Chief Editor’s Message

This edition’s focus is on salt and sub salt imaging in the Gulf of Mexico (GoM). Having worked in deepwater GoM and having taught deepwater exploration at Houston Community College, I wanted in this column to take some of what I taught before on the different plays in the deepwater GoM, salt tectonics and economics to help explain the importance of deepwater GoM and salt and sub-salt imaging.

The three different major exploration trends in the deepwater GoM are (Cossey, 2004):

1. The Flex Trend play;
2. Fold Belt;
3. And, the Mini-Basin play.

Flex Trend play. Located just beyond the shelf edge, where there is a flex in the sea floor profile. Most discoveries were small reserves, discontinuous sands. These were AVO “bright spots” on 2D data. Larger flex trend discoveries were Pompano, Cognac, Lena, and Zinc (Cossey, 2004).

Fold Belt. The zone of interest for the fold belts is the Lower Tertiary Wilcox which is deposited in turbidity currents (submarine fans) (Meyer et al., 2007). This is the same Wilcox which has been an onshore zone of interest producing primarily gas in fluvial, deltaic, and shallow marine sandstone reservoirs from southwest Louisiana through south Texas to northeast Mexico (Meyer et al., 2007) generally seen on seismic as bright spots.

The Fold belts formed when the salt began to move upward forming salt pillows, fold belts, and thrusts in the sediments above the salt. The centers of the folds or thrusts are salt, and hydrocarbons flow into reservoir sands that are at the top of the folds or truncated by the thrust faults.

The three-fold belts are:

1. Perdido Fold Belt which is on the US-Mexican border in the Alaminos Canyon Area with fields such as Great White; Tobago; Trident Whale; and Silver Tip. The depth of the water tends to be 2440 m to 2740 m and the total depth of the wells is around 5800 m. There are three structural styles present: folding which has 4-way closure, imbricate folds with shallow detachment which is 3-way closure against a fault, and subsaline folding with thrust belts which is 3-way closure against faults;
2. Port Isabel Fold Belt which lies in the Port Isabel area, offshore Texas, which is in the westernmost deepwater GoM, had a series dry wells during the late 1990s which has discouraged further drilling (Bugti and Mann, 2016). The structure is localized zones of intensive, imbricate thrust faulting and associated folding (Bugti and Mann, 2016) which is caused by shortening at depth across these two surfaces with salt and shale diapirism (Bugti and Mann, 2016). Sub-circular shale and salt diapirs at the Oligocene and Miocene levels are characteristic of this fold belt (Bugti and Mann, 2016). It has been proposed by Bugti and Mann (2016) that the inclined thrust surfaces may act as barriers that inhibit vertical migration of oil and gas into higher levels of this fold belt;
3. Mississippi Fan Fold Belt which is in the eastern part of the GoM in the Walker Ridge area. The first discovery was Cascade which was drilled in 2482-m of water and to a depth of 8515 m. The structure tends to be asymmetric thrusts with the zone of interest being like the Perdido Folds (Wilcox).

Mini-Basin play. Mini Basin Plays occur when the salt begins to form into pillows. It is observed that a withdrawal basin forms, which is a mini-basin. There, turbidity currents and source rocks are deposited. As the salt diapir grows, the withdrawal basin further develops, then Turtle structures may form. Turtle structures, such as Thunder Horse, tend to be prolific reservoirs. The two reservoirs are found beneath a thick layer of salt (Waggoner, 2009), and because of this salt layer, it was difficult to see the reservoir.

Traditional narrow azimuth streamer data acquired at different shooting azimuths showed different images beneath the salt. This was due to what is referred to as illumination. Over Thunder Horse multiple narrow azimuth streamer surveys that were acquired at different shooting azimuths were used for interpretation. BP, because of Thunder Horse, developed wide azimuth streamer and nodal data to better image beneath the salt. This was a big change in seismic acquisition.

Thunder Horse consists of two fields known as North and South. Three major reservoirs ranging from approximately 5,480 m to 9,150 m (Waggoner, 2009) exist in both fields, with the reservoirs being Upper Miocene turbidite sandstones. The South field features a four-way structural closure while the North field is a three-way structural closure (Waggoner, 2009).

Thunder Horse is in Mississippi Canyon block 776, 777, 778 and 882. The discovery well was drilled in approximately 1920 m of water to a depth of 7850 m from a drillship, hitting three intervals of oil. The field produces 250 MBOEPD of oil and 200 MMCFPD of gas. It was discovered in 1999 but first oil was seen in 2008, so it took 9 years to get to market (Waggoner, 2009).

BP Thunder Horse Platform is a semi-submersible Production, Drilling and Quarters (PDQ) facility where processing of the reservoir fluids is done onboard, and the oil and gas are exported through separate pipelines to the BP-operated Mardi Gras transmission system, which is the industry’s highest capacity deepwater pipeline (Waggoner, 2009).

All these deepwater GoM plays are related to the evolution of salt diapers from the early stages (fold bets) to the final stages (formation of salt canopies). Salt tectonics, sedimentation, and growth faulting are intimately related. Deep sedimentary basins containing salt are more prospective than basins without salt because salt not only creates the necessary environment for trapping, but it also dissipates heat more efficiently. As a result, the deeper portions of the basin are cooler, this allows the source rock to be in oil window for a longer time.

