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

Mark Rowley,
Partner, Baker Botts (UK) LLP

PART 2

In the first part of this Article "Turkmen Gas - Export Strategy and Trans-Caspian Opportunities", Turkmenistan's gas export strategy was considered with particular emphasis on the historical context, and the country's relationship with Russia.

In Part Two of this Article, we assess the current state of the Turkmen - Russian relationship, and consider the possibility of Turkmenistan committing to a Trans-Caspian export link and supplying gas to Europe via the Nabucco pipeline, or other competing projects.

New President, New Focus
In consequence of its over dependence on the Russian export route for its gas, from the time of its independence Turkmenistan has experienced a steady decline in gas output and exports. A new gas deal in 2003 agreed with Uzbekistan and Russia aimed to increase Turkmen gas exports over a 25 year period, but further consolidated the country's dependence on Russian export routes, giving Gazprom an effective monopoly over future Turkmen gas exports. By 2005 the commercial terms on which Turkmenistan has been able to trade its gas directly had changed, so that all of the gas exported by Turkmenistan via Russia is purchased by Gazprom at the border.

2006 may prove to have been the watershed in the evolution of Turkmenistan's gas exports. In that year, Turkmenistan demanded a price hike for its gas sales to Russia, from $65 to $100 per 1,000 cubic metres (at a time when Gazprom was selling Turkmen gas to Europe at around $260 per 1,000 cubic metres). 2006 also saw the death of President Niyazov (Turkmenbashi) and the election of President Berdymukhamedov, who commenced an incremental and more open assessment of the opportunities for diversification of hydrocarbon exports. In hindsight, 2006 may have been the time when the EU and the US should have seriously renewed their efforts with respect to the Trans-Caspian export route for Turkmen gas.

Since 2006 Turkmenistan has established some clear internal oil and gas industry development priorities, including new onshore and offshore E&P projects; the accelerated development of the Turkmen sector of the Caspian; and the development of additional refining capacity and a serious petrochemicals sector.

Notwithstanding the gradual refocusing of its attention towards alternative export options, Turkmenistan has maintained a strong relationship with Russia, and has continued to develop long-term gas supply contracts, entering into two significant agreements in July 2008. The first agreement established twenty-year gas pricing principles, pegging the price paid by Russia for Turkmen gas to the average wholesale European and Ukrainian prices received by Russia, resulting in a rise from around $150 per 1,000 cubic metres in 2008, to approximately $225 per 1,000 cubic metres for 2009. The second agreement secured for Turkmenistan Russia's financial and technical assistance for the development of transportation infrastructure and gas field development in Turkmenistan.


The new pricing principles agreed with Russia have been seen as a strategic decision by Russia to pay effectively market (premium) rates for Turkmen gas, in order to tie-up Turkmen gas production in direct competition with alternative "non-Russian" gas export projects, such as Nabucco. Similarly, around this time, Russia offered to purchase Azerbaijani export gas at "European market prices".

Recent Diplomatic Events
The explosion on the Central Asia Centre Pipeline (CACP) (Dauletebad - Darylik section) near the Turkmen-Uzbek border in April 2009, which halted 95% of gas exports from Turkmenistan to Russia, triggered a rapid deterioration in relations between the two countries. Turkmenistan was quick to blame Russia for causing the explosion due to Gazprom's offtake behaviour, whilst Russia asserted that poor pipeline maintenance in Turkmenistan may have been the cause. This incident follows an escalation of rhetoric, at a time when Russia has experienced falling European gas demand. With the pipeline now repaired, gas flows have still to be substantially resumed, a situation arguably to Gazprom's advantage, but which has resulted in a loss of revenue to Turkmenistan estimated to be up to $1 billion per month. With the crash in gas demand from Gazprom's customers, Russia has sought to re-engage with Turkmenistan regarding the terms on which Turkmenistan sells its gas, requesting a reduction in either the fixed volumes or the price of the gas under the Russian export contracts. Negotiations are ongoing.

Arguably this incident has given Turkmenistan a pretext to move closer to a Trans-Caspian Pipeline option, which scenario is broadly consistent with President Berdymukhamedov's recent pronouncements (and those of the Turkmen Government generally), tacitly criticising Russia and calling for an energy market protected from political risks. The President's address at the April 2009 international conference on energy supply stability in Ashgabat, attended by US, EU and Russian delegations, emphasised the need for energy diversification and partnership, the inclusion of new countries into the geography of export routes, and the creation of a new system of ties with Europe.

