SHELL E & P

Hunting for deepwater subtle traps: from geology to technology

Colin J Grant, Francesco Menapace, Uisdean Nicholson, Dominic McCormick, Ciaran O’Byrne, Gabriel Guerra & Jim Pickens

Post-rift, deepwater stratigraphic traps, the main theme of this presentation, have proven highly material where they have a large connected reservoir pore volume and are associated with a rich, active petroleum system. Significant discoveries of this type include the Marlim, Roncador, Albacora, and Mexilhao fields from offshore Brazil, the Foinhaven and Schiehallion fields from the West Shetland Basin, and Ceiba, Jubilee, Tweneboa and Enyenra from offshore West Africa.

Similar subtle traps are also a common success theme in syn- and post-rift stratigraphy of intracratonic rift basins such as the North Sea and likely occur in other underexplored rift, sag and post-rift basins globally. In other areas, however, successful traps have proven to be less than commercial in size. In this contribution, we will look at the trapping styles that are commonly encountered, the seismic technology used to help identify these, the statistics behind these discoveries, and from these identify some of the pitfalls awaiting those eager to join the hunt but for whom geology or serendipity do not favour.

Deepwater Subtle Traps

Two fundamental subtle trap types that recur in deepwater fields with a stratigraphic trapping component are pinch-out or “wedge” traps and erosional truncation traps. The former occur when deepwater sandstones on-lap onto a paleo-slope, while the latter rely upon local or regional unconformities to create sealing geometries. Between these end-member groups occur stratigraphic-structural combination traps that represent the bulk of producing traps. Table 1 shows a synthesis of selected trap types determined from published literature and in-house evaluation. Graphic examples of some of those listed will be shown in the presentation.

Table 1: A selection of DW turbidite traps with a stratigraphic trap component

Hunting for subtle traps: Role of Modern Technology

Today, high fidelity marine 3D seismic imaging and advances in computing technology have made the identification of subtle stratigraphic traps using horizon and interval attribute mapping a standardized interpretation workflow. Multiple technologies exist for rapid screening of multi-attribute volumes to discriminate reservoir fairways, trapping elements and reservoir fluids. With older (pre-Cenozoic) plays or at depths that are below the conventional AvO floor, rock properties can make fluid prediction difficult or impossible even if there is good rock-property calibration available. Shell has developed its own proprietary software for rapid volume screening that provides a fast and efficient way of searching for reservoir fairways. We also have 2D based technologies that can quickly identify stratigraphic pinch-outs. Other technologies that are used routinely to enhance trap understanding are contour or opacity stacking, seismic inversion methods such as elastic impedance inversion, and other quantitative interpretation products aimed at differentiating fluids and reservoirs. However, if the seismic data is band-limited, noisy or both, painstaking loop-level mapping is often needed to augment or replace these more sophisticated methods.

Despite the recent advances in interpretative technology, it is important to remember that the foundations of exploration success in deepwater plays are often laid down at the acreage selection stage. Success begins with selection of the right basin, the right play and the right acreage with the right level of commitment. It involves prudent multi-disciplinary basin evaluation. Often potential fields, 2D seismic, surface geology and play analogue data are only of evaluation. Many of the successes mentioned in this article were made based on solid regional geological foundations that did not rely upon interpretation technology, per se.

The Gold Rush

Since the discovery of the giant Jubilee field by Kosmos Energy in 2007 in Turonian-age deepwater turbidite reservoirs offshore Ghana, the increased pace of exploration along the West African continental margin can be compared to a gold rush. A similar phenomenon has recently propagated around the eastern seaboard of Africa in light of recent spectacular successes offshore Mozambique and Tanzania, albeit chasing a Paleogene deepwater gas play. This

appetite for deepwater acreage has had an impact on the dynamics of the exploration industry.

There are now many more and smaller players operating within this arena than five years ago and, as a result, there is little prospective open acreage remaining. But as with all gold rushes, there will be those who chose wisely and find success, by their own measure, and there will be those who won’t.

Many of the new entrants that have rushed into the African deepwater scene are small to mid-cap companies that are likely to be under-mid-capitalized for the commitments they have taken on.