Costs GoM Exploration. In the 2017 March oil and gas lease Sale (Lease sale 247) the highest bid was submitted by Shell for over $24 million for a deepwater block in Atwater Valley (Marex, 2017). The top 4 high bidders were (Marex, 2017): Shell ($55,856,380); Statoil Gulf of Mexico ($44,500,688); Hess ($43,873,740); Chevron U.S.A. ($35,566,603); and ExxonMobil ($21,910,475).

The key cost drivers for offshore drilling include: water depth; well depth; reservoir pressure and temperature; field size; and distance from shore (US Energy Information Administration, 2016).

Future in the GoM. Many are now looking at the Lower Tertiary Wilcox Trend to supplement the maturing Miocene trend and to maintain the basin’s production level (Viator, 2009). The offshore Wilcox play is estimated to contain 3-50 BBOE with giant fields like BP’s Kaskida discovery (Viator, 2009) and the extent of the Lower Wilcox is over 34,000 mi2 (Meyer et al., 2007). At 3 BBOE and $50 per BOE it works out to be $150 billion worth of oil. The Wilcox Trend is overlain by a thick salt canopy, which until recently has inhibited exploration due to poor subsalt seismic imaging (Meyer et al., 2007).

Another potential play is the Norphlet (Upper Jurassic) oil play, and, like the Wilcox oil play, it is an extension of the mature onshore and continental shelf gas play (McDonough et al., 2008) which was first drilled in 2003 in De Soto Canyon and encountered approximately 30 m of oil column within the aeolian sand (Saunders et al., 2017). Hydrocarbon accumulation is attributed to the Jurassic Smackover Formation, which acts as both the source and seal for underlying Norphlet aeolian reservoirs (Tew et al., 1991; Douglas, 2010). Aeolian deposits have proven to be effective reservoirs due to preservation of high porosity with interconnected pore throats and high net-to-gross sand proportions (Douglas, 2010).

The Norphlet play encompasses an area of approximately 700 mi2 spread across De Soto Canyon, Lloyd Ridge, and Mississippi Canyon protractions.

Shell’s Fort Sumter prospect, drilled in 2016 in the Mississippi Canyon area, was drilled in 2152 m of water to a total vertical drilling depth of 8,539 m measured depth into the Norphlet. The recoverable resources are estimated to be more than 125 MMboe.

There is an interest in Mexico’s deepwater leases. It is believed that some of the unnamed sands in the northern Yucatan margin are related to the Norphlet Formation of the northeastern GOM. This may form a future prospective fairway (Saunders et al., 2017) for the GoM.

Advances in seismic imaging such as those mentioned in this edition of the RECORDER, can help with developing these future trends.

Changes in Engineering. Like what has been happening in the shale plays onshore, there have been significant changes in the drilling and production in the GoM to lower the breakeven price from above $70 BOE to below $50 BOE (Tan, 2017).

The use of subsea tiebacks to nearby existing production facilities has allowed producers to reduce both project costs and start-up times (Blum, 2016). This has been done by leveraging existing infrastructure to reduce the time for a well to come onstream (Tippee, 2016). The time to bring a deepwater well onstream has been reduced to 3 years (Tippee, 2016) compared to BP Thunderhorse taking 9 years to come onstream. Subsea processing technologies has enabled long-distance tieback opportunities that can exceed more than 33 km for remote and marginal fields (Tippee, 2016).

An example of this is ExxonMobil Julia field uses a 25-km subsea tieback to the Chevron operated Jack and St. Malo floating production platform (Tippee, 2016).

Another change in the deepwater is the use of Floating Production Storage and Offloading (FPSO) ships and Floating Production Units that can process the hydrocarbons and offload it to tankers to get the hydrocarbons to market.

FPSO’s eliminate the need to lay expensive long-distance pipelines from the processing facility to an onshore terminal (Wikipedia: Floating production storage and offloading, 2017). This is economically attractive for smaller oil fields, which can be exhausted in a few years and once the field is depleted, the FPSO can be moved to a new location (Wikipedia: Floating production storage and offloading, 2017).

Petrobras was the first to do this to develop its Chinook-Cascade fields which were drilled in Walker Ridge where there was no infrastructure. In Canada there are two FPSO’s in the Grand Banks of Newfoundland.

Floating liquefied natural gas (FLNG) is relatively new, but Petronas has put a FLNG this year in the Kanowit gas field offshore Bintulu, Sarawak, Malaysia (Offshore staff, 2016).

Another change is the implementation of horizontal drilling and fracking in the Gulf of Mexico (GoM) which is providing new profit opportunities in mature fields. There are three geological factors that need to be looked at to determine the success of fracking in reservoirs:

1. Mineralogy. The presence of brittle minerals like silica and dolomite (and to a lesser extent calcite) break like glass while clay is more ductile and absorbs more of the pressure and often bends under applied hydraulic pressure without breaking;
2. Overpressured. If the formation is overpressured the artificially created fracture network can penetrate further into the formation because the formation is critically stressed than normally pressured formation.
3. Rock fabric which is the natural fractures, bedding, etc. that can be obtained through Azimuthal Attributes and Geometric Attributes.

These reservoirs in the deepwater GoM tend to be sandstones and overpressured which will help with fracking the reservoirs.