April 2014

Regional Report: Gulf of Mexico

Leasing, exploration and drilling activity in the world’s leading offshore basin has surpassed pre-Macondo levels.

Pramod Kulkarni / World Oil
First oil production began in February 2014 from the Mars B development through the Olympus TLP (left), Shell’s seventh, and largest, floating deepwater platform in the Gulf of Mexico. The Marine Well Containment Company’s (MWCC) single-ram capping stack is now capable of handling well fluids under HPHT conditions—15K psi and 350°F (center). Freeport-McMoran inherited the Holstein drilling and production platform (right) through its acquisition of Plains E&P.   


All the leading indicators are in place for sustained E&P activity over the next decade, and beyond. This includes strong leasing activity in the Central Gulf, new 3D seismic surveys with wide-azimuth technology, and a high level of approved permits and steady drilling operations in both shallow and deep waters. Table 1 shows drilling applications approved by the Bureau of Safety and Environmental Enforcement (BSEE). According to BSEE data, there are more active leases in deepwater areas, but there is significantly more drilling activity in the shallow-water blocks. In the deepwater GOM, the drilling rig count has climbed steadily, from a recent low of 10 in late 2010 to about 58 in March 2014, Fig. 1. Overall, operators have adjusted reasonably well to more cumbersome permitting requirements, including stringent spill containment plans and adherence to the Safety and Environmental Management System (SEMS) II workplace safety rules. Table 2 identifies the specific drilling rigs operating in the deepwater GOM. During 2014, up to 16 newbuild drillships or semisubmersibles will join the Gulf of Mexico deepwater fleet. These include Maersk newbuild drillships Valiant and Viking, which are enroute from South Korea.


Table 1. Approved drilling applications reveal the strength of shallow-water activity.



Fig. 1. After a drastic dip in 2010, rig activity in the deepwater Gulf has shown a rising trend.


Table 2. Drilling rigs operating in the deepwater Gulf of Mexico




In March 2014, the U.S. Department of the Interior’s (DOI’s) Lease Sale 231 for the Central GOM, attracted $850 million in high bids on 326 blocks covering 1.7 million acres. Bidders included BP, prohibited from participating in the last three auctions under a governmental contract suspension. The leading Gulf operator won 24 of its 31 bids, including an area near the firm’s plugged Macondo well. The highest single bid came from Freeport-McMoRan, which bid $69 million and beat out five competitors to drill in the Atwater Valley area, where five discoveries have been made. McMoran bid a total of $321 million. Other winners included Chevron ($103 million), Murphy Oil ($50 million) and Cobalt International ($26 million).


Mexico’s oil and gas industry reforms will take place in two rounds. During Round Zero, which concluded on March 21, Pemex finalized the list of fields that it seeks to keep. Mexico’s energy ministry has six months to determine the company’s technical and financial ability to successfully develop them. Lozoya told Reuters in March 2014 that Pemex will ask to keep all the fields that it currently has in development, both onshore and offshore, as well as areas where the company has conducted seismic surveys, Fig. 2. In Round 1, Pemex will compete with international operators for the remaining blocks. The operators will have opportunities for both profit and production sharing. This round is expected to take place toward the end of 2015 or in early 2016.


Fig. 2. Pemex rig Centanario drilling on the Mexican side of the Gulf of Mexico. Pemex’s Maximino discovery (500 MMboe) was one of the major finds of 2013.


In addition to the Central Gulf sale, the Department of Interior also opened bids in March, worth $21 million, submitted by Exxon Mobil for three blocks that are partially located in Mexican waters. Leases awarded as a result of these bids will be subject to the terms of the U.S.–Mexico transboundary agreement, which was signed recently by President Obama. Meanwhile, Pemex officials made a trip to the Arabian Gulf in late March, to court potential investment partners from that region, such as Abu Dhabi’s Mubadala and International Petroleum Investment Company.


The Paleogene period, commonly known as the Lower Tertiary, occurred between 23 million and 66 million years ago. Fossil records suggest that during this time period, mammals evolved from simple to complex and diverse lifeforms. Perhaps, because of this evolutionary development, the Paleogene formations—specifically the Upper Paleocene and Lower Eocene known as the Wilcox trend—in the deepwater GOM are yielding prolific crude oil reservoirs, Fig. 3. The trend begins onshore and extends across the Alaminos Canyon, Keathley Canyon and Walker Ridge areas, and also Mexico’s territorial waters. However, there are drilling, completion and production challenges, due to water depths to 12,000 ft, drilling depths to 35,000 ft and HPHT conditions. Furthermore, 90% of the trend is below salt canopies, which range from 7,000 ft to 20,000 ft in thickness. Despite the difficulties, numerous operators—BP, Shell, Chevron, Petrobras and Anadarko—have announced significant, recent discoveries at these depths.