Deepwater exploration wells now routinely cost between US$60 – 150 MM each. There have also been marked increases in surety-bond liability insurance for deepwater operations following the Macondo incident. A direct consequence of this high-cost environment is that as PSC’s mature and drilling deadlines approach, equity divestment becomes a necessity. Ioffshore Africa, deal flow is going though an up cycle that is a direct consequence of the high cost of deepwater exploration and the difficulty in securing venture capital for drilling operationally and technically difficult wells. Deal flow opens the back door to more conservative corporations that have an appetite for relatively low-risk deepwater exploration. However, substantial financial risks await those who rush into complex deepwater plays without a good understanding of the technical challenges, especially with promotes on equity running as high as three-for-one in some deals.

So all of this begs the question, is the West African Cretaceous deepwater turbidite play currently being hyped by an industry desperate for venture capital, or do the plays warrant continued high exploration expenditure in the light of recent exploration success? Below, we will finish this paper with a look at statistics from exploration drilling, field size estimates and published reservoir data to a plausible answer to this question.

All that is Gold does not Glitter

The graph in Figure 1 shows a creaming curve compiled for the West African Upper Cretaceous deepwater turbidite play. Of the 62 exploration tests in the population sampled, there have been 47 exploration discoveries (an astounding 76% technical success rate). A success rate such as this is as much testament to fine exploration acumen as it is to the trapping potential of deepwater depositional systems. From these there are estimated to be around 17 fields that have been, are being or have potential to be commercialized under existing fiscal and cost environments (a 27% commercial success rate). High technical and modest commercial success spells good news for some as it makes the marketing of undrilled opportunities much easier. It also makes for an easier sell to management when contemplating a farm-in. But creaming curve and success statistics can often be misleading. Discovery sizes and reservoir statistics add much more to the discussion.

Figure 1: West African Upper Cretaceous Deepwater Creaming Curve (data sourced from Wood Mackenzie, data and other open sources).

A field-size distribution chart created from a global dataset comprising deepwater reservoir traps that have a stratigraphic trapping component is shown in Figure . Also shown in this chart is a separation of fields based on reservoir classification. Slope-channel/valley discoveries differ in size by almost an order of magnitude from discoveries interpreted as confined/unconfined apron reservoirs.

The post-rift, West African Upper Cretaceous turbidite play of the transform margin basins comprises sandstones deposited mostly within a slope-channel valley setting. These somewhat inferior quality reservoirs contrast sharply with the quartz-rich, higher-net-to-gross confined and/or unconfined toe-of-slope apron systems that are more common in the Paleogene of offshore Brazil, West-of-Shetland, Mozambique and in the North Sea. Finding modest oil volumes in poorer quality, often thin channelized reservoirs in tough PSC contract environments and in deepwater does not make commerciality easy. These observations might explain a widening gap through time between the technical and commercial success rates across West African basins as well as the increased pace of deal flow in PSC’s in which discoveries have been made.

Over the next couple of years the rapid pace of exploration drilling will eventually uncover whether or not the spectacular successes and high resource densities found within the Tano basin, West Africa and more recently from the Sergipe-Alagoas Basin offshore Brazil, can be repeated elsewhere along the transform and rift margins on both sides of the Atlantic Basin.

Figure 2 Global field-size distributions compiled from deepwater turbidite discoveries with a stratigraphic trapping component. The mean field size from the global distribution is 450 MMBOE. The global distribution is separated into two parts based on reservoir depositional setting: channel/valley and confined/unconfined apron. There is an order of magnitude difference in mean field size between these, posting mean field sizes of 100 and 930 MMBOE, respectively.

The Mamba Complex supergiant gas discovery: an example of turbidite fans modified by deepwater tractive bottom currents.

Franco Fonnesu ¹ Marco Orsi¹

1Eni E&P, Via Emilia 1, 20097 San Donato Milanese (MI), Italy

The huge gas discoveries recently made in Mozambique deep water in both Area 1 (operated by Anadarko) and Area 4 (operated by Eni, with partners ENH, Galp and Kogas) have clearly shown that the Palaeogene turbidite succession represents the main exploration target in both areas. In Area 4 these gas-bearing reservoirs have been indicated with the general term of “Mamba Complex”. Within the Mamba Complex each sandstone reservoir package, that can attain thicknesses on the order of some hundreds of metres, is interpreted to represent a basin floor fan accumulation (sensu Posamentier and Walker 2006) deposited by sand-rich gravity flows during lowstands via slope channels and/or canyons originally connected with a shelf area thought to be located several tens of km westward of Area 4.

