' down to -5000 bpd at 10,000' depending on many factors, but low volume (-100 bpd) stages exist.

Motor:
The electric submersible motor is a two-pole, three-phase, squirrel cage induction type. The motor runs at a nominal speed of 3500 rpm on 60 Hz frequency and 2900 rpm on 50 Hz. The motor is filled with a refined mineral oil to provide dielectric strength, lubrication of bearings and thermal conductivity. The thrust bearing of the motor carries the load of the rotors. The electrically nonconductive mineral oil lubricates the motor bearings and transfers heat in the motor to the motor housing. Heat from the motor housing is in turn carried away by the well fluids moving past the exterior surface of the motor. For this reason, the motor should not be set below the point of fluid entry unless some means of directing the fluid by the motor is utilized. Typical nominal motor diameters of equipment may be: (a) 3.75", (b) 4.56", (c) 5.402, 5.44", 5.62", and (d) 7.38" for various casing sizes. Some motors are offered with somewhat different diameters and some manufacturers do not carry some of the diameters indicated. Some Motor construction may be a single housing or several "tandems" bolted together to reach a desired horsepower rating. Motors range in horsepower from 5 to 1000 hp and larger.

Pump:
The electric submersible pump is a multistage centrifugal type. The type of stage used determines the approximate design volume rate of fluid produced but as the fluid compresses, each stage will have progressively less volume to handle. The number of stages determines the total head designed for and the motor horsepower required.

The usual materials used in manufacturing an impeller are Ni-Resist with some options for sand handling. Diffusers are typically manufactured of Ni-Resist. The standard shaft material is K-monel. Optional, high-strength shaft materials are Inconel and Hastalloy. Bolt-on heads and bases make it possible to vary the capacity and total head of a pump by using more than one pump section. However, large capacity pumps typically will have integral heads and bases. The nominal outside diameter of a pump will range from 3.38" to 11.25" but 7.62" to 8.38" could be largest oil well applications.

Seal Section. Protector, Equalizer:
The motor protector's primary purpose is to isolate the motor from the well fluid. There are, in general, two types of industry protector or seal section designs although there are specific differences from one brand to another. One type uses a positive bag seal and the other type uses a labyrinth or tortuous path. The "positive seal" design incorporates a fluid barrier bag to allow for thermal expansion of the motor fluid yet still provided isolation of motor fluids from wellbore fluids. The "labyrinth path" utilizes differential fluid specific gravity to prevent well fluid from entering the motor. This is accomplished by paths where the motor fluid is allowed to expand to displace more or less of the wellbore fluid as it expands through a tortuous path at an interface near the top of the protector. There are usually several "labyrinth paths" in one protector and more could be added by placing protectors in series. Normally the bag type positive seal protector is backed up with "labyrinth paths" so that bag failure is not necessarily catastrophic.

The protector or seal section performs four basic functions. These are: (1) It connects the pump to the motor by connecting the housing and drive shaft; (2) Houses a thrust bearing to absorb pump shaft thrust (if present); (3) Isolates the well fluid from the motor while still allowing pressure equalization between the wellbore and the oil-filled motor; and (4) provides for thermal expansion of the motor oil due to heat generated by the motor during operation and thermal contraction of the motor oil following pump shutdown/startup.

Gas Separator:
The gas separator is installed between the protector or seal section and the pump. Its purpose is to separate a significant portion of any free gas in the produced fluid and provide a fluid intake section for the pump.

There are two major types of gas separator designs - the static type and the rotary type. The static type reverses the fluid flow direction within the housing but the use is not as frequent now. At this point of low pressure there is gas separation. Any gas remaining in the fluid is separated by the pickup impeller which causes a vortex. The vortex allows the gas and fluid to separate. The separated gas is vented to the annulus and the higher density fluid flows into the first stage of the pump.

The rotary type design utilizes a rotary inducer/centrifuge to centrifugally separate the gas and produced liquids. The gas/fluid mixture initially enters the intake ports and moves into the inducer. This increases the pressure of the fluid and moves it through the transition section into the centrifuge. In the centrifuge the fluid is forced to the outside and gas rises through the centrifuge and flow divider into the crossover section. Here, the gas vented into the annulus and fluid is directed into the first pump stage. At present three (four in the near future) manufacturers are producing this type of separator. A "Vortex" separator may have a smaller paddle wheel at the bottom of a chamber where gas and fluids can swirl before exiting the separator.

Special stages are offered by some manufacturers when there is no path for separated gas. The special stages mix the gas and fluids and some are more proficient in producing head in the presence of high gas content.

Pressure Sensing Instrument:
The instrument has two major components - a surface readout unit and a downhole pressure and temperature sensing instrument. The downhole sensor is bolted to the base of the motor and sends a "ghost" signal to the surface unit through the motor windings and power cable as opposed to older designs requiring an extra "I" wire. One readout instrument alternates pressure and temperature readings on a 20-second interval. Other downhole instruments including intake and motor winding temperature. Other types of instrumentation are available.

There are many factors involved in operating ESP systems to lift a field. Below is an outline covering many of the aspects to be aware of when operating ESP's.

Outline of Factors for Good ESP Operations:

1) Well Data for Design and Operation:
i) Well tests
ii) IPR data
iii) Temperature and fluid properties
iv) Harsh conditions present?
(a) Sand
(b) Scale
(c) H2S, CO2
(d) Viscosity, emulsion
(e) High Temperature
(f) High gas production with the liquids
(g) Deviation
(h) Other?
v) Well Profile
vi) Tubulars
vii) WHP
viii) HZ of power supply available
ix) VSD part of installation?