Fig. 3. Gulf of Mexico geologic trends with oil and gas pay zones, including the Paleogene Wilcox trend. 



A key factor in the wave of exploration successes in the GOM is seismic surveys. With each advance from 2D to 3D seismic acquisition, enhancements in data processing, such as prestack depth migration, and now wide-azimuth acquisition, operators have been able to better image structural and stratigraphic traps (see sidebar). All the major seismic contractors—Western Geco, PGS, CGG, TGS, Spectrum and others—have acquired multi-client surveys many times over, each with greater resolution and better illumination. Many operators also opt for proprietary 3D seismic for more precise imaging of specific targets, and also employ 4D time-lapse surveys to discern efficient ways to drain the reservoir.


The Gulf of Mexico is an equal opportunity offshore sector. As described below, operators, both large and small, and majors as well as independents, are making significant discoveries and planning ambitious field developments. Noteworthy is the pervasive cooperation between the operators to take advantage of subsea tie-backs and common export lines. There has been significant M&A activity in the Gulf lately, with the departure of stalwarts such as Apache and Devon to focus on shale opportunities, and the resurgence of old timers, exemplified by Freeport-McMoran, and Energy XXI, and the arrival of newcomers, including Cobalt International and Venari Resources.

BP holds 650 leases in the Gulf of Mexico, more than any other operator. The company plans to concentrate future activity and investment around its four major operated production hubs—Thunder Horse, Na Kika, Atlantis and Mad Dog, Fig. 4. In early 2014, BP announced the start-up of production from its Na Kika Phase 3 project (50% BP, 50% Shell). The project includes the drilling and completion of two new wells, and the addition of subsea infrastructure to tie back to the Na Kika platform. Production from Na Kika first began in 2003.


Fig. 4. BP’s Thunderhorse is the world’s largest production-drilling-quarters (PDQ) facility, with production in excess of 200 Mboed.


BP’s latest discovery is Gila, in the Keathley Canyon area, its third significant find in the Paleogene play, following Kaskida in 2006 and Tiber in 2009. Gila is 25 mi to the west of Tiber at a 4,900-ft water depth. The discovery well penetrated multiple Paleogene-aged reservoir sands prior to being drilled to 29,221 ft, TD.

Shell. In February 2014, Shell began production from the Mars B development (Shell 71.5% operator, BP 28.5%) through the Olympus tension leg platform (TLP), 130 mi south of New Orleans. At a 3,100-ft water depth, Olympus has 24 well slots and a self-contained drilling rig. Production from the TLP will ramp up to 100,000 boed by 2016. The TLP will also provide process infrastructure for the adjacent West Boreas and South Deimos discoveries. The entire Mars field has a resource base of 1 billion boe and life-of-field is expected to extend beyond 2050. To date, the field has produced 700 million bbl.

Earlier in July 2013, Shell connected production from Cardamom field (100% Shell) to the Auger TLP. Since coming online in early 2014, the platform is producing near its peak of 50,000 boed.

In May 2013, Shell made a final investment decision on the Stones (100% Shell) ultra-deepwater project, expected to host the deepest production facility in the world. Discovered in 2005, Stones field is in 9,500 ft of water, approximately 200 mi southwest of New Orleans. The project encompasses eight blocks in the Paleogene trend. The development will start with two subsea production wells tied back to an FPSO, due to the lack of infrastructure. However, natural gas will be transported to shore by pipeline. This first phase of development is expected to have annual peak production of 50,000 boed from more than 250 million boe of recoverable resources. In total, Stones field is estimated to contain over 2 billion boe of oil-in-place.

In July 2013, Shell announced a discovery well at Vicksburg (75% Shell, 25% Nexen), 75 mi offshore in Mississippi Canyon Block 393, in 7,446 ft of water. The well was drilled to TD at 26,385 ft and encountered more than 500 ft of net oil pay. The 100-million-boe recoverable resources from the Vicksburg “A” discovery will add to the more than 500 million boe discovered earlier at nearby the Appomattox and Vicksburg “B” wells. The partners are following up the Vicksburg “A” well with a sidetrack to test the Corinth prospect, a separate fault block from the Vicksburg discovery. Shell and Nexen are in the design phase of a semisubmersible production platform for Appomattox.