Earlier in April 2009, President Medvedev of Russia had also proposed a new deal with Europe, for a new "Energy Charter", to replace the Energy Charter Treaty, signed but never ratified by Russia, and long dismissed by it as biased in favour of European consumers. In similar terms to the position being taken by Turkmenistan, President Medvedev set out Russia's proposals for a system fairly balanced among producers, transit countries and consumers.

So the dividing lines over the future shape of the export markets of the Caspian and Central Asian states are beginning to be drawn, which are themselves closely linked to the fortunes of projects such as South Stream and Nabucco and their search for gas supplies. The signature by Turkmenistan in April 2009 of a memorandum of understanding with the German company RWE AG, itself a Nabucco shareholder, granting RWE AG access to Caspian Block 23, typifies the turn in focus of Turkmenistan to consider, if not yet to embrace, the Trans-Caspian/European export option.

Trans-Caspian and Nabucco Pipelines - Problems with the Europeans?
When, in 2007, Turkmenistan, Russia and Kazakhstan agreed terms for the Prikaspiiski Caspian Gas Pipeline (a Russian gas export route through which Kazakhstan and Turkmenistan had suggested that at some future point they might seek to export up to 30 billion cubic metres (bcm) per annum), President Berdymukhamedov did not exclude a Trans-Caspian gas pipeline to join with the South Caucasus Pipeline (SCP) in Azerbaijan, although he indicated that of the then available options to Turkmenistan it was the least favoured export option behind those to Iran, China and Pakistan/India. His position perhaps reflected the failure of the EU Members to speak in a co-ordinated and committed manner regarding southern corridor gas export options to Europe, including the SCP from Azerbaijan to Turkey, the Turkey-Greece-Italy Interconnector, Nabucco from Turkey to Austria via Romania, Bulgaria and Hungary, and the rival Russian-sponsored South Stream project.

Nabucco's viability as a project depends on securing first and second-phase gas, and to date it has made no concrete progress signing-up reliable supplies. The constituent shareholding countries of Nabucco have been unable to speak with one voice on their preferred supply strategy, and accordingly have not generated significant sustained EU and US support in progressing supply commitments. Russia has successfully exploited European concerns, and promoted its rival Nord Stream and South Stream projects, and sought to tie-up potential Nabucco gas supplies for itself, through approaches by Gazprom to Azerbaijan and Turkmenistan to secure gas exports at prices more closely linked to the European market.

Although Shah Deniz Phase 2 gas has been touted as a potential Nabucco first phase supply, as yet, the Nabucco project has no commitment from Azerbaijan, Turkmenistan, Kazakhstan, Turkey or Iran to supply gas. The recent agreement of Azerbaijan to supply 0.5 billion cubic metres of gas to Russia from 2010 (with the Russian desire to significantly increase these volumes and to potentially include Shah Deniz Phase 2 gas) is indicative of the gas supply challenges which continue to face the Nabucco project. Although, in some circles Azerbaijan's move is seen as a bargaining chip in order to achieve a better gas sales/transit deal with Turkey and the other Nabucco shareholders.

European and US companies (and governments) have expressed frustration with Turkmenistan over a perceived lack of commitment from the country to the Nabucco project, but there may now be indications that this position is changing. Any supply of gas to Nabucco from Turkmenistan would necessitate a Trans-Caspian link to Azerbaijan (or Russia), and this has always been the principal stumbling block to Turkmenistan's export aspirations. There are however signs that the EU and Nabucco are finally grasping this nettle, and in November 2008 the EU's Second Strategic Energy Review announced the creation of the Caspian Development Corporation which would focus on the development of Turkmen gas export options for delivery to Europe via the southern corridor. In December 2008 the Austrian company OMV and RWE AG established the Caspian Energy Company to assess options for the building of a Trans-Caspian pipeline, and to look for partners for a project which would build and operate such a pipeline. There are also encouraging signs that the differences between Azerbaijan and Turkmenistan on their Caspian Sea boundaries (including their disputed hydrocarbon fields) may soon be resolved, although as yet there appears to be no resolution with Iran.

Perhaps these are encouraging signs, and answer some of the Azerbaijani and Turkmen criticisms of Nabucco, that it has failed to establish a clear project timetable and that project financing is unresolved. The interests of Turkmenistan and the European market may truly be beginning to converge, and, notwithstanding the eventual fate of Nabucco, a Trans-Caspian pipeline may be a logical outcome, and the first building block, of such convergence. Whatever decision is made by Turkmenistan regarding a Trans-Caspian gas export route, such decision will be heavily influenced by the positions taken by Russia and Azerbaijan with regard to their own gas export requirements. These three countries, and to a lesser extent Kazakhstan, will be the principal determinants of the eventual shape of the Trans-Caspian hydrocarbon export market, and its associated infrastructure.

