Global DWOverview.pdf

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2 Global Overview of DeepwaterExploration and Production

with Henry S. PettingillNoble Energy, Houston, Texas, USA

Introduction

Exploration and production in deep water (500–2000 m [1640–6560 ft]) and ultradeepwater (>2000 m [6560 ft]) have expanded greatly during the past 15 years, to the point atwhich they are now major components of the petroleum industry’s annual upstream budget.Most E&P activity has concentrated in only three areas of the world: the northern Gulf ofMexico, Brazil, and West Africa. Globally, deep water remains an immature frontier, withmany deepwater sedimentary basins being only lightly explored.

Deepwater discoveries account for less than 5% of the current worldwide total oil-equivalent resources1 although this amount is increasing rapidly. These resources are predom-inantly oil and are concentrated in non-OPEC countries; thus, deep water represents animportant component of the world’s future oil equation. Gas exploration in deep water isextremely immature, reflecting current infrastructure and economic limitations, but it is alsodestined to become a major focus in the future.

Although the global deepwater play was initially restricted to a few large major compa-nies, progressively smaller companies have become involved throughout time. Presently, evenlarge- or medium-size companies must understand the geologic, engineering, and economiccharacteristics of the deepwater play. Generally, smaller companies are exploring in areaswhere (1) major infrastructure already exists, and consequently they are able to operate, and/or(2) they can be a partner with a limited working interest, thus limiting their financial risk whilestill exposing them to potentially high rewards.

This chapter presents an overview of exploration and development in deepwater settings.The first part addresses the critical geologic aspects of global deepwater exploration and pro-duction by summarizing the geologic habitat, productive trends, and potential reserves. Thesecond part summarizes these characteristics for the past and present frontiers and presentscommon themes and concepts that lead to speculation concerning the future of deepwaterfrontiers. The third part addresses trends in the technologic and business requirements neces-sary for exploring and developing deepwater plays. Finally, we briefly summarize theworkflow for explorationists who develop and work deepwater prospects.

This chapter is, in part, an update of previous work (Weimer and Pettingill, 2000; Pettin-gill and Weimer, 2001, 2002). The chapter employs data compiled from public informationsources and presentations at recent conferences dedicated to deepwater geology, such as Wor-rall et al. (1999, 2001), Lawrence and Bosman-Smits (2000), and many trade magazines.

Exploration and production trends of deep and ultradeep water

Discovered petroleum resources in deep and ultradeep water

By the end of 2002, approximately 74 billion BOE of total resources had been discov-ered in deep water from 18 basins on six continents (Figures 2-1a–2-1c, 2-2). Most resourceshave been found in the northern Gulf of Mexico, Brazil, and West Africa (Figure 2-2). This

1. The term “resources” is employed here, rather than “reserves,” to reflect the fact that not all of the discoveredhydrocarbons have been proven to be economic, and therefore they are not classified as reserves. For all bar-rel oil equivalents (BOE), the conversion factor employed is 6000 cu. ft. gas = 1 barrel oil or condensate.

Global Overview of Deepwater Exploration and Production

2-20

Figure 2-1a. Deep water discovered resources versus time as of end of 2002. (a) oil versus gas.Updated from Pettingill and Weimer (2001).

Figure 2-1b. Deep water discovered resources versus time as of end of 2002. (b) Resources (billionBOE) based on deep water (500–2000 m) versus ultra-deep water (>2000 m). Updated from Pet-tingill and Weimer (2001).

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Exploration and production trends of deep and ultradeep water

2-21

Figure 2-1c. Deep water discovered resources versus time as of end of 2002. (c) Developed versusundeveloped resources. A significant amount of gas found prior to 1984 remains as strandedresources. Updated from Pettingill and Weimer (2001).

total consists of 43 million bbl of oil and condensate, and approximately 180 trillion ft3 (tcf) ofgas. Deep water (500–200 m [1640–6560 ft] deep) holds about 85% of the discoveredresources; ultradeep water has about 15% (Figure 2-1b). More than half of this total has beendiscovered since 1995; however, only about 31% of the total resources are developed or cur-rently under development and less than 5% have been produced, thereby underscoring theplay’s immaturity (Figure 2-1c).