Chevron. A top leaseholder in the Gulf of Mexico, Chevron’s net production from its deepwater platforms was 91,000 bopd, 69 MMcfgd and 8,000 bpd of NGLs. Foremost among the new projects for Chevron is the host floating production unit (FPU) for Jack and St. Malo fields. The FPU was towed recently to location between the two fields, in 7,000 ft of water in the Walker Ridge area. The facility has a design capacity of 170,000 bopd and 42 MMcfgd to accommodate production from the Jack/St. Malo fields and third-party tie-backs. First oil is expected later in 2014. The fields have recoverable resources of 500 million bbl and a lifespan of about 30 years. Total project cost for the initial development phase is about $7.5 billion. Chevron already has begun FEED studies for Stage 2, with a final investment decision set for 2015.

Chevron’s second major project in 2014 is Big Foot, also in the Walker Ridge area. The planned facility has a design capacity of 75,000 bopd and 25 MMcfgd. The field has an estimated production life of 20 years, and total potentially recoverable resources are estimated to exceed 200 million boe. The platform is expected to be towed to location in third-quarter 2014, and first oil is expected in 2015.

Upcoming projects for Chevron include Stampede (FID in 2014), Rosebank (evaluation), Mad Dog II (evaluation) and Buckskin/Moccasin (appraisal). Setting the stage for a future development is the Coronado discovery, announced in March 2013. The Coronado well was drilled to a TD of 31,866 ft in 6,127 ft of water, about 6 mi from the Shenandoah discovery. The well encountered more than 400 ft of net oil pay.

Exxon Mobil. Two deepwater Gulf of Mexico projects are underway: Hadrian and Julia. Situated in Keathley Canyon Block 964 at a 7,382-ft water depth is Hadrian South field (Exxon Mobil 50%, Petrobras 25% and Eni 25%). The recently drilled KC919-3 wildcat well encountered more than 475 ft of net oil in predominantly Pliocene, high-quality sandstone reservoirs. Later in 2014, production from Hadrian South will be tied back to Anadarko’s Lucius spar.

The first phase of Julia field (50% Exxon Mobil, 50% Statoil) was sanctioned in May 2013 with a capital investment of $4 billion. The discovery well was drilled to a depth of 31,168 ft. Subsequent appraisal drilling has quantified recoverable resources of 6 billion bbl. The field is scheduled to be brought onstream in 2016, with an initial production capacity of 34,000 bopd.

Anadarko Petroleum. In the deepwater Gulf of Mexico, one area that Anadarko is focusing attention on is the Shenandoah basin, in the Walker Ridge area, forecast by the company to have the potential to be one of the largest oil accumulations in the area. Anadarko’s Shenandoah-2 well encountered more than 1,000 net ft of pay in multiple Lower Tertiary reservoirs. The company also has participated in the adjacent Yucatan and Coronado discoveries.

Meanwhile, in the Keathley Canyon area, Anadarko has installed the spar platform at its Lucius field, which is on track for first production in the second half of 2014. This year, Anadarko plans up to four appraisal wells, to delineate the extent of the Shenandoah basin. In 2013, Anadarko sanctioned development of its Heidelberg field in the Green Canyon area. With recoverable resources estimated at 200 MMbbl, the field is expected to commence in mid-2016 with a truss spar that is under construction. Exploration and appraisal activity is in progress at the company’s Deep Nansen, Bimini, Haleakala and Phobos prospects. The Phobos discovery, in the remote Sigsbee Escarpment Block 39, was drilled to a TD of 28,675 ft, in 8,500 ft of water, 11 mi south of the Lucius development.

Noble Energy. Gaining a reputation as a frontier explorer, Noble Energy holds 461,000 net acres in the deepwater Gulf of Mexico, with 35 MMboe of reserves. Its production from eight producing fields is 19,000 boed. The company sanctioned two major projects in 2013: Big Bend, with first production expected in 2015, and Gunflint, with first output planned for mid-2016. Big Bend has gross resources of 30-65 MMboe, with a peak production rate of 22,000 boed (90% oil). The production scheme consists of a single-well subsea tie-back. In the first half of 2016, Noble will tie-back peak production from the adjacent Dantzler field to Big Bend at the rate of 36,000 boed (85% oil). Noble had announced the Dantzler discovery in December 2013. The exploration well encountered over 120 net ft of primarily crude oil pay in two Miocene reservoirs. The well was drilled to a TD of 19,234 ft in 6,580 ft of water. In 2014, Noble Energy is planning a wildcat and appraisal drilling campaign using the newbuild Atwood Advantage drillship, Fig. 5.