Is There Enough Gas?
In conclusion, there has long been a concern that Turkmenistan may have insufficient gas to meet its commitments and aspirations, and the aspirations of its potential customers in Europe, China, Russia and Iran. These were largely unanswered questions in the self-audited world of Turkmenistan prior to 2008, where a lack of transparent reserves data had hindered Turkmenistan's growth as a major gas exporter. Matters are now changing with a recent Gaffney Cline and Associates audit of the South Yolotan Osman Field in South East Turkmenistan indicating potential gas reserves for the field within the range of 4 to 14 trillion cubic metres, which would make the field the fourth or fifth largest in the world (Gaffney Cline and Associates also indicating potential for overall Turkmen gas reserves to be in the region of 28 trillion cubic metres). These potentially significant reserves should enable Turkmenistan to deal more assertively with its existing customers, and to legitimately establish its credentials as a major exporter to both the European and East Asian markets, export routes permitting.

Labels: baker botts, turkmen gas

posted by The Rogtec Team @ 10:55  0 Comments

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


Kieran Fitzpatrick: Operations Manager, Halliburton Sperry Drilling, Russia


David J. Brunnert: Vice President: Intervention Services, Weatherford International Ltd.

With the age of peak oil perpetually drawing nearer, around 40% of the world's oil today is produced from brownfields. Currently and in the future there is a need to understand how to develope these fields in order to sustain production. Brownfields by their very nature will become the largest available hydrocarbon deposits in the world. Extending field life and recovery will become the primary focus of many operators. Brownfield development encompasses many different technologies, from reservoir engineering and monitoring to fracturing and stimulation, remediation, intelligent well systems and flow monitoring. This discussion is exclusively looking at the drilling systems aspect to increasing field potential.

How are operators in Russia currently employing drilling technologies to improve their brownfield performance?

Vitaly Chubrikov: The need for drilling efficiency, along with geological uncertainties, are becoming focus areas for operators that drive their well construction strategies in Brownfields. Many drilling contractors are adding new mobile rigs to their fleets and implementing operational process improvements to reduce NPT. The rig contractors are also upgrading existing fleets with equipment such as pumps, solids control and top drives that enhance the value added by technology based on the requirements of operators. The contractors are working with oil companies and service companies to apply drilling technologies such as engineered programs with PDC bits, non-damaging drilling fluids, pre-countered mud motors, Rotary Steerable Systems, LWD tools with real-time reservoir data and geo-steering techniques. Rotary Steerable systems and near bit geologic and reservoir data help operators to optimize well placement to recover by-passed reserves in Brownfields.

Kieran Fitzpatrick: Operators in Russia are using a variety of drilling technologies to extend the life of old fields that were initially developed during Soviet times. These include:

• Building larger pads with additional longer reach wells to reduce cost per well for the pad, roads, service infrastructure and production facilities
• Drilling new infill wells beneath old fields to access deeper targets identified by modern seismic techniques or exploratory drilling, or in fields that were previously deemed uneconomic to develop
• Use extended reach drilling to develop previously inaccessible reserves, e.g. extensions of fields offshore or under lakes and rivers
• Sidetrack depleted or abandoned wells to reach rim or attic oil, as well as previously untapped fault blocks or traps
• Use under balanced or managed pressure drilling to minimize reservoir damage and remove the additional costs of large frac jobs
• Use coiled tubing drilling or radial drilling (lateral jet drilling) techniques to reduce rig mobilization and drilling costs for slim hole sidetracks
• Use steam assisted gravity drainage (SAGD) wells in shallow, heavy oil reservoirs
• Drill multilateral wells in order to minimize surface footprint, as well as reduce construction and production facility costs
• Geosteer within thin oil bands in order to increase hydrocarbon section length
• Reduce drilling days by optimized use of modern drilling equipment, fluids and hydraulics to drive down development drilling costs

David Brunnert: Advances and cost reductions in drilling technology are dramatically changing the situation. Reserves that used to be uneconomical to produce are now being considered. The challenge is to balance the cost of premium equipment with its intended benefits. This exercise is not trivial; one should not assume that practices that work at-scale in other markets will automatically work in Russia. Likewise, the scale of the Russian market and the ingenuity of the workforce make some things achievable here that are not achievable elsewhere.

What are the key aspects operators should consider when utilizing drilling technologies on brownfield wells?

Vitaly Chubrikov: Economics and PI determine the technology selection. Production enhancement and time to recoup investment determine the IRR on capital employed. A strong business case supported by value added technology arguments are required to get AFE's approved for implementing drilling programs with applicable technologies and equipment. Well designs, interactive engineering, reservoir and production models require collaborative efforts to support the AFE's. The best solutions come from operators working with drilling contractors and service providers.

