Left: Shell’s Stones field will produce to the Turritella FPSO. It will be the deepest FPSO development in the world. Image: Royal Dutch Shell. Center: Anadarko Petroleum’s Heidelberg truss spar development achieved first oil in January, one year after its sister spar Lucius. Image: Anadarko Petroleum Corp. Right: Big Bend and Dantzler fields came onstream towards the end of 2015. The fields are tied back to SBM Offshore’s Thunder Hawk semisubmersible production facility. Image: SBM Offshore.

It is a grim picture in the Gulf of Mexico (GOM)—as elsewhere—with persistently low prices driving ongoing cost-cutting, project delays and cancellations. The smell of layoffs and bankruptcy hangs in the air. Uncertainty about when, and how, a recovery might take place weighs heavy on the pace of E&P activity.

“We’re in a long-term business, but everyone is thinking short-term,” John Hess, head of deepwater operator Hess Corp., told the Houston Chronicle at the February IHS CERAWeek conference.

DEEPWATER HEARTBEAT

Fig. 1. Production in the U.S. Gulf of Mexico (2010–2017), MMbopd. Image: EIA.

Still, there is a pulse, and with it comes the lifeline of work in a fast-receding marketplace. In the midst of the downturn, the deepwater GOM perversely continues in a production boom. After falling every year since 2003, Gulf production was 1.4 MMbopd in 2014, and is expected to average 1.61 MMbopd in 2016 and 1.79 MMbopd in 2017, reaching 1.91 MMbopd in December 2017. That will account for about 21% of total, forecast, U.S. crude oil production, according to the Energy Information Administration (EIA), Fig. 1.

Contributing to the EIA’s forecasted production growth are 14 deepwater projects: nine that started in 2015, four starting in 2016, and one anticipated to start in 2017. Last year’s additions were Silvertip, Deimos South and West Boreas (Shell); Hadrian South (Exxon Mobil); Lucius (Anadarko); Big Bend and Dantzler (Noble Energy); and Marmlard (LLOG Exploration). EIA had expected LLOG Exploration’s Son of Bluto 2 field to come online in 2017, but the subsea tieback began producing to Delta House in April 2015.

Start-ups this year include Anadarko’s Heidelberg field, which began producing in January. Heidelberg is a truss spar, aimed at reducing development costs. Shell’s Stones field development, which is also due this year, uses the second floating production, storage and offloading (FPSO) vessel in the GOM. The first GOM FPSO was installed by Petrobras and put online in 2012. The other two fields starting production in 2016 are subsea tiebacks—Noble Energy’s Gunflint, and Freeport-McMoRan’s Holstein Deep, Table 1.

Table 1. Anticipated deepwater Gulf of Mexico field starts in 2016–2017.

Production from other Delta House tiebacks has been ramping up steadily. Freeport-McMoRan’s (FM O&G) Horn Mountain Deep well, which will be tied back to existing facilities, is expected to begin production during first-half 2017.

Shell’s Stones field. The Turritella FPSO set sail in November 2015 from Keppel’s Singapore shipyard, and it is expected to be in the GOM for start-up before mid-year 2016. Named after a genus of Tertiary age snails, the Turritella was built by an $800-million JV led by SBM Offshore. Shell’s contract for the vessel was signed in July 2013, for an initial period of 10 years

The Stones Lower Tertiary development is in 9,500 ft of water, about 200 mi offshore Louisiana, in the Walker Ridge area. The Turritella will be the deepest FPSO development in the world. Shell holds 100% interest in the project.

Shell achieved first commercial production in the Lower Tertiary from the Perdido platform in 2010. Its Olympus platform in Mars field came online in early 2014, and it is expected to produce up to 100,000 bopd.

Stones field was discovered in 2005, and first-phase peak production is expected to be 50,000 boed from more than 250 MMboe of recoverable resources. The field is estimated to contain over 2 Bboe of OIP.

Phase one of the Stones project starts with two subsea production wells and will ultimately include eight wells tied back to the FPSO. Multi-phase seafloor pumping is planned to pump oil and gas from the seabed to the vessel, increasing recoverable volumes and production rates.

The converted Suezmax FPSO has a disconnectable buoy turret, so that it can weathervane in normal conditions, and disconnect from the FPSO in hurricane conditions. The FPSO is a typical Generation 2 design, with a processing facility capacity of 60,000 bopd, and 15 MMscfd of gas treatment and export. The Suezmax hull will be able to store 800,000 bbl of crude oil, and total topsides weight will reach 7,000 t.

