reading pdf Rev 00 SECTION 1 INTRODUCTION & OBJECTIVES 1 1 1 Location of the TGT field The Te Giac Trang (TGT or White Rhinoceros) field is geographically located in the northern part of Block 16–1 in[.]
Rev: 00 SECTION INTRODUCTION & OBJECTIVES 1.1.1 Location of the TGT field The Te Giac Trang (TGT or White Rhinoceros) field is geographically located in the northern part of Block 16–1 in the Cuu Long Basin approximately 100km southeast of Vung Tau; 20km northwest of the Bach Ho Field and 35km west of the Rang Dong Field Figure 1-1 TGT Field Location Map The most northerly accumulation in TGT field (H1.1) straddles the 15-02/01 and 16-1 Block boundaries, but it is separated from Thang Long JOC's Hai Su Trang (HST) accumulation to the immediate north by a significant east-west fault, with throw in excess of 100 metres at reservoir depths Aside from the reserves within TGT Field, the selected development plan for TGT will also accommodate the future development of satellite fields nearby such as: Voi Trang, TGD, and HST Page: of 20 Rev: 00 1.1.3 Background on Hoang Long Joint Operating Company The current Contracting Parties in Block 16.1, with their respective interests, are as follows: x PetroVietnam Exploration and Production (PVEP): 41.0% x SOCO Vietnam Ltd (SOCO): 28.5% x PTT Exploration and Production (PTTEP): 28.5% x OPECO Vietnam Ltd: 2.0% 1.2.1 Exploration and Appraisal History Mobil acquired 3316 kms of 2D seismic over the centre of the block in 1974 Subsequently Geco shot 1713 kms of higher density 2D seismic data over the same area in 1978 Later in 1984 Vietsovpetro (VSP) acquired some 1714 km of 2D seismic data and shot a further 639 km of 2D data on the eastern side of the block in 1986 In 1989 VSP drilled 16-BV-1X (Ba Vi-1X) well on the eastern end of the Ngua O prospect to a Total Depth (TD) of 3463 mRTE within the Pre-Tertiary granite basement Numerous oil and gas shows were observed within the thin sands of the Tertiary section and also within the underlying volcanics Six DSTs were conducted and resulted in small flow rates of oil from the Lower Miocene (including 203 BOPD from DST#5 and 43 BOPD from DST#6) DST#6) The 16-BV-1X well location is illustrated in the figure below The Phase exploration period d ran from the 8th December 1999 to the 7th December 2002, with an extension granted until the 6th March 2003 HLJOC acquired 640 km2 of 3D seismic data in 2000 and drilled two exploration wells- 16.1-NO-1X and 16.1-VT-1X wells The locations of these wells are shown in Figure 12 below 16.1-NO-1X was drilled in May 2002 to a TD of 3684 mRTE in the Pre-Tertiary granite basement Extensive oil and gas shows were observed within the e Lower Miocene and Upper Oligocene sandstones below 2483 mRTE and also within the section of extrusive volcanic rock and granite basement The well encountered 42m of net oil pay (8.50m in Lower Miocene sandstones and 33.35m in Oligocene sandstones) A drill stem test (DST) was conducted within the underlying Pre-Tertiary Granite Basement interval and acheived an average oil rate of 251.5 BOPD after acidization and nitrogen lift 16.1-VT-1X was drilled in October 2002 to a TD of 2490 mRTE in Pre-Tertiary Granite Basement Significant oil and gas shows were observed within the Upper Oligocene sandstones below 1927mRTE to top of granite basement The well encountered a total of 23.70m of net oil pay: 4.54m in Lower Miocene sandstones and 19m in Upper Oligocene sandstones A DST conducted in Upper Oligocene Sandstones and Granite Basement achieved an average oil flow rate of 3846 BOPD through an 181/64-inch choke Page: of 20 Rev: 00 At the end of the Phase period d twenty percent of the original area on the western side of the block was relinquished The remaining area at the end of Phase was 2631 km2 During Phase 2, which ran from the 7th March 2003 to the 7th of December 2003 HLJOC drilled one appraisal well and one exploration well- 16.1-VT-2X and 16.1-VV-1X Figure 1-2 Exploration and Appraisal Map 16.1-VT-2X -VT-2X was drilled in February 2003 to a TD of 2530 mRTE within