Fig. 5. Newbuild Atwood Advantage will be conducting wildcat and appraisal drilling for Noble Energy.


Petrobras. The Brazilian operator was the first to introduce an FPSO-based production system to the Gulf of Mexico. In March 2014, Petrobras set a new production record of 40,000 bopd from the deepwater Cascade (100% Petrobras) and Chinook (66.7% Petrobras, 33.3% Total) fields. Cascade has three wells in operation, and Chinook has two wells. The record was set by bringing onstream two new wells, Chinook-5 and Cascade-6, contributing 28,000 boed to the previous output of 12,000 boed.

Hess is conducting its E&P activity to maintain a production rate of 70,000 boed through 2017. Its key deepwater producing assets are Shenzi, Conger and Llano. Two projects are waiting in the wings—Tubular Bells, with first production slated for third-quarter 2014 at the rate of 25,000 boed, and Stampede, which is awaiting FID in second-half 2014, Fig. 6.


Fig. 6. Crowley recently completed ocean towing services for topsides of the Hess Tubular Bells platform.  


Cobalt International. A relative newcomer, Cobalt holds lease interests in more than 240 deepwater blocks in the Lower Tertiary and Miocene plays. Cobalt operated the North Platte discovery in the Lower Tertiary in 2012. At a well depth of 34,500 ft, the North Platte discovery well is one of the deepest in the region, and encountered over 550 net ft of oil pay in multiple, high-quality, Inboard Lower Tertiary reservoirs. In late December 2013, Cobalt announced a dry hole—the Aegean #1 exploratory well, on Keathley Canyon Block 163, had reached objective TD of 34,701 ft, MD, after having drilled through the targeted, Inboard Lower Tertiary formation. The targeted zones did not encounter commercial hydrocarbons.

Freeport-McMoRan. In late May 2013, Freeport-McMoRan acquired Plains Exploration & Production, to add several deepwater producing fields to its existing shelf and onshore properties. The deepwater facilities are Marlin, Horn Mountain in Mississippi Canyon, and Holstein in Green Canyon. Production volumes for both Marlin and Horn Mountain are expected to reach 60,000 boed, each, by 2018. Holstein hub volumes are expected to reach 40,000 boed by 2016.

Freeport-McMoran has identified 14 exploration and development projects in the Green Canyon area, targeting highly productive Miocene and Wilcox sands with a 995-MMboe net resource potential. In the Mississippi Canyon area, Freeport-McMoran has identified 19 E&P projects, targeting stacked, high-quality Miocene reservoir sands with 286-MMboe net resource potential. Freeport-McMoran made news in March 2014 by bidding $69 million for Atwater Valley Block 198. Meanwhile, the company is continuing its work on two shallow-water, ultra-deep wells with HPHT challenges. These include Davy Jones No. 2, on South Marsh Island Block 234, and Blackbeard West 2, on Ship Shoal Block 188.

Fieldwood Energy. A portfolio company of Riverstone Holdings, Fieldwood Energy is led by a management team constituted from Dynamic Offshore Resources, which had several assets, including the deepwater Bullwinkle field that was originally developed by Shell. The company has gained a high profile through a series of acquisitions. In late September 2013, Fieldwood acquired Apache properties for $3.75 billion. In January 2014, Fieldwood acquired Sandridge Energy properties for $750 millon. As a result, within four months, Fieldwood went from a start-up to a major operator, with production of 125,000 boed and leases on more than 650 blocks. Fieldwood plans to drill 30–45 wells during 2014, to help increase production from both its shelf and deepwater assets.

LLOG Exploration is a leading, privately held, deepwater exploration company with interests in more than 137 blocks (80% undeveloped) in the Gulf of Mexico, net 2P reserves of over 200 MMboe, and net production of 35,000 boed. Its operations are primarily in the Mississippi Canyon, Green Canyon, High Island, Main Pass and South Timbalier areas. In second-quarter 2014, LLOG will employ two newbuild drillships—Sevan Drilling’s Louisiana and Seadrill’s West Neptune—to drill wildcat and appraisal wells. LLOG has operated the OPTI-EX floating production system (FPS) since 2011 for output from Who Dat field. The company is continuing the construction of its Delta House floating production system (FPS) that is scheduled to be installed in the Mississippi Canyon area during first-half 2015. The FPS will have a full capacity of 60,000 bopd and 150 MMcfgd.

