| DECEMBER 2001- RELEASES |
| ACTIVITY UPDATE (31-12-01) |
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· Saltfleetby-6 flows 9 MMSCFD with up to 21 BBLS/MMSCFD condensate. 1 Saltfleetby-6, Onshore UK (ROC: 100% and Operator) Saltfleetby-6 has flowed gas at a rate of 9.0 MMSCFD with up to 21 BBLS/MMSCFD condensate. The well is a long reach, appraisal/development well, drilled into the field's previously undrilled southern culmination, from an existing surface production facility. Initial pressure measurements suggest that the gas-bearing sands at Saltfleetby-6 are at, or close to, original reservoir pressure which is consistent with the reservoir model now being used to develop the field. It is anticipated that the well will be brought on to full production during January, 2002. Commenting on the well results ROC's CEO Dr John Doran said: "This
is a very good result because Saltfleetby-6 has long been recognised as
the riskiest appraisal well yet drilled in the field. It should boost
field production in a few weeks time and positively impact field reserves."
2 Cliff Head-1, Offshore Perth Basin, Western Australia, (ROC: 30% and Operator) Roc Oil (WA) Pty Ltd, Operator for and on behalf of the WA-286-P Joint Venture, advises that the Cliff Head-1 exploration well reached Total Depth of 1499 m on 29 December, 2001, five days after spudding. Log interpretation indicated an oil column between 1278.5 and 1283.5 metres below rotary table (mBRT), immediately below the Kockatea Shale which constitutes the regional seal. A fluid sample obtained from this five metre interval confirmed the presence of oil. The excellent reservoir quality, which is better than expected, has encouraged the Joint Venture to further evaluate the commercial significance of the discovery. By 00:01 hours (Western Standard Time) on 31 December the Cliff Head-1 well was in the process of being plugged back to the 13 3/8 inch casing shoe at 403 mBRT and preparations were underway to drill a sidetrack hole to intersect the oil bearing reservoir at a higher structural elevation with a bottom hole location approximately 1.0 km to the north northeast of the surface location. Revised mapping of the prospect, incorporating the Cliff Head-1 data, indicates that there could be in excess of 70 MMBO in-place updip from the discovery. It is estimated that it will take 10 days to drill the sidetrack well and evaluate the structure's updip potential. The WA-286-P
Joint Venture is comprised of: -
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"It is encouraging that an exploration well in the offshore Perth Basin can go from spud to Total Depth in five days and drill a five metre oil column in an excellent quality reservoir en route. However, the primary purpose of Cliff Head-1 was to find commercial amounts of oil and not simply to confirm a novel exploration concept and that is why the Joint Venture is now focussed on immediately appraising the commercial significance of this discovery."
Dr John Doran |
| ACTIVITY UPDATE (28-12-01) |
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· Cliff Head-1 well drilling ahead at 660 metres BRT Roc Oil (WA)
Pty Ltd, Operator for and on behalf of the WA-286-P Joint Venture, advises
that at 0600 hours on 28 December 2001 (Western Standard Time) the Cliff
Head-1 well was at a depth of 660 metres BRT and drilling ahead in 216
mm (8½ inch) hole. For the Cliff Head-1 location refer to the map
on Attachment
1. The WA-286-P
Joint Venture is comprised of: -
---------------------------------------Equity
Dr John Doran |
| ACTIVITY UPDATE (27-12-01) |
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· Ensco-56 rig arrives at Cliff Head-1 well site. Well spudded. Conductor
pipe and surface casing set. Preparing to drill ahead. 1 Cliff Head-1, Offshore Perth Basin, Western Australia, (ROC: 30% being earned and Operator) Roc Oil (WA) Pty Ltd, Operator for and on behalf of the WA-286-P Joint Venture, advises that the Ensco-56 jack-up drilling rig arrived at the Cliff Head-1 well site on 24 December 2001 (refer to ROC's release to ASX dated 17 December 2001). The Cliff Head-1 well was spudded at 0600 hours on 25 December 2001 (Western Standard Time) and 660 mm (26 inch) hole was drilled to 75.5 metres below the rotary table (mBRT), where 508 mm (20 inch) conductor pipe was set and cemented. The well was then drilled to 403 meters mBRT in 445 mm (17 ½ inch) hole where 340 mm (13 3/8 inch) casing was set and cemented. At 0600 hours (Western Standard Time) on 27 December the operation was installing BOP equipment at surface in preparation for drilling ahead.
