IOR drilling technologies


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  • En systematisk prosess med stor involvering. Tidsangivelsene sier når noe senest må være ferdig, men om en lisens ønsker å starte Maturation fasen tidligere enn 1. januar så kan de gjøre det. Statoil har også benyttet Sintef Kunne til å hjelpe oss i den Kreative fasen. Ende produkt kan være en liste av boremål som meldes inn til Brønnkonstruksjonsprosessen og Teknologi behov som meldes inn til F&U innmeldingen.
  • Quality – scale problematikk , injektivitet ( dette var vel aldri noe stort problem for injekstjon ppå statfjord)
  • Quality – scale problematikk , injektivitet ( dette var vel aldri noe stort problem for injekstjon ppå statfjord)
  • Figure on top shows the location of the compressor module (hanging beneath the flare deck). Figure on left shows the reserve growth on Kvitebjørn. After a re-modelling done in 2006, the reserve increased by almost 50% compared to the PDO volume. Pre-compression is the single most important IOR method to increase the reserves on Kvitebjørn. Figure at the bottom shows the latest prognosis of the base (natural depletion) and pre-compression profiles.
  • Copied from Terje Schmidts presentation Multilaterals : roughly 20 , 5 level 5 installed DIACS : Subsea 20 – Platform 18 TTRD : 14 PLATFORM – 2 SUBSEA (Norne 2005 - 1500 m sidetrack, GF Sør 2006) Light well intervention : 12 operations – 2006 campaign ongoing Sub sea separation : Tordis Sub sea pumping : Tordis Sub sea compression : Åsgard , being developed
  • Can be a large number of reasons for drilling sidetracks On the left: Example of existing well with water encroachment around existing wellbore Additional reserves identified in vicinity (isolated by faulting) Conventional options: 1. new well or 2. conventional sidetrack (remove existing completion, re-use only upper part of well) Both alternatives very expensive and can easily be cost prohibitive depending on volume of remaining oil. On the right: Through tubing option. Leave existing completion in place. Re-use majority of existing well. Save time and money. Environmental benefits as well: materials and chemicals usage a fraction of conventional scenarios TTD not new in the industry or Statoil. Over 30 wells drilled by Statoil – primarily in platform wells. What we are discussing today is the Statoil strategy and actions to develop the technique and extend the application – particularly to subsea wells
  • Now looking at a subsea scenario. The cost implications of conventional technques are even more dramatic and benefits and potential for TTDC even greater in contrast. Large proportion of Statoil production coming from subsea wells this is a key forcus area for the company. Scearios from left to right indicate a progression in time and technical solutions Conventional sidetrack – conventional drilling unit Through tubing sidetrack – still using conventional non-optimised rig Introducing fit-for-purpose ’lighter’ solutions – Category B rig and riser that will be discussed in next slide The effect of introducing fit-for-purpose technical solutions is that the cost per operation can be signficantly reduced making it economical to pursue smaller and smaller targets As dedicated organisational capacity and equipment is implemented – learning curve advantages are realised – efficiency increases even more and even smaller targets can be harvested
  • Now look at technology required to establish a safe and efficient work platform and access to subsea wells for through tubing work 1st look at what we in Statoil call the Category B or ”Cat B” rig (and yes that is somewhere between a light Cat A system and a heavy Cat C or C drilling unit). In contrast to a conventional drilling unit the Cat B is relatively small and configured specifically for through tubing operations – in fact all types of production and injection well management in addition to TTDC. Able to handle live well operations. In addition to mooring dynamic positioning is available as an option for better efficiency on shorter duration operations. Cat B is work in progress with technical feed studies nearing completion and a commercial tender to be completed (and contract awarded) before the end of yr. Take a look at the riser system connecting the rig to the well. This provides both well access and key well control functions. Statoil have been intimately involved in developing a unique riser system for Cat B operations over several years – unique in that it can be used for both TTDC and live well intervention operations with a minimum of re-configuration. As you can see from pictures this equipment already exists and has been used for two TTDC wells that were drilled during the winter of 2009/2010. Those operations were conducted from the Stena Don drilling unit.
  • As well as an efficient working platform and well access Statoil have also identified development areas for downhole tools and technology required to improve and expand TTDC applications. Illustrated here are 3 examples at different stages of implementation: Protection of the existing completion equipment during the TTDC operation is essential. A customized system compatible with Statoil wells has been developed and is now implemented on all TTD operations Drilling systems suitable for the size and directional path of holes being drilled and at the same time compatible with subsea well configurations have been developed and already successfully tested on several wells (including the example give on the next slide). Multi-lateral junctions providing mechanical and hydraulic integrity have been developed. These will allow combined production and access from/to the existing and new wellbore providing increased flexibility when planning these operations. This technology is now available and awaiting the first field trial.
  • As mentioned there were 2 subsea TTDC wells drilled during last winter – 1on Åsgard field and one on Norned field. This was the first field trial of the new riser system – as well as being challenging operations in their own right. Despite the challenges – good planning and operational focus led to both wells being completed successfully. The graphic here indicates the well path that was drilled on the Åsgard well. 2 producing zones Upper one easy Lower zone with several targets – cleared 4 out of 5 World record length Most important – well production came in over expectations delivering a commercial success. Increased oil recovery.