The global deepwater exploration success rate2 was about 10% until 1985, but it hassince averaged approximately 30%, having been driven by remarkable success in the Gulf ofMexico and West Africa (Figures 2-3, 2-4). Exploration success rates have been highest inWest Africa and lowest in Asia. In the lower Congo Basin, the geologic success rate over thepast few years has exceeded 80%.

Since deepwater drilling started during the late 1970s, 38 giant discoveries (>500 mil-lion BOE recoverable) have been made in deep water (Table 2-1; Figure 2-5). Of the 58 giantsof the decade 1990–99 that were true wildcats, roughly one-third were found in deep water(Pettingill, 2001). Although the total number of giant fields discovered worldwide in recentdecades has leveled off, the discovery rate of deepwater giants is rapidly increasing. Associ-ated deepwater giant reserves are approximately 66% oil, compared with 36% oil for all giantsof the same time period.

2. Published reports more often do not distinguish geologic success from economic success. Furthermore, it isdifficult to determine economic viability for recent unappraised deepwater discoveries, which are often farfrom infrastructure. These quoted success rates are corrected for obviously uneconomic discoveries, but theyundoubtedly reflect some discoveries that will become economic only after further infrastructure growth orother fiscal/market changes and others that will ultimately be deemed uneconomic. Therefore, these successrates are probably intermediate between geologic and economic success. Nonetheless, because most of thediscoveries in the major provinces could probably be developed economically once infrastructure is estab-lished and/or contract terms improved, these success rates may be taken as a reasonable indication of eco-nomic success (i.e., as a slight overapproximation).

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Cumulative Total Deep Water

Cumulative Total Developed

1985 Total:

60% Developed by 2002

1990 Total:


2002 Total: 31%

Developed or in

Development

1995 Total:



2-22

Figure 2-2. Total discovered deep water (>500 m ) recoverable resources per region, announced as of November 2003 (in billion BOE). These resourcesinclude producing reserves, those in development, and technically recoverable resources for which development has not been sanctioned. Major prospec-tive deep and ultradeepwater basins are also shown. Green = oil, red = gas. Updated from Pettingill and Weimer (2001). Note that the resource estimatesin Figures 2-1a to 2-1c (74 billion BOE) were compiled at the end of 2002; the estimates for Figure 2-2 (78 billion BOE) were compiled in November 2003.

1Pettingill & Weimer 2002

Mid-Norway

Faroes

White Zone

W. Shetlands

NWS & ZOCA

US GoMTamaulipas & Campeche

Morocco

Scotian &Jeanne D’Arc

Trinidad

Sakhalin

NigeriaEq. GuineaGabonCongoAngola

Mozambique

S. Africa

Tanzania

So. CaspianItaly

Egypt

NW & SE BorneoNW & SE Borneo

PhilippinesPhilippines

3.5

Areas of Prospective Deepwater

and Ultra-Deepwater Basins

10,9

6,8

0.4

9.6

3,0

0,8

2.9

E. India

Taranaki

RecoverableResources in BBOE

green= oil, red = gas

Total Discovered

78 BBOE

48 BBO + 174 TCF

:

8,6

3,0

11

4.4

Brazil

1,82.4

1.5

3

183

17

Petroleum geology of deepwater basins

2-23

Figure 2-3. Exploration success rate in six primary deep water regions of the world, and globalaverage. Data from this study and from Harper (1997). Updated from Pettingill and Weimer(2001).