The WA-286-P
Joint Venture is comprised of: -
---------------------------------------Equity
2 Saltfleetby-6, Onshore UK (ROC: 100% and Operator) Saltfleetby-6, a long reach, relatively high risk, appraisal/development gas well drilled into the field's southern culmination from an existing surface production facility, has been completed for production. After a brief clean-up flow, expected to take place later this week, it is anticipated that the well will be brought on to full production during January.
3 3D Seismic Survey, deep water Block 7, Offshore Mauritania (ROC: 2.0%) Acquisition
of a 1360 sq km 3D seismic survey in Block 7 was completed on 20 December.
The survey, which commenced on 15 November 2001, was acquired with the
PGS Ramform Valiant vessel. The data will be processed by Veritas in its
London processing centre. Dr John Doran Return to ASX Releases main page |
| UK ASSET UPDATE AND OPERATORSHIP AWARD IN ANGOLA (19-12-01) |
|
KEY POINTS UK
ASSET UPDATE
CABINDA
SOUTH BLOCK, ANGOLA
1. ONSHORE UK 1.1 Saltfleetby Gas Field, South Humber Basin (ROC: 100% & Operator) The appraisal/development well, Saltfleetby-6y, is currently being completed as a gas producer from the main Westphalian reservoir in the previously undrilled southern culmination of the Saltfleetby Gas Field. Saltfleetby-6y has drilled approximately 200 metres of horizontal and near horizontal gross section through the main gas reservoir of which approximately 120 metres represents net gas pay. The well is approximately 1.8 km south of the main part of the Saltfleetby Field (Attachment 1). Because it is drilled as an extended reach well from an existing production site, Saltfleetby-6y will be brought on to production very quickly, probably during January 2002. The "punch-through" portion of the well, confirmed 22 metres of vertical gross gas column, of which 16.5 metres represents good quality net gas pay. The Saltfleetby-6y production hole was drilled into the southern culmination updip from the punch-through. Reservoir quality in Saltfleetby-6 and the sidetrack Saltfleetby-6y has been confirmed by electric logs as being comparable to the best seen previously in the field. This is a particularly good result because, prior to drilling, the Saltfleetby-6 well and its associated, pre-planned, sidetracks were regarded by ROC as carrying higher appraisal/development risk than the other wells drilled in the field. One of the most important - and potentially very positive - aspects of Saltfleetby-6 is that it is the first well to encounter a GWC. Because none of the previous five wells in the field identified an unequivocal GWC, field reserve estimates have been necessarily based upon assumptions as to where that contact might be located. Previous drilling had confirmed gas down to 2,313 metres and the reservoir model used to date had assumed that the GWC was at 2,319 metres, 6 metres deeper than the lowest known gas. Saltfleetby-6 has demonstrated that the GWC, at least in the field's southern culmination, is at 2,338 metres, 25 metres deeper than the previous lowest known gas and 19 metres deeper than the GWC previously assumed for the field. It is not, however, known if the GWC now established in the field's southern culmination can be extrapolated across the entire field or whether it is confined to the southern culmination (Attachment 2). The potential
extent of the GWC established by Saltfleetby-6 will be considered as part
of ROC's routine end-of-year review of its Company-wide reserves, though
full re-building of the geological model to take account of the information
gleaned from Saltfleetby-6 and -6y will not be done until after production
from Saltfleetby-6y has been monitored for some time. If, in the fullness
of time, it is considered that the GWC in Saltfleetby-6 is likely to be
the same throughout the field area then that interpretation, combined
with the newly established net gas pay in the southern culmination, will
go some way towards increasing remaining reserves to offset actual production
in 2001. By the end of 2001, Saltfleetby will have produced almost 29
BCF gas and 540 MMB condensate since first production in December 1999
(Attachment
3). 1.2 Other Areas Onshore UK (Generally ROC: 100% & Operator) Apart from its production operations at Saltfleetby, ROC's activities onshore UK are focussed on exploring the surrounding South Humber Basin. Acquisition of two 3D seismic surveys, together totalling 400 sq km, originally scheduled to begin in early 2001, but deferred due to the outbreak of Foot and Mouth Disease, is now expected to start in January 2002. The prime purpose of the surveys, which, collectively, is the largest 3D seismic project undertaken onshore United Kingdom, remains unchanged: the generation of attractive drill targets from the prospect and leads inventory which ROC has compiled on the basis of pre-existing, mainly 2D, seismic data. This A$10 million 3D seismic survey will represent a major 2002 exploration investment for ROC. ROC has also
identified other areas of interest within its onshore UK portfolio, some
of which may merit consideration for drilling in their own right during
2002. However, the Company's strategy is to assemble a comprehensive inventory
of many different drill targets between now and late 2002, with a view
that the preferred prospects will then be drilled as part of a multi-well,
back-to-back, exploration drilling campaign which is expected to start
in about 12 months time.