  • SDL can handle issues such as tight hole, hole collapse, difficulties to get liner to TD etc.. SDL potential in 2009: Reduce Non-Productive Time with 320 MNOK on the Norwegian Continental Shelf for 12 ¼” sections alone
  • IOR drilling technologies

    1. 1. Improved Recovery (IOR) in Statoil Improved recovery through drilling and well technologies Terje Schmidt, Alastair Buchanan, Morten Eidem
    2. 2. Annual Process Idea Phase 1 Oct 1 Mar 1 May 1 Jun 1 Nov 1 Jan Preparation Idea Maturation Project Product to Capture IOR Ideas & Projects across Statoil
    3. 3. IOR techniques identified in 2010
    4. 4. Water injection improvements <ul><li>How can rapid water break through to producer be controlled? </li></ul>
    5. 5. Water injection assisted by EOR chemicals <ul><li>Areal and vertical sweep </li></ul><ul><li>Displacement efficiency </li></ul><ul><li>Injection water quality </li></ul>EOR = Enhanced Oil Recovery with a potential of 6%
    6. 6. Low Pressure & Pre-compression <ul><li>117bar: Expected recovery factors: 60% for gas and 41% for condensate </li></ul><ul><li>37 bar: Increase gas recovery factor to 75% and condensate recovery factor to 45% </li></ul>0 20 40 60 80 100 120 140 160 PDO (2001) Reserve upgrade (2006) Precomp stage 1 (cut-off 2045) Precomp stage 2 (cut-off 2045) Precomp stage 1 & 2 (after 2045) Reserves, MSm3 o.e. Production potential from pre-compression Compressor module 117bar 37bar 15bar
    7. 7. Extensive IOR recovery “toolbox” used by Statoil <ul><li>Pressure depletion </li></ul><ul><li>Water & Gas Injection </li></ul><ul><li>Microbial </li></ul><ul><li>Chemical & Thermal methods </li></ul><ul><li>Horizontal wells </li></ul><ul><li>Multilateral & Advanced wells </li></ul><ul><li>Liner Drilling </li></ul><ul><li>Managed pressure drilling (MPD) </li></ul><ul><li>Through tubing drilling (TTRD) </li></ul><ul><li>Well Intervention </li></ul><ul><li>Topside or Subsea </li></ul><ul><li>Processing & Compression </li></ul>
    8. 8. Through Tubing Drilling and Completion
    9. 9. Why through tubing drilling & completion - Classification: Internal 2010-08-25 Example: Watered out well ” New” TTDC well Remaining oil
    10. 10. Taking the technology subsea < 300 kSm3 < 100 kSm3 < 50 kSm3 Additional reserves Enabled by new technology and methods = IOR
    11. 11. The Statoil Category B initiative (Cat B) Lightweight HP riser system (through tubing) Full DP or mooring assisted station keeping options Topside system sized for through tubing operations (2⅞” & 3 ½” drillpipe) Integrated high capacity coiled tubing package (2 ⅞” / 3 ½”) Full handling of live well returns Semi-submersible rig hull type
    12. 12. Downhole technology developments
    13. 13. Work in progress – delivering results A world record 1744 m through tubing sidetrack TVDMSL T1 T2 T3 T4 T5
    14. 14. Steerable Drilling Liner
    15. 15. <ul><li>Conventional drilling </li></ul><ul><ul><li>Liner has to be run separately after the wellbore section is drilled </li></ul></ul><ul><ul><li>Wellbore is not secured until the liner is installed </li></ul></ul><ul><li>SDL drilling </li></ul><ul><ul><li>Simultaneously drill and secure </li></ul></ul><ul><ul><li>Wellbore always secured </li></ul></ul>This is Steerable Drilling Liner
    16. 16. More cost effective drilling <ul><li>Allow simultaneous drilling and lining of the borehole </li></ul><ul><ul><li>Mitigate challenges with unstable formations </li></ul></ul><ul><ul><li>Reduce Non-Productive Time </li></ul></ul><ul><li>Improved well construction efficiency is crucial for increasing production rate and recovery </li></ul>
    17. 17. Steerable Drilling Liner development <ul><li>May 2006: Tender - Baker Hughes submit project proposal </li></ul><ul><li>December 2006: Project initiated </li></ul><ul><li>August 2008: 9 5/8” full scale field test </li></ul><ul><li>April 2009: 7” full scale field test </li></ul><ul><li>August 2009: Worlds first offshore test performed on Brage (9 5/8” liner) </li></ul><ul><li>January 2010: Offshore test executed on Statfjord (7” liner) </li></ul><ul><li>March 2010: Commercial state </li></ul>
    18. 19. Future “One-trip” Steerable Drilling Liner <ul><li>Drill liner in place and cement in one run </li></ul><ul><li>Improve drilling robustness </li></ul><ul><li>Reduced well construction time </li></ul>Most efficient measure to keep up the production level and increase the recovery Yearly value creation for a “one trip” system fully implemented on the Norwegian Continental Shelf is estimated to NOK 2 billion / year
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