Although the Organization of Petroleum Exporting Countries (OPEC) accounts foralmost 80% of the world’s current oil reserves (BP, 2003), only 17% of the world’s current oilreserves lie in OPEC’s deep waters, all in the waters of Nigeria and Indonesia. In contrast,members of the Organization for Economic Co-operation and Development (OECD; an inter-national organization comprising 30 member countries from Europe, Asia, the Middle East,Australia, and North America; see www.oecd.org) account for only 8% of current global oilreserves but hold 27% of current deepwater oil resources discovered to date (Figures 2-4, 2-5).The OECD accounts for 73% of the world’s deepwater gas resources reported to date, but only9% of the current total global gas resources. Therefore, deep water is a frontier with relativelymore resources for the OECD, particularly when we consider the gas fraction of the total deep-water resources.


Basin types

Worrall et al. (2001) divided the global deepwater play into four broad types of basins:(1) basins with mobile substrates (salt, shale) fed by large rivers; (2) basins with mobile sub-strates fed by small rivers; (3) basins with nonmobile substrates fed by small rivers; and (4)basins containing nondeepwater reservoirs. To date, about 75% of the discoveries in deepwater occur in the first two types of basins (Figure 2-6).

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(%

)

http://www.oecd.org


2-24

Figure 2-4. Deep water giant discoveries exceeding 500 million BOE, as of November 2003. The South Atlantic and Gulf of Mexico discoveries consist ofoil and gas; Europe, Asia, and Australia are predominantly gas discoveries. MMBOE is million barrels of oil equivalent; BBOE is billion barrels of oilequivalent. Data from IHS Energy Group (2003, used with permission) and many published references. Includes data supplied by Petroconsultants SA;copyright 2003. Updated from Pettingill and Weimer (2001).

each stack of barrels represents one field:

green = >50% oil

red = gas

= 500 MMBOE

Ormen Lange11 TCF

Malampaya 4.7 TCFE

Scarab-Saffron 4.5 TCFSimian 2.5-4.0 TCF

Jansz* 20 .0 TCFScarborough 6.0 TCFGeryon-Orthrus 4.0 TCFIo* 4.0 TCFCallirhoe 3.5 TCFChrysaor 3.3 TCFE

Dalia 975 MMBOEGirassol 883 MMBOEHungo 725 MMBOEKissanje 550 MMBOE

Sunrise-Sunset 9.5 TCFE

Bosi 1.1 BBOE Agbami 876 MMBOEBonga 810 MMBOEAkpo 790 MMBOEBong. SW 583 MMBOENNWA-Doro 4.4 TCF

Deep Water Giants(>500m Water Depth, >500 MMBOE)

35 Discoveries, 38 BBOE

1-RJS-582 300-600 MMBOE1-SPS-35 2.5-14.7 TCF

Roncador 3.2 BBOEMarlim 2.9 BBOEMarlim Sul 2.7 BBOEAlbacora 964 MMBOEBarracuda 860 MMBOE1-ESS-121 660 MMBOE

Dhirubhai 4.8 TCF

Kikeh 530 MMBOE

Thunderhorse 1.0 BBOE

Mars 570 MMBOE Tahiti 502 MMBOE

Brecknock 5.9 TCFE


2-25

Table 2-1. Giant deepwater discoveries (>500 million BOE). Several are not fully appraised and are expected to change significantly. Includes data supplied by Petroconsultants SA; Copyright 2003.

Basin/Country

Discovery name

Discovery near

StatusRecoverable

resourcesWD (m)

Resource reference

Gulf of Mexico, USA

Mars 1989 Producing486 million bbl oil + 504 bcf

1014 IHS, 2003

Gulf of Mexico, USA

Tahiti 2002 Discovery 502 million BOE 1231 IHS, 2003

Gulf of Mexico, USA

Thunderhorse 1999 Discovery 1.0 billion BOE 1963 IHS, 2003

Campos, Brazil 1-ESS-121 2002 Discovery 660 million bbl oil 1426 IHS, 2003

Campos, Brazil Albacora 1993 Producing872 million bbl oil + 549 bcf

1000 IHS, 2003

Campos, Brazil Barracuda 1989 Producing807 million bbl oil + 316 bcf

1160 IHS, 2003

Campos, Brazil Marlim 1985 Producing2.7 billion bbl oil + 1.2 tcf

853 IHS, 2003

Campos, Brazil Marlim Sul 1987 Producing2.5 billion bbl oil + 1.3 tcf

1120 IHS, 2003

Campos, Brazil Roncador 1996 Producing2.9 billion bbl oil + 1.75 tcf

1853 IHS, 2003

Santos, Brazil 1-RJS-582 2002 Discovery288 million bbl oil + 139 bcf (poss. 300–600 million BOE)

