Petrofac to increase Kazakh production

Petrofac to increase Kazakh production By Darshini Shah | Mon, 1st July 2013 - 09:38 Petrofac (PFC) has signed a memorandum of understanding (MOU) with KazMunaiGas Exploration Production (KMG EP) of Kazakhstan. The MOU allows the parties to explore opportunities to improve the efficiency of oil production and increase production from KMG EP's mature Emba fields. Under the terms of the MOU, Petrofac intends to evaluate the Emba fields and to submit an offer for the long-term improvement of the management and production in selected Emba fields in order to progress a potential production enhancement contract. "We hope that our partnership with Petrofac will allow us to accomplish optimisation of production and improve oil recovery in EMG mature fields," commented KMG EP chief executive Abat Nurseitov. Andy Inglis, chief executive of Petrofac Integrated Energy Services, added: "We are delighted to be forging what we anticipate will be a long-term relationship with KMG EP, which will allow us to provide capability and performance-enhancing management for their mature fields in what is a strategically important region for us." Analyst view Oil services group Petrofac designs and builds oil and gas infrastructure, trains oil-field staff and maintains facilities. It also invests alongside producers in oil fields and helps national oil companies improve their oil production. At its full-year results at the end of June, management confirmed that it expected modest growth in net profit in 2013, with the majority of this being weighted into the second half. Petrofac also confirmed that it still expected to double 2010 earnings by 2015. Since the start of the year, shares in the company have lost a quarter of their value on the back of the terrorist attack on a gas facility in Algeria and concerns around a lack of Middle East opportunities. However, analysts at Citigroup saw scope for a re-rating over the next year as the current backlog underpins 14% earnings growth in 2014 and award intake continues to accelerate. In a note to investors in the middle of June, they wrote: "Given the potential catalyst afforded by an active second-half pipeline, we add Petrofac as a most preferred stock in our three-month best-ideas database." Tony Shepard, analyst at Charles Stanley, was also optimistic on the stock, explaining: "Given the good long-term prospects and the sector discount rating, we reiterate our 'accumulate' recommendation." Petrofac is trading on a 2013 price/earnings and enterprise value/EBITDA ratio of about 9.4 and 7.5 times respectively, a 15% discount to the peer group. ====================================== (RNS) 2013-07-18 07:00 Petrofac Limited - Petrofac Emirates restructure Previous | Next | All news for this company RNS Number : 5599J Petrofac Limited 18 July 2013  Press Release 18 July 2013 PETROFAC LIMITED Petrofac increases interest in Abu Dhabi joint venture Petrofac announces that it has entered into agreements which will increase its economic interest in Petrofac Emirates, its Abu Dhabi based joint venture with Mubadala Petroleum, to 75%. This follows the sale by Mubadala Petroleum of its shares in Petrofac Emirates to Nama Project Services LLC, an affiliate of Nama Development Enterprises (Nama), a leading local service provider to the energy industry across the United Arab Emirates (UAE). The remaining 25% will be to the benefit of Nama. Completion of the transaction is subject to conditions precedent, including the usual regulatory consents. Formed in 2008, Petrofac Emirates was the first joint venture company in the UAE to provide a full range of engineering, design, procurement and construction services for major onshore oil and gas, refining and petrochemical projects. The joint venture has grown strongly since 2008 and in 2013 has been awarded three strategically important projects in Abu Dhabi: an engineering, procurement, construction, transportation and commissioning contract for the Upper Zakum field in consortium with Daewoo Shipbuilding & Marine Engineering Co Ltd (Petrofac Emirates' share US$2.9 billion); a US$187 million onshore EPC contract for the development of the Bab Habshan-1 project and a US$500 million onshore EPC contract for expansion of gas compression facilities at the Bab field. Maurizio La Noce, CEO of Mubadala Petroleum, said, "Mubadala Petroleum, in partnership with Petrofac International, established Petrofac Emirates five years ago as a major provider of, and centre of excellence for, engineering, procurement and construction services to the oil and gas sector in the UAE and the region. Mubadala Petroleum has contributed local sector knowledge and relationships, and encouraged the recruitment and development of Emirati talent into the business. Having nurtured and matured the business into a stable and profitable venture, Mubadala Petroleum's interest is now being transferred to the UAE's private sector, in line with Mubadala's strategic objectives and mandate. Mubadala Petroleum will concentrate on its core international E&P business, and most important UAE gas supply projects. In this context, we will continue to support the Abu Dhabi based Petrofac Emirates business and will look at opportunities to leverage on our existing and strong relationship with Petrofac International to identify mutually beneficial opportunities aligned with our ambitious growth objectives in our core geographies." Matthew Hollis, Managing Director of Nama, said: "We are very proud to have worked closely with Petrofac over the last 20 years. Their impressive performance has enabled them to grow in to one of the most successful leading EPC contractors in the world today. Their UAE joint venture with our friends in Mubadala Petroleum has further enhanced this success in recent years and so for all of us at Nama it is now a great honour to have been given the opportunity to be partners in bringing Petrofac Emirates into the private sector here in Abu Dhabi." Marwan Chedid, Chief Executive of Petrofac's Engineering, Construction, Operations & Maintenance division, said: "Since its inception in 2008, we have established a first class engineering centre in Abu Dhabi with Petrofac Emirates. The joint venture has created business opportunities and established strong relationships over the last five years, in addition to helping Petrofac to expand our local talent pool by attracting UAE nationals to join our talented team. Looking forward, we want to build on the success we have achieved to date, including the important projects we have secured in Abu Dhabi this year. Nama is a first class local partner and we are optimistic about the future prospects of Petrofac Emirates. Likewise we look forward to maintaining our strong links with Mubadala Petroleum as we explore other opportunities collaboratively outside the region." Financial reporting Under the terms of the restructure, Petrofac will report 100% of the revenue and backlog on all current and future Petrofac Emirates' projects (with Nama's 25% economic interest reported as 'profit for the year attributable to non-controlling interests'). Ends For further information contact: Alison Flynn +44 (0) 207 