OE's latest review of deepwater subsea tieback projects ongoing in the Gulf of Mexico shows the region is still suffering from the after-effects of the drilling moratorium that followed in the April 2010 Macondo disaster's wake. Jennifer Pallanich checks the status of some of the more notable developments in this sector.
Since OE last updated its files on deepwater Gulf of Mexico subsea tiebacks a year ago, at least nine such projects have begun production. Some of these are standalone projects while others are expansion projects as with Chevron's Tahiti phase two or the final pieces of an initial development plan, as with Shell's Perdido development.
At least four subsea tiebacks are under development: ATP's Clipper, BP's Galapagos, and LLOG's Goose and Mandy fields. Three tieback projects seem to be near sanction: Murphy's Dalmatian and Medusa projects and Noble Energy's Gunflint.
Given the low number of fields in the development phase or awaiting sanction, it appears the effects of the deepwater drilling moratorium that struck the Gulf of Mexico a couple of years ago are still lingering. Some operators have indicated uncertainty no longer remains in the Gulf, so there could soon be an uptick with subsea tieback projects returning to levels of years before the moratorium.
According to Infield Analysts newly published Global Perspectives Subsea Market Report to 2016: Whilst the Macondo-MC 252 disaster was indeed highly significant in terms of the regulatory impact and future project profitability, the USA remains a hugely important and prospective deepwater and subsea market. Indeed, the level of production from deepwater prospects is steadily growing, while the shallow production remains a flatter profile. This fact underlines the growing importance of the subsea market for the USA and the wider region.
Macondo caused a dent in the capex in 2010 and 2011, the report notes. Future investment decisions are expected to involve longer time spans before actual development and face worse financing conditions. On the other hand, any future subsea equipment and infrastructure will need to comply with these regulations and have higher safety specifications, something that will lead to greater capital expenditure per development. In addition, old equipment will need to be replaced or upgraded to match the safety regulations, pushing the subsea expenditure even higher.
Infield estimates companies will dedicate up to $20 billion in developing their tieback projects in the region between 2012 and 2016, with an upward annual trend from $3.4 billion earmarked for 2012 and $4.9 billion the expected spend in 2016. The firm further forecasts the spend for subsea trees alone at $10.3 billion with 174 subsea trees expected to be installed and tied back to host infrastructure by 2016. Up to 380km of umbilicals and power lines are expected to be required to connect the satellite fields with their host facilities in the same time frame.
Just a few months ago, the Anadarko's operated Caesar-Tonga tieback project began production to Anadarko's Constitution spar in 5000ft of water using steel lazy wave riser technology. When the project came onstream in March, partner Statoil said the first three wells were expected to ramp up to 45,000boe/d, with a fourth well slated to be drilled and completed in 2012.
The deepwater fields have an estimated resource base of 200 million boe to 400 million boe. The Constitution spar is in Green Canyon block 680, about 10 miles away from the Caesar and Tonga finds. Caesar was discovered in 2006 in 4500ft of water in Green Canyon block 683 while West Tonga was found the following year in Green Canyon block 726.
Anadarko operates the project with 33.8% interest on behalf of partners Shell (22.5%), Statoil (23.6%), and Chevron (20.3%).
In 1Q 2012, ATP brought onstream the Mississippi Canyon block 942 A-3 well in its Morgus field, which is part of the Telemark project. When production began from the Morgus well to the ATP Titan floating drilling and production platform, the well was flowing at rates of 7000boe/d. Titan, located in 4000ft of water, had already been receiving production from the Mirage field in Mississippi Canyon block 941.
ATP operates the Telemark Hub with a 100% working interest.
Elsewhere in the Gulf, ATP said it expects to begin production at its Clipper project in 2H 2012. The two wells at Clipper in Green Canyon block 300 were drilled and completed last year. They tested at 16,000boe/d, net. The Clipper pipeline is to be installed in 3Q 2012, with production following from the 2005 discovery in 3450ft of water.
Noble Energy, a partner in the BP-operated Galapagos development project, said development work is â€˜essentially complete and expects first production from the Isabela, Santa Cruz and Santiago fields in 2Q 2012.
The three fields included in the project are the 2007 Isabela discovery, the 2009 Santa Cruz discovery and the Santiago discovery of 2011. The fields are to be tied back to the nearby Nakika platform at Mississippi Canyon block 474 where final topside hook-ups and commissioning remained earlier this year. Production will come from the upper and middle Miocene. Noble Energy said production rates are expected at 10,000b/d net.
Noble Energy said the total gross potential for the Galapagos project is 260 million boe. Isabela is in Mississippi Canyon block 562, and Santa Cruz and Santiago are in Mississippi Canyon block 519. Project sanction came in 2009. Water depths are about 6500ft in the region. Noble Energy operates Mississippi Canyon block 519 with 23.25% interest on behalf of partners BP (46.5%), Red Willow Offshore (20.25%), and Houston Energy (10%). BP operates Mississippi Canyon block 562 with 67% interest on behalf of Noble Energy (33%).
Chevron brought phase two of its Tahiti project onstream, with water injection beginning in February. The supermajor said it is drilling and completing additional producers for the $2.3 billion project in Green Canyon block 596, 597, 640 and 641. The waterflood project in 4000ft water depth was sanctioned in 2010.
Wells are producing from pay sands in the Lower and Middle Miocene to the Tahiti truss spar installed in 4200ft of water, which has been in production since 2009. Phase two is intended to keep production levels at 135,000b/d.