1493 IHS, 2003

Santos, Brazil 1-SPS-35 2003 Discovery 7.7 tcf 485 IHS, 2003

Møre, Norway Ormen Lange 1997 Discovery13.2 tcf +138 million bbl cond.

886 IHS, 2003

Nile Delta, EgyptScarab-Saffron Complex

1998 Producing 4.5 tcf total 612 IHS, 2003

Nile Delta, Egypt Simian 1999 Discovery 2.5–4.0 tcf 579IHS, 2003; Upstream,

2002

Lower Congo, Angola

Dalia 1997 Developing900 million bbl oil + 450 bcf

1360 IHS, 2003

Lower Congo, Angola

Girassol 1996 Producing725 million bbl oil + 950 bcf

1365 IHS, 2003

Lower Congo, Angola

Hungo 1998In develop-

ment700 million bbl oil + 150 bcf

1202 IHS, 2003

Lower Congo, Angola

Kissanje 1998In develop-

ment500 million bbl oil + 300 bcf

1011 IHS, 2003

Niger Delta, Nigeria

Agbami 1998 Discovery780 million bbl oil + 576 bcf

1435 IHS, 2003


Akpo 2000 Discovery590 million bbl oil + 1.2 tcf

1366 IHS, 2003

Table 2-1 continued on next page


2-26

Mobile-substrate, large-river basins

Where large rivers are available to deliver large volumes of sediment into the deep water,there is the potential for abundant deepwater reservoirs. The sediment loading and deformationof the mobile substrate creates stacked reservoirs, a high density of leads, multiple play types,and migration pathways. Both extensional and contractional domains exist within thesemobile-substrate basin settings. The large volume of sedimentary fill causes the generation ofpetroleum. Examples of producing basins with salt as the mobile substrate include the LowerCongo (deepwater Angola) and the northern Gulf of Mexico. Deepwater Nigeria is the pri-mary example of basins with mobile shale and a large-river sedimentary delivery system(Figure 2-7).


Bonga 1995 Developing735 million bbl oil + 451 bcf

1125 IHS, 2003


Bonga South-west

2001 Discovery500 million bbl oil + 500 bcf

1245 IHS, 2003


Bosi 1996 Discovery683 million bbl oil + 2.3 tcf

1424 IHS, 2003


Nnwa-Doro 1999 Discovery 4.4 tcf 1283 IHS, 2003

Krishna Goda-vari, India

Dhirubhai 2002 Discovery 4.8 tcf 1006 IHS, 2003

W. Palawan, Philippines

Malampaya-Camago

1989 Producing3.5 tcf +198 million bbl oil/C

736 IHS, 2003

Baram (Sabah), Malaysia

Kikeh 2002 Discovery 530 million bbl oil 1341 IHS, 2003

Bonaparte, Australia

Sunrise-Loxton-Sunset

1975 Discovery7.7 tcf + 299 million bbl cond.

159 IHS, 2003

Browse, Australia

Brecknock 1979 Discovery5.3 tcf +103 million bbl cond.

543 IHS, 2003

Carnarvon, Australia

Callirhoe 2001 Discovery 3.5 tcf 1221 IHS, 2003


Chrysaor 1995 Discovery2.9 tcf + 75 million bbl cond.

806 IHS, 2003


Geryon-Orthrus 1999 Discovery4.0 tcf +1.2 million bbl cond.