811 4913 Head of Media Relations Petrofac Tulchan Communications Group Ltd +44 (0) 20 7353 4200 Stephen Malthouse Martin Robinson petrofac@tulchangroup.com Notes to Editors Petrofac Petrofac is a leading international service provider to the oil and gas production and processing industry, with a diverse customer portfolio including many of the world's leading integrated, independent and national oil and gas companies. Petrofac is quoted on the London Stock Exchange (symbol: PFC). Petrofac designs and builds oil and gas facilities; operates, maintains and manages facilities and trains personnel; enhances production; and, where it can leverage its service capability, develops and co-invests in upstream and infrastructure projects. Petrofac's range of services meets its customers' needs across the full life cycle of oil and gas assets. With more than 18,000 employees, Petrofac operates out of seven strategically located operational centres, in Aberdeen, Sharjah, Abu Dhabi, Woking, Chennai, Mumbai and Kuala Lumpur and has a further 24 offices worldwide. For additional information, please refer to the Petrofac website at www.petrofac.com. Nama Nama is dedicated to further developing and maintaining its position as one of the leading, local business groups serving the oil and gas, power and water and industrial sectors of the UAE economy. Their objective is to professionally satisfy the needs of our local customers, while ensuring that we remain one of the first choices for international organisations looking for a reputable local business partner. For additional information, please refer to Nama's website at www.namauae.com. This information is provided by RNS The company news service from the London Stock Exchange END MSCEDLFFXDFBBBL ======================================= Fish-inspired vessel joins Brazil offshore oil boom Thu, Aug 08 08:25 AM EDT 1 of 4 By Andrew Callus LONDON (Reuters) - A strange-looking vessel inspired by the exotic sucker fish is due to leave Norway for Brazil's giant offshore oilfields this week on a mission to revolutionize deep sea oil loading methods. At 47 meters tall, 28 meters long and with an 11 meter keel, HiLoad DP unit No. 1 looks top-heavy and out of place in the water, more like a partly submerged container-port crane than a ship of any type - or a fish for that matter. But attached to its mother ship, the oil tanker Navion Anglia, the vessel is preparing to head anyway from the Norwegian port of Kirstiansund in southern Norway to the ocean off Rio de Janeiro on a debut 10-year commercial trial contract for Brazilian state oil company Petrobras. Its deployment in the Campos and Espirito Santo pre-salt basins reflects the burgeoning scale and increasing remoteness of offshore projects that supply about one third of the world's crude oil, and the challenges of developing such resources economically. The Norwegian-built craft is designed to load oil from deep sea Floating Production, Storage and Offloading (FPSO) vessels directly onto a standard tanker with no extra equipment. It offers a cost-saving alternative to specialist shuttle tankers with their own dynamic positioning (DP) systems, and to the use of moored loading buoys with their associated tug boats. There are already about 150 FPSOs - often simply converted tankers but also increasingly sophisticated new-built vessels - working offshore, as oil companies go so deep in the search for oil where traditional platforms and pipelines are impractical. Petrobras and the Brazilian offshore fields it controls are the apex of that boom. Data from industry consultants IHS says 21 of the 48 FPSOs currently under construction are being built for Petrobras. Energy business advisers Douglas-Westwood has forecast that between 2013 and 2017, $91 billion will be spent on FPSOs - double the amount over the past five years. The sheer scale of Brazil's offshore projects, along with relatively calm weather compared with the North Sea and other deep sea locations, makes them an ideal commercial testing ground for the new technology, but there are other factors at play. "One of the drivers is that Brazil will have to export a lot of its oil - so direct loading onto normal tankers instead of reloading from shuttle tankers will create considerable savings," said Yngve Kloster, project manager for the deployment of HiLoad DP unit No. 1 to the Petrobras project. "We also see it as an alternative in (offshore) Africa where they use offloading buoys you can approach with a normal tanker, but where you will need a tug to assist as well." Kloster said there could be environmental benefits too from lower fuel consumption and reduced leakage of polluting vapors during loading. MUTANT DORSAL FIN Kloster works for Teekay Corp, an oil shipping, production and transport specialist company which last year bought the HiLoad DP unit No. 1 along with a half share in the developer, Norway-based Remora AS. It paid $55 million for the HiLoad DP No. 1 - a prototype built in 2010 - and paid $4.4 million for its 49.9 percent stake in the business. Remora is the Latin name for the sucker fish, a species whose crowning glory is a dorsal fin that has mutated into a sucker behind its head. The fish empties water from chambers in the sucker to create a vacuum and grab a ride under something larger - usually a shark - for a feed on leftovers and parasites. The HiLoad DP (Dynamic Positioning) unit works in much the same way - although unlike the fish, it is the feeder rather than the fed, and it takes control of its larger host. A sucker slab grabs the tanker below the water line, and more suckers on the section of the craft above the surface secure a hold higher up on the tanker's hull. Once attached, three powerful DP thruster engines that can rotate 360 degrees keep the host tanker steady and a safe distance from the FPSO. A hose attached to the HiLoad from the FPSO fills the tanker with crude. HiLoad DP No. 1 and its crew of three can travel at four knots and up to three nautical miles from its mother ship or an FPSO to which it can attach itself when not in use. It can handle any tanker up to "Suezmax" size (160,000 deadweight metric tons), grabbing it and loading it with oil in a process that takes 24-30 hours - comparable with a shuttle tanker loading time, Kloster says. The prototype is designed to work with "spread moored" FPSOs, which are fixed in place, but during the Petrobras contract it will also be tested with a "turret moored" FPSO. Turret FPSOs are moored from a section around which the rest of the vessel rotates in the wind and the current - extra movement that requires more powerful dynamic positioning systems for the tanker to match. Kloster said the company will design, and hopefully build, future versions that are more powerful and can more easily cope with turret moored FPSOs and bigger tankers. Teekay said in May it hoped to start operations in early 2014. It also has a contract to provide shuttle tankers from this year for BG Group, the British company and Petrobras' partner offshore Brazil. BG Group declined to comment for this story. Petrobras had no immediate comment. (Reporting by Andrew Callus; editing by David Evans) ================

