Xcite Energy Share Discussion Threads

[irnbru2] 07/11/2014 09:06

Yea, and they are all you.

[mclellan] 07/11/2014 08:58

Certainly much more interest again.
I just looked at the Stats and there were 2,415 page views yesterday compared with 632 the day before.

Visitors

Yesterday: 293 168 visitors the previous day

30 day average: 243

[mclellan] 07/11/2014 08:55

Carla- I suppose there might be a bit of buying from the Investors' Chronicle article

[carla1] 07/11/2014 08:47

WOW mc.....what do they Know ???

A declare a BLUEY :-)

[mclellan] 07/11/2014 08:37

jcd- thanks. I just looked that up, on your post.

Buy Xcite as Bentley revs up
Xcite Energy (XEL) is a speculative resource play with an investment case that hinges on its ability to bring the massive Bentley field in the North Sea into production. Xcite's shares have fallen by 55 per cent in the year to date, as the oil price slumped and risk appetite dwindled for offshore oil and gas plays on the UK Continental Shelf (UKCS). But the tide could soon turn, as we believe that a succession of developments means Bentley is now likely to be brought into production sooner rather than later. The question is by whom?

[carla1] 07/11/2014 08:35

Something has leaked...our TROLLS have been put to sleep and we are UP and AWAY !!!

Good Luck all Longs

[jcd1972] 07/11/2014 08:32

Who'd want to be out over the weekend Carla! Investors Chronicle have spoken!

[mclellan] 07/11/2014 08:31

It's about time!

[carla1] 07/11/2014 08:28

:-) its looking lively mc

[mclellan] 07/11/2014 08:25

Calm down, carla:-)
Don't wind up the trolls.

[carla1] 07/11/2014 08:21

Look at the BUYING !!!


Paying over the ASK !!

[carla1] 07/11/2014 08:19

She Gonna BLOWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWWW

Rig NEWS IMMINENT !!!!!!

[carla1] 07/11/2014 08:16

Oh its a COILED SPRING today :-)

[carla1] 07/11/2014 08:08

Looking lively...volume building :-)

[carla1] 07/11/2014 07:46

morning REAL ONES

[mclellan] 07/11/2014 07:44

XEL will be presenting at Oilbarrel on the 2nd DEC 2014 (added to the header area)

[mclellan] 07/11/2014 07:36

Morning all- many thanks again to mikepage for his unending faith in XEL and the wealth of information.

[arlington chetwynd talbot] 06/11/2014 23:41

Yeah, just a pity he didn't forecast this fall... eh?

[ttail] 06/11/2014 23:16

Just catching up on the day's post-been out for the day.
Mikepage, congrats once again. You are restoring faith in this share for many.
Sterling work.
Hope all this translates to a good return for all genuine holders.

[mikepage19] 06/11/2014 22:54

bleepy, no problem mate.

As you say "Bentley is a MONSTER", and it's about to be woken.

Page 20 is all we need to see-



FFS people the market bet against XER raising funds for the flow test in 2008/2009, share price £0.04.
They are playing the exact same game, £0.44. But this time BENTLEY IS NUMBER 5 IN SIZE regarding Oil fields in the UKCS remaining reserves, and XER are one of the most respected Heavy Oil Players in the business.

By the time SPP (Bentley projected second phase peak production,57,000bbls/day*)
is online, Bentley (you noticed I didn't mention XER) will be number 2 behind Buzzard in the UKCS; fn amazing!

As I said, don't expect a major RNS until around about the 21st....

One last thing- 257MMbls is just the beginning, try P2=4??+MMbls
All will be revealed soon!

[bleepy] 06/11/2014 22:28

Excellent research mike and opening the world of oil and gas for us all to appreciate,more so the monster Excite.

Many thanks again.

[mikepage19] 06/11/2014 21:47

Some very good presentations, you'll like Statoil's-








Remember Xcite have been in dialog (in the past) with Chevron regarding their Captain Field.
They are at present undergoing pilot studies for EOR on Captian.