2. UK NORTH SEA 2.1 Kyle Oil Field (ROC: 12.5%) The Kyle Oil Field came onto production in April 2001 after a somewhat chequered development history, particularly during the preceding two to three years. To date, the field's cumulative production is in the order of 5.5 MMBO. Kyle is currently producing at rates in the range 12,000 - 15,000 BOPD from the Cretaceous Chalk and Palaeocene sand reservoirs. The third, and most recent, producing well came on stream in November 2001 and produced at an initial rate of up to 8,500 BOPD from the shallower Paleocene reservoir, with a lower gas-oil ratio than the two oil producers completed in the underlying Cretaceous Chalk reservoir. Kyle oil is transported via the Maersk-owned Curlew Floating Production, Storage and Offloading facility ("FPSO"), while gas is sold to Shell-Esso and exported via their SEGAL pipeline system to shore at St. Fergus. There are
a number of different scenarios which could be applied to the further
development of the Kyle Field, including the possibility that one or two
additional wells would be drilled during 2002. However, the details of
future field development depend upon at least five factors, namely the
Joint Venture's evolving technical understanding of the nature of Kyle
production; the operating costs of the field; the capacity of the production
facilities to handle associated gas production; the potential receipt
of third party tariffs and the perception of future oil price trends.
To a large extent, these same factors influence the determination of the
commercially recoverable reserves at Kyle which is an exercise that will
be undertaken during the next month by an Independent Expert as part of
ROC's routine review of its year-end reserve inventory. The drilling during February to June 2001 of the 22/2a-11x well on the Chestnut Field proved to be something of an engineering challenge, but the end result of the EWT was satisfactory. The well and associated EWT were fully funded by third parties; initially Brovig Production Services and, subsequently, Amerada Hess Limited, who joined the Joint Venture during the drilling of the well and became the new field operator. One hundred and fifty-nine days after the commencement of drilling, EWT production started and a total 1.05 MMBO and 0.9 BCF of gas were produced during the subsequent 124 day testing period, which included some weather downtime. It appears that the EWT well is optimally situated near the crest of the field (Attachment 4). It is anticipated that a significant amount of the field's reserves will be drained by this well, particularly if, as is presently envisaged, a water injection well is drilled as part of Phase Two of the Development Plan. Details of the potential development are currently being reviewed as the new operator tries to identify the optimum development option. One of a number of alternatives is to transport the oil through one of the several fixed platforms which exist in the Chestnut area. This approach would likely delay full field production until early 2004, but it would also offer a potentially more commercially attractive alternative to developing the field via an FPSO which, typically, would have a higher operating cost. As with ROC's
other North Sea fields, the commercially recoverable reserves at Chestnut
will be subject to a thorough re-evaluation in the light of the most recently
obtained production data as part of ROC's routine year-end reserve review
which is scheduled to be completed during January 2002. The mid-2001 Buzzard discovery, which is near to ROC's Ettrick area licences, is potentially the largest oil find in the UK North Sea for more than ten years (Attachment 5). Published statements by the Buzzard co-venturers indicate that drilling within the field has already established recoverable reserves in the order of several hundreds of millions of barrels. The Buzzard discovery, highlighted the untapped exploration potential which still exists in this region and strongly implied that the area's production infrastructure will be greatly improved during the next several years. ROC holds
varying interests in three exploration areas east of the Buzzard Field,
including the Ettrick Field where Enterprise has recently been appointed
operator. The combination of this change of operatorship and the Buzzard
discovery has created renewed industry interest in the Buzzard-Ettrick
area. As a result of this upsurge in enthusiasm, an exploration well is