Harsh environment Jotun FPSO design taking precedence over haste

European contractors are struggling to batten down costs consumed by North Sea production floaters, but construction schedule overruns are not as bad as rumors suggest. This subject was a major issue at the 14th Annual Floating Production Systems Conference in London, organized by IBC Global Conferences. The negative aspects were touched on by Inge Laskemoen, Senior Vice President for Field Development at Kværner Oil & Gas Norway. He outlined events leading to delivery of the Jotun FPSO to Esso. Jotun is a joint development of three fields in the Norwegian North Sea, called Elli, Elli South, and Tau. For a Norwegian project, the international content is unusually high - operator Esso and Enterprise each own 45%, with the balance held by Statoil, Conoco, and Amerada Hess. Production, which started last October, is derived through wells drilled from a wellhead platform, with oil and gas exported to the floating production,storage, and offloading (FPSO) vessel, which in turn offloads to shuttle tankers. The location is 165 km west of Haugesund, in 126 meters of water. Kværner gained the EPIC contract for the FPSO in April 1997. First oil was achieved 30 months later. New challenges arose each day of those 30 months, according to Laskemoen - but the stiffest emerged before the contract had even been awarded. In 1996, Kværner had been toying with a new hull design developed by its Masa Yard division in Finland, which was about to be deployed in a floating storage unit on Norsk Hydro's Field. Schedule driven Duration of recent FPSO construction projects (in months) from contract award to first oil. Balder execution time includes re-build to meet field requirements. ((In architecture, a turret (from Italian: torretta, little tower; Latin: turris, tower) is a small tower that projects vertically from the wall of a building such as a medieval castle. Turrets were used to provide a projecting defensive position allowing covering fire to the adjacent wall in the days of military fortification. As their military use faded, turrets were adopted for decorative purposes, as in the Scottish baronial style. )) Modifications were required, however, particularly to the turret, in order to convert this concept into a seaworthy FPSO. In November that year, Kværner took the gamble of ordering a vessel based on this design from Masa Yards - in anticipation of winning the Jotun prize. That risk had to be taken, Laskemoen claimed, because of Esso's tight schedule for this project. "It was necessary to start several engineering activities on the topside facilities at this stage prior to award of the FPSO contract, in order to provide interface information from the topside facilities design needed for the detailed design of the vessel." Esso had demanded a 20-year working life for the vessel, with no drydocking in that period. Long discussions ensued between Kværner and Esso over how to interpret this 20-year rule, which differed from the detailed specs in the shipbuilder's tender. Compromises were eventually reached, but these enforced some re-design and changes to the fabrication process. Added complications followed. Late in the conceptual engineering phase, the field partners decided that the FPSO should itself provide saleable gas for direct export into the Statpipe trunkline system (unlike other FPSOs, which deliver their gas untreated for clean-up elsewhere). Accommodating this late change proved to be a struggle. "As a result, we got out of sequence in ordering the topside processing equipment," Laskemoen said. Waves dictate change A further dilemma was the potential impact of severe weather on the hull. Model tests had shown that large waves in this location would deposit green water onto the deck. Further analysis suggested that the quantity and impact could be significant, leading to further very late design changes being imposed. "The cost consequences became more significant than they could have been," said Laskemoen. Major improvements that had to be instituted included protection of cable racks, the deluge skid with bulkheads, more protection wall for the emergency generator and re-routing of the exhaust duct, and structural reinforcement of the escape route and other structures. At the time of construction, many other North Sea gas development projects were also underway, many incurring serious schedule/ cost overruns. Kværner and Esso tried to keep a lid on potential problems by strengthening the Jotun project team. They created an "alignment initiative" to aid staff interaction at all levels and thereby improve execution of the project. However, planning and execution problems continued to surface. As the project progressed, it emerged that the FPSO tender had been based on a concept that was not sufficiently matured. Topsides modification had to be performed at the detailed design phase. In turn, process overlapped into the detailed engineering phase, forcing further widespread modification. These overruns put engineering as a whole out of sequence. The effect of performing so many activities in parallel was to increase the strain on human resources to meet schedules. That situation was exacerbated by the high workload at the time in Norwegian yards, which meant that local pre-fabrication support staff was not readily available. "We had to buy to higher cost and lower quality," said Laskemoen, "resulting in reduced productivity." With delays hitting all main deliveries to the Jotun assembly site in Stavanger, Kvarner decided to insist on earlier arrival of outstanding packages such as the compression unit, "in order to have the major units lifted onboard the vessel for completion under our own control. There was more carry-over work than expected, and too many problems surfaced during completion and commissioning activities. This again resulted in increased workload to the assembly site, and further challenges regarding completion of the vessel." Other challenges Other problems that had to be faced included: •FPSO's mooring anchor chains: These had been installed prior to arrival of the vessel, and were lying on the seabed waiting to be lifted up. After the majority had been pulled in, some twisting of the chain was encountered due to sideways pulling. The chain locked in the guiding system, and as a result, the pulling method had to be modified •Flushing and preservation: The heating and cooling medium systems were flushed and preserved prior to sailaway from the yard, but preservation proved unsatisfactory. Chemical flushing was needed to clean the system properly. Esso, which had global expertise in this field, worked with Kværner to find a chemical medium applicable to the completed system which could be used without destroying gaskets and seals. •Firewater systems: Some vibration was being experienced, which led to significant repair and re-design of some of the firefighting water system components. "For many of the FPSOs built in recent years," Laskemoen concluded in his pre