the Pre-Tertiary Granite Basement Low to intermediate gas shows were observed within the interval 1751 to 2131mRTE and poor oil shows were observed within the underlying Lower Miocene to Upper Oligocene section Three thin Upper Oligocene sandstones were interpreted as oil bearing with a total of only 1.5m of net pay No DST's were conducted in the well 16.1-VV-1X -VV-1X was drilled in March 2003 to a TD of 3759.5 mRTE within the Pre-Tertiary Granite Basement Several zones of oil and gas shows were observed within the Upper Oligocene sandstones and the PreTertiary basement section A total 41.46m of net oil pay was encountered in the Middle Tra Tan formation A DST conducted within the Pre-Tertiary basement produced 13 BO to surface, after acidization and nitrogen lift At the end of the Phase exploration period a further twenty percent of the original area of the block was relinquished from the western and northern sides of the block The area a remaining at the end of Phase was 1974 km2, as illustrated on the map below The Phase exploration period ran from the 8th December 2003 to 7th December 2005, but an extension was subsequently granted, from the December 2005 to December 2007 n 2004 HLJOC shot 462 km2 of 3D seismic data in the eastern part of the block and 577 km2 of 3D seismic In data in 2006 in the gap area located between the 2000 and 2004 3D seismic areas Between February 2005 and November 2006 HLJOC drilled three exploration wells and four appraisal wells (16.1-TGT-1X, 16.1-TGT-2X, 16.1-TGT-3X, 16.1-TGV-1X, 16.1-TGT-4X, 16.1-TGX-1X, and 16.1-TGT-5X) -TGT-1X resulted in the Te Giac Trang Field discovery It was drilled in June 2005 to a TD of 4478 16.1-TGT-1X mRTE in the Upper Oligocene Middle Tra Tan formation Extensive oil and gas shows were encountered, whilst drilling the Lower Miocene Upper Bach Ho formation and Lower Bach Ho formation sandstones Shows were also encountered in the Upper Oligocene Upper-Middle Tra Tan Formation DST#1 within the Upper Oligocene Intra D1 failed to flow although some 200 litres of green oil were reversed out of the test tools, and DST#2 within the upper part of the Intra Lower Bach Ho 5.2 achieved a maximum oil rate of 8377 BOPD plus 4.11 MMSCFPD of gas through an 80/64-inch choke -TGT-2X was drilled in January 2006 to TD of 3436 mRTE in the Upper Oligocene Middle Tra Tan 16.1-TGT-2X formation Extensive oil and gas shows were encountered whilst drilling the Lower Miocene Upper Bach Ho formation, the Lower Bach Ho formation sandstones and the Upper Oligocene Upper-Middle Tra Tan Page: of 20 Rev: 00 formation sandstones A total of 143m of net oil pay was subsequently interpreted from wireline logs DST#1, in the Upper Oligocene Upper Tra Tan formation achieved an average oil flow rate of 3301 BOPD plus 0.86 MMSCFPD of gas through a 52/64-inch choke DST#2, in the upper part of the Lower Miocene Intra Lower Bach Ho 5.2 sandstones achieved an average oil rate of 3980 BOPD plus 2.35 MMSCFPD of gas together with 1655.5 BWPD of water through a 52/64-inch choke DST#2rr achieved an average oil rate of 4345.3 BOPD plus 2.21 MMSCFPD of gas together with 1043 BWPD of water DST#3, in the lower part of the Lower Miocene Intra Lower Bach Ho 5.2 sandstones achieved an average oil flow rate of 7030.3 BOPD plus 5.08 MMSCFPD of gas through a 56/64-inch choke 16.1-TGT-3X was drilled in March 2006 to a TD of 3650 mRTE in the Upper Oligocene Middle Tra Tan formation TGT-3X encountered extensive oil and gas shows and 150m of net oil pay was interpreted from logs of the Intra Lower Bach Ho 5.1, the Intra Lower Bach Ho 5.2 and the Upper Oligocene A DST in i the upper part of the Intra Lower Bach Ho 5.2 sandstones, achieved an average oil flow rate of 8827 BOPD plus a gas rate of 5.43 MMSCFPD through an 88/64-inch choke Figure 1-3 Prospect Inventory 16.1-TGV-1X was drilled in May 2006 to a TD of 3926 mRTE in the Upper Oligocene C sequence No shows were encountered above the Oligocene C 27m of net oil pay were indicated by logs within the Oligocene C sequence 16.1-TGT-4X was drilled in August 