proposed to be drilled in 2002 to test the Squirrel Prospect in block
20/7a. This prospect is similar in concept to the Buzzard Field 15 km
to the west, although it is somewhat smaller (Attachment
5). This field,
which straddles the UK-Norwegian international boundary, has also been
subject to renewed joint venture interest as a result of the Enterprise
acquisition of Petrobras. The new operator, Enterprise, has been able
to bring unique insights to the area by virtue of its participation in,
and operatorship of, nearby acreage and fields, including the Pierce Oil
Field, 30 km to the north of Blane. During 2001, relevant parties with
interests in the Blane Field, both on the UK and the Norwegian side, have
reviewed various options with the objective of appraising and, if appropriate,
developing, the field in an optimum and timely manner. As a result of
the progress which has been achieved, ROC expects the first Blane appraisal
well to be drilled during 2002, and for this well to be designed as a
future producer. The intention is to establish whether a tilted contact
exists thereby greatly enhancing the potential commercial development
of the field. The Enoch and J1 licence area has also undergone a change in operator from Petrobras to Enterprise. Recent reviews of the two discoveries have confirmed the geological models, allowing the further consideration of development possibilities. It is clear that J1, a high pressure, high temperature, gas condensate discovery has little synergy with Enoch and that the development scenarios are likely to be independent of each other despite their close proximity. An evaluation of the upside exploration potential of the area is being undertaken by the operator. Development
of Enoch and J1 will probably require subsea tie-backs to nearby infrastructure.
The new operator is currently building a base case for development planning,
initially for Enoch then J1, in conjunction with a full exploration review
of the block and generation of a prospect inventory. This work is aimed
at an EWT on Enoch during 2003 and first oil from a full field development
by 2004. Commenting on ROC's UK activities, the Company's CEO, Dr John Doran stated that: "The Saltfleetby Gas Field continues to demonstrate that it is ROC's core asset in the UK. Production continues to exceed expectation and current field decline is modest while the results of the latest drilling at Saltfleetby-6 open up the possibility that ROC's current recoverable reserve estimate may, not for the first time, prove to be somewhat conservative. With Saltfleetby as a stunning case history, it is hard not to be enthused about the exploration potential of the surrounding South Humber Basin which has received very little 3D seismic coverage to date and only very sparse exploration drilling. Now that the unfortunate delay in acquiring 3D seismic, caused by the Foot and Mouth outbreak, appears to be behind it, ROC is champing at the bit to get on with exploring the region around Saltfleetby, all of which is 100% owned and operated by the Company. ROC's participation in the UK North Sea has provided it with a bittersweet experience. The delay in bringing the Kyle Field into production was extremely frustrating, although initial field production rates in excess of 20,000 BOPD went some way towards compensating for the delay. There were also some interesting moments during the drilling phase of the Chestnut EWT well although, once again, the end result, including flow rates in excess of 15,000 BOPD from the single well, have helped to offset the concerns. The likely delay in achieving first oil from the Chestnut Field to early 2004 is logical since it is designed to maximise the value of the asset, and, as such, ROC considers it to be in the best longer term interests of the Company. ROC
is also pleased that Enterprise, the new operator of the Ettrick, Blane
, Enoch and J1 undeveloped fields, wishes to fully and quickly explore
and appraise the potential of these fields and associated prospects.
3. ONSHORE ANGOLA (CABINDA) 3.1 Onshore Cabinda South Block (ROC: 45% and operator) ROC wishes to advise that Sonangol, the National Oil Company of the Republic of Angola, has formally approved the transfer of operatorship of this Block from Fina Oil and Gas Cabinda BV (an affiliate of TotalFinaElf) to ROC. The transfer takes effect from 13 December 2001. Details of ROC's interest in the Cabinda South Block are set out in the Company's release to ASX issued on 18 October 2001.