sentation, "the production facilities are more complex and the execution time and investments are at another level compared to the more simple design. The main reasons for these differences are: •Long field life •Environmental requirements - zero emissions philosophy •Production of crude of a quality to achieve the best possible market price •For Jotun, gas production to sales quality Jotun's FPSO, which has a design capacity of 89,000 b/d, plus water treatment at 122,000 b/d, water injection at 190,000 b/d, and gas compression at 53 MMcf/d, was delivered five months later than originally planned. Compared to other recent North Sea FPSOs, this is reasonably good, Laskemoen claimed. In general, floaters are still being produced quicker than fixed platforms of similar capability, he claimed, and at lower cost. ============= UPDATE 1-Chevron-led Kazakh oil venture sees sharp output rise in 2018-19 Mon, Jan 28 07:19 AM EST By Raushan Nurshayeva ASTANA, Jan 28 (Reuters) - Output at Chevron-led Tengizchevroil (TCO), Kazakhstan's largest oil producer, is set to rise by 12 million tonnes per year in the 2018-19 timeframe from last year's 24.2 million tonnes, TCO General Director Tim Miller said on Monday. Data released by TCO project partner Lukoil this month said the venture's production stood at 25.1 million tonnes (about 503,000 barrels per day) in 2012. "Our 2012 production was 24.2 million tonnes. This was 3.7 pct lower than our business target of 25.1 million tonnes," Miller told an enlarged meeting of Kazakhstan's Oil & Gas Ministry. "The primary reasons for this were mechanical problems ... severe weather conditions and transportation restrictions." The huge Tengiz oilfield, located onshore in western Kazakhstan, is one of three main drivers of Kazakhstan's plans to raise its oil output by 60 percent by the end of the decade. Kazakhstan is now the second-largest post-Soviet oil producer after Russia. The vast Central Asian nation of 17 million plans to raise output to 130 million tonnes by 2020 through expansion at the Kashagan offshore field in the Caspian, higher output at Tengiz and the Karachaganak oil and gas field. Kazakh Oil & Gas Minister Sauat Mynbayev said earlier on Monday Kazakhstan's total oil output was set to rise to 82 million tonnes in 2013 from last year's 79.2 million tonnes. TCO's output is set to remain at the current level for a few years as the venture has first to implement the Wellhead Pressure Management Project (WPMP) to install a pressure boost facility and drill additional wells post-WPMP to lay the groundwork for the crucial Future Growth Project (FGP). "The Future Growth Project will expand production capacity by 12 million per year," Miller said. "Start-up of the FGP operation will be in the 2018 to 2019 timeframe." "We are targeting the final investment decision for the fourth quarter of 2013," he said without specifying the sum. Chevron holds a 50-percent stake in the venture, while ExxonMobil owns 25 percent, Kazakh state oil company KazMunaiGas has 20 percent and Lukarco, controlled by Lukoil, the remaining 5 percent. Since TCO's creation in April 1993, the venture's cumulative payments to Kazakhstan had totalled $74.2 billion, Miller said. "In 2012, total payments exceeded $14 billion for the second consecutive year," he said. ================== Product description With subsea tieback projects, what goes on above the surface is just as important as what is happening beneath it. EDG has the topside expertise to support your subsea tieback projects, and we are committed to quality, cost-effective designs. Tiebacks to deep water, floating facilities require a different approach than the traditional topsides projects in shallow water or to fixed platforms. Shallow Water and Fixed Platform Topside Projects Schedule Most projects have a target completion schedule. Depending on the aggressiveness of the schedule, maintaining it could take precedence over cost control and, possibly, quality. Quality Quality, sometimes equated with operability, is a primary consideration during the design and construction phases. Depending on the level of quality desired by the client, adjustments to the project budget and schedule may be required. Cost Cost is always a consideration on any project. Most projects have a cost threshold beyond which it is no longer economically feasible. Cost considerations may also limit factors such as the quality and delivery of equipment. Deep Water Topside Projects When designing for deep water projects, it is necessary to consider three additional priorities. Balancing these six priorities is a complex process and can become even more challenging when one must take precedence over the others as the defining criterion for design. Deep water priorities to consider beyond schedule, quality and cost Location The location (center of gravity) of new equipment is paramount to floating facilities that depend on ballast to return the vessel to an upright, level position. If the location for the new equipment results in a list that cannot be corrected with the available ballast, a new location must be found. Deck extensions, raised decks and mezzanines create more location options for equipment, at the expense of an increase in weight. However, this may be the only way to shift the Center of Gravity of the equipment to a location where ballasting can return the vessel to an even keel. Weight Floating facilities have a maximum weight they can accommodate and still maintain the required freeboard. If initial weight estimates for the tieback project exceed the allowance for new equipment, it may not be practical to complete the project at that location. Equally challenging, retrofitting additional flotation or reducing weight through the removal of other equipment can be prohibitively expensive. Precise weight estimates at the beginning of the project, as well as aggressive weight monitoring and control as the project progresses, are critical to achieving desired weight targets. Depending on the project weight allowance, some or all equipment may need to be selected based on the lowest weight versus the shortest delivery or lowest costs. Space If the available open space does not adequately house new equipment, and the applicable weight budget for the project cannot cover structural steel to allow greater deck space, the tieback may not be completed at a particular host. Choosing equipment that fits within the accessible space, and thereby eliminates the need for deck extensions or mezzanines, may take precedence over the lowest cost and fastest delivery.

Manchester and Beyond

Author Gramacho View Profile | Add to favourites | Ignore
Date posted 2011-10-18 11:49
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This note details some of the discussion at Manchester. Further background and my thoughts are captured within the paragraphs bounded in parentheses thus [ ].

This post has been a bit slow in the making as I am currently on extended vacation in Portugal. Hence further posts will be limited for a while.

