Sirius Petroleum Share Discussion Threads

[drrichard] 20/9/2016 20:49

Excellent Sherlock. If we cannot make this work with the team we have assembled then no-one can. As DrRosso pointed they appear to have made some savings on the original ideas for their FDP.
Cannot believe that Rockflow would have cited our BoD's plans if they were not confident they could not be implemented.

[sherl0ck] 20/9/2016 20:36

This is what I think the CPR is saying in connection with our proposed development plan:

D1, D2 & D3 reservoirs could be extensive but we need to run some fairly straightforward tests to determine flow rates etc. D4 & D5 are gas. F will be left alone and G will produce oil but only via Ororo 2. It's likely that out of the two oil zones that flowed in 1986 - D3 & G, the latter was the one with the 2k flow rate and may have been chosen as the 'banker' that we know will provide immediate cash-flow, while more appraisal work is required on D1-D3.

G only being targeted by Ororo-2 does seem to infer that it isn't the largest reservoir and D1, D2 & D3 are likely to be potential key target areas for additional Ororo wells if we proceed with full field development.

Oddly there's no mention at all of the deeper sands? Perhaps this was left out for now due to more circumstantial evidence based on other nearby fields and maybe for funding purposes the CPR had to very strictly focus on what can currently be determined. The deeper sands are critical however so I expect to see these figure once we have full details of any drill programme. If we have already secretly evaluated these somehow, I guess the info will only be revealed when the time is right. Rockflow admitted that the CPR was based purely on the data Sirius provided them with.

Dual lateral wells (multilateral) with horizontal bores that can really maximise flow in each reservoir will be utilised for field development rather than single vertical wells. This is essentially one borehole with twin lateral branches that can either target completely separate reservoirs or increase the contact area in the same reservoir. Whilst normally around 1.5x more expensive to drill than a standard well, you'd obviously expect improved overall flow rates and better field economics due to reduced flow lines and surface facilities such as platforms.

Whilst the wording is slightly ambiguous as to whether Ororo-2 will actually be single or multilateral (I'm guessing the latter), it appears that for $31.7m (£25m) we get a well which allows further investigation of D1, D2 & D3 before being drilled deeper for the extended well test and production of oil from G.

We also get what is likely to be Ororo-3, a completely separate well to simultaneously obtain gas production from both D4 & D5. It's not completely clear whether this one will also be a multilateral well with two branches in each D zone or a single well with independent dual casing perforations to allow hydrocarbons to flow into the well from both reservoir areas.

The extended well test (EWT) on G, whilst adding to costs, provides valuable real-time production data ahead of any more permanent facilities. It's typically utilised to reduce uncertainties inherent in marginal fields, better assess reservoir boundaries & characteristics (this is where the extra time afforded by the EWT and the skills of the geologist and their technical analysis of data really comes into play) and help further prove up reserves over a longer test period, which could be anything from a month up to a year.

EWT bridges the gap between traditional appraisal testing from multiple wells and full field development. Often the result of EWT is a reduction in the number of appraisal wells required prior to committing to full field development, so potentially major cost savings.

It's also very useful for cash flow purposes due to the resulting oil off-take, thus immediately helping offset capex - particularly with our preferential cost recovery rates. Whilst it appears that G will produce anyway, the promise of almost immediate revenues would likely help with funding discussions and might specifically underpin the Board's comments about service providers covering upfront costs and clawing these back from resulting revenues. If Ororo-2 was only an appraisal well and production was planned for further down the line, this might be trickier.

Whilst there's no mention at all, it would also seem sensible before or after the EWT to send the drill bit into the deeper sands and evaluate these since it could significantly impact reserves and be crucial to help determine further field development plans. I can't imagine for a second that Ororo-4 & Ororo-5 would be planned to solely target D1-D3 whilst still having done no further evaluation of the deeper sands that have significantly elevated the volumetrics of neighbouring fields.

The use of a conductor supported platform (CSP) appears to be more cost-effective due to it's minimal design, eliminating the need for an expensive jacket structure and more rapid installation (no costly mobilisation of heavy-lift vessels required). As such it's often touted as an ideal solution for shallow water marginal wells. They're normally unmanned and exclude extensive processing facilities, which could just be handled by the barge. It's also a flexible solution as additional conductor legs can be added to aid production capacity should well count increase.

I'm no expert by any stretch of the imagination but overall it seems to me that we're going to get a lot of 'bang for our buck', especially in the current low services cost environment. I really like the principles behind the multilateral wells, EWT and CSP. We seem to be cost effectively using proposed funding in a way that maximises appraisal work whilst also delivering immediate cash & oil flow. The former probably helps mitigate a financier's risk while the latter probably aids our credibility as a technical expert, and potentially a quality operator.