2006 to a TD of 3537 mRTE in the Upper Oligocene Middle Tra Tan formation Moderate to good oil and gas shows were encountered in the ILBH 5.2, Oligocene C and D However, only 29m of net oil pay was interpreted from the log data DST#1, in the Upper Oligocene, achieved a maximum oil flow rate of 609 BOPD was attained through a 24/64-inch choke 16.1-TGX-1X was drilled in October 2006 to a TD at 3506 mRTE in the Upper Oligocene Middle Tra Tan formation 16.1-TGX-1X encountered some oil and gas shows while drilling at the top of Intra Lower Bach Ho 5.2 and a total of 303m of interpreted net sandstone reservoirs (14.4m net oil pay) in the Lower Miocene Upper and Lower Bach Ho formation, Upper Oligocene Upper Tra Tan formation sandstones No DSTs were conducted in this well 16.1-TGT-5X, was drilled in n November 2006 to a TD of 3405mRTE in the Upper Oligocene Middle Tra Tan formation Oil shows were encountered in both the Intra Lower Bach 5.2 and the Upper Oligocene Tra Tan C Page: of 20 Rev: 00 sequence Log analysis indicated some 52m of net pay in the 5.2 and C DST#11, in the Oligocene C sequence, tested 37.48º API oil at a maximum rate of 6098.5 BOPD with 2.07 MMSCFD of gas through a 80/64 inch choke DST#2, in the Intra Lower Bach 5.2 sequence, tested 40.93 ºAPI oil at a maximum rate of 8103.6 BOPD and 5.30 MMSCFD of gas through a 48/64 inch choke Between March 2007 and November 2007 HLJOC drilled five exploration wells: 16.1-TGC-1X, 16.1-TGD-1X, 16.1-TGH-1X, 16.1-TGL-1X and 16.1-VN-1X wells 16.1-TGC-1X was drilled in March 2007, was drilled to test four-way dip closure at the ILBH 5.2 level and a fault-bounded closure at the Oligocene C, in an axial basin position on the southern part of block 16.1 Poor to moderate oil shows were encountered in the lower part of the ILBH 5.2, plus moderate oil shows in the Oligocene C The well was not tested and plugged and abandoned on 9th May 2007 16.1-TGD-1X was drilled in April 2007 and focused on potential HPHT reservoirs within the Oligocene lower D and E and Oligocene F sequences The well was suspended on 20th August 2007 and re-entered in December 2007 16.1-TGH-1X was drilled in July 2007 to a TD at 3680 mRTE in the Upper Oligocene Upper Tra Tan formation The well encountered some oil and gas shows while drilling in the Upper Tra Tan formation and a total of 137.6m of interpreted net sandstone reservoirs (12.2m net oil pay) in the Lower Miocene UpperLower Lower Bach Ho formation and Upper Oligocene Upper Tra Tan formation No DSTs were conducted in this well 16.1-TGL-1X was drilled in August 2007, targeting the 5.2 and Oligocene C sands within their respective closures Good oil shows were recorded in the Oligocene C and the uppermost Oligocene D sequence Whilst logs suggested a total net pay of some 30 metres, MDT pressure data indicated the majority of these to be tight A DST in the Oligocene failed to produce The well was plugged and abandoned on 25th September 2007 16.1-VN-1X was drilled in September 2007 to a TD at 3130 mRTE in the Pre-tertiary Granite basement The well encountered some oil and gas shows while drilling in Lower Lower Bach Ho and Lower Tra Tan formation Volcanic/Granite Wash/Weather Granite and a total of 269.75 of interpreted net sandstone reservoirs (13.87m net oil pay) in the Lower Miocene Upper-Lower Lower Bach Ho formation and Upper Oligocene Middle Tra Tan formations The well was plugged and abandoned on 30th October 2007 1.2.2 TGT HIIP and Reserves Estimation The TGT field development area comprises a series of geologically similar, but separate, fault blocks with oil reserves mapped in both the Miocene and Oligocene Formations The total TGT 2P most likely OIIP estimate for Block 16-1 is approximately 219.3 MMbbl and the corresponding reserves estimate is 70.1 MMbbl The following tables are an extract from the approved TGT Reserves Assessment Report: Accumulations H1.1 + H1.2 Block (TGT-1X/TGT-2X) H2 Block (TGT-5X) H3 Block (TGT-4X) H4 Block (TGT-3X) Total Block 16-1: Table 1-1 Page: of 20 2P 153.9 7.5 1.3 56.6 219.3 3P 268.2 19.3 2.5 126.3 416.2 