NOTES AND COMMENTS FROM PRESENTATION
Slide 5 Company Highlights
"We will probably sell our AB interests to raise some more money." [Have to be careful here whether the “probably” qualification used by CG is significant or whether he just means subject to an acceptable bid. This is discussed later in the post presentation chat section.]

Slide 6 Company Forward Growth Strategy
10-12 geologists, engineers and facilities staff have been hired. [On a project this size this is just the initial team, more staff will be required as the project ramps up.]

Slide 7 2011/12 Work Program
[In the London Proactive presentation in August Ewen said we would see a new phase of exploration on both Akri Bijeel and Sheikh Adi and the extent of this was revealed in slide 7. He also mentioned a development program which I took to be an EWT=Extended Working Time in the Akri Bijeel block but this was not mentioned in the Manchester presentation.]

Chris indicated that in March next year GKP could have 7 rigs running in Kurdistan in which it has an interest.

[OMG this should have been one of the highlights of the evening. 7 rigs FFS=fee for service, no one else in Kurdistan comes close to this. Some of the majors in the south will exceed this but they are drilling close spacing in fill wells and working over wells in mature fields. All of GKPs wells are essentially exploration wells as they are so far apart. IMO there is not a single operator in the UK Nth Sea that will be involved with 7 wells drilling concurrently, perhaps Statoil in the Norwegian sector but no one else. I suppose the proposed sale of Akri Bijeel has undermined this but don’t be surprised if negotiations on the sale are not complete until end 2Q/early 3Q. IMO the price could be rising by $100m+ per month as wells progress and encounter new oil discoveries.]

Sh-2 is testing [further discussion Slide 14] and is nearing completion after which the Weatherford rig will move to the far east end of anticline to drill Sh-6 (location shown in Slide 10). It is sufficiently far down dip at Jurassic level that it offers the best opportunity of finding the OWC. [Even if the well does not find the contact, which would be the case if the interval around -2230m SS is not a reservoir quality rock, IMO it should find oil sufficiently deep to raise the P50 close to the “filled to spill case”.]

SA-1 is complete. Mikey Admin’s note covered the use of the workover rig for testing. The Discoverer-1 rig is currently rigging up at Sh-5.

Chris mentioned a bigger rig may be needed for Sh-7 in order to drill to the Permian. This was mentioned in my post of 5th Sept “Conversation with John G re Sh2, 4 and More”. Chris later mentioned that although Shaikan 7 is shown as contingent and they have not yet contracted a rig, he felt they are committed to drilling the well.

The MOL rig has reached TD and just getting ready to start the testing program.

[Bekhme-1 was spudded on 25th Mar and was said to be “approaching TD” in the GKP mid year report of 14 Sept.]

The rig will go to Aqra-1. It is an exploration well in the shallow part of the section and an appraisal of Bijeel in the deeper part.

[This is an interesting comment in that you rarely have this scenario. Usually it is the deeper part of the section that is the exploration target because a discovery has already been made at a shallower depth. But we are dealing with MOL here and they appear to do many things *rse backwards lol! The other point of interest is that the Aqra surface location is shown between the two main surface anticlines marked on Slide 19. On the face of it not an obvious place to drill for a shallow exploration target. However if you look at the surface terrain depicted in the link below Aqra is a surface anticline.

[IMG]http://i53.tinypic.com/331dmxv.png[/IMG]

It will be interesting to see if they find water or oil in the shallow section. If oil is found that could suggest Bekhme and Bakrman are connected and really one humongous field. If water is found they could obtain one or more aquifer pressure points for comparison with oil pressure points which hopefully they will obtain in Bekhme and Bakrman if discoveries are made. It should be possible to get an approximate estimate of the oil water contact in each anticline. The issue would be obtaining an uncontaminated water sample to measure/estimate the water composition and density to predict the water pressure gradient.]

At Bakrman-1 MOL has made progress on getting the location ready and it will bring in a second rig.

EWT(Extended Working Time) upgrade and expansion: eng work is done and the mods and upgrade are out to tender.

The pipeline is to be worked with the KRG, possibly with other operators. [Not clear what this means in practice.]

[Missing from this slide is the time line for the 3D interpretation and processing/reprocessing. The London presentation indicated interpretation continuing through end November. A few folk seem to be getting hot and bothered about a perceived delay this but IMO it is not a big issue. We have heard the most important piece of news coming out of the 3D seismic, i.e. the size of the Shaikan container has, if anything, increased slightly. Yes they will reprocess the seismic but that’s not uncommon. The Geos have to try different processing options to try to extract the maximum info from the data set. There is not a lot of past experience in the region that will have established the best techniques and optimum processing parameters to provide the ideal processed data set. Geos are never satisfied which is a good thing as long as they do something positive with what they have.

The full benefit of the 3-D will be seen when it is matched to the well results from Sh-2 through Sh-6. It should then be possible to place the Sh-7 well and pick development well locations with some confidence. IMO there is no point in trying to revise the Shaikan OIP now purely on the basis of the 3-D. It does not predict a number of the factors that drive OIP e.g. oil saturations, porosity and oil formation volumes factors. For that we need more wells and oil samples and they are on the way. Having said all that, I am sure it would be appreciated if GKP would demonstrate to its shareholders that it is deriving benefit from money it has spent on the 3-D.]

Slide11: Shaikan
Section is still the old 2-D data, the 3D data looks better.

Slide 13: Shaikan
Shaikan 1 tested 18-55 API oil. The range of APIs and rates seen in Sh-1 has been confirmed by Sh-2. They have found 53 API and 16 API in Sh-2. [We know the KC-C tested 36API and the lower KC-B tested 40 API so either the upper KC-B or more likely the KC-A has tested 53API.]