[mikepage19] 06/11/2014 21:11

Bentley is getting cheaper to produce by the day!

The perfect storm coming-

Statoil has decided to suspend two new rigs due to overcapacity in the rig portfolio. The semisubmersibles Transocean Spitsbergen and Songa Trym will be suspended through 2014, a period which might be extended.

The Transocean Spitsbergen. From Transocean.

The exploration program in the Barents Sea for 2014 is nearing completion, said Statoil. After the Transocean Spitsbergen has completed the Saturn well, the rig will cut and retrieve a wellhead in the Mercury exploration well. The job is estimated to be finished in mid-November.
Subsequently, the rig will be suspended to the end of the year. The suspension is a result of overcapacity in Statoil’s rig portfolio, and unsuccessful attempts to mature alternative assignments for the rig.
“The exploration program has been highly efficient. Transocean Spitsbergen drilled the last seven wells 40 percent faster than the industrial average in the Barents Sea. This allowed two more wells than originally planned to be drilled. We are very pleased with the work performed for us by Transocean. Unfortunately we are now in a situation of overcapacity, at the same time as the industry is facing high costs and lower profitability,”; says Statoil’s chief procurement officer Jon Arnt Jacobsen.
Transocean Spitsbergen is planning a yard stay from 1 January 2015. The rig is under contract to Statoil to the start of 3Q 2015.
Songa Trym will be suspended after the rig has completed plugging a well on the Oseberg field in the North Sea. This job is scheduled to be completed in mid-November.
“Songa Trym has delivered well on efficiency and safety, and we would have liked to use the rig also for the rest of the year. We have tried to find new assignments for the rig, but our attempts to realize the identified options have not been successful. We are now together with our partners maturing identified drilling assignments for both rigs for 2015,” says Jacobsen.
After the two rigs are suspended Statoil will have 15 rigs in activity on the Norwegian continental shelf.

[mikepage19] 06/11/2014 21:05

I remember this piece from the early days.
I suggest all holders have a good read, the last few paragraphs hold the key-

Bentley
Aberdeen-based Xcite Energy has a 100% interest in block 9/3b, containing the Bentley field. Amoco made the discovery in 1977 while drilling through the reservoir for deeper, lighter oil, but failed to test the oil to surface. Conoco then took on the license, drilling three appraisal wells on the structure during 1983-86, none of which, again, flowed oil to the surface.
After acquiring further seismic over Bentley in 1991, Conoco returned the block to the UK government in 1993. “They could not explain why the wells had failed,” says Xcite director Rupert Cole. “However, the techniques employed in those times would probably never have resulted in successful wells. And with the crude price slumping to $10/bbl, there was no incentive to pursue further tests.”

Recent 3D seismic suggests a larger contiguous pool of oil on Bentley (right) compared with the picture from 2D seismic in 2003.
Click here to enlarge image

Aside from CGG’s speculative 3D survey in 1998, there was no activity on the field until 2003, when the Department of Trade and Industry introduced a “Promote” license scheme as part of the UK’s 21st seaward licensing round. Xcite’s E&P director Stephen Kew, along with others in the Xcite team today, had worked for Conoco UK while Bentley was still a live project. Their prior knowledge was instrumental in Xcite securing the block, against intense competition, via a Promote license in 2003.

“Based on the data we had at the time of our application,” Cole says, “we were looking at in-place volumes of around 500 MMbbl. We saw 10% recovery as the minimum threshold to make this an attractive investment.”

RPS Energy Canada last year performed a more in-depth analysis of Bentley’s resources based on information from the four wells and the 2D dataset. This estimated oil in place in the range of 508-691 MMbbl, with P50 contingent reserves of 68 MMbbl, and a further 40 MMbbl of prospective resources in two nearby exploration targets possibly connected to the Bentley structure.