1231 IHS, 2003


Io 2001 Discovery included in Jansz 1352 —


Jansz 2000 Discovery20 tcf + 54 million bbl cond.

1321 IHS, 2003


Scarborough 1979 Discovery 6.0 tcf 912 IHS, 2003

Table 2-1. (Cont.) Giant deepwater discoveries (>500 million BOE). Several are not fully appraised and are expected to change significantly. Includes data supplied by Petroconsultants SA; Copyright 2003.

Basin/Country

Discovery name

Discovery near

StatusRecoverable

resourcesWD (m)

Resource reference


2-27

Figure 2-5. Giant oil and gas field discoveries of the 1990s (98 billion BOE from 76 discoveries).Discovered resources versus physical environment (onshore, shallow water: 0–500 m, and deepwater: >500 m), and distribution of oil, condensate, and gas. Inset shows distribution of deepwa-ter resources for OPEC, OECD, and the rest of the world. After Pettingill (2001). Reprinted withpermission of SEG.

Figure 2-6. Discovered resources versus deepwater basin setting. Classification of mobile sub-strate and unconfined turbidite settings is adapted from Worrall et al. (1999, 2001). Additionalfrontier settings are added here, with corresponding reserves from this study. Note that “con-fined” and “unconfined” are end members, and basins may evolve from one to the other or varyspatially between end members. A portion of the confined resources are actually in a low-confine-ment setting (e.g., Marlim, Albacora, Campos Basin, Brazil), as shown on the graph. Updatedfrom Pettingill and Weimer (2001).

44%

20%

36%

Total: 98 BBOE from 76 Discoveries >500 MMBOE

Gas

Condensate

Oil

Deep Water 1990’s Giants:

20 BBOE from 23 Discoveries

Deep Water

Oil Opec

15%

Deep Water

Gas

41%

Deep Water

Oil Non-Opec

44%

Mobile Substrate Extensional

Mobile Substrate Contractional

Confined w/o Mobile Substrate

Unconfined

Non-deepwater Reservoirs

12%

0.03%

10%

10%

68%

Percent of Global Deepwater Total Reserves (78 BBOE)

Confined UnconfinedBasin FloorExtensional Contractional

Mobile

Substr

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ate


2-28

Figure 2-7. Schematic cross-sections illustrating the different petroleum systems for deepwater settings. Each

section shows the relationship of source rocks with structural styles, stratigraphic fill, and migration path-

ways. 1. Rift source rocks (often lacustrine) (a) with salt deformation: Campos and Santos Basins (Brazil), and

Lower Congo Basin (offshore Angola), (b) basement blocks: northwest Australia, West of Shetlands, and mid-

Norway; 2. Marine source rock (a) early divergent margins source rock: northern Gulf of Mexico, lower

Congo and Nile, (b) Cenozoic divergent margin (Niger Delta, northwest Borneo Mahakam Delta). 3. Active

margins: Apennine foredeep. 4. Biogenic gas: Nile Delta, northern Gulf of Mexico. Inset chart illustrates the

relative amount of discovered resources versus source rock. Modified from Pettingill and Weimer (2001).

1A Pre-Pass. Marg. Rift SR 1B Rift SR, No Salt

Lower Congo N.W. Australia (Canarvon, Bonaparte)

Campos and Santos West ShetlandsMid-Norway

2A Early Pass. Marg. Marine SR 2B Tertiary P. Marg. Marine SR

U.S. GoM Niger DeltaPoss. Lower Congo N.E. BorneoNile Delta Mahakam Delta

1. RIFT SOURCE ROCK (often lacustrine)

2. PASSIVE MARGIN MARINE SOURCE ROCK

3. ACTIVE MARGINS

Apennines Foredeep

4. BIOGENIC

Nile Delta (partial contribution)Gulf of Mexico (e.g. Mensa)

Discovered Resources vs.