GKP has completed testing of the Triassic and is now working its way through the Jurassic Butmah. In Sh-1 only the upper part of the Butmah was tested although there were shows all the way through it. In Sh-2 the bottom and middle have been tested and the top is going to be tested.

[IMO this is good news. According to DGA and RSC, the Butmah has the highest OIP of any single formation and so it is important that as much of it as possible is tested to confirm just how much of it is pay. The 5 Sept RNS stated that there would be up to 5 additional tests so this would indicate testing is nearing completion. There may also be a Mus interval test to conduct before testing is complete although that would probably be a sixth test since 5th Sept and would contradict the RNS. In any event we can look forward to a mega RNS on testing results.]

Chris recalled the story of how the flare and smoke from the flare from Sh-2 could be seen from Erbil some 200km away and why they had then to put out the press release quickly because everyone would know (there was a major field extension) before GKP wanted to make an announcement.

[There is still a misunderstanding about this by some folk who appear to think GKP were trying to delay news or hide something. IMO the intent would have been to wait until the test was complete and a reliable/representative well rate was achieved after clean up of fluids lost to the reservoir. However the widespread visibility of the flare meant that it would have been an open secret in Kurdistan that the major step out of Shaikan had been successful which could have led to a “disorderly market” in the shares.]

CG described Sh-2 as being under engineered to take the pressure in the Triassic.
.
Sh-4 is in the Triassic. 9-5/8” casing has been set at the bottom of the Triassic Kurre Chine B and the well has been logged. The top part of the Jurassic looks very good [as previously announced] and the bottom part “is still being analysed”. Chris indicated the well is probably going to be drilled to the KC-C. [Further comments in Post Meeting Chat section.]

Shaikan 5 will be more crestal. [It will still add to the OIP by increasing the proven area but is unlikely to increase the depth of lowest known oil.]

Slide 14 Shaikan 1 and 3 EWT
Chris briefly discussed the thorny issue of production without revealing much.

[IMO the lack of a clear explanation why production has been so low is the most contentious issue at present.

Initial problems with export were discussed in my post of 5th Sept “Conversation with John G re Sh2, 4 and More”. Here is the relevant extract.

“There have been two main reasons for the delay in establishing continuous exports. The first is as discussed by Ewen at Proactive i.e. the requests by the KRG for domestic production. The second has been problems trying to achieve export spec oil by chemical means. The first H2S scavenger did not perform according to the chemical company’s assurances which I assume were based on lab tests. The scavenger was incompatible with the crude. This resulted in a batch of oil having to be sold in small quantities over a period. Meanwhile the topsides upgrade project to achieve pipeline spec is going ahead full speed.

JG advises that they will announce export when it is on a regular, sustained basis.“

My interpretation of this is that they had a storage tank full or part full of off spec crude. In an FPSO=FPSO - Floating Production Storage and Offloading vessel


Read more: http://www.answers.com/topic/oil-field-acronyms#ixzz1c0BjfzIJ

you could route crude to an off spec tank but in this scenario there is only one tank and the crude in that tank had to be sold in small batches as far as export is concerned. There was also a political element that GKP has no control over and which obviously is sensitive.

What is not clear is why production to the domestic market is low. You would think that when the KRG agreed to resume exports this would have led to a shortfall in supplies to the domestic market. It is not clear why this did not lead to a domestic contract with consistent demand for Shaikan crude. One would expect GKP to be able to report monthly production by this stage but it does not appear to be happening leading to distrust on the part of PIs which can’t be good. ]

Slide 15
The dev well plan is what it says it is “Conceptual” so the picture should not be taken too literally. An extensive fracture analysis has been done. Decisions have to be made regarding vertical, horizontal and inclined wells and the direction of deviation relative to the axis of the anticline((A fold with strata sloping downward on both sides from a common crest.
)). [If you recall one of the key findings of the Mirabaud report was that the principal fracture orientation at Shaikan is not parallel to the axis of the anticline reducing the risk that fracture intensity will reduce away from the spine of the field. In other words, provided the orientation of the wells is optimised, there is a chance wells will have good productivity over most of the structure.]

Slide 17
A second well will be drilled in SA to the north of the first one.

Slide 18: Ber Bahr
[This is the standard Ber Bahr slide that has been around for a while but with the updated reduced OIP estimate from Genel. Please note how Lake Dohuk is represented in the surface map. One would think that the lake could play a large part in any development as it appears to be about 10 km from E to W and 7.5km from N to S at its widest points. This would suggest land access for drilling BB appraisal and development wells would be severely constrained and that one or more drilling platforms might be required. Now go to slide 16 and blow it up to 200% (or better still go to slide 15 of the Sept forward strategy presentation) which shows a satellite view of the lake. Note that Lake Dohuk is only about 1km from E-W and 3km from N-S! The BB slide is completely unrepresentative of the Lake, fortunately! Perhaps it served as a useful ruse to deter bidders lol!]

Slide 19: Akri Bijeel
Chris said the Akri Bijeel Block is highly prospective.
[Did anyone else notice the significant emphasis on HIGHLY in the tone of his voice? A reflection of the Bijeel discovery but perhaps also of Bekhme-1 findings? He rarely used that change of emphasis elsewhere in the presentation.]

Slide 20: 3 Year and 6 Mo Share Price Performance
This slide is one that Ewen used in London but Chris made the point that the GKP sp has held up very well since the beginning of August in comparison with many AIM oil stocks which have dipped 40% [as the market reacted to Greece etc.] whereas the GKP price has only fallen by 4% .


QUESTIONS FROM THE FLOOR

Most of the questions have been covered but for the benefit of those at the back of the room I want to mention that when Chris summarised this question to the room he omitted the political element contained within the full question.