According to interpretation of the 2D seismic, Bentley has a saddle feature with two structural highs. The field lies west of the Viking graben, an area prospective for heavy oil in the late Palaeocene (Tertiary) Dornoch formation. The primary source rock is Upper Jurassic Kimmeridge clays, with hydrocarbon migration occurring during the Eocene and Oligocene eras via a fault system along the margins of the Viking graben.

Although Bressay to the north is the nearest discovery, its geology is much more complex, characterized by deeper, more stratified channel sands. The nearest geologically analogous producing heavy oil field is thought to be Captain, 250 km (155 mi) to the southwest. Although of a lower Cretaceous age, Captain is also an unconsolidated, high porosity, high permeability sandstone reservoir, which Texaco developed successfully in the mid-1990s with downhole pumps and long horizontal wells. Over the years the recovery target has risen from an initial 22% to more than 35% at present, with a longer-term target of 50%.

Like other, neglected heavy oil fields in the northern sector, the nature of Bentley’s crude was unknown when Xcite took charge in late 2003, as no samples had been recovered from the wells. Both the original well tests were also dogged by technical problems. In Amoco’s case, the probable cause was formation damage caused by overweight drilling mud. Also, the casing was inadequately cemented, making it hard to isolate the oil-bearing section.

Conoco’s 9/3-2A test in 1983 failed to flow oil to the surface for several probable reasons, according to Xcite. The well was completed with a fine sand screen designed to protect the electric submersible pump employed for the test. But the high-pressure drawdown applied by the pump may have caused the sand face to slump, leading to clogging of the screens with oil-coated sand grains, forming a skin to stop oil migration. “Pumps in the 1970s and ’80s were not sand-tolerant,” Cole adds.

Other contributory factors may have been a build-up of asphaltenes – high molecular weight compounds found typically with heavy oil. Cooling of the wellbore with mud and completion fluids may have led to asphaltene precipitation in the nearby pore space. Also, calcium naphthanate soaps may have formed following a chemical reaction between the naphthanic acids in Bentley’s oil and the alkaline properties of the mud used to drill the reservoir section in the 9/3-2A well. This would have created a thick, soap-like skin around the wellbore, restricting permeability and the movement of oil.

To assess the likely behavior of the reservoir under production, Xcite commissioned a trial simulation study from RPS, which had performed similar work for other North Sea heavy oil fields. Xcite also commissioned GeoMark in Houston to predict the probable fluid properties, using a proprietary methodology that combines geochemical data with pressure and temperature data.

Early this year, Xcite drilled and successfully tested its 9/3b-5 well, conducted by AGR Peak Well Management from the Byford Dolphin. The aims included:
Obtaining a crude sample to establish API gravity, viscosity, and the oil’s acid and metals contents
Flowing crude to the surface via a drillstem test (DST) at rates suitable for the well conditions, the completion, and the sand-tolerant electric submersible pump’s capacity
Drawing a water sample from the aquifer for chemical analysis and for wireline log calibration.

Test partner Schlumberger supplied the DST equipment, including the slow-start pump. “We had to be very careful not to recreate the same problems in the well as before,” Cole explains.

The well was drilled to a total depth of 4,105 ft (1,251 m) and, as expected, intersected Palaeocene Upper Dornoch sands at 3,712 ft (1,131 m) with an 87 ft (26.5 m) gross hydrocarbon column.

“Our plan had been to flow test for 24-36 hours,” he adds, “but with two weather fronts approaching, we knew we only had 20 hours maximum before operations would have become dangerous. So we started slowly, gradually increasing the speed of the pump. After 17 hours, we had achieved the full projected rate of 150 b/d equivalent from the 50-ft (15.2-m) perforated section of the oil column.”
The characteristics of the reservoir were in line with expectations, i.e. high porosity and permeability unconsolidated sandstone; a reservoir temperature of around 103º F (40º C); a depth to the top of the reservoir of 3,712 ft; and no gas cap. Schlumberger’s review of the well data and recovered hydrocarbon/fluid samples also suggested a high permeability formation of greater than 5 darcies, later confirmed as up to 10 darcies.

