TOTAL E&P Australia (Total) has signed up to use AGR’s Riserless Mud Recovery (RMR®) system. The contract is for two exploration wells to be drilled over the next year in the Browse Basin off North West Australia.
Bernt Eikemo, AGR’s Vice President of the Enhanced Drilling Solutions (EDS) division (Asia Pacific), said: “AGR is delighted to be part of Total’s drilling team during the forthcoming exploration campaign. We hope that this is the start of a long, successful relationship with Total E&P Australia.”
He added: “Our previous experiences with several operators in the Browse Basin and the North West Shelf have shown that unconsolidated sand formations become much more benign when drilled with RMR® using a proper mud system.”
RMR® has been used by Total on several other projects internationally but this is the first time that the operator has used the system in Australia.
The main reason for using RMR® on these wells is to be able to drill through the unconsolidated sands of the Grebe Formation. It is renowned for stuck-pipe problems when drilling riserless using seawater and sweeps.
RMR® (system example attached) enables the use of weighted, engineered mud in the top-hole section. All mud and cuttings are returned to the rig with no discharge to the seabed. The top-hole section can be drilled more safely, quickly and with less impact on the environment.
RMR®, together with its sister technology the Cutting Transportation System (CTS™), has been deployed on more than 500 wells worldwide to date.
Tap Oil Limited (Tap) advises that at 0900 hours (AWST) today the Atwood Eagle semi-submersible drilling rig commenced drilling the Tallaganda-1 exploration well in the WA-351-P permit.
The Tallaganda-1 prospect straddles both the WA-351-P and WA-335-P permits in the Carnarvon Basin, offshore Western Australia. The well will target 0.8 to 1.3 Tcf (mean to P10) of gas within WA-351-P (Tap estimate).
The prospect will test the gas potential of sandstones in the prolific Triassic age, Mungaroo Formation, in a well defined horst block as imaged by high quality modern 3D seismic data. This is the primary play type of the North West Shelf.
The well will be drilled as a vertical well in a water depth of 1,141 m and is expected to take 37 days (trouble free) to drill with a projected total depth of 4,250 m. Weekly updates will be provided on Wednesdays during drilling operations.
Tap’s cost for the well will be carried up to a cap of $10 million following Tap’s farmout of 25% of its participating interest in the permit to BHP Billiton Petroleum (North West Shelf) Pty Ltd in 2011.
Tap’s Managing Director/CEO, Mr Troy Hayden, said:
“We are pleased to have commenced the Tallaganda-1 well which has the potential to deliver a resource multiple times larger than Tap’s current 2P reserves. Success at Tallaganda-1 will also give greater certainty as to the prospectivity of the Triassic potential on the permit.”
The Operator completed a detailed assessment of the plays, prospects and leads in the permit in 2010 including the 3D seismic acquired in 2008. Further leads and prospects have been defined in the Triassic Mungaroo Formation which Tap has assessed as a 2-3 Tcf combined speculative resource on block.
Additional leads have been identified in WA-351-P in the Jurassic and Early Cretaceous, both of which are productive elsewhere in the Carnarvon Basin. Current indications are that this shallower potential is larger, but higher risk, than the Triassic in this permit. Further work will be done on these objectives.
WA-351-P Joint Venture Participants
BHP Billiton Petroleum Pty Ltd (Operator)
BHP Billiton Petroleum (Northwest Shelf) Pty Ltd 55%
Apache Northwest Pty Ltd 25%
Tap (Shelfal) Pty Ltd 20%
An ambitious exploratory well project has entered the record books – with AGR’s Riserless Mud Recovery (RMR™) system from their Enhanced Drilling Solutions division helping to make it possible.
Woodside called a total section depth of 1,905m (6,250ft) on the Tidepole East-1 exploration well off Western Australia. It was the first time that Woodside had used the Casing While Drilling (CWD) method on one of its wells and the depth reached sets a new world record for the technique.
RMR™ enabled Woodside to use the type of drilling mud needed to maximize the wellbore smearing effect that CWD provides, which helps keep the wellbore stable.
The system allows top-holes to be drilled using weighted mud, with fluid and cuttings returned to the rig and no discharge. It is also able to supply the low pump rates and good hole-cleaning capability required to drill efficiently, despite the relatively narrow annulus that was a feature of this project.
Thanks to RMR™ and the casing being run during the drilling process, there were no losses to the formation during that stage – an all-too-common occurrence with conventional drilling method.
AGR’s ingenuity solves the challenge
Standard internal or external wellhead adapters could not be used on this project for the RMR’s™ Suction Module (SMO) without extensive modification to the Permanent Guide Base, or without causing difficulties when it came to landing the High Pressure Well Head (HPWH) on the Low Pressure Well Head (LPWH) later on in the operation.