The person responsible for drilling the BB well (TH) that could have a big impact on GKPs value is someone that probably covets GKP. We have just seen the TD reduced by 1000m in BB but when compared with Shaikan the equivalent horizons in BB are about 600-800m shallower. This means that the pressures in the Triassic are likely to be lower and the chance of getting through the Triassic and seeing the full extent of the new oil potential it has shown, which we have not been able to do in Shaikan (and Sheikh Adi), should be higher. Yet the revised well TD reduces the chance of extending the known oil bearing horizons deeper in the Triassic section and reaching the elusive Triassic dolomite.

CG indicated that 2100m is the commitment depth. He also said he is not the operator but in his view if we are swimming in oil at 2100m are we going to stop?

[IMO there is a potential conflict of interest here. Genel can elect not to explore the full potential of the Triassic thereby not proving the full potential of BB. Any bid for GKP in the event of BB success would only have to factor in oil discovered down to the upper part of the Triassic leaving the Triassic dolomite and anything below as exploration upside thrown in for free.

The PSC commitment does not appear to be depth dependent, it is cost dependent. From memory the PSC commitment is to spend a minimum of about $13.5MM. If there is a depth commitment this must have been reached in licence management meetings presumably with GKP in attendance and with GKPs concurrence which frankly would be good to confirm.

We have tried twice unsuccessfully to get to the Triassic dolomite and now it looks like a major commitment in the shape of a new rig will be required to get there which won’t be until 4Q 2012 in Shaikan 7. It would seem that an opportunity should be taken to get there much sooner in BB-1 where nature has conspired to make it easier to do so. The dolomite is predicted to be at 2300m in BB-1 whereas it was not reached after drilling to 3300m in Sh-2 and 3780m in Sheikh Adi.]

Chris later indicated that the seismic (from which the formation tops will have been picked) is probably the old DNO seismic. [I am not sure if this would call into question the predicted depths. SA-1 is an example of how depths can be different from predicted. The well encountered a repeat section due to faulting that caused tops to be deeper than predicted.]

In response to being asked when investors can see the 3D seismic Chris indicated he doesn’t see any problems with producing some cross sections for the next meeting.

One of the other presenters asked CG “What is the Proven Developed Producing reserves on sustained production?” He explained that the numbers in the public domain are OIP. [GKP is relatively unique for an AIM explorer at this stage in proceedings in that does not speak in terms of 2C Contingent Resources or Reserves. This appears to be deliberate strategy until more information is obtained. ]

POST PRESENTATION CHAT
This has been covered very well by MrAverage1 and Dragon_Ventures. (He should have called himself The Inquisitor lol!) A few more Q&As and thoughts are included below.

GKP decided to drill another well in SA to define the structure as soon as possible. The 3D seismic will be used to pick the location. [Note full extent of the possible eastern extension of BB into the Sheikh Adi Block may not be completely covered by the 3D, refer slide 15 of the Forward Strategy Presentation which shows the 3D outline does not cover the northern part of the SA Block. (It is also shown as a blue line in the top left picture of the BB compilation in a link further on in this post)]

Does core analysis and well test results support good matrix permeabilities?
There is no doubt it is fractured and that is the reason for high rates but there is also matrix porosity. CG also said he did not have the core analysis at his fingertips but certainly some of the matrix has permeability and some is tight .

You are implying that you will not go to the Lower Triassic dolomite in Sh-4?
Shaikan 4 well is designed like the others and we can’t take the chance to go to the dolomite.
[This was followed by some banter regarding John G’s hope that there may be a pressure trend that leads to lower KC-C pressures in the west and hence perhaps an ability to go to the deeper dolomite.]

The new seismic, is it as expected?
3D you get a very good resolution clear picture on flanks where you have tertiary cover. On the crest have a tertiary limestone but also Cretaceous in places [Tertiary has been eroded on parts of the crest.] and have to shoot with dynamite. The picture is not as clear. That is still the case with the 3D but it has filled in a lot of the gaps. [The 2D line spacing was about 5km. I didn’t check the 3D line spacing. Offshore it would be every 12.5 or 25m but I am not sure if that would have been practicable on the Shaikan anticline. Nevertheless it will have been a much, much closer spacing than the 2D.] The structure has not changed.

Is Vallares going to bring anything to the picture? [Like $10Bn lol!]
Anastasia “They will have their own perspective.”

There was some discussion about the release of data from BB during which CG indicated they do get daily reports from BB-1 which is standard industry procedure. Hence GKP will be kept very up to date with progress. The spud announcement was released simultaneously.

At what point would they test northern structure in SA that could be an extension of BB?
SA2 will be within the 3D and within the same structure. It is probably slightly north east. “We need to test the Jurassic in the hanging wall.”

Is it designed to investigate the high pressure?
I think the rig is adequate to test this well. [This still leaves open the question of whether SA2 could reach the Triassic dolomite. As the rig schedule stands Sh-7 would spud about 1 month after SA-2. If it were to make better progress than SA-2, because say the Cretaceous is less troublesome, then Sh-7 might reveal the dolomite pressure regime and give an indication if it could be drilled safely at SA-2.]

In Ber Bahr the 2D seismic covers only the south of the block. The Surface anticline looks like it has been eroded in the north of the block and was a bigger structure at one time. You guys indicated that BB may be 1.5x the size of Shaikan. Was this was based purely on seismic in the south?

Chris initially passed on this indicating he had not worked on it. When pressed further about the 3D perspective presentation he stated “That was based on the seismic we had” and inferred it was the data shot by DNO [prior to the break up of their former mega block].

[What I was getting at without explaining myself very well is illustrated in the attached link which is a Ber Bahr compilation.

[IMG]http://i52.tinypic.com/wan8ep.png[/IMG]

In the Nov 10 presentation (top right picture) an anticline is depicted in the northern part of the BB block and north of the seismic (top left picture). I am not clear if this is:
a) A surface anticline that is expressed also at subsurface level and is therefore another subsurface target or
b) The remaining part of a much larger surface anticline that has been eroded at the surface to leave three separate present day surface anticlines but one very large anticline at the subsurface level
c) Simply the surface expression of a fault.