Noble Energy’s Gunflint field. Noble Energy’s Gunflint development is set for start-up in mid-2016. It follows Big Bend and Dantzler production, which went onstream in late 2015 at an estimated 20,000 boed, roughly doubling the firm’s total 2014 GOM production. Situated on Mississippi Canyon Blocks 698 and 782, the fields are subsea tiebacks to SBM Offshore’s Thunder Hawk semisubmersible production facility.

The 2008 Gunflint discovery, a subsalt Miocene find in Mississippi Canyon Block 948, was drilled to approximately 29,280 ft, TD. It found more than 550 ft of net hydrocarbon pay in multiple reservoirs. Two appraisal wells were drilled and evaluated in 2012 and 2013, and the decision to develop the prospect was made in 2013.

The Gunflint plan is for a two-well tieback to come online during mid-2016. Noble contracted EMAS in 2014, to provide installation of subsea pipeline umbilicals and ancillary equipment. The pipeline will tie back to Williams Partners’ Gulfstar floating production system (FPS), which has a base design for up to 60,000 bopd and 135 MMcfgd. The floating spar was moored on site in February 2014, in about 4,300 ft of water. The hub handles production from Hess and Chevron’s Tubular Bells field to feed Williams’ downstream gathering and processing facilities.

Anadarko’s Heidelberg field. Heidelberg achieved first oil in January 2016. It is Anadarko’s second truss spar development in the GOM in the last two years. Heidelberg field was discovered in February 2009, in Green Canyon Block 859, and more than 200 ft of oil pay were encountered. An appraisal well was drilled in 2012 to 31,030 ft, and it hit approximately 250 ft of pay. It has estimated reserves of 200–400 MMboe.

Fig. 2. LLOG’s Delta House FPS came online in April 2015 and reached its rated oil capacity in January 2016.

The development will include six production wells with 6-in. flowlines, 35 mi of 20-in. oil export line, and 9 mi of 16-in. gas export line. The truss spar facility has a capacity of 80,000 bopd and 80 MMcfgd. Its design is the same as the Lucius spar, used in Keathley Canyon, which began production in January 2015 and is estimated to hold recoverable resources of more than 300 MMboe.

Technip built both spars at its facility in Pori, Finland. The Heidelberg spar was the 17th delivered by Technip out of 20 worldwide.

Freeport-McMoRan’s Holstein Deep. Production from the initial, three-well subsea tieback in the Holstein Deep development program is expected by mid-2016. Freeport-McMoRan estimates that the three wells will start production at approximately 24,000 boed. The development is in Green Canyon Block 643, west of the Holstein platform, in 3,890 ft of water. The production facilities can process 113,000 bopd at full capacity. A fourth well is planned as part of the second phase of the Holstein Deep program.

The Holstein Deep delineation well reached TD at the end of 2014, at approximately 31,100 ft. The well encountered about 234 total net feet of Miocene oil pay, with excellent reservoir characteristics and good correlation to the discovery well and a previous sidetrack penetration. The results led Freeport-McMoRan to increase the field’s net potential to more than 250 MMboe from a previous estimate of approximately 140 MMboe. The data support the potential for additional development at Holstein Deep, to achieve production of up to 75,000 boed by 2020.

LLOG Exploration’s Son of Bluto 2. LLOG brought its Delta House floating production system online in April 2015 to initiate production from two 2012 Miocene discoveries—MC 431 Number 2 in Son of Bluto 2 field and MC 300 Number 1 in Marmalard field.

LLOG then began ramping up production to its Mississippi Canyon production facility, and by January 2016, Delta House had reached its rated oil capacity of 80,000 bpd. The FPS has a peak capacity of 100,000 bopd and 240 MMcfgd.

The FPS taps three fields: Son of Bluto, Marmalard and Otis (discovered in 2014). Four more fields may be tied into the host platform. LLOG had completed nine of its 10 development wells in 2015, and planned the 10th for during second-quarter 2016.

LLOG Mississippi Canyon production also comes from 10 wells in Who Dat field. Production there began in 2011, and in 2014, it was 32,000 bopd and 42 Mcfgd.

Freeport-McMoRan’s Horn Mountain Deep. Initial production (IP) from FM O&G’s Horn Mountain Deep well is expected during the first half of 2017. The well, along with two development wells, may produce as much as 30,000 boed.

