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Tuesday, 05 September 2017 09:12

DGE III hits at Rampart Deep

Deep Gulf Energy III (DGE III) has encountered hydrocarbon pay at the Rampart Deep well in the deepwater Gulf of Mexico, according to partner Stone Energy.

Deepwater Asgard. Image from Transocean.

The Rampart Deep well (MC 116 #1) is in Mississippi Canyon Block 116, about 8.5mi south of the Pompano field, at 2600m water depth. The well is being drilled with the Transocean Deepwater Asgard drillship.

Stones says 130ft (net) of liquids-rich natural gas pay in three primary zones. According to DGE III, prospect mean reserve potential is 32 MMboe. First production is anticipated in 2019.

The completion of the Rampart Deep well will be deferred while the partners analyze the well data, and will be further evaluated in conjunction with future Derbio drilling results, Stone says. 

Drilling plans for Derbio will be reviewed with the Rampart Deep partners over the next 90 days.  If Derbio is successful, first production from the Rampart Deep/Derbio project is expected by late 2019 and could be a multi-well tie back to the Stone 100% owned Pompano platform.

In addition to the reserve potential of Rampart Deep, Stone says that this well also provides critical information that reduces the exploration risk of its Derbio prospect, which is positioned up-dip from Rampart Deep and located one block to the northwest in Mississippi Canyon Block 72.

"The Rampart Deep well is encouraging to Stone as this discovery provides us with potential future reserves as well as important information that should reduce the risk of our other prospects in the area, particularly the Derbio prospect,” says Stone Interim CEO and President James M. Trimble. “The discovery at Rampart Deep, along with a success at Derbio, would allow us to further leverage our infrastructure position at our Pompano platform by generating additional production and cash flow with minimal incremental operating cost."  

RDE III is the operator of Rampart Deep with 30% interest. Partners include Stone Energy (40%), and Ridgewood Energy Corp. (30%).

Stone currently holds a 100% working interest in the Derbio prospect, but the Rampart Deep partners may elect into the Derbio well for a 60% total working interest, proportionate to their respective Rampart Deep working interests, with the remaining 40% owned by Stone. 

Read more:

Deep Gulf Energy spuds Rampart Deep prospect

Operators are evacuating platforms and rigs as Hurricane Harvey, a Category 4 hurricane, spins in the Gulf of Mexico, according to the Bureau of Safety and Environmental Enforcement (BSEE).

Hurricane Harvey's path. Image from NOAA.

From operator reports obtained by BSEE, it is estimated that about 21.55% of the current oil production of 1.75 MMb/d in the GoM has been shut-in, which equates to 377,117 b/d. 

It is also estimated that some 23.24% of the natural gas production of 3.22 MMcf/d, or 748 MMcf/d in the Gulf of Mexico has been shut-in. 

After the storm has passed, BSEE says the facilities will be inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back on line immediately. 

Facilities sustaining damage may take longer to bring back on line.

Based on data from offshore operator reports submitted as of 11:30 CDT today (25 August), personnel have been evacuated from a total of 86 production platforms, 11.67% of the 737 manned platforms in the Gulf of Mexico. 

Personnel have been evacuated from four rigs, equivalent to 40% of the 10 rigs of this type currently operating in the GoM, which include jackups, platform rigs, all submersibles and moored semisubmersibles.

One dynamically positioned (DP) rig has moved off location out of the storm’s path as a precaution, representing 4.7% of the 21 DP rigs currently operating in the GoM. Personnel remain on-board and return to the location once the storm has passed.

BSEE’s Hurricane Response Team says they will work with offshore operators and other state and federal agencies until operations return to normal and the storm is no longer a threat to GoM oil and gas activities.

As of 6 p.m. CDT, Hurricane Harvey was classified as a category 4 hurricane, with wind gusts reading at 74 mph, according to the the US National Hurricane Center. 

NOAA said that sustained hurricane-force winds were spreading onto the middle Texas coast.

"A station at Aransas Pass run by the Texas Coastal Observing Network recently reported a sustained wind of 74 mph (119 km/h) with a gust to 96 mph (154 km/h)," NOAA reported at 6 p.m. CDT on 25 August.

Category 4 hurricanes can reach maximum sustained winds of up to 130 mph (215km/h). 

“The Gulf Coast region of Louisiana, Mississippi, Alabama and Texas is the heart of the nation’s oil and natural gas industry,” says the US Energy Information Administration (EIA). “According to the EIA, the US Gulf of Mexico accounts for nearly 20% of total US crude oil production, and the Texas Gulf Coast is home to more than 25% of US refining capacity. This makes the Gulf Coast the largest domestic supplier of transportation fuels.

“As an industry, we develop extensive guidelines and best practices to assist companies in protecting workers, securing infrastructure and ensuring environmental protections in the case of a supply disruption. America's vast energy infrastructure network is designed to sustain disruptive events like Hurricane Harvey, due to its geographic diversity and industry experience responding to similar storms over the years, such as Rita, Ike and Sandy. Industry engagement with federal, state, and local government officials to improve preparedness for hurricanes and other natural or man-made disasters is another way in which system resilience is improved.”