The terrain view in the link below shows three possible anticlines in the BB block. The two southern expressions are covered by seismic in the BB block but not the northern one. There is some coverage of the northern one in the adjacent block to the west (Murphy’s Dohuk Central Block).

[IMG]http://i51.tinypic.com/35mo9oi.png[/IMG]

The above discussion illustrates that the seismic in BB from which the GKP interpretation was made is pretty sparse. There is probably room for more than one interpretation and it is no surprise that pre drill estimates by Genel should be on the conservative side.]

Anastasia said he appointment of extra NEDs linked to the move to the main market but not surprisingly would not be drawn on a date. Chris is not on the Board so he felt he could not comment on the roles of the two additional NEDs yet to be appointed.

Have they finished the special core analysis?
We just got a specialist petrophysicist who has taken over the program. [Without that and insights from a spell of continuous production the question of what is the optimal way to produce Shaikan remains open. Chris said that everything is on the table.]

The Triassic was meant to be gas!
There is definitely some oil there. Chris explained that what they originally called the Triassic dolomite is quite thick in an offset well (Jabal Kand). DGA were able to use that information to calculate a rough volume at Shaikan. He said that hasn’t gone away it is just that GKP has found some more pay that they are calling the Kurre Chine C and they haven’t yet reached the dolomite.

[BTW the attached link indicates the Lower Triassic Geli Khana contains a gas generative source rock in the Jebel Kand area which would explain why DGA made a gas estimate for Shaikan Lower Triassic and Permian.

www.uni-sci.org/htmls/geo-m.Wuria%20Jihad%20Jabbar.doc

But note an earlier post of mine dated 22 August which indicated there is cause to believe the source rocks in the Shaikan Lower Triassic area should be in the oil temperature window. The question is whether the rocks are oil prone, oil and gas prone or gas prone.]

At what point will a reserves report be produced?
Not until we have a development report and some production.

Chris said GKP will use the 3-D to pick the best place for Sh-7 to get to the Permian

Anastacia said that Tony Hayward will be attending the conference that GKP is sponsoring in Erbil in November and she expects this may generate few stories. [Oh to be a fly on the wall at that one!]

The Inquisitor asked whether Genel would drill-test-drill on BB or drill to TD and test. Chris explained GKPs approach. GKP have had lot of problems with open hole testing and have had to repeat the tests. They know now that they can case and test. “We know we can treat the formation damage because have had success acidizing. “

[The reason for OH testing=((OH - Openhole Log
)) was to conduct a test before too much formation damage occurs from drilling. It was not clear to me which route Genel will chose. There tends to be more pressure to test as you go on a discovery well but it remains to be seen whether Genel will adopt that approach.]

For those of you who are also invested in PCI (or who might be thinking of do so) I asked Chris what he thought of the Dinarta Block immediately north of Akri Bijeel.
HKN have struck in an anticline to the north of Shaikan (Swara Tika) and he doesn’t see any reason why the Dinarta Block should not work for Petroceltic.


I had a concern as to whether the prolific Sargelu is missing in Sh-2 based on a DGA slide shown at the strategy presentation which suggested the top interval was the Alan formation. However Chris assured me that is not the case, and the Sargelu is present.

Finally we discussed the AB sale. He indicated that he did not know anything about a possible change in GKPs timeframe for the sale but did say that the longer GKPs stays in the block then assuming they make discoveries probably the value is going to go up.

OVERALL THOUGHTS
As far as the presentation went you lot were the investor equivalent of a hostile northern working men’s club where the audiences had a reputation for taking no prisoners lol! I think Chris was in the wrong place at the wrong time i.e. after a period of sp stagnation.

There was a fair smattering(Superficial or piecemeal knowledge:) of good news coming out of the Dublin/Manchester presentations. The overall activity level (up to 7 concurrent wells) is immensely impressive. Bekhme-1 will definitely be factored into the Akri Bijeel price. If MOL gets its act together there will be an opportunity for any new discoveries at Aqra-1 and Bakrman-1to be factored in also. Both wells should be drilling the Jurassic during Q2 2012. Although the well results may not be in the public domain, if the Jurassic has been logged GKP will be in possession of the logs and bidders will be made aware of the nature of any discovery under a confidentiality agreement.

Shaikan-7, although currently classed as contingent looks as though it will get the go ahead and with a larger rig and the appropriate well design we should get to the Permian picking up the Triassic dolomite on the way.

We did not learn much more about Sh-2 and Sh-4 it was rightly held tight by CG. Sh-2 may turn out not to have as much pay as Sh-1 but we already know it is prolific and has at least one Jurassic interval with a higher gravity oil than Sh-1. We already know Sh-4 is a spectacular well.

Chris made the comment that Shaikan 1 was the best well he had ever seen.
However this statement from the mid year report suggests he may have to revise this when Sh-4 is complete. Well logs and core data thus far in the mid to upper Jurassic show a massive oil column with net pay intervals of 278 metres, even better than those seen on Shaikan-1.

The continued delay in establishing consistent production remains a significant concern and importantly a lost opportunity to be acquiring production data from Shaikan. GKP has installed EWT equipment but an EWT is not being conducted! The key questions appear to be?

Has a suitable temporary chemical solution (H2S scavenger) been found to enable export?

Why would the KRG not permit a modest amount of export to proceed, e.g. 3-5000 bbl/d ? It is small beer in comparison to the total exports that have been permitted. Is it part of a strategy that no new fields will be placed on production to exert pressure on Baghdad?

Why hasn’t a modest continuous production to the domestic market been established?

Chris indicated that they are working within the parameters given to them. [It is safe to conclude that if they were allowed to produce every day there is no doubt GKP could do it.]

That’s all. I’m off to enjoy Gramacho and the Algarve

Regards and GLA,

Gramacho