2) Select Target Production:
i) AOF of well
ii) Bubble point
iii) Produce above or below bubble point
iv) Target production

3) Equipment Design:
i) Determine TDH
ii) Select type of pump and calculate number of stages
iii) Intake: Standard or gas separator
iv) Protector/Seal/Equalizer
(a) Bag/s
(b) Labyrinth sections (*)
(c) Tandem protectors?
v) Motor, type, HP
vi) Downhole instrumentation
vii) Cable: round / flat, size
Bands or cross coupling protectors
viii) Well head feed through type
ix) Control panel: Standard or VSD
x) See API RP 11S4 Recommended Practice for Sizing & Selection of ESP Installations

Example Simple Conceptual Design:

Consider the following data for design purposes. More detailed data would be required for actual application design:

IPR:
SIBHP: 2900 psi
Test Rate: 4000 bpd
Test Pressure on Perforations: 400 psi

Little gas
Perforations Depth: 6500 ft
Pump Depth 6000 ft
Casing: 5.5 inch
Tubing (to be determined but for 4000 bpd should be 3 ½, 4 or 4 ½ inch approximately)
WHP: 100 psi

Consider combination of water and oil such that the combined SpGr is 0.9. Approximate using volume of liquids do not change with down hole pressure and temperature. This is not true of course but approximately true if high water cut and little gas. This assumption allows a simple design example. For more and more gas and oil with water, this would be less and less true.

Power supply is 60 HZ. Use the above pump performance curve for this example.

Target rate: 4000 bpd

The pressure at the perforations is 400 psi. Consider the casing flow to the pump intake has little friction.

The pump intake pressure, PIP, is 400 psi – 500 ft ( .9*.433 psi/ft) = 205.15 psi.
For tubing flow to calculate the discharge pressure, consider tubing is selected such that friction pressure is 2-5% of the tubing pressure drop. This is typical for design of ESP. For this design use 3% for friction pressure drop.

Discharge pressure = WHP + .433(.9)(Depth)(1.+ % Friction) =
= 100 + .433(.9)(6000)(1. + .03) = 2508.3 psi

Then the TDH or total dynamic head is : TDH = (Pd – PIP)/( (.433)(.9))
= (2508.3-205.15) / ( (.433)(.9)) = 5901 ft

From the above performance curve read about 43.5 ft / stage.

Then the number of stages required is:
* Stages = TDH/ (head/stage) = 5901/43.5 = 136 stages

The HP required from the motor would be:

(* Stages) ( HP/Stage) (SpGr) = 136(1.95)(.9) = 238.7 HP
A larger somewhat de-rated motor would normally be selected for application



To complete the design, a cable would be selected (normally with no more that 30 V/1000 ft voltage drop), a switch board or VSD would be selected, and use of tubing for this design should be such that the pressure drop due to friction would be about 3% of the total tubing pressure drop. Other hardware would be ordered.

For heavy oil viscosity correction factors would come into play. For free gas at the pump intake, the gas would become part of the volume digested by the pump and the gas would also reduce the effective SpGr of the mixture. For more than 10-15% at the pump intake, we would become more concerned with the need for gas separation.

VFD or Variable Drives:
For critical installations, many times the data is such that the design may not fit the well conditions as the operator would prefer. Also changing well conditions may require changes in the ESP operation before the unit is pulled. If sufficient motor capacity is available, then a VSD can help achieve optimum operating conditions before the unit is pulled.


Variable frequency drive (VFD) controllers are solid state electronic power conversion devices. AC input power is first converted to DC intermediate power using a diode rectifier and/or thyristor (SCR) bridge. The DC intermediate power is then converted to quasi-sinusoidal AC power using an inverter switching circuit. [1] Figure 1 is a basic block diagram of a VFD connected to a motor.



For the electrical submersible pump (ESP) application there is a step up transformer and a length of cable between the output of the VFD and the motor.

VFD's for ESP oil well applications are divided into two major categories. They are either variable voltage inverters (VVI) or constant voltage inverters (CVI).

AC motor characteristics require the applied voltage to be proportionally adjusted whenever the frequency is changed in order to deliver the rated torque. For example, if a motor is designed to operate at 460 volts at 60 Hz, the applied voltage must be reduced to 230 volts when the frequency is reduced to 30 Hz. Thus the ratio of volts per hertz must be regulated to a constant value (460/60 = 7.67 V/Hz in this case). For optimum performance, some further voltage adjustment may be necessary, but nominally constant volts per hertz is the general rule. This ratio can be changed in order to change the torque delivered by the motor. The VVI VFD controls the output voltage by controlling the DC voltage level with SCRs. The output of this type of drive is a quasi-sinusoidal wave called a 6 step shown below in Figure 2.



The vertical distance from the top of the top step to the bottom of the bottom step equals the DC bus voltage. As the frequency increases the SCRs on the input will cause the bus voltage increase and conversely when the frequency decreases the SCRs will reduce the bus voltage.

VVI VFDs with 6 step outputs have been applied to ESP oil well applications for over 30 years. There is some additional motor heating associated with the use of 6 step because on the harmonic content of the quasi-sinusoidal wave shape. This additional heating as been compensated for by using motors that have be re-rated for the application of 6-step VFDs.

The CVI VFD controls the output voltage and frequency with a pulse width modulated (PWM) output shown in figure 3 below.



The peak between the top of the positive pulses and the bottom of the negative pulses always stays the same (or constant voltage). The width (or duty cycle) of each individual pulse increases with increasing frequency therefore increasing the average applied voltage. This voltage and frequency control is shown in Figure 4 below. The average voltage over the low frequency period will be lower than the average voltage over the higher frequency period.



When the CVI VFDs are applied to the ESP oil well application, the rapid switching of the PWM output causes reflections to occur over the long lengths of power cable. This can cause voltage spikes up twice the peak system voltage to appear at the output of the step up transformer and the ESP motor terminals. Figure 5 shows the ringing that occurs at the end of the voltage transitions during the PWM switching.



To reduce the risk of insulation failure and to reduce motor heating due to harmonics the manufactures of these drives have included low pass filters on the output of their CVI VFDs. This is filtered PWM (FPWM3) or variable sine wave generation PWM (VSG PWM4). A typical voltage output waveform of a filtered CVI VSD is shown in figure 6 below.



Variable frequency drives for ESP oil well applications range in size from 25 KVA to 2000 KVA at 480 volts to 2400/4160 volts. They can be designed for stand alone applications in the field in NEMA 3 or 4 enclosures or they can be in NEMA 1 enclosures for motor control room applications. When purchased from an ESP vendor they will come with the necessary controls for motor and VFD protection and control.

1. Campbell, Sylvester J. (1987). Solid-State AC Motor Controls. New York: Marcel Dekker, Inc. pp. 79
2. Bose, Bimal K. (1980). Adjustable Speed AC Drive Systems. New York: IEEE Press
3. Registered trademark of baker-Hughes Centrilift
4. Registered trademark of Wood Group - ESP, Inc.