Summary of OIIP (MMbbl) for Te Giac Trang Field Accumulations H1.1 + H1.2 Block (TGT-1X/TGT-2X ) H2 Block (TGT-5X) H3 Block (TGT-4X) H4 Block (TGT-3X) Total Block 16-1: Table 1-2 1P 80.5 5.1 7.7 93.4 1P 26.4 1.5 2.6 30.4 2P 49.2 2.2 0.13 18.5 70.1 Summary of Reserves (MMbbl) for Te Giac Trang Field 3P 76.8 6.0 0.25 40.7 123.7 Rev: 00 14km 12km Proposed H1 WHP Location Proposed H4 WHP Location 2km radius ‘low’ ‘‘llo ow’ angle a n g le wells welllls Figure 1-4 TGT P2 Hydrocarbon Pore Volume (HCPV) Map b A small proportion of the OIIP in the H1.1 fault block overlapss the block boundary between Block 16-1 (operated by HLJOC) and Block 15-02/01 (operated by Thang Long JOC) Page: of 20 Rev: 00 The 2P mean volumetric estimates of the OIIP located in Blocks 16-1 and 15-02/01 for the Lower Miocene are: 93.92 MMbbl (95.91%) and 4.01 MMbbl (4.09%) respectively In the Oligocene C, there is no OIIP in Block 15-02/01 and 22.71 MMbbl in Block 16-1 The split for the total OIIP in the H1.1 fault block located in Blocks 16-1 and 15-02/01 is 116.64 MMbbl (96.68%) and 4.01 MMbbl (3.32%) respectively The proportions of OIIP in the H1.1 fault block in the two blocks, described above, have been agreed with TLJOC and documented in the TGT Reserves Assessment Report and a pre-Unitization Agreement is due to be approved during April 2008 Recoverable reserves estimates for the Miocene and Oligocene reservoirs have been calculated using recovery factors based on extensive reservoir simulation studies carried out in-house by Hoang Long JOC In addition to the TGT field, there iss another confirmed discovery in Block 16.1 called Voi Trang, which was first drilled in 2002 and further appraised with a second well in 2003 The quality of data available on Voi Trang is currently not considered sufficient to allow the submission of a Reserves Assessment Report, so a further appraisal plan has been submitted for Voi Trang There is a further prospect in Block 16.1 which is currently being evaluated with the TGD-ST1 well, and a number of other un-drilled prospects 1.3 Subsurface summary and conceptual depletion plan 1.3.1 Geological Summary The reservoirs within TGT include sandstones of the Lower Bach Ho Formation (Bl.1 Sequence) of Lower Miocene age, and the Upper and Middle Tra Tan formations (C and D Sequences) of Upper Oligocene age Informally at TGT the sandy lower interval of the LBH Formation has been historically sub-divided into the Intra Lower Bach Ho 5.1 (ILBH 5.1) and the Intra Lower Bach Ho 5.2 (ILBH 5.2) 5.2) Both the ILBH 5.1 and 5.2 were deposited in alluvial floodplain and shallow lacustrine environments Whilst a wide range of depositional sandbody types may be developed in this setting, the limited available core, plus many of the wireline-log motifs, suggest that the reservoirs are predominantly channel-fill, sheet flood and crevasse splay sands Cores cut in TGT-2X, TGT-3X and TGT-4X indicate that a significant portion of the upper 65-80m of the ILBH 5.2, (the e ILBH5.2 Upper) - which forms the most productive reservoir interval in the H1, H2 and H4 fault blocks - is marked by a basal transgressive unit, overlain by debris flows and hyperpycnal sands with high rock quality This event clearly marked an increase in water depth and a change in sand-body depositional architecture Since this lithological change is clearly identifiable on wireline logs in TGT-1X, TGT-2X and TGT-3X (and with lesser confidence in TGT-4X), a further sub-division of the ILBH 5.2 into ILBH 5.2 Upper (ILBH 5.2U) and ILBH 5.2 Lower (ILBH5.2L) has been made Regional geological information suggests that the e Oligocene C Sequence was deposited in a lacustrine environment with the development of fluvial sands Wireline-log motifs suggest both channel-fill (finingupwards) and progradational (coarsening-upwards) sandbodies A single core cut in the Oligocene C in TGT4X contains channel-fill sandstones with heavily bioturbated overbank mudstones, indicating an alluvial plain depositional environment No core has been cut to date in the Oligocene D Page: of 20