Positive drilling results were announced in September 2015 from the Horn Mountain Deep well at approximately 16,925 ft, TD. Logs indicated roughly 142 net ft of excellent Middle Miocene oil pay. The results also included the presence of sand sections deeper than known pay sections in the field. The Horn Mountain production facilities in FM O&G’s Mississippi Canyon area are capable of processing 75,000 bopd.

Since starting development in 2014, FM O&G has drilled 12 wells, all with positive results. The firm expects all of them to be completed, and on production, by 2017. The success at Horn Mountain Deep follows the positive drilling results announced in July 2015 from three wells drilled in the Horn Mountain area, including the Quebec/Victory (QV), Kilo/Oscar (KO) and Horn Mountain Updip. In aggregate, these wells may be able to produce over 27,000 boed, with IP expected in mid-year 2016.

GOM BY THE NUMBERS

Rig count. The Baker Hughes rig count of Feb. 29, 2016, pegged the U.S. GOM federal OCS and state count at 25, down 27 rigs year-over-year, a 51.9% decrease. Texas offshore accounted for three rigs versus none in 2015; Louisiana held even at 22 rigs. The highest count on record is 128 rigs in January 2001; the lowest is nine in August 1992.

Table 2. Approved permits by water depth for all types.

For the same period, IHS Petrodata counted 48 contracted rigs, compared to 64 last year. With 123 rigs available, the utilization rate is 66.7% vs. last year’s 79%.

Drilling permits. Deepwater drilling permits continued to grow in 2015, but shallow permits dropped from 434 to just 170, said the Bureau of Safety and Environmental Enforcement (BSEE), Table 2. For January 2016, shallow permits dropped from 18 last year to eight this year; the deepwater count in January 2015 was 58, compared to 59 in January 2016.

Lease sales. As of mid-March, four GOM lease sales remained in the 2012–2017 schedule, Table 3.

Table 3. 2012–2017 lease sale schedule.

The Bureau of Ocean Energy Management (BOEM) conducted consecutive sales on March 23 for the Central and Eastern areas, comprising approximately 45 million acres. Sale 241 in the Central area covered about 8,349 unleased blocks, in water depths from 9 ft to more than 11,115 ft. Sale 226 was the second Eastern sale in the current five-year plan; it offered 162 blocks in water depths from 2,657 ft to 10,213 ft. Sale 241 attracted $156,385,610 in high bids on 128 blocks covering 693,962 acres. Meanwhile, Sale 226 did not receive any bids. Most of the Eastern GOM planning area cannot be offered for lease until 2022, as part of the GOM Energy Security Act of 2006.

Central Sale 247, proposed for 2017, the last in the current schedule, covers 46 million acres. Scoping meetings were completed in 2015, and a supplemental environmental impact statement is being prepared.

The 2017–2022 schedule has 13 potential lease sales planned, and ten are in the Gulf of Mexico.  

Mexico cuts costs and sets deepwater auction

The price of oil is poorly timed for Mexico’s ambitious plans to reinvigorate its energy sector, with changes to Pemex and foreign investment. At the February IHS CERAWeek conference, Pemex CEO José Antonio González Anaya said they were initiating a cost-cutting plan, based on $25/bbl oil. Initial rounds of auctions of onshore and offshore blocks have generated less interest than anticipated.

But stand by. Mexico’s much-anticipated deepwater auction, was set recently for Dec. 5, 2016. Prequalification of bidders takes place on June 14 and July 1. The auction had been postponed after the first public tender, in July 2015, awarded only blocks in the GOM’s southern rim.

The upcoming deepwater auction, the fourth public tender, offers 10 blocks. Four are in the Perdido belt that spans the maritime border. Drilling on the U.S. side has been successful, helping pump up interest in the Mexican side. Six blocks are in the frontier area of the Salina del Istmo basin.

The three prior auctions involved shallow-water and onshore blocks. In 2014, Mexico approved opening the country’s oil and gas industry to foreign investment for the first time since 1938. The first public tender in July 2015 offered 14 shallow-water blocks, with only two awarded in the GOM’s southern rim. Both blocks went to a consortium made up of Sierra Oil & Gas, Talos Energy and Premier Oil. Low oil prices were cited as a key reason for the lackluster showing.

The second auction, in September, did better, with three of five shallow-water blocks receiving bids. The winners were Eni, and consortia of Pan American Energy with E&P Hidrocarburos y Servicios, and Fieldwood Energy with Petrobal.

Tender three in December 2015 involved onshore fields in 26 blocks, in the states of Chiapas, Nuevo León, Tabasco, Tamaulipas and Veracruz. Mexican oil and gas firms won 20 of 25 contracts.