4) Installation:
a) There are many factors to be considered to prepare for installation, install the cable and unit components and start up and monitor the unit. See API RP 11 S3, Recommended Practice for ESP Installations. See API RP11S5 Recommended Practice for Application of ESP Cable. See APIRP 11S6 Recommended Practice for Testing ESP Cable Systems.

5) Operation / Monitoring:
i) Monitor: Amps, surface voltage, downhole temperature and pressure starts/stops, power supply frequency

ii) Advanced
(a) Motor winding and well temperature
(b) Motor fluid dielectric strength
(c) Vibration
(d) Discharge pressure
(e) See API RP 11S Operation, Maintenance & Toubleshooting of ESP Installations

6) Removal from Well/ Inspection;
i) Remove with care
ii) Inspect as removed: Sample fluids , solids etc
iii) Collect fluid and solids samples
iv) Observe color indicating exposure to excessive heat
v) Note Vibration marks if any
vi) Any evidence of cable or pothead burns
vii) Mechanical damage if evident
viii) Package including pothead and instrumentation (without removal) to shop for teardown

7) Shop Teardown:
i) Have available historical run data and documentation
ii) Sample internal materials and fluids
iii) Search for primary cause of failure and other conditions:
(a) Wear
(b) Foreign materials
(c) Electrical transients or electrical burns
(d) Water in motor?
(e) Seal function or failure of:
1. Shaft seals
2. Bag preventer
3. Contamination of labyrinth sections
4. Wear or failure of thrust bearing
(f) Motor: Burned or contaminated
(g) See API RP 11S Recommended Practice for ESP Teardown Report
iv) Determine possible reuse of pump and motor if reconditioned and tested. See APIRP11S2 Recommended Practice for ESP Testing. See API R P11S8 Recommended Practice on ESP Vibrations. See API RP 11S7 RP on Application and Testing of ESP Seal Chamber Sections

8) Determination of failure:
i) Examine removal and teardown data and assess cause/s of failure

9) Continuous Improvement:
i) Indicate equipment that could extend run life such as sand resistant
(1) Stages/ impellers or high temperature trim or need for better checks at installation etc. Note that these recommendations my not be implemented on the new equipment going in but possibly on the following run/pull/installation.

10) Maintenance of Failure Data Base:
a) In order to show improvements with time in run life, it is necessary to have a good record of past failures and the cause of each. Only then can attention be focused on the most critical areas and only then can improvements in run life be achieved.



For additional information on a failure tracking project details see: Industry
Reliability and Failure Tracking Joint Industry Projects seek to increase ESP and PCP Run-Life By Jesus Chacin, Paul Skoczylas and Darren Worth, Rogtec, Issue 7.

Labels: deployment, electric submersible pumps, ESP, factors for successful operation, oil gas, production, Russia, Zeitecs

posted by The Rogtec Team @ 11:48  0 Comments

Ye. O. Cherkas (OJSC NK Rosneft-NTC, D. A. Antonenko and P. V. Stavinsky (OJSC NK Rosneft)

Introduction
Drilling of horizontal holes imposes special requirements on the reliability of prediction of reservoir structure and quality within a large radius from the borehole. However, the reservoir prediction tools currently available to geologists suffer, to some extent or another, from measurement errors, which inevitably leads to modeling uncertainty and increases risks associated with drilling of horizontal holes. In view of the high costs involved in horizontal drilling projects and uncertainties inherent in any model, it has become imperative to address this issue. Incorrect description of a reservoir may result in swelling of irrecoverable field development costs. In a typical geological model, four major sources of uncertainty may be identified: (1) data quality and interpretation; (2) structural and stratigraphic models; (3) geological-statistical model and its parameters; and (4) uncertainty related to equiprobable realizations. In an ideal case, uncertainty decreases as the field becomes more developed.
As regards the Vankor field, which is currently under development, the most challenging tasks from the uncertainty standpoint are as follows: (1) reducing risks associated with horizontal drilling; (2) putting together a program for detailed exploration; and (3) refining the drilling program.

This paper proposes a method for analyzing uncertainties inherent in geological models. Modeling based on this method will yield data (in the form of maps) representing the quantitative distribution of uncertainties in determining the presence of a reservoir and its properties, which must be used to evaluate potential drilling risks.

General Information about the Field
The Vankor gas and oil field is located in the Krasnoyarsk Krai. This paper deals with one of five productive reservoirs with about 390 million tonnes of original oil in place. The field was discovered in 1988 and is yet to be put into commercial production. As of this study, there were 27 wells already drilled into the reservoir of interest. The deposit is a layer-uplifted pool, and the reservoir is terrigenous.

The Vankor uplift is an isometric structure extending from the south northward. The predominant depositional environment was shallow-water (barrier-bar complex).

Method
The best criterion for assessing the overall ambiguity determining the accuracy of geological model parameters is the "validity of the oil-in-place estimate". This criterion is dependent upon the basic characteristics of the reservoir and, therefore, may serve as a measure of accuracy in constructing the model. To evaluate the validity of the reserve estimate, one must evaluate the calculation accuracy of every parameter in the calculation formula


where stands for "stock tank oil initially in place", GRV stands for "gross rock volume", N/G stands for "net-to-gross", is porosity, is oil saturation, is oil density, and is the oil shrinkage factor.

To this end, a general procedure was established for handling each parameter, namely:

1. estimating possible variations in the value of each input parameter;
2. defining the RMS deviation;
3. mapping mean values of the parameter, with fixed values assigned to individual wells and taking into account the RMS deviation in the crosshole space;
4. estimating parameter variance; and
5. mapping oil-in-place variance by multiplying out variance maps for all parameters, provided that they are independent (this condition has been introduced to simplify the estimation process).

Uncertainty Calculation Approach
The principle of accounting for uncertainties is as follows: At first, one should estimate the possible error of the measurements determining the RMS deviation. Then, this error is multiplied by a random surface whose spread of values follows a Gaussian curve with mathematical expectation equal to zero and a variance equal to unity. Finally, the result is added to the reference surface:



where is one of the surface realizations, is the reference surface, is a surface or a constant determining the RMS deviation error, and is a random surface of errors with + and - values around zero.