Source Rock Habitat:

3. Active Margin& Other 1%

1B. Rift, No Salt(mostlyMarine)

16%

4. Biogenic 2%

1A. Rift, Pre-Salt Lacustrine

35%

2A. Passive Margin Marine, Pre-Salt 2%

2A. Passive Margin, Post-SaltMarine

28%

2B. Pass. Marg. without Salt, Marine Deltaic

16%.


2-29

Mobile-substrate, small-river basins

Mobile-substrate basins that are fed by smaller high-sediment-load rivers occur alongsteep margins. Petroleum-producing examples include several of the basins around the Islandof Borneo (Brunei, Sabah, and Sarawak) and also the Campos Basin in Brazil. For this latterexample, the Neocomian lacustrine source intervals occur below the mobile substrate (Aptiansalt). As a consequence, understanding and predicting the charge history is a greater challengein this basin and complicates deepwater prospectivity (Figure 2-7).

Nonmobile-substrate, small-river basins

Deepwater basins with no mobile substrate that are fed by small rivers have a density ofleads that is about one-half that in basins with mobile substrates, but the lead size is 10 timesas large. Examples of basins that produce from such a setting include (a) West of ShetlandIslands fields—Foinaven and Schehallion fields, and (b) More and Voring Basins in offshoremiddle Norway. The Ormen Lange gas field in the mid-Norwegian Shelf consists of reservoirsdraped over basement structures (Gjelberg et al., 2001) (Figure 2-7). The key aspect in thesekinds of basins is that basement highs help focus petroleum migration. Commonly, the reser-voir will occur draped over basement highs.

Nondeepwater-reservoir basins

The final type of deepwater basin contains reservoirs that were not deposited originallyin deep water. For example, the North West Shelf of Australia produces from Jurassic and Cre-taceous fluvial-deltaic synrift strata. The overlying postrift section is thin and has subsidedinto deep water (>500-m water depth). Examples of shallow-water carbonate reservoirs indeep water include the Malampaya field, Philippines, and recent Albian discoveries in theCampos Basin, Brazil. Also, these basins reflect a small portion of production in deep water(Figure 2-6).

Petroleum systems

The six elements of the petroleum systems of deepwater and ultradeepwater margins arebriefly summarized here. The most common types of petroleum systems found in deep waterare summarized in Figure 2-7.

Reservoirs

To date, most deepwater reserves have been discovered in Cenozoic-age reservoirs,although there is a modest but growing contribution from Cretaceous reservoirs (Figure 2-8).Almost 90% of the reserves found, to date, are within deepwater sandstone reservoirs, butthere is a small contribution from shallow-marine and fluvial sandstone reservoirs and a minorcontribution from carbonates. Porosity and permeability in deepwater reservoirs can be excel-lent (>30% porosity and thousands of md permeability), because many are fed from matureriver systems that drain stable cratons. Furthermore, high porosities are often maintained bylow geothermal gradients (which retard diagenesis) and underconsolidation resulting fromoverpressures. These are typical characteristics of deepwater areas downdip of young deltaicdepocenters. Reservoir architecture (connectivity and continuity) ranges from poor to excel-lent in deepwater sands. In general, high net/gross channel-fill and basin-floor sheet sandsprovide excellent reservoirs, whereas low net/gross channel-fill and thin-bed levee reservoirscan be more difficult to develop economically. Predrill predictive capability for these reser-voirs is critical.


2-30

Figure 2-8. (a) Deepwater resources discovered after 1978 plotted versus reservoir age and (b) deepwaterresources versus lithology. Lithology data for 200–500 m are from Cook (1999, used with permission); data for>500 m are from Pettingill and Weimer (2001). Note the differences in reservoir types with the water depths.Updated from Pettingill and Weimer (2001).