Kieran Fitzpatrick: Operators should look at all the different drilling technologies available when evaluating methods to enhance or prolong production from old fields. Methods include:

• Assign a senior drilling engineer, drilling superintendent and reservoir engineer as a team to continually evaluate new or enhanced drilling technologies for suitability in their reservoirs and to develop a broad solution to reservoir development
• Use matrix planning to match the most cost-effective drilling method to the most cost-effective completion method for each reservoir in each field
• Determine the smallest diameter completion string that can provide the required production rates, then design the well geometry (including expandable casing and under-reamed hole) and fluids program to achieve that geometry with minimal risk
• Gyro re-survey older wells to improve knowledge of well positioning for collision avoidance mainly.
• Drive drilling costs and times down by use of technical limit drilling techniques, upgraded rig equipment, new or enhanced drilling technologies and optimized drilling practices.

David Brunnert: The key is to understand the risk of the operation. Brownfields, by definition, lack high pressures and/or production rates. Thus, even small errors in execution can render recoverable reserves uneconomic.

What is the history of sidetracking to enhance field production in Russia?

Vitaly Chubrikov: Sidetracking operations are rapidly growing segment in Russia; most operators do see sidetracking as the economical tool to enhance production in Brownfields. In many cases the cost of sidetracking is considerably lower than the cost of a new drilled well when factoring in the required infrastructure cost such as road access and new pads. The well candidate selection criterion for re-entry is a key element for sidetracking program success. Development of a comprehensive and reliable dynamic field model will help operators gain the most benefit from sidetracking.

Recent introduction of under balanced Coiled Tubing Drilling (CTD) technology in W. Siberia has proved to be a commercially viable in some Brownfield applications. It can deliver increased production with reduced formation damage. CTD will likely be more frequently employed in the coming years based on recent positive results. Again good candidate selection is critical to the economic success.

Kieran Fitzpatrick: Re-entry sidetracks on an industrial scale began in 1999 in the Surgut area. The first issues that arose were matching the well bore dogleg severity to the liner capability and the selection of surface and downhole equipment and tools. More recently, under balanced and coiled tubing drilling techniques have been employed. High angle sidetracks drilled from watered out or abandoned wells are now commonplace in many old oilfields. Examples of sidetracking techniques from the giant Samotlor Field in Western Siberia include conventionally drilled sidetracks, typically 142.9 mm (55/8"), and coiled tubing drilled sidetracks, typically 123.8 mm (47/8").

Other issues associated with these sidetracks include high torque and drag requiring specialty lubricants, and high ECD (equivalent circulating density), which often causes induced fractures and significant downhole drilling fluid losses.

David Brunnert: As a technology intended for brownfield development, sidetracking has been used in the former Soviet Union since the 80s. Azerbaijan, the Krasnodar region and West Ukraine were the leaders in its implementation. This is due to the fact that these regions featured mature fields. The technology featured the milling out the section of the casing, using an expandable cutting tool, then drilling the lateral directionally. In the 90s the demand for sidetracking services increased significantly. Several major service companies offered modern sidetracking technologies, using advanced systems, providing "one-run" whipstock set-up and milling off the window. Nowadays there are 4-5 service companies who offer this technology, so the customer can select different technologies, at different prices. The problems today might be with the volume of quality services available for an affordable price.

How can sidetracking improve field production?

Vitaly Chubrikov: Sidetracking allows for recovery of by-passed reserves by improving reservoir coverage. This is particularly true in tight or highly laminated formations or in water-flood applications where recovery factors are lower than in homogenous permeable formations with natural pressure drive mechanisms. Dynamic field models, good geologic mapping and knowing the reservoir allow for the most hydrocarbons to be produced from a given field.

Kieran Fitzpatrick: Sidetracks can usually improve field production in different ways, e.g.:

• Use a watered out or abandoned well to access new or bypassed reserves
• Geosteer within thin oil bands in order to increase hydrocarbon section length
• Use extended reach drilling techniques to reach additional untapped reserves
• Use under balanced fluids or non-damaging drilling, cleanup and completion fluids to enhance production without expensive and sometimes damaging stimulation treatment
• Use sidetracks with LWD/MWD tools to accurately place either injection or production wells into the optimum location ("sweet spot") in the reservoir

David Brunnert: Sidetracking allows an operator to re-enter a well bore to gain access to reserves that were previously bypassed. It is a valuable way to dramatically expand the drainage area of a well, or a system of wells.

What other drilling technologies can be employed on brownfield sites?