A characteristic feature of the error surface is the fact that errors at well points acquire zero value, to increase gradually as one moves away from the wells. Thus, the RMS deviation depends on data quality and distance to the well. This approach suffers from the drawback that the range of the error variogram is unknown. It cannot be taken as equal to the variogram ranges used in the modeling of a property of interest because of their heterogeneity. Besides, randomly modeled errors may acquire positive as well as negative values because possible scenarios lie on either side of the baseline interpretation. The variogram range is selected by the interpreter based on subjective estimates of the error variance length. If the range is excessive, the final uncertainty map is smoothed out with partial or complete loss of information. If the range is too small, one will end up with a heavily "noisy" picture.

Structural Uncertainty: Presence of Reservoir
One of the burning questions during early phases of field development is whether oil is present in field areas not covered by exploratory drilling. Analysis of uncertainties may give a feel about the degree of uncertainty in identifying the presence of oil. One of the criteria for such analysis is the position of the top of the OWC. Analysis should proceed along the following lines: (1) delineate a surface over the top of a reservoir (average value); (2) introduce an error into the average value; and (3) derive intersection contours for multiple realizations of the top of reservoir and OWC surfaces.



A set of 200 contours of the top of reservoir-OWC intersection contours has been obtained for the Vankor field. The extreme values are shown in Figure 1. It can be seen that uncertainty in the position of the OWC top, which is essentially the sum total of uncertainties in the positions of the top of reservoir and the OWC, may give rise to a serious error in oil-in-place estimates. In the Vankor field, no reservoir was present within the area marked by the solid black line in 23% of cases out of the set of multiple realizations. A well drilled into the questionable target after this work had been completed failed to reveal any presence of oil. Thus, the high likelihood of absence of oil, predicted by modeling, was corroborated by real evidence. In the course of this work, two other areas characterized by great uncertainty as regards presence of oil were identified (marked by broken lines).

Structural Uncertainty: Rock Volume
Uncertainty in the position of reservoir boundaries and contact determination contribute the error in the gross rock volume measurement. As regards the structural modeling error, its major source is the ambiguity of structural surfaces in the crosshole space. The error grows with distance from wells and is zero in their immediate vicinity.

The error in determining the position of reservoir boundaries was selected based on the quality of seismic data. For the Vankor field, it was assigned as +-15 m.

Estimation of the spread of OWC values was based on the results of well tests in target sands. The spread of values was defined as the difference between the highest and lowest OWC levels. In the case of the Vankor field, the spread of OWC values was 15 m.

In this case, selection of variogram ranges was based on seismic data pertaining to the reservoir and well spacing.

As a result, maps of potential errors in determination of the top and bottom of the reservoirs as well as OWC were produced. Within the boundaries of the field, the average spread of reservoir top and bottom positions is about 5 to 6 m. Uncertainty in OWC position approaches maximum toward the field boundary and between the two blocks of the Vankor field. The rock volume was calculated as the product of gross thickness within a cell times the cell area. Figure 2 is a map showing possible deviations of the gross rock volume from average values.


Proceeding from the results of analysis of structural uncertainties, one can draw conclusions as to the presence of oil in field areas yet to be covered by exploratory drilling. This information is useful in deciding whether additional exploration of the field is needed. Information about possible variations in reservoir boundaries and OWC levels in the presence of oil is instrumental in decision-making processes as part of the field development strategy, especially when it comes to drilling of horizontal holes.

Uncertainty in Reservoir Properties
Variances of reservoir properties are mapped as follows. The input data include zero-variance points or, in other words, correlation marks by wells. An algorithm using a continuous Gaussian distribution and predetermined variogram parameters provide the basis for constructing error surfaces for a property with a given deviation from the mean. Variogram parameters are assigned based on the depositional environment (barrier-bar features, pronounced lateral consistency of properties) and well spacing. All realizations of error surfaces for a given property are reduced to a single variance map of this property at the assigned level of deviation from the mean.

Net-to-gross Ratio
The primary sources of error in identification of pay zones in wells include the resolution of logs, accuracy of determination of reservoir quality by logging, and error in the use of critical values to identify a reservoir. In order to assess uncertainty in reservoir properties, one must first know the deviation from the mean. It is recommended to select the deviation of the net-to-gross ratio from the mean on a distribution bar chart of the model (tied to log data), because we are dealing essentially with assessment of the uncertainty inherent in the model’s volumetrics. As can be inferred from Figure 3(I) the maximum net-to-gross ratio distribution density in accordance with the model is close to the interval of 15% deviation from the mean. The deviation of the net-to-gross ratio from the mean in the crosshole space is close to 4-5%.

Porosity Ratio
The sources of porosity determination error include measurement techniques, instrument error, and subjective factors. The deviation was selected from porosity distribution based on log data in correlation with core data (Fig. 3(II). It can be seen from Figure 3(II) that the maximum density of porosity values coincides with the 0.18-0.22 interval. This spread of values corresponds to 10% deviation from mean porosity. In the crosshole space, the deviation of porosity values is 0.6%, increasing to 0.8% toward field boundaries. The map indicates areas requiring updated data.

Oil Saturation Factor
The error in determining the oil saturation factor stems from the quality of interpretation of log data, reservoir resistivity determination error, groundwater level, height above groundwater level, capillary curve, etc.

According to the model, the distribution of the oil saturation factor is at its maximum in the 0.4-0.7 interval, which corresponds to 25% deviation from the mean (Fig. 3(III)). In the crosshole space, the deviation of oil saturation from the mean is 4.5%.



Uncertainty in Oil Properties
The oil shrinkage factor and density at the surface were determined as the average of a number of analyzed samples. To take the determination error into account, distribution functions were created with due account for the results of analysis of all oil samples in surface and reservoir conditions. The distributions provided the basis for calculation of oil parameter variances.

Uncertainty in Oil-in-place Estimates
After mapping of variances of each parameter in the oil-in-place estimation formula, variances of oil-in-place estimates are mapped by multiplying out variance maps for all parameters, provided that they are independent.