AGR’s ingenuity provided the solution, with an internal adapter being devised that could be split. This meant that the casing could be drilled down with the SMO in place.
General Manager EDS Asia Pacific, Bernt Eikemo, said: “When it was time for the HPWH to be landed on the LPWH, the SMO could simply be lifted off the LPWH using two ‘tugger’ winches on the rig, with an ROV performing the split.
“This of course has never been done before but, with a simple design and good communication with the ROV Company, it proved to be a great solution and it took next to no time for the ROV to release the locking pins and split the adapter.”
The operation went smoothly, with an impressive Rate of Penetration (ROP) achieved of some 60m (197ft) per hour. Bernt added: “This would have been impressive even with conventional drilling. To be able to drill these kinds of wells and others in a quick, simple way like this can potentially create great savings for operators.
“Working within areas with challenging geotechnical conditions, a proper mud system and the ability to have full returns are vital for success. RMR™ is perfect for this application.”
AGR recently surpassed the 500-well landmark for its Cutting Transportation System (CTSTM) and RMR™. Next year will see the first deployment of the company’s EC-Drill™ Managed Pressure Drilling system.
- AGR Signs Deal to Supply RMR to Woodside for Use on Australia’s North West Shelf
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- Norway: NPD Announces Oil Discovery East of Ula Field
- Milestone Achievement for AGR’s Drilling Technology in Chirag Field, Azerbaijan (mb50.wordpress.com)
- USA: Aker Solutions to Open Hi-Tech Drilling Equipment Simulator in – Houston (mb50.wordpress.com)
Nathan Bell April 18, 2011 - 2:50PM
There’s an old joke among oil drillers: “We didn’t hit oil, but at least we didn’t hit gas”.
Just 10 years ago, gas was an irritating, near-worthless by-product of oil production. Now an oilman’s job depends on it.
Major oil producers like Chevron and ExxonMobil are chasing gas because they can’t get their hands on any more oil.
What’s more, it’s now much less expensive to transport, to the point here gas is now a real substitute for oil. The switch to LNG is on.
But what really accelerated the pace of change was the advent of Liquefied Natural Gas, or LNG.
Prior to this development, gas had to be transported through huge, and hugely expensive, pipelines. Only those projects close to customers or existing pipelines made economic sense. LNG did away with all that.
Through a process known as liquefaction, gas is chilled into LNG, occupying a volume just 1/600th of its gaseous state. This small fact changed the face of the industry.
Where once large and expensive pipeline networks were required to transport gas point-to-point, now ships deliver it anywhere in the world.
Nevertheless, it’s still a complex process. Once LNG reaches its destination, it has to be turned back into its gaseous state – a process somewhat unimaginatively known as regasification – and transported conventionally via pipelines to end users.
At both ends of the LNG chain, nature and technology collide. And the costs of that battle aren’t cheap.
The supply glut
LNG prices are traditionally linked to the oil price. In days when oil fetched $US20 a barrel this quirk was seen to benefit buyers of gas. Today, with oil prices at over $US100 a barrel, it’s a boon to gas producers.
Producers have responded by scrambling to increase output. There’s now every sign of a global glut of LNG.
Qatar is home to the world’s largest gas fields, where enough oil and condensate by-product lowers the effective cost of gas production to almost zero. Cost-free cargoes of Qatari LNG thus ply the world’s oceans, holding prices down.
In Australia, new capacity worth nearly 60 million tonnes per annum (mtpa), has already been committed. With coal seam gas reserves yet to come on stream, that figure is likely to grow.
The shale gas revolution in the US will also have an impact, turning what might have been an importer of LNG into a possible exporter.
And shale and coal seam gas discoveries that have transformed the North American gas market may also occur in new markets like China, India and Brazil. If that occurs, some of the world’s largest potential markets may not need to import LNG at all.
A glut of LNG over the next few years appears likely. Indeed, we’ve been warning of this possibility.
But over the longer term, demand for LNG should easily catch up and perhaps even exceed new capacity.
Growing demand for LNG
The world’s biggest and hungriest energy consumers have barely embarked on their conversion to gas.
In 2005 China had no re-gasification terminals at all. Today, there are six in various forms of development. Each will be able to process millions of tonnes of LNG each year. Currently, Chinese LNG imports are less than 6mtpa. In 15 years’ time, they’re forecast to increase 10-fold. India, Brazil, South Africa, Vietnam and others are constructing new terminals to import LNG.
Overall, demand is expected to grow 15mtpa for the foreseeable future. That’s the equivalent of a new North West Shelf every year.
With Qatar indicating it has reached its supply limit – volumes are not expected to exceed 77mpta for some years – Australian producers are well placed to fill that supply shortfall.
The switch to gas is already on. Developing countries are increasingly seeing LNG, not oil, coal or renewables, as the primary solution to their growing energy demands. Investors take note: this is a sector that will offer rich pickings for investors.