With the Miocene, due to the gravitative sliding of the slope, these sediment transfer conduits and part of the terminal fans were progressively incorporated within the advancing deformation front of the east-verging toe thrust system. The most advanced thrust front runs close to the boundary between Area 1 and Area 4. The Area 4, apart from a gently eastward structural dipping and some NW-SE normal faults, can be considered as fundamentally undeformed. This relatively simple structural situation has allowed to reconstruct in detail the external geometry of the fans enlightening that most of the Oligocene and Eocene systems appear to be characterized by seismic geometry and lateral facies changes that are unusual in

“normal” gravity-flow dominated systems: i.e.(1) a marked channel asymmetry with constant southward shifting of sand depocenters (2)Fan tops constantly showing a lateral passage from sand to shale responses along gently southward dipping seismic reflections, (3) local presence of fan-detached sediment waves.

According to the writer’s previous experience in Atlantic-type deep-water passive margins (i.e Angola, Nigeria, Gabon), the Mamba Complex reservoir units are

“anomalous” either in terms of thickness or sand content with respect to the turbidite systems usually found in these settings. The difference is that the Mamba fans appear extremely sand-rich, coarse-grained and developed with thicknesses that never have been directly observed (or described in the literature). In other words, with very few exceptions, the thick-bedded coarse-grained turbidites that constitute the bulk of the fan units (Facies F5 sensu Mutti, 1992) are noticeable for the lack of vertically associated fine-grained facies deposited by the dilute and turbulent part of turbidity currents (Facies F8 and F9). Where preserved and cored, the finer-grained facies show strong evidence of transport and deposition affected by the interaction of turbidite turbulent flow and bottom-current motion: i.e (i) repeated vertical passages, within the same bed, between parallel lamination and ripples indicating velocity pulsations; (ii) presence of mud-drapes within the small-scale cross-laminae; (iii) bi-directionality of the cross-laminae within the same bed; (iiii) shale clasts embedded within fine-grained sand layers. These “anomalous” structures, combined with the seismic geometries above described, support the idea of a possible winnowing and redistribution of the finer materials operated by the action of northward flowing sin-depositional bottom currents capable to deflect and incorporate within the adjacent sediment drifts the fine-grained sediments delivered by the gravity flows.

ABSTRACT

Successful exploration in mature areas; - recipe from Revus and Agora stories Svein Ilebekk, Cairn Energy UK/Norway

Revus Energy AS was established in late December 2002, financially supported by HiTec and 3i with a total committed capital of 50 mills USD. The business model was to organically build an exploration portfolio and to acquire production for tax purposes. The company was listed on the Oslo Stock Exchange in 2005 and was later taken over by Wintershall in December 2008. At the start in 2002/2003 the activity on NCS was low, less than 20 E & P companies were active and only 15-20 exploration and appraisal wells were drilled each year. The oil price was 20 USD when we started the company.

Agora was formed late 2009, in the middle of the financial crises. As the framework conditions had changed since we formed Revus and activity level was relative high, the business model for Agora included exploration drilling on both the UK and Norwegian continental shelves. The financial support, 200 mills USD, was provided by RIT Capital Partners plc and Lord Rothschild’s family interests. After initial successful exploration results Agora was taken over by Cairn Energy early 2012.

During the 10 years of activity in Revus and Agora the companies acquired a number of licences in which there have been a number of discoveries made before and/or after we were taken over by Wintershall and Cairn. In total the two companies have been

involved in more than 20 discoveries on the UK and Norwegian continental shelves. The first of these to be put on stream, Knarr (PL373, BG operator), will start production in 2015. The aggregated forward modeled gross and net productions profiles from the major discoveries indicate 200000-250000 boepd and 60000-80000 boepd respectively in the period 2016-2024.

How to make such an exploration success? It’s a team effort, involving Revus/Agora teams as well as licence partners and stimulated by the UK and Norwegian authorities.

The key success factors are:

• Fit for purpose business plan adjusted to existing framework conditions

• The very best exploration team

• Sufficient financing to support forward plan (3-5 years)

• Good interaction between Board, Management and Employees

• Incentives to all staff, openness, ownership and dedication

• Monitor and measure predicted performance against actual outcomes

Today the exploration activity level on NCS and UKCS are at peak; - strong competition for quality acreage, lack of technical resources, cost increase and rig market vacuum for available slots. Is it possible to duplicate the Revus/Agora story? Yes, it is possible, but will require the very best technical team available in the market, a focused business plan and sufficient funding (300-500 mills USD) and a bit of luck.