If we're not going to be taken over more imminently or form a JV with a recognised partner, doing a really good job on Ororo will be a crucial stepping stone to unlocking more funding and being allowed to tackle some of the bigger assets.

[bronislav] 20/9/2016 20:09

Would love to have a peep at the real options valuation carried out by the Greek professor.

[dr rosso] 20/9/2016 19:46

Executive Summary
Sirius Petroleum holds a 40% working interest in the Ororo Field Licence in Nigeria, which is located 6km offshore of the western Niger Delta in 25 feet of water. Hydrocarbons were discovered in seven sandstone reservoirs (D1 to D5, F and G) in Ororo-1 drilled by Chevron in 1986. Four of the reservoirs were tested, two produced oil (D3 and G) and two produced gas condensate (D4 and D5). Wireline log analysis indicates the upper part of D1 and D2 contain gas with a possible oil leg below. Although the logs clearly show the presence of gas in the upper D1 and D2, definition of oil legs is less clear due to changes in log character caused by increased clay content. The F sand is considered to be charged with oil. No hydrocarbon-water contacts could be defined as the hydrocarbon columns in each reservoir extend to the base of the sand within Ororo-1.

Sirius is currently planning to drill Ororo-2, where wireline pressure tests and samples will be taken to confirm the presence of an oil leg in D1 and D2. A commingled drill stem test of the D1 to D3 reservoirs will then be run to obtain flow rates for these reservoirs.

The well will subsequently be deepened and an Extended Well Test (EWT) is planned for the G reservoir. An Eclipse model, constructed by Schlumberger, was used to simulate the recoverable volumes of oil and associated gas from the D1, D2, D3, F and G reservoirs.

A development of the field envisages dual lateral wells with 1 to 2 horizontal 500m bores in the D1, D 2 and D3 reservoirs, dependent on confirmation of oil legs in D1 and D2, and oil column heights. Currently the F sand is not considered for development due to limited oil volumes. The G sand will be produced solely by Ororo-2. It is also planned to drill one well to obtain commingled gas production from the D4 and D5 reservoirs.

Sirius will fund all of the testing and development costs for Ororo, and recover costs from production with preference over other partners. As a result of this financing agreement, Sirius’ net entitlement to production will be more than 40% of life of field gross production, and the percentage will be variable depending upon costs, oil prices and production volumes

Sirius has stated that they intend to install a Conductor Supported Platform prior to drilling Ororo-2. Oil from the EWT will be piped from the platform to a barge, where it will be treated and exported via a shuttle tanker. Gas will be exported via a 5km 8” pipeline to Parabe. For Full Field Development, it is envisaged that further platforms will be installed and the barge be upgraded to take the greater volumes produced. Export of hydrocarbons will be using the same routes as the EWT. Recent costs have been obtained from contractors by Sirius for the above development scheme and these have been used in the economic analysis.

Total CAPEX for the EWT has been estimated as US$31.73 million and a full field development between US$99.23 million and US$126.15 million
depending on the size of resource to be developed. OPEX has been estimated around US$10 million per annum. The Ororo field has been awarded under the standard Nigerian Marginal Field Fiscal Terms. In addition, a Royalty is due to the Chevron and Nigerian National Petroleum Corporation under the marginal field farm-out agreement.

[solarno lopez] 20/9/2016 16:18

good man sher

[sherl0ck] 20/9/2016 16:12

I've spent a couple of days trying to get my head around the development plan briefly outlined in the CPR summary. From what I've researched, I like what I see. A lot of sensible thought has gone into the way forward and I've accordingly bought a few more shares today. Will detail my research and thoughts later when I get a chance to write it up.

[dr rosso] 20/9/2016 14:28

Interesting to compare with the recent Exec Summary because it shows how plans have changed under Havoc. Far more cost-efficient despite a higher upfront fee.

[dr rosso] 20/9/2016 14:14

The vessels are scheduled for delivery in 4Q 2016 and 1H 2017. ...... weld-on connectors are ideally suited for extreme service conductor and


The Sept 2014 journal article entries match with separate news items dated Aug 2014 in which Cosco is to supply Maersk with 2 subsea service vessels/ NOV connectors. Nothing to do with Sirius. The bit about 3 development wells is a Sirius rns dated July 2014, which is worth a re-read

[drrichard] 20/9/2016 13:15

This looks interesting my friends. I have been trying to get in to get details but am haveing a little difficulty. Anybody else fancy a go?
Offshore201409 Dl - Scribd

1409OFF_C1 1 9/2/14 3:38 PM ..... plans three development wells on the Ororo feld, which Schlum- ..... support, including the provision of hardware for the training, comes from .... The vessels are scheduled for delivery in 4Q 2016 and 1H 2017. ...... weld-on connectors are ideally suited for extreme service conductor and

Interesting that although two years old it appears bang up to date vis a vis three wells and timescale. Could they have been planning this for two years?