Traps

Trap styles vary, and the main trap types of turbidite plays are shown in Figure 2-9. Totalreserves associated with these trap types have yet to be quantified; however, a significant pro-portion of resources is from fields having a stratigraphic component to their trap. To date,structural closure is dominant in West Africa, although often the trap volume is defined by theoverprint of stratigraphic pinch-outs and discontinuities. In the salt minibasin plays of the cen-tral Gulf of Mexico, combination structural-stratigraphic traps are most common (Pettingill,1998), whereas in the emerging foldbelt plays, structural trapping is dominant. In the uncon-fined setting, depositional mounding may create or enhance structural closure (e.g.,Scarborough discovery; Kirk, 1994). On the other hand, pure stratigraphic traps also occur inthe unconfined setting, where offlapping fan deposits pinch out laterally (e.g., Ram-Powellfield; Clemenceau et al., 2000).

Seals

In the deep-marine depositional environment, adequate top seals are generally present.Top-seal integrity, on the other hand, is often a serious risk because of overpressures andcrestal faulting. Understanding the relation between reservoir pressure (from both bouyancyand overpressure), overburden pressure, and rock strength, is critical. In Nigeria, Brunei, andthe northern Gulf of Mexico, some accumulations are more aptly described as “imperfectleaks” than as perfect traps. When a component of stratigraphic trapping is required, the pres-ence of a side seal can also introduce risk, especially in the case where the updip axis of afeeder channel is required to seal. Relatively few fields are documented to have this seal com-ponent, although several exist in the northeastern deep Gulf of Mexico.

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Not PublishedNeogene-PleistocenePaleogeneCretaceousTriassic-Jurassic

8591

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113 1

0%

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Water Depth (m)

Perc

en

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eep

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TurbiditeSandstone

ShallowMarine &Fluvial Sst.

A. B.


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Figure 2-9. (a) Schematic diagram showing different trap styles for the deepwater settings. AfterPettingill and Weimer (2001). Reprinted with permission of the Gulf Coast Section SEPM Foun-dation. (b) Discovered deepwater resources versus the trap categories. Note that total resourceswith published trap information is 28 BBOE (about one third of resources discovered), so obser-vations are preliminary. (c) Classification of trap type employed for this study. As defined by thisclassification scheme, structural traps have only structural elements (faults, dip-closure, or dia-per interface), whereas pure stratigraphic traps depend solely on reservoir discontinuity. Combi-nation traps, however, exist only if both types of elements are in place (examples shown in lowerleft of A).


Unconfined Settings

Basement

Block

Foldbelt Structures

(may be either

salt- or shale-

cored)

Stratigraphic Traps

(A) Updip Pinchout

(B) Erosional truncation

(C) Updip channelpinchout

Fault Traps

Confined Settings

Combination Structural - Stratigraphic(a) Fault & pinchout (b) Diapir flank & pinchout

Fault-RelatedRollovers Fault-Dependent

Salt Flank Traps

Shale Diapir

Traps

Turtles

A.

Combination64%

Structural26%

B. Discovered Resources vs. Trap Type

PureStratigraphic

10%

A1

Sand A

-Structure-dependent(fault, 4-way, diapiric)

-Filled to equal - elevation(often to spill)

1. STRUCTURAL a. with no stratigraphic overprint

A A`

A

A`

Sand

A 1

AShale


-Not filled to equal-elevationdue to strat. limitations

b. with no stratigraphic overprint

Trapping depends on both:

-Stratigraphic variation(pinchout, erosional,

truncation, diagenesis)

AND

-Structural element







A`

A

B`

B

C

C`

Shale

Shale

Sand

2. COMBINATION

3. PURE STRATIGRAPHIC

Stratigraphic dependent only

(pinchout, erosional

truncation, diagenesis)

B`

B

A`

A

A A`

CC`

B B`

B B`

A A`

C. Classification of Trap Type


2-32

Source rocks

The potential for source rocks is good in deep water; world-class source rocks have beenfound in Jurassic, Cretaceous, and Tertiary strata (Figure 2-10). In general, five kinds of sourcerocks have been identified for deepwater and ultra deepwater settings: three are oil-prone andtwo are gas prone.