A map of uncertainties inherent in the density of oil in place is shown in Figure 4. According to the map, the overall uncertainty in field reserves may amount to about 10% of original oil in place.



A set of structural maps and maps of reservoir parameters with whatever errors they contained was used to produce a set of Vankor field reserve density maps, and estimation was made of the probability density and cumulative frequency functions for oil-in-place reserves expressed in tonnes. Over a set of a hundred realizations, the spread of oil-in-place estimates is within +-10% of the mean. According to the diagram of sensitivity of oil reserves to the major estimation parameters, the most tangible impact on uncertainty in oil reserves within the bottom portions of the reservoir is produced by oil saturation, although in most cases it is the gross rock volume. This can be explained by the fact that most of uncertainty is associated with the edges of the field and the space between two of its blocks, where rocks exhibit poorer reservoir properties (see Fig. 3).

Conclusion
The proposed method for assessing the overall uncertainty inherent in oil-in-place estimates makes it possible to plan detailed exploration of the field and to refine the reservoir management plan in order to reduce the combined geological risks and, consequently, increase the profitability of the project.

Labels: drilling risk assessment, Exploration, horizontal well, Label, modeling, oil gas, reservoir, Rosneft, Russia, Vankor field

posted by The Rogtec Team @ 10:50  0 Comments

Dean Watson, Vice President of Schlumberger's Drilling and Measurements business in Russia.



Kieran Fitzpatrick, Operations Manager, Halliburton Sperry Drilling, Russia




Vitaly Chubrikov, Baker Hughes INTEQ, Business Development Manager, Russia



Brod Sutcliffe, Global Business Development Director for Weatherford Drilling Services

ROGTEC: What are the key advantages of ERD for the Russian market place?

Dean Watson: The key advantages for ERD in the Russian market place are the same as they are in other market places: a cost effective solution with proven ROI, an environmental solution or an accessibility solution. By a cost effective solution the meaning is rationalization of ROI for the infrastructure required to exploit the assets. If ERD proves to be the most cost effective solution taking into account other drivers such as environmental issues or accessibility then it makes sense for our clients to use this technology. In some cases ERD can be rationalized in Russia to address environmental concerns or in areas where there is limited infrastructure.

Kieran Fitzpatrick: Specific advantages of ERD are as follows:

1. Extend life of mature fields (producers/injectors).
2. Satellite field developments.
3. Eliminate drilling/production islands.
4. Access reserves in environmentally sensitive areas.
5. Traditional ERD, e.g. the world class wells in Sakhalin, where the use of a land rig and onshore production facilities to access offshore fields are much less expensive. They are able to operate all year (unlike offshore rigs in the frozen ocean), and more efficiently (but less expensive) environmental and safety compliance.
6. Multiple well ERD from Russian tundra locations (pads), resulting in less environmental & ecological disturbance, as well as the ability to drill under lakes & rivers e.g. under Samotlor Lake.

Benefits

1. Access reserves economically.
2. Fewer pipelines - reduction in costly subsea equipment.
3. Bring production forward.
4. Re-assess opportunities previously uneconomic.
5. Plan new bespoke ERD developments.

Vitaly Chubrikov: ERD technology has different potential and applications for both mature (brown) and new (green) fields; outlined below are the separate advantages:

Brown fields:

Capital costs reduction; most of production comes from W. Siberia where pad drilling is standard, due to the swampy landscape and limited existing infrastructure. ERD will allow the drilling of wells with longer range from existing pads to reach field areas which would normally require building new pads

Better production and longer wells life cycle. ERD employs Rotary Steerable Systems and Logging While Drilling technologies; the combination of these provides accurate wellbore placement in better quality reservoir zones that ensures better production and longer life cycles with ERD wells

Better production from complex water flooded fields; ERD will allow the setting of multiple geological targets to produce from several relatively good zones within water flooded zones Green Fields:Less capital intensive field development projects. Pad and infrastructure construction on land (access roads, pipe lines, energy lines etc) are a significant part of capital investments to develop Green Fields, in some cases more than half of the entire field development costs. Introduction of ERD wells will allow the development of green fields from fewer pads, which will significantly reduce development costs.

Development of offshore green fields are even more capital intensive, and so the potential of capital cost reduction through the application of ERD technology is even better.

As already mentioned above, the advantages of RSS and LWD technologies are also fully applicable to green fields.

Brod Sutcliffe: Weatherford offers a full range of drilling services for ERD wells. Our Revolution Rotary Steerable and Weatherfod LWD systems can be combined to provide an excellent Extended Reach Drilling System. We offer the Revolution System in all hole sizes and we now offer both wired and wireless motorized RSS options for increased bit speed and ROP. Our LWD systems holds world records for Pressure, Temperature, Dog Leg and for pulse detection in extreme drilling environments - a key attribute for ERD drilling. Our LWD systems offer a full complement of azimuthal measurements for GR, Spectral Gamma Ray, multi-frequency resistivity, azimuthal density and thermal neutron porosity.

All azimuthal measurements deliver both realtime and recorded data imaging and this data can easily be transported to any location with our Realtime Operations Service.

ROGTEC: Outside of the current economic situation what is the market and potential for ERD in Russia?

Dean Watson: Although ERD is currently relatively small in Russia, this technology will continue to grow as offshore assets and eastern Siberia are developed.

Kieran Fitzpatrick: Sakhalin is the biggest market in Russia remaining at 1 P3 rigs. ERD wells can bring additional reserves on line which may not be otherwise accessible with conventional well designs. As new reserves are identified in more isolated and remote locations, ERD well designs will have increased applications.
Please also refer to the below reference on potential fields

Vitaly Chubrikov: Declining production in brown fields will make operators look for technologies to maintain or improve production, at increasing costs; eventually ERD would become economical for operators.

Green field development will definitely employ ERD technology for discovered fields in the Barents Sea, Caspian, Sakhalin and Eastern Siberia.

However at the moment ERD application is also limited by existing rigs fleet technical capabilities Р in reality there are just a few rigs available across Russia technically capable to drill wells over 6,000m MD.

Brod Sutcliffe: ERD drilling can dramatically reduce the environmental wellsite footprint of an operation as well as significantly reduce capital cost. Any market where these issues are concerns will benefit from ERD drilling.

ROGTEC: What are the key fields and regions for this technology?