[dr rosso] 20/9/2016 10:09

1m "sell" at 37, followed by 3 "buys" which add up to virtually exactly.. you guessed it

[drrichard] 19/9/2016 19:16

Excellent, DrR. Shows what we are trying to achieve in the light of the works summary given in the CPR. Still, with GL, HAVOC and Schlum to hand you can bet your bottom dollar that they helped devise the plan in the first place.

[dr rosso] 19/9/2016 19:04

Some technical stuff...


Extended Well Testing Boosts Prospects For Development Of Marginal Fields
08/25/1997


To maintain production and profitability, operators must find ways of bringing smaller and more marginal fields on stream while reducing development costs.
Extended well testing (EWT) provides one route for both obtaining the data required to reduce the uncertainties-and thus the costs-of facilities design and reducing the uncertainties of reserves and productivity.

In the right circumstances, it provides the key to unlocking untapped reserves and reducing the overall costs of field development. EWT can provide the bridge between conventional appraisal testing and commitment to full field development.
It provides a cost-effective route to prospect evaluation and reduction of critical uncertainties in future field performance. It has been instrumental in minimizing appraisal costs for a number of operators and permitting them to progress with field developments.

EWT Objectives...

Confirm the extent of reservoir connectivity around the producing well.
Confirm long-term well productivity.
Identify production chemistry and fluid processing issues and optimize solutions for future management.
Reduce the overall cost of appraisal programs.


The effect of constant pressure boundaries (gas cap or aquifer) can be evaluated. In addition, the significant production volumes achieved leads to information on depletion and in-place volumes and on the drive mechanisms that may be present in the reservoir.

Depending on reservoir behavior and geometry, the volume of data gathered during an EWT-and the resulting radius of investigation-can be sufficient to reduce the number of appraisal wells required prior to commitment to field development, thus reducing the overall cost of appraisal programs.

A typical EWT involves using a drilling rig as a temporary production unit, from which crude oil is transferred by temporary export line to an oceangoing tanker stationed close by. Prolonged production period provides the opportunity to consider a number of variations on this arrangement. Alternatively, the well can be completed with a tubing hanger and a production string through the use of an SSTT providing dual-bore access.

The completion can then be retrieved or used as a suspension string depending on the results of the test program. This offers the option of larger bore completions providing opportunities for increased flow rates and revenue stream.

This technique significantly reduces the cost of reentry and recompletion should the well be included in future development plans, despite the subsea production christmas tree not being committed to or available.

This scheme has become the preferred route for completing development wells for a number of operators in the North Sea, including BP and Amerada Hess Ltd., and is applicable to EWTs.

Subsea tie-back
The well can be completed with a permanent or temporary subsea christmas tree and tied back to the rig via a flexible riser.

Although this increases expenditure on hardware, it offers the opportunity to test a second well simultaneously through the BOP stack.

In addition, a fast-track drilling program can be accommodated by employing simultaneous drilling (through the marine riser) and production (Simops).

The number of producing wells can be increased by tying multiple wells back in parallel or by employing subsea chokes and "daisy-chaining" wells with jumper flow lines between hubs mounted on production guidebases (PGBs).

Flow rate data for each well can be acquired with downhole flow meters. The facility now resembles an option that can be utilized subsequently, with or without modification as appropriate, as an early production system or first phase development facility.

The separation train is usually designed to accommodate significantly higher flow rates (currently as much as 30,000 b/d of oil) than for a DST and customized to the test objectives. Such capacity is designed to provide sufficient drawdown on the reservoir to permit evaluation of vertical permeability and effectiveness of drive mechanisms.

There is opportunity to offset the cost of operations through sale of the crude. For example, Ranger was able to break even after its £17 million ($27 million) test program in Pierce from the proceeds of the sale of crude.

Rigless alternative
Relocation of the process facilities to the deck of the storage tanker offers large potential savings in rig hire (Fig. 5 [20,499 bytes]).However, the effect of this is reduced by the need for additional hardware such as subsea well control and a high-pressure flow path to the tanker deck and the costs of modifying the tanker.

The process facility can be located on a simple structure on the deck of the tanker, and the use of a temporary, modular design will minimize modifications required to the vessel and permit the ship to return to crude-carrying duties.

To minimize costs if production from two or more wells is planned, the wells are daisy-chained to a single flow line/riser as described earlier. The cost of subsea chokes and the jumper flow lines and hub connectors will be considerably less than multiple risers.

Individual production data can be collected from each well by downhole flowmeters with the data transmitted to surface via electrical connections within the control umbilical.