Venari Resources demonstrates the value that even a non-operator can generate in the Gulf of Mexico. Through winning bids for leases and joint venture acquisitions, Venari has become a top 15 leaseholder in the deepwater areas. Venari has participated as a non-operator with Anadarko and Chevron, in the Shenandoah and Coronado discoveries.


Marine Well Containment Company (MWCC) is continuing work on an upgraded containment system to handle higher capacity and compatibility with a wider range of well designs, flowrates and environmental conditions. Included in the expanded system are two marine capture vessels. In November 2013, MWCC announced that its single-ram capping stack, which is part of the company’s interim containment system, can now cap a well that has fluids with temperatures up to 350°F and pressures to 15K psi. In May 2013, BSEE and the Helix Well Containment Group (HWCG) conducted a successful week-long test on capping a well at a Noble Energy test site, in a 5,000-ft water depth.


Since the 2009 moratorium, BSEE has steadily stepped up its enforcement of safety non-compliance, Table 3. In April 2013, BSEE issued its SEMS II Workplace Safety Rule through employee training, empowering field level personnel with safety management decisions, and strengthening auditing procedures by requiring them to be completed by independent third parties. Since July 2013, BSEE has overseen the response to three loss-of-well-control incidents. Future plans for BSEE include pre-production inspections, review of deepwater operation plans (DWOPs) and decommissioning of subsea and deepwater structures, such as spars and TLPs.


Table 3. Bsee enforcement activity, number of inspections




The Gulf of Mexico is a natural resource gift that keeps on giving. There are plenty of exploration opportunities in virtually every area and at every depth. If oil prices remain around $100/bbl, and natural gas prices stay above $4/Mcf, the only concerns that operators have are rising costs for services and supplies, and the onset of more rigorous environmental regulations. There are already rumblings from the Obama administration, and environmental activists, about new restrictions on greenhouse gas emissions in an effort to reduce fossil fuel production. wo-box_blue.gif



Some of the best oil and gas prospects in the Gulf of Mexico lie below giant salt structures. Lately, seismic contractors have been shooting wide-azimuth surveys to better image sub-salt reservoir formations. This technique has achieved a step-change improvement in data imaging by increasing the far offsets. Seismic contractor Petroleum Geo-Services (PGS) is going one step even further in its Triton survey through full-azimuth (FAZ) seismic acquisition, with far offsets in excess of 16 km. Conventional wide-azimuth surveys typically provide 8-km offsets.

To illuminate deep, sub-salt Wilcox targets in the Garden Banks and Keathley Canyon areas, the PGS Triton survey utilizes a total of five vessels in its Orion configuration to acquire high-fold, long-offset, dual-sensor FAZ data. This shooting configuration combines two high-capacity streamer vessels, each towing 10 8-km streamers, in combination with three independent source vessels, in a simultaneous long-offset (SLO) configuration. The dual-sensor streamers allow the PGS data processing team to remove receiver ghost effects from seismic data, thereby recovering far greater reservoir resolution and description than conventionally towed hydrophone-only streamers.

“This is the next step forward,” explained Gregg Parker, regional president, North and South America, MultiClient, in a recent interview with World Oil. “The Orion configuration will be able to resolve complex subsalt geology for a highly prospective area that includes recent sub-salt discoveries, such as Gila and Tiber.”

PGS is using seismic vessels Apollo and Valiant to acquire the Triton survey. The data acquisition is expected to be completed by mid-2014, and the processing, which will include advanced depth imaging, will be completed during 2015.  wo-box_blue.gif


The full-azimuth Triton survey is being acquired, using a simultaneous long-offset (SLO) configuration, with 16.5-km offsets to illuminate sub-salt formations across 390 OCS blocks in the Garden Banks and Keathley Canyon areas. The two towed streamers are each 8,100 m long. Three source vessels are used: two vessels 8,000 m ahead, and one in line with the streamer vessels.
About the Authors
Pramod Kulkarni
World Oil
Pramod Kulkarni pramod.kulkarni@worldoil.com
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