Dean Watson: Geographically potential markets exist where there are offshore assets as well as accessibility issues potentially caused by a lack of infrastructure. The following come to mind: Sakhalin, the Caspian, the far north and eastern Siberia.

Kieran Fitzpatrick: On Sakhalin, Odoptu and possibly others; remote tundra fields in NW Siberia and fields where the cost of a platform is prohibitive, e.g. Shtokman. Also, Near-shore fields in the Barents Sea and Ob River delta (areas frozen in winter so not suitable for platforms) by ERD. Inland ERD wells are likely to get longer from larger tundra pads to reduce environmental footprint.

Vitaly Chubrikov: Barents Sea, Caspian, Sakhalin, Eastern Siberia, some recently discovered fields in W. Siberia and Komi in remote areas.

ROGTEC: What are the key factors for success in planning and delivering ERD wells?

Dean Watson: Key factors for the success in ERD are: innovative technology, people expertise, process organization and communication. Appreciation to the cost involved and the potential downside if there is a major or catastrophic event should be fully understood. Success is in the planning and detail and Schlumberger has a proven track record to successfully delivery ERD wells.

People and the competency of people at the wellsite are important elements to the delivery of ER wells and so developing knowledge and expertise, through training should be put in place well in advance. Promoting communication between all members of the project will provide another success factor.

Time for the planning cycle is essential. Drilling an ER well is not just an extension of a typical directional well. Depending on the scale of the project or well, the required or suggested planning and lead time could be between 2 to 4 years lead time, from the conceptual phase through to spud.

There are numerous design criteria that have to be considered in detail for ERD. The final geometric profile and planned well trajectory is key, especially the build up section. This section must be planned to accommodate minimal tortuosity and a "smooth" well bore, a factor that plays an important deliverable in the final execution of the well and the ability to run tubulars throughout the well.

Other factors that have to be managed are wellbore stability, ECD management, wellbore positioning and real-time monitoring. The later point illustrates the requirement to plan for the ability to maintain good data telemetry and data management throughout the well execution.
ECD management and planning is vital during the modeling phase as this alone could be a limiting factor for the well delivery and operations. Planning for realtime monitoring is essential so as the drilling progresses the performance versus the model can be tracked and updated as necessary.

Operational challenges have to be evaluated and contingency planning put in place. Torque and drag, hole cleaning, barite sag, well control, these are all additional factors that have to be considered at the design phase. This is where the selection of the correct downhole drilling technology is critical. Rotary steerable systems are now the drilling technology of choice for ERD, as they provide the opportunity to deliver continual rotation, promote good hole cleaning and hence avoid the opportunity for stuck pipe or inducing pack-offs or poor well bore stability.

The completion type and any future well intervention must be considered as one of the primary design criteria.

In line with all the design factors, obviously then the rig must be sized to accommodate all the operations from drilling, tripping, completion running and workover capability, all of which may require upgrades to the equipment or sourcing of an ERD capable, specific rig.

Kieran Fitzpatrick: An ERD well is a very sensitive system so it is essential that with so many variables that can affect the eventual success of an ERD project that all aspects of the wells are very carefully planned. There must be a total team effort during the planning and execution of the well. Drilling Environment, Well Engineering and well designs, and drilling parameters play a very important role in ERD Well Design:

Drilling Environment:
Onshore / Offshore
Lithology
Shallow Gas
Pore Pressure
Fracture Gradient
Depleted Zones
Faults
Seismic Data

Well Design:
Profile Design
Hole Size
Casing Designs
Torque and Drag
Hydraulics
Hole Cleaning
Borehole Stability
Risk Mitigation
Lessons Learnt

Drilling Parameters:
Drill String Design
Rig Limits
Mud Design
Operating Procedures
ECD Management
Directional Control
New Technology
Casing Running
Completions

During the planning phase, great care must be taken to get the best possible rock strength analysis done. The second critical part of the planning phase is the best possible torque & drag modeling. This should include drilling fluid lubricity testing. Accurate Equivalent Circulating Density (ECD) & hole cleaning modeling are also required.

It is also essential to determine/model whether casing will run in the hole conventionally. Premium casing threads are needed, as the casing may have to be pushed. It may be necessary to float casing into at least one hole section, as well as running roller centralizers.
In the operating phase, torque & drag monitoring is the most important parameter to monitor the build up of cuttings' beds in the low side of the hole. Consistent procedures to measure pick-up/slack-off weight & torque on connections are essential. Premium drilling fluid lubricants, e.g. TORQ-TRIMЁ 22 lubricant will be needed as well as mechanical torque reduction equipment, e.g. drill string torque reduction (DSTR) subs. Both factors (torque & drag and fluid lubricants) are essential during well completion as well as drilling phase.

Another key item is the final completion string. Well screens with a Swellpacker isolation system are a proven option to cementing which is very difficult in long horizontal sections.

Finally, the rig must have the capability. The drill string will see big loads, so premium connections are required. Big pipe (5-7/8" or 6-5/8") is recommended for more pulling power, more torque, less buckling & better hole cleaning. The pumps must be big & the standpipe pressure rating adequate (5000 psi recommended). The top drive must be able to rotate at least at 120 rpm with high torque loads. A Pressure-while-drilling (PWD) tool is needed to monitor ECD.

Every tool, joint of pipe, sub, etc. should be benchmark tested, labeled & hours tracked in a register to minimise the risk of failure. Non-spec tubulars & tools should be removed from the rig.

The shakers must have the ability to handle high flow rates with high cuttings' loads through fine mesh screens. The concentration of ultra-fine solids builds rapidly due to "mortar & pestle" grinding by the drill pipe against the low side of the hole, so extra centrifuges & high dilution rates are needed.

The key is careful planning. You need enough time & resources to do this thoroughly.

Vitaly Chubrikov: Good geological field knowledge; custom-planned wells; involvement of the Operator, Rig Contactor and Service Companies engineering, geological and operational experts in all well planning and execution and a lessons-learned cycle to improve efficiency and performance on each following well.

Brod Sutcliffe: ERD drilling is in most cases an offshore operations. There is limited activity onshore to the high cost. However difficult terrain, environmental site issues and near shore locations to offshore reservoirs can bring an opportunity to onshore ERD. Any fields agreeable to the business drivers such as limited surface access or superior economic choice would be open to an ERD application.