Rig intervention is still required to complete the wells, install christmas trees, and to kick off and suspend the wells. Care should be taken over the scheduling of these and production operations in order to minimize, or eliminate, the risk posed by unattended live wells.

Until recently, the use of the FPSO concept for field development has been limited, but this is changing. It may soon be economic to consider using temporary floating production vessels for long-duration tests.

The simplest schedule for testing is to carry out the flow period immediately after completion of the drilling program. This will also minimize the total cost of the operation.

A number of specialist items of equipment, such as downhole monitoring systems, premium production tubing, subsea production trees, and mooring chain may affect the schedule, depending on the test configuration chosen and current availability.

Finally, there are likely to be a number of submissions required to the regulatory authorities. These are obviously specific to each governmental sector but usually cover the management of safety and the placement of temporary pipelines. As these submissions do not entail equipment fabrication, it is possible to eliminate any effect on the schedule by commencing preparation early, for minimal extra commitment costs.

Delaying commitment to the temporary production arrangement until after initial tests on the well increases total expenditure, because additional rig time is required to suspend and then subsequently reenter the well. The extra costs incurred in hardware and running the completion are more than offset by the subsequent saving in rig time..

The reduction in environmental effects owing to reduced flaring is supported by the good record of minimizing spills and overboard discharge of hydrocarbons.



Conclusions
The cost-effectiveness of a particular test will be influenced by rig rate, oil price, flow rate, and the benefits of implementing new technology. For a given field, the total cost of field development may be marginally increased by including an EWT. Nevertheless, this is likely to be more than compensated for by the reduction in cost of development facilities as the range of likely production profiles is reduced. The uncertainties surrounding the economics of the development of marginal fields can be reduced significantly, permitting the commitment to development to be made without potentially costly delays or further appraisal wells.

The preparation and planning required for an EWT is significantly more than for a traditional DST. Therefore, it is imperative that both project management and operations are undertaken by competent parties. An operation such as an EWT requires careful, competent management, and communications and project coordination need to be given a high priority.

[dr rosso] 19/9/2016 18:31

Flowing gas through a 5km pipeline to Parabe must mean there is a working arrangement with Chevron, which is the field operator and owns 40% of the lease. I wonder if Chevron intends the big 2 in block 95, Parabe and Meren, to be brought back into production?

[jamie40] 19/9/2016 14:49

Come on Bobo, pull your finger out!!

[solarno lopez] 19/9/2016 13:54

hahaha thanks Sher

[sherl0ck] 19/9/2016 13:40

Sol - if I was fortunate to be an insider there's no way I'd be posting here! The best we can do is research as much as poss, read the RNSs carefully and cross reference with AIM guidelines and other regulatory info to get a sense of what's likely going on. Even then it's only a best guess until the Company confirms.

Whilst it's another embarrassing wording error, the website clarification of Ororo in OML 95 makes much more sense in the context of the original paragraph. It would also be impossible to have somehow farmed into the wider block without an RNS and farm in fees.

[cornishtrader1000] 19/9/2016 13:21

So back 'just' Ororo!!

[solarno lopez] 19/9/2016 12:59

Thanks Sher, I was trying to tease from you a, definite yes I know there will be an AD cos I have been told !

[sherl0ck] 19/9/2016 12:34

IF we raise any substantial amount of money then undoubtedly so as it will be classed as an RTO under AIM guidelines and will need shareholder approval and vote at an EGM. This is what I think Bobo was referring to when he talked about 'regulatory requirements' in the recent investor video segment.

I skimmed through SLE's 400 page AD this morning. Their financial raise and share in the already producing OML 18 block is a lot more substantial than Ororo but it gives you a rough idea on what an AD contains.

What we don't know is whether our financing will be focused purely on a) securing enough money to drill Ororo 2 b) be more extensive to cover a greater degree of Ororo field development c) be larger still to encompass Ororo & other assets (in which case we'd probably need additional CPRs done) and/or even d) include other complex transactions such as JVs, RTO with Owena, takeover, acquisition of assets as part of a consortium etc.

Again, because CPRs normally end up with various drafts and quite a bit of back & forth between the CPR provider and the Company, I'd be surprised if we were happy to ok the final approved draft without having a good idea that we're likely to secure funding. It's not guaranteed of course, but you'd be pretty stupid to go down this road and only then begin to initiate some sort of beauty parade and start some negotiations.

Seems to me like we did this earlier in the year, hence the comments about proposals on the table. If we're also no longer based at 42BS, I'd see that as a positive sign that it perhaps served its purpose. We'll see.

[solarno lopez] 19/9/2016 12:07

So are you saying there WILL be an AD SHER

[sherl0ck] 19/9/2016 11:59

Full CPR, along with much more technical details and seismic survey maps will more than likely be published as part of the admission doc. This is just the exec summary.