Revived exploration on the flanks of Troll

Vegard Gunleiksrud, Tor Veggeland, Richard Olstad, Per Bakøy, André Janke, Kristian Angard, Harald Aubert, Per Avseth and Reidar Müller

Tullow Oil Norge AS, Tordenskiolds gt 6B, 0160 Oslo, Norway

The giant Troll oil and gas Field (Fig. 1) was successfully discovered and appraised by Shell and Norsk Hydro in the late 70’s and early 80’s. On the northern flanks of Troll, the Fram Field structures were discovered by Mobil and Norsk Hydro during a second successful exploration phase in the 90’s. During the last 30 years eight dry wells have been drilled on the western and eastern flanks of Troll.

A general perception (e.g. Goldsmith 2000, Horstad et al 1997) is that more hydrocarbons than what yet is discovered may have migrated into and through the Troll Field. As we understand, there is no established model for spill or leakage out of Troll. Four wells East of Troll targeted the spill route out of Troll, but the structures were proven dry.

Tullow Oil Norge, as operator of the partnerships PL 550 and 551, has identified several prospects both on the migration route into the Troll Field and on the migration route out of the field. The model for the significant Kuro prospect implies a new explanation of the controlling mechanisms of the Troll Field hydrocarbon contacts. Tullow Oil will operate one well in 2013 (PL551) and one well in 2014 (PL550) in order to test some of the identified prospectivity.

As the flanks of the Troll Field had been thoroughly explored through several exploration phases during three decades, we tried to use some alternative approaches in order to define prospectivity. Our highest ranked prospects on the flanks of Troll are to a large degree resulting from the following “not-so-traditional” elements:

• Ultra Far Offset seismic data – valuable info from data formerly regarded as “garbage”

• Injectite sandstone reservoirs – not a traditional play in this area

• Alternative source basin – giving “life” to well known structures formerly regarded too risky

Fig 1. BCU twt map with fields and discoveries (incl. elements from PGS Mega Merge grid)

The PL551 Mantra prospect will be drilled in 2013. Mantra is a 147 mboe oil prospect supported by a depth consistent seismic anomaly in a rotated Jurassic fault block (Fig.2).

The main reservoir is in the late Jurassic Sognefjord Fm, proven as excellent in the Troll Field. The main challenge with the Mantra prospect is source and migration, assuming a main model for sourcing from the marginally mature Heather Fm. at the Uer Terrace.

Alternative models include migration from mature Draupne and Heather Fms. in (1) the Sogn Graben via the Skarfjell oil discovery and (2) the Lomre Terrace.

Fig. 2. Cross section through licenses PL550 and PL551 demonstrating the relationship between the northern tip of the Troll Field and the identified prospects and leads.

The 2013 Mantra well will also test the significant Kuro prospect in a down-flank position.

Kuro is a 118 GSm3 Paleocene gas prospect. Seismic and well observations on the eastern flanks of Troll indicate that Paleocene Ty Fm. sandstones are in direct communication with the Sognefjord Fm. Troll gas pay. The Ty Fm. sandstones are interpreted to be the source (“parent”) of a large scale Paleocene injectite sandstone complex (Fig. 3). Extrapolated Troll gas pressure gradient intersects the regional minimum fracture gradient at depth of the Kuro prospect apex. The apex of the Kuro prospect may act as a pressure valve for the entire Troll Field, and could hold a gas column of 550m in dynamic equilibrium. This hydrodynamic trap/valve model is supported by pockmarks and significant shallow gas observations in the overburden above the Kuro apex.

In the late Jurassic syn-rift succession several stratigraphic trap prospects are identified.

Ultra Far offset seismic data have been key in identifying these prospects. The PL550 Gotama prospect is defined by an ultra far offset seismic anomaly very similar to anomalies matching the Fram and Troll Field outlines. The main reservoir of the Gotama prospect is intra Draupne Fm. sandstone, believed to be re-deposited Sognefjord Fm. sandstones eroded off a paleo “Troll high”.

Tullow Oil Norge holds 5 licenses around the Troll Field, and we believe there is still a substantial potential for discoveries on the flanks of Troll. Drilling activity the next few years will prove whether the prospect models are right or wrong. To be continued …. (Exploration

In document Expanded Abstracts - Exploration Revived 2013 (Page 45-55)