According to Cole, the well’s “high skin” value of 29 was typical of an appraisal well with formation damage — due mainly to the need to re-circulate the mud to keep the well fluids warm — and a thick cemented zone caused by wellbore washout.

“If we hadn’t had the skin at that level, we would have achieved production of 500-600 b/d, but that would have exceeded the pump’s capacity. We would also have liked to flow the well for longer, then maybe the skin would have gone down. But we achieved our main aim, which was to flow oil to the surface.”
A lower skin value would probably be feasible for Bentley’s production wells where washout would not be an issue. This could be achieved by drilling gravel-packed, 3,000-ft (914-m) horizontal wells 15 ft (4.6 m) from the top of the formation, with a potential flow rate of 4,000 b/d of oil per well assisted by artificial lift, i.e. submersible pumps.

Following this positive outcome, Xcite is moving straight to an early production system (EPS) on Bentley’s northern lobe. “This is being designed right now,” says Cole. “We aim to complete FEED work for the EPS by the end of this year, and we also plan further reservoir modeling with PGL in an attempt to firm up the field’s resources by the fall. Hopefully we can then get the EPS development plan to the government by year-end. Going straight to an EPS also gives us more flexibility, as it allows us to optimize the full-field development solution and to determine the best way of drilling and completing the wells in order to minimize our drilling costs.”

The EPS, probably delivering first oil in 2009, will involve drilling up to three horizontal production wells. Xcite is currently negotiating a contract for a rig. The company anticipates two drill centers for the full-field development in the northern and southern sectors of the field. These would be drilled from wellhead platforms where oil and water will undergo first-stage separation before heading through pipelines to a ship-shaped FPSO equidistant from the platforms and equipped for oil processing, water handling, and separation. The treated crude would then be transferred to a shuttle tanker via a loading buoy.
PGL Senergy is developing a new 3D reservoir model incorporating reprocessed 3D seismic and well data from the recent test. Interpretation to date suggests greater structural relief at the top of the Dornoch formation. If correct, this would increase substantially the structure’s extent.

“We don’t know yet what sort of volumes we will pick up on the edges of the Bentley structure,” says Cole, “but if we can get our drill centers in the right place, we would include a potential accumulation known as prospect A, since we are confident that it is part of the main structure. Also, it appears to have a slight gas cap over it, which is potentially good news. However, this needs to be drilled first to verify our prognosis.”

Seismic studies have also identified a possible Jurassic accumulation underlying the Bentley field — although significant oil shows were encountered at this level in wells 9/3-1, 9/3-2A, and 9/3-3. “Half-graben features in evidence on the seismic may provide a trapping geometry, but this needs to be studied further. The structure may not be that big, but if the lighter oil can be recovered economically, this might be useful as a diluent for the development,” says Cole.

Bentley’s full-field development will be largely water-driven. “We will also have to replace that water. With all these heavy oil fields, you get more and more water through the life cycle. The trick is to ensure a constant oil flow through drilling new wells to maintain peak oil as long as possible. We are looking for full-field production spanning seven to 10 years.”

Analyst Mirabaud Securities has estimated total field life costs at $1.1 billion for opex, including lease of the FPSO at a rate of $225,000/day, and $640 million for capex, over half of which is attributed to the wells. Xcite’s management has prior experience with floating production in the North Sea: Smith, Kew, and Remshaw were responsible for Conoco’s McCulloch development in 1994, which featured the UK’s first fully tariffed FPSO.

Recently, Xcite agreed to exchange the results of its 9/3b-5 well with data from a new appraisal well StatoilHydro is planning this fall on Bressay. “The well we drilled is probably what they need for Bressay,” says Cole, “but they also require a longer flow test.”

Theoretically, Bressay could be jointly developed with Bentley as a tieback, with the cost of the FPSO shared between the partners. “We have had very open discussions with StatoilHydro,” says Cole, “but they are at least two years behind us in project planning. In our view, we have to get Bentley into production as soon as possible, thus providing opportunities for others in this area.”