On 22 August, operator Anadarko began removing personnel working in the GoM, closely watching Harvey. Others, including Shell and Exxon, followed by also evacuating personnel, and shutting in production. 

Read more:

Harvey leads to shut ins, evacuations in GoM

Friday, 25 August 2017 08:19

FAR seals Guinea-Bissau deal

FAR Ltd. has received official confirmation from the government of Guinea-Bissau for the increase of its stake in the Sinapa and Esperanca licenses, which includes an extension, and the drilling of at least one well in each block.

Map of Sinapa, Esperanca. Map from FAR.

In early April, negotiations concluded with the national oil company of Guinea-Bissau, Petroguin, to revise the terms of both the Sinapa and Esperanca. 

FAR believes the two blocks to display a similar geological setting to offshore Senegal and SNE field discovery.

Under the revised license terms negotiated by FAR and its joint venture partner Svenska Petroleum Exploration, FAR now has a 21.42% participating and paying interest in the permits, an increase from the 15% participating and 21.42% paying interests as previously reported. These changes reflect the fact that Petroguin will no longer have a participating interest in the joint venture prior to a commercial discovery. Upon making a commercial discovery, Petroguin will have a reduced participating and paying interest of 10% and FAR and Svenska will respectively have interests of 19.28% and 70.71%. 

In addition, the new license terms negotiated include more favorable arrangements for deepwater investment including a reduction to production royalty rates payable to the government. The JV has also been awarded a three-year extension to the current license periods, now ending on 25 November 2020. During these license periods, the JV will drill one exploration well on each license with a minimum expenditure commitment for each license of US$3 million (gross). These changes in the terms of the licenses have been now been approved by government decree.

“FAR has previously mapped a 470 MMbbl prospect called Atum on the Guinea-Bissau shelf edge in a play similar to the large SNE discovery made by FAR and it’s Senegal partners in 2014,” says Cath Norman, FAR managing director. “FAR looks forward to working with Svenska and Petroguin leading up to drilling our first exploration well offshore Guinea-Bissau.” 

FAR’s acreage offshore Guinea-Bissau is shown in the accompanying maps. Blocks 2, 4A and 5A are also known as the Sinapa and Esperanca blocks. 

FAR has mapped the Atum prospect in Blocks 2 and 4A as a shelf edge prospect having a best estimate (P50) prospective resource of 471 MMbbl (gross, unrisked recoverable oil resources). 

The company reported in 2016 to have an extensive inventory of leads and prospects mapped offshore Guinea-Bissau. 

Read more:

FAR, Svenska up stake off Guinea-Bissau

Premier Oil has entered into an infrastructure partnership for the Tolmount gas development in the Southern North Sea, as the company looks to deliver first oil from Catcher in 2H 2017. 

Map of Catcher, Tolmount. Source - Premier Oil.

The company signed a deal with Dana Petroleum and CATS Management for Tolmount, in which the front-end engineering and design (FEED) is underway on the first phase of the project. The agreement will see the trio jointly construct and own the Tolmount platform and export pipeline as a standalone development, as well as undertake the onshore modifications at the Dimlington terminal.

The Greater Tolmount Area, in Block 42/28d, has the potential to contain up to 1 Tcf, including the fully appraised Tolmount main structure of 540 Bcf and upside at Tolmount East and Tolmount Far East, which is estimated to hold 220 Bcf and 150 Bcf of unrisked gas resource, respectively.

The field will be tied-in to the platform and a tariff will be paid to the infrastructure owners for the transportation of gas production through the infrastructure over the life of the field. Premier will maintain its 50% equity interest in the licence.

Premier says that its share of the capex required to develop the large gas field is now estimated at only US$100 million.

“On this basis, Tolmount is a very attractive project, meeting our economic thresholds even at low gas prices, allowing us to use our UK tax losses and with significant further reserve upside,” says Premier Oil.

Subsurface studies on Tolmount East and Tolmount Far East continue ahead of any future appraisal drilling.

In February 2017, Tolmount’s development concept, comprising a standalone normally unmanned installation (NUI) and a new gas export pipeline to shore, was selected. In the initial phase, which will target the Tolmount main structure, it is expected to recover 540 Bcf (P50 estimate) of gas from four producing wells at a plateau production capacity of 300 MMcf/d (gross).

“The first half saw good progress on the Catcher and Tolmount projects, a world class exploration success in Mexico and the acceleration of cash flow from disposals. Following the successful completion of our refinancing, we are ahead of plans to restore financial strength while progressing a number of exciting projects for future growth,” says Tony Durrant, Premier chief executive.

Catcher is set for first oil in 2H 2017. Its total capex is estimated at $1.6 billion, 29% lower than at sanction.

“We now look forward to a rising production profile delivered from our low operating cost base and lower committed capital expenditure as the Catcher field comes onstream,” says Durrant. “Our focus for the second half of the year is to deliver first oil from Catcher on schedule and under budget, to complete our planned disposals and to bring forward to board sanction the Tolmount field.”  

Read more:

Premier's Catcher on track

Premier sets 2017 global plans

Wood Group wins Tolmount FEED