ROGTEC: What are the key benefits of your specific ERD solution?

Dean Watson: Obvious benefits of our specific ERD solution would be to deliver the well with good performance, with in the project time line and cost effectively. Good planning and lead time would ensure that the correct and appropriate technology, services and rig selection or upgrades could be planned and delivered. Ultimately resulting in a final proposed well design to reduce risk and maximize success. This is based on Schlumberger's leading position in the ERD market and a proven track record with both appropriate technology and the people (their knowledge and expertise) to make this happen.

Kieran Fitzpatrick: Halliburton's Sperry Drilling and Drill Bits and Services provide a matched drilling system that minimizes the amount of ‘spiraling' in the wellbore. Our ‘point-the-bit' Geo-Pilot rotary steerable system matched with a long-gauge Geo-Pilot bit deliver a smooth, non-tortuous wellbore. When spiraling in the well occurs over the many thousands of meters it can result in numerous problems such as excessive torque and drag and poor hole cleaning. Elimination of this spiraling increases the chance of being able to drill the section successfully and minimizes problems when running casing or completions. In addition, Sperry Drilling has a comprehensive range of logging-while-drilling (LWD) sensors which can provide solutions for formation evaluation, geosteering and wellbore stability without having to use wireline logging techniques which can be expensive, difficult and risky in an ERD well. Using Max3Di drilling optimization software, directional drilling efficiency and reliability can be increased by immediately detecting out-of-bound conditions. Drilling costs can be reduced and the decision-making process can be expedited by providing key data to personnel both at the rigsite and in Real Time Centers, where drilling performance can be modeled before going downhole to choose optimum parameters and avoid surprises. Post-well analysis with instant replay allows us to identify problems and work on solutions for future wells.

For Sperry Drilling the key advantages are as follows:

1. Experience in drilling extended reach wells in different counties around the world.
2. Well Engineering Design and planning, specific engineering group.
3. Real Time CentersStrataSteer 3D geosteering service.
4. BHA analysis with MaxBHA software.
5. Well optimization of drilling parameters. Max3Di drilling optimization software. Quicker drilling times and reduced formation exposure time.
6. GeoTap formation pressure tester and pressure-while-drilling LWD tools aid with the calculation of correct formation pore pressures and ECD circulating pressures to help maintain the optimum mud systems and hole cleaning. This enables ERD wells to be drilled with real-time data transmission.

Mud systems, Baroid:

1. Experience (Baroid have engineered 25 of the 30 longest reach wells in the world).
2. Suitable fluids, engineered for stability, lubricity & minimum ECD.
3. DFG software for best-in-class hydraulics & ECD prediction.
4. Premium lubricants for drilling & completion fluids.
5. Wellbore stability software & wellbore strengthening technologies & products (WellSET Lost Circulation Treatment).
6. Optimized theology under downhole conditions for maximum hole cleaning.

Vitaly Chubrikov: Large local and international ERD experience; complete portfolio of technical expertise, superb equipment and state-of-art software.

Brod Sutcliffe: For Weatherford Drilling Services our products are: Rotary Steerable Technology, Full LWD capability, Azimuthal measurements with realtime imaging for accurate geosteering, Realtime Operations and Drilling Optimization (Vibration, PWD, BHA design).

ROGTEC: What are the most common problems which occur in the Russian market with ERD?

Dean Watson: The challenges in the Russian market are the same as they are in other ERD markets.

Kieran Fitzpatrick: The main problems are a lack of understanding of the benefits of ERD, a lack of planning and expertise and lastly a lack of drilling rigs capable for ERD.

Vitaly Chubrikov: The cost of ERD still does not allow economical application for brown fields. Also lack of technically capable drilling rigs.

ROGTEC: How can well bore instability be minimized pre and during drilling ops?

Dean Watson: Well bore instability can be minimized by review and root cause analysis of offset well data as part of the planning phase. This may entail full geomechanics studies to evaluate the zones of potential challenges, the stress direction, formation and compressive strength and breakout characteristics.

Working with the drilling team in the development of good drilling practices and training during the pre planning phase helps identify and promote awareness of key issues amongst the whole team. This allows for the experts to communicate the mitigating measure to be deployed and the urgently of quick identification and communication during the execution phase.

Once in the drilling phase then adherence to the set and agreed drilling and operation practices should be followed and monitored in realtime. Monitoring and comprehension of the events and risks throughout the hole section and early identification of hole changes is essential.
Mud chemistry and theology are key aspects that also require good design to address the wellbore stability but must also deliver the necessary characteristics as a drilling fluid to aid the complete process.

Kieran Fitzpatrick: A thorough well-bore stability evaluation needs to be carried out encompassing regional tectonics, structural analysis and experience from wells that have been drilled in the same area. By carefully planning the well direction and profile, well bore instability issues should be minimized. While drilling, hole conditions should be carefully monitored for signs of borehole deterioration. In addition, LWD sensors can provide early warning signs of borehole instability and provide valuable information on stress directions.

In summary:
Accurate rock strength measurement & geomechanical analysis.
Proven drilling fluid technology.
While drilling, adequate mud weight, based on rock strength analysis.
Good hole cleaning modeling & practices.
Well thought-out circulation & tripping practices.
Understand the effect of high ECD's on borehole stability & induced lost circulation, especially in ERD wells at shallow true vertical depth (TVD).

Vitaly Chubrikov: The question requires the writing of an additional article! It is a very complex problem which does have technical solutions, individual to each field. Usually solutions are around drilling fluids properties, drilling parameters and practices.

Brod Sutcliffe: Pre-well planning can assist in optimizing the well profile, the mud program and the BHA design. Then, while drilling, we monitor in realtime, ECD, cuttings removal, Stick-Slip, three-axis vibration, temperature, bore/annular pressure etc. to reduce wellbore instability.

ROGTEC: What are some of the key indicators of problems during drilling an ERD well?

Dean Watson: Indicators normally manifest themselves very quickly and unfortunately on ER wells they can have catastrophic effects on the well or project. The key is obviously in the avoidance of such problems and as stressed above this is why the planning stage is so critical as well as the level of expertise of the people involved. Schlumberger has a good track record in helping our clients to minimize such problems.