Vitaly Chubrikov: Drilling technology applications are gaining popularity because of the operator's need to enhance production on rapidly depleting reservoirs. The cost of replacing production with new Greenfields is often still more expensive than Brownfield production enhancement. The following drilling technologies have growth potential in Russian Brownfield markets:

• Rotary Steerable Systems
• Advanced LWD sensors (pressure, sampling, look ahead of the bit)
• Real-time petrophysical data management
• Under balanced drilling
• Coiled Tubing Drilling
• Drilling Optimization programs, integrated bits / fluids / motors / steering
• Sector Models and Geosciences
• Enhanced PDC bits designs
• Non-damaging drilling fluids and improved solids control

Kieran Fitzpatrick: Optimized use of current and new technology is the key to cost-effective production drilling in brownfield reservoirs. Some examples such as the use of under balanced and coiled tubing drilling were given earlier. When planning new infill wells, operators should carefully consider the complexity of the well bore trajectory when requiring a horizontal well in the zone directly under the existing pad. This can involve a complicated build and reverse turn when drilled from the same pad. They should consider drilling a simpler trajectory from a nearby pad.or weigh the benefits and costs of introducing a new pad in the field.

David Brunnert: The nature of brownfields drives operators to be extremely conservative on cost. Using a low cost rig can bring a cascade of problems with it that offset the benefit. Nevertheless, if an operator chooses to use a rig with limited torque or hoisting capabilities, there are tools that can mitigate the effects. Tools such as mechanical friction reduction tools or aluminum drillpipe reduce the effects of torque and drag and allow a wider range of well services to be completed while paying less for the rig.

How important is the crew on drilling operations?

Kieran Fitzpatrick: The drilling crew and the primary drilling service contractors are the most important element of a successful brownfield drilling campaign. Competent drilling personnel must be actively sought when planning any technically complex drilling program. Ongoing training must be an integral part of the drive towards cost-effective production drilling.

The drilling and service crews should be rewarded on the basis of planned versus actual well productivity, not merely on drilling rate and drilling non-productive time (NPT).

Close cooperation with the customer to provide all existing well data and good teamwork is essential for success.

In closing, I thank Peter McNaughton (Baroid technical manager) and Vladimir Semenov (Sperry senior directional drilling coordinator, Tyumen) for their extensive contributions.

Vitaly Chubrikov: The drilling contractor is a key contributor to the well construction process. A well-trained and experienced rig crew ensures that wells are drilled safely, efficiently and effectively. Coordination and cooperation of drilling operations with the service companies enhances the value added from the technologies that are utilized. The crews contribute to the construction of a well with a gauge hole, less tortuous path, and minimal fluid losses. All of these will enhance the productivity of a well and the hydrocarbon recovery of reservoir. And those determine the economic benefits to all parties.

David Brunnert: Like so many other things, people are critical of brownfield operations. Brownfield operations typically lack many of the automated systems that help monitor the performance of the rig and downhole conditions. Thus, it is critical that the crew be well trained and pay close attention to each and every action. Again, one small mistake on a brownfield well and the project can be rendered uneconomic. Even worse, a minor accident can cause hardships, delays and costs that are unacceptable.

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

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.

Peter McNaughton earned a B.Sc. (Geology) from University of Queensland, Australia and M.Sc. (Mining Geology) from University of Leicester, UK. He joined the oilfield in 1973 as a mud logger for Core Laboratories Inc., working throughout SE Asia. He joined Baroid in 1976 as a mud logger and completed mud school in 1978. He worked continuously for Baroid as a Mud Engineer and Operations Supervisor in Australasia, Technical Professional in Aberdeen, and Technical Manager in SE Asia. He also worked in several customer offices as a Project Drilling Fluids Coordinator, including the planning and start up of ExxonMobil’s extended reach drilling project on Sakhalin Island, Russia. He is currently the Baroid Russia Technical Manager, based in Moscow.

David J. Brunnert,
Vice President Intervention Services, Weatherford International Ltd.
Mr. Brunnert has more than 15 years of experience in the development and commercialization of innovative drilling and intervention tools for the upstream oil and gas industry. A graduate of West Point, he has a Bachelors of Science in Mechanical Engineering and a Masters of Mechanical Engineering from the University of Houston. An active member of the Society of Petroleum Engineers, Mr. Brunnert is currently serving on the SPE/IADC 2010 Drilling Conference Program Committee. He holds 20 patents and is responsible for managing Weatherford's Intervention Services Product Line globally.

Labels: baker botts, brown field, Halliburton, Weatherford

posted by The Rogtec Team @ 17:45  0 Comments

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