Dr John Doran |
| ACTIVITY UPDATE (17-12-01) |
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KEY POINTS · Assignment of drilling rig for Cliff Head-1 wells ROC, on behalf of the WA-286-P Joint Venture, advises that the Ensco-56 drilling rig was taken under assignment from Apache Energy Limited on 17 December 2001 for the Cliff Head-1 well. The rig is currently under tow with an estimated arrival date at the Cliff Head-1 well site on or about the last week of December, subject to weather. Refer to the Cliff Head-1 location map. The WA-286-P
Joint Venture is comprised of: -
---------------------------------------Equity
Dr John Doran |
| ACTIVITY UPDATE (13-12-01) |
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KEY POINTS · Saltfleetby development drilling confirms gas sands 1. DEVELOPMENT DRILLING 1.1 Saltfleetby Gas Field, Onshore UK (ROC: 100% and Operator) The Saltfleetby-6z development well, which was side tracked after the original punch-through Saltfleetby-6 well had confirmed the presence of gas-bearing sands, has set 5½ inch casing to 3,051 metres. A further sidetrack development well, Saltfleetby-6y, then commenced drilling and at 0600 hrs (UK) time on 12 December 2001 was being drilled in 4¾" hole at a depth of 3,120 metres. Encouraging gas shows and clean sand have been encountered. Current hole inclination is 83 degrees. The forward plan is to build angle to horizontal and then conduct a turn in azimuth to the west. Following completion of the well and subject to final well results, a short flow test will be conducted to clean up the gas stream prior to the well being tied into the gas export system during January 2002. 2. EXPLORATION 2.1 WA-286P, Offshore Western Australia (ROC: 30% and Operator) Preparations
continue for the Cliff Head-1 exploration well, which is expected to start
drilling prior to the end of the month, subject to rig availability and
weather conditions. A 1,350 km 3D seismic survey, operated by UK-based Dana Petroleum plc, is underway offshore Mauritania. At 11 December 2001 approximately 1,160 sq km of data had been acquired. The survey is estimated to be completed by 18 December 2001.
Dr John Doran |
| ACTIVITY UPDATE (06-12-01) |
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SUMMARY · Saltfleetby-6z development well reaches top of reservoir target 1. DEVELOPMENT DRILLING 1.1 Saltfleetby Gas Field, Onshore UK (ROC: 100% and Operator) At 0600 on 5 December 2001 (UK time), the Saltfleetby-6z development sidetrack had reached the top of the target reservoir at 3,171 metres. Current hole inclination is 81 degrees. Five and one half inch casing will be run and cemented prior to drilling the reservoir section of the well at a near horizontal angle. Total depth of the horizontal section is anticipated at 3,340 metres. 2. EXPLORATION 2.1 WA-286P, Offshore Western Australia (ROC: 30% and Operator) Preparations
continue for the Cliff Head-1 exploration well, which is expected to start
drilling in late December 2001 with the precise start date subject to
rig availability. The 1,523 km 2D seismic survey was completed on 3 December 2001. The seismic data acquired from the survey is now being processed. 2.3 Block 7 Offshore Mauritania (ROC 2%) A 1,350 km 3D seismic survey, operated by UK-based Dana Petroleum plc, is underway offshore Mauritania. At 4 December 2001 approximately 827 sq km of data have been acquired.
Dr John Doran Return to ASX Releases main page
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| ACTIVITY UPDATE (04-12-01) |
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Due to a rearrangement of the Joint Venture exploring Area C (Blocks 2 and 6) offshore Mauritania, ROC's equity will increase in these areas as follows: · BLOCK 6 Roc Oil (Mauritania) Company a wholly owned subsidiary of ROC, will increase its equity from 2.5% to 5% in Block 6 where an exploration well, Thon-1, is expected to drill in the latter part of 2002. Because of continuing farmout arrangements, ROC will only be required to fund 3.75% of the cost of Thon-1. · BLOCK 2 There is no change to the 2.4% equity which ROC holds in Area B where the Chinguetti-1 oil discovery was made earlier this year. That equity is held by Elixir Corporation Pty Limited a wholly owned subsidiary of ROC. It is anticipated that the Chinguetti discovery will be appraised during the latter part of 2002.
Dr John Doran Return
to ASX Releases main page
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