Ensure that all critical parameters have been modeled in advanced and actual data is available to evaluate trends. Calibration of wellsite data is essential for the maximum value to be extracted from the realtime data versus the models (which have been validated against offset information). Clear divergence from the established pre-drilling models which are being updated in realtime for all phases of the operation (drilling, tripping, and casing running), for example torque and drag, ECD, vibration, stick slip and other drilling dynamics. Continuous review of formation and associate uncertainties are also key indication of variations to the plan which may require immediate evaluation and changes to the predicted models.

Kieran Fitzpatrick: When an ERD well is planned, a comprehensive "road-map" of expected measured parameters should be produced from modeling expected scenarios. Any deviation from what has been expected is an indication that there may be problems. Typically, the well will be monitored from a Real Time Centre (RTC) which may be located at a remote location some distance from the actual well location. The RTC may, for example, be located at the operator's main office where teams of experts can monitor the well's progress while also monitoring wells at other locations. This allows for the maximum use of what are becoming increasingly scarce, experienced personnel.

Inadequate hole cleaning in large diameter, high-angle hole sections.
Deviation of actual torque & drag away from modeled trends.
PWD data indicating excessive annulus cuttings' loads.

Vitaly Chubrikov: Again, it is a difficult question and depends on the problems observed. Not to be specific, these could be excessive torque & drag, pressure increase, decrease or fluctuations, fluids losses or gains, cuttings volume etc.

Brod Sutcliffe: The critical issues for ERD would be ECD management, hole cleaning and hydraulics, drillstring mechanics (Torque and Drug), wellbore stability, drilling fluid, casing issues, drilling operations issues, pro-active geosteering and navigation. ERD wells can be technically challenging to plan and implement. What advise would you offer an operator considering and ERD solution?

Dean Watson: Invest in the upfront planning cycle. Getting it right first time requires good and extensive planning. Good planning will allow the operator to avoid an incident that may lead to a disastrous scenario. This potentially disastrous scenario is the major cost element that will affect the ERD project budget.

People are a key asset. Developing expertise and competency is essential and additional formal ERD training should be considered.

Know what works. Know what the limits are and find effective solutions. Develop a learning curve on the ERD campaign. Do not start with the most difficult well first. Capture as much information and lessons learned as possible to update and validate the models for the project or field. Data is essential. Success is in the detail.Bring together the operational teams during the preparatory phase to gain specific ERD training and to also highlight the key challenges that are expected during the execution. This also provides the opportunity for new ideas or challenges to be presented prior to spud!

Peer reviews are key to helping to identify whether the process has been followed and whether there are any potential show stoppers or barriers that have been missed in the planning phase.
Ensure that the well objectives have clarity and are understood by all. Selection of the appropriate technologies is essential and inline not only with the objectives but also to provide the necessary data to execute the well whilst minimizing the risks.

For today's ERD execution the benefits of realtime monitoring and support from the organization in town is now seen as a major way forward. The opportunity to engage not only the wellsite experts but those who have ownership of the well design programs in town can only add benefit and reduce the operational risk. Communication is key.

Kieran Fitzpatrick: Plan every aspect of the well, have a plan for every eventuality and learn from the experience of others who have drilled similar types of wells.

Consult with contractors and specialists that have extensive experience in this area. Careful planning is also required as per previous comments.Upgrading the rig and contractor equipment to meet the required objectives, for example hookload, torque, flow rate standpipe pressue etc is also essential.Using premium equipment such as top drives, downhole equipment, tubulars and connections and fluids also.

Technology used to push ERD limits:

Rotary Steerable Systems (RSS).
Casing / liner drilling systems.
Casing / liner flotation methods.
Pressure While Drilling (PWD).
Torque and Drag management.
Learning / knowledge transfer.

Vitaly Chubrikov: Economics: ERD costs vs. production over well life.

Good understanding of expectations and goals to select appropriate available technologies.

Solid understanding of the field geology and associated challenges.

Brod Sutcliffe: Good pre-well planning, alignment of operational objectives, good communication with all operational groups (Drilling, Geology, Completions, Reservoir, Petrophysics) and the selection of fit-for-purpose technology for job execution.

Dean Watson, Vice President of Schlumberger's Drilling and Measurements business in Russia Dean Watson is currently the Vice President of Schlumberger's Drilling and Measurements business in Russia. A 16 year veteran of the oilfield, he has held several Operational and Headquarters positions.

He graduated with a Mechanical Engineering degree from the UK and immediately put his education to use as a design engineer in one of Schlumberger's Technology Center. After several years in various positions he was then transferred to headquarters to lead a road map for new technology in Drilling Tools. A few years later he was then able to see first had the results of this work when he assumed a role as Operations Manager for China, Japan and Korea. Before assuming the VP position in Russia he was the world wide Operations Support Manager for Drilling and Measurements at Headquarters.

Kieran Fitzpatrick, Operations Manager, Halliburton Sperry Drilling, Russia Kieran has been based in Moscow for 2.5 years and in Russia for 5 years. He started in the North Sea in 1985, and has been with Halliburton since 1988, primarily working in the Middle East (Dubai / Abu Dhabi / Oman / Qatar / Pakistan / Bahrain / Egypt / Yemen / Saudi Arabia). Kieran was educated at the Belfast Municipal Institute and The Queen's University of Belfast.

Vitaly Chubrikov, Baker Hughes INTEQ, Business Development Manager, RussiaVitaly Chubrikov graduated from Gubkinsky Oil & Gas University in Moscow in 1995 and joined Baker Hughes soon after, as a field engineer. Over the years he has held various field and office positions in both domestic and international assignments.

Brod Sutcliffe, Global Business Development Director Weatherford Drilling ServicesBrod Sutcliffe has worked in the oil & gas drilling industry for 29 years since graduating in Geology from Leeds University, UK. After spending several years in the field as a wellsite geologist, LWD engineer and directional driller, Brod has held a number of operational and business development management positions.

Labels: Baker Hughes, ERD, Extended Reach Drilling, Halliburton, oil gas, Russia, Schlumberger, Weatherford

posted by The Rogtec Team @ 09:35  4 Comments