Chevron operates Tahiti with 58% interest on behalf of partners Statoil (25%) and Total (17%).
Condor field partner LLOG said the Green Canyon block 448 field began production in June 2011. The DGE-operated single-well subsea tieback to the Marquette facility in Green Canyon block 52 began flowing at 3000b/d and 4mmcf/d gross, LLOG said. The Condor field in 3266ft water depth was originally discovered in 2008.
In June 2012, Eni began production at its Appaloosa project in Mississippi Canyon blocks 459, 460, 503, and 504. The 20-mile subsea project tied back a well to the Eni-operated Corral platform. When it began production this past year, it was at a rate of 7000boe/d. The hydrocarbons join one other well Eni is producing to the Corral platform, which is now processing 46,600boe/d gross. The Appaloosa field is in 2500ft water depth.
LLOG anticipates first production from the Goose field in Mississippi Canyon block 751 in 3Q 2012. The field, discovered by Spinnaker in 2003, is a single well subsea tieback to LLOG's existing Valley Forge production manifold at Mississippi Canyon block 707. The plan includes a single selective smart frac pack completion in two zones.
Spinnaker put its discovery on hold because of a lack of nearby host facilities, effectively stranding the asset, and leading the company to release the block. LLOG acquired full interest in the block in 2009.
LLOG's Mandy development, in 2465ft water depth, features three wells tied back to the W&T-operated Matterhorn TLP in Mississippi Canyon block 243. The Mandy field is in Mississippi Canyon block 243. According to LLOG, the three wells have been drilled, completed and flow tested. The field is expected to flow initially at 15,000b/d and 12mmcf/d beginning in 2Q 2012. LLOG estimates the field holds between 10 and 30 million boe of gross reserves. LLOG operates Mandy with 50% interest on behalf of Apache (50%).
Murphy anticipates sanctioning its three-well Dalmatian development this month. The subsea wells, to be tied back to Petronius, are expected to see first oil in 2015. Murphy estimates the 2008 discovery holds 55 million boe of recoverable resource. The operator anticipates drilling Dalmatian South in 3Q 2012, with well completions slated for mid-2013. Dalmatian lies in DeSoto block 48 in 5876ft of water.
Also expected to begin production in 2015, this time in 2Q, is Murphy's Medusa project. The three-well subsea project, aimed at recovering between 16 and 27 million boe, should see the first production well be spud in 2Q 2013. Murphy operates Medusa in the Mississippi Canyon area of the Gulf of Mexico with 60% interest.
The Newfield-operated Pyrenees field began production in 1Q 2012. The field, in Garden Banks block 293, is in 2100ft of water. The deepwater tieback carries production from the Pyrenees field to Spectacular Bid, Garden Banks block 72 Platform A, which has been online since 1996 in 1785ft of water. Newfield discovered the field in 2009. Stone Energy holds 30% in the block.
Noble Energy said it expects to have results in 2Q 2012 on its Gunflint appraisals in 6100ft of water. The 2008 discovery well hit over 550ft of net pay, and the operator estimates the field in Mississippi Canyon block 948 holds resources of 70-500 million boe or more. Because of the uncertainty of the amount of reserves in the ground, Noble Energy has considered several solutions for Gunflint, including a subsea tieback, a modified existing platform, or a newbuild platform.
One or two more appraisal wells are needed, the company said, noting it is considering a scalable development plan that would make the Miocene development economically viable with existing discovered resources. Front-end conceptual studies are complete. Noble operates Gunflint with 26% interest.
The Raton South subsea tieback is now online, producing 3000b/d net, Noble Energy said. Located in Mississippi Canyon blocks 204, 248 and 292, Raton South in 3400ft of water is tied back to a non-operated host facility.
Last summer, Shell said it would develop its Cardamom field in the deepwater Gulf as a tie back to its Auger production facility. Shell expects the Cardamom project in Garden Banks block 427 to produce 50,000boe/d at peak production and over 140 million boe over its lifetime to the Auger TLP.
Shell's exploration plan for Cardamom in 2720ft water depth was the first to receive approval from the US government after the deepwater drilling moratorium was lifted last year. In 2010 Shell discovered what it has sometimes referred to as Cardamom Deep in 2010 about four miles below the seabed using advanced seismic technology followed by exploration drilling.
The completed subsea system will include five well expandable manifolds, a dual 8in flowline, and eight well umbilicals. Modifications to the Auger TLP include additional subsea receiving equipment, a new production train and weight mitigation, which is expected to increase the Cardamom liquid handling, cooling and production capacities. The first Cardamom Deep exploration well has been producing directly from the Auger TLP since December 2010. The original 1995 Cardamom discovery has produced to the Auger TLP since 1997. The Auger TLP itself has been online since 1994 and has produced over 300 million boe. Shell operates Cardamom with 100% interest.
Marathon is also working to tie its Ozona Deep project in Garden Banks block 515 back to the Auger TLP as a one- well development. Marathon operates the field in 3280ft of water with 68% on behalf of partner Marubeni (32%). According to the Bureau of Safety and Environmental Enforcement, Marathon's Serrano tie back has begun producing to Auger.
Elsewhere in the deepwater Gulf, Shell has continued to tie back fields to its Perdido spar in the Alaminos Canyon area of the Gulf. Late last year, both the Great White field in Alaminos Canyon block 812 and Tobago in Alaminos Canyon block 859 started sending producing to the Perdido spar.
The Great White field is in 7925ft of water while the Tobago field lies in 9436ft of water. OE