Potential oil source rocks for deepwater plays can be either continental or deep-marinein origin. First, good lacustrine source rocks have been documented in synrift settings, such asin the Campos Basin of Brazil and in portions of West Africa (Guardado et al., 1990, Teisser-enc and Villemin, 1990, Sequeria et al., 1998, Schiefelbein et al., 2000).

Second, deep-marine potential source rocks were deposited during the later stages ofevolution of several of the world’s continental margins and are associated with major trans-gressions or relative rises (Mitchum et al., 1993; Duval et al., 1998). The present-daydeepwater environment is a continuation of ultradeepwater depths established during theMesozoic in most frontier regions of the world (e.g., the Atlantic margins and the Gulf of Mex-ico). This prolonged period of deposition in bathyal water depths can produce excellent sourcerocks, although their efficiency varies through time and space. Along the West African margin,multiple marine source rocks exist and are progressively younger with movement into deeperwater. Some of these may be considered “world class,” such as the Akata Shale in Nigeria(Doust and Omatsola, 1990, Tuttle et al., 1999) and the Iabe/Landana Formations in the lowerCongo Basin (Rummelhart et al., 2001).

Figure 2-10. Graph showing recoverable resources in deep water versus the age of the sourcerocks. Most of the discovered resources have Jurassic or Cretaceous source rocks. Updated fromPettingill and Weimer (2001).

0

5

10

15

20

25

30

35

Rovera

ble

Resourc

es (

BB

OE

)

Gas (BBOE)Oil & Cond. (BBO/C)

pre-J

ur

Paleogene

Creta

ceous

Jura

ssic

Neogene

Biogenic

Source Rock Age


2-33

Third, in some equatorial regions, Tertiary land-plant material, which is traditionallygas-prone, can contribute to oil-producing source rocks. This material initially was depositedin coastal and shallow-marine depocenters (Schiefelbein et al., 2000). However, during Ter-tiary lowstands, some of this humic material was transported into deeper water andconcentrated in zones that ultimately formed oil source rocks, as shown by Peters et al. (2000).This kind of source rock is now recognized in Nigeria, Brunei, and southeast Borneo.

Oil quality varies in the world’s deepwater basins and even locally in some basins. Thisvariable quality can be a concern for development, especially in ultradeep water, where there isless overburden to mature source material. Specific problems include the presence of high-sul-fur oils (from Type II S-carbonate source rocks), waxy oils (common with lacustrine sourcesand from biodegradation), asphaltenes, low API gravity, acids, and hydrates.

In most deepwater areas explored to date, there is enough disseminated organic matter inthe sediments to generate large volumes of biogenic gas. Therefore, in areas where infrastruc-ture allows economic gas extraction, there is an excellent chance of economic quantities of gascharge. For example, the producing Mensa field in the northern deepwater Gulf of Mexico ismostly biogenic gas (Pfeiffer et al., 2000). In some regions, however, such as Southeast Asia,nonhydrocarbon gas (e.g., CO2, N2) is a risk.

Generation and migration

Because source rocks in most of the major producing regions have only recently becomemature, timing is often a lower risk in deep water. Migration routes into traps are sometimesstraightforward via adjacent depocenters and faults (Figure 2-7). In other regions, however,migration can be more problematic. For example, in mobile-substrate basins, there are usuallysufficient faults and piercements to provide adequate vertical migration. However, (paleo-)fetch relationships and migration conduits can be complicated locally, particularly for thosetraps that depend on charge from older grabens or minibasins that do not lie directly under-neath. Many of the Cenozoic mobile-substrate deepwater regions are overpressured, with adynamic system of fluid trapping and leaking, such that unique conditions are required thatallow oil to migrate into a trap via a fault but not to escape upward. In the relatively unstruc-tured, unconfined setting, vertical oil migration is sometimes impossible.

Critical geologic success factors

On the basis of the above six components of deepwater petroleum systems and of indus-try’s collective global experience, four critical factors have been identified for successfulexploration and development in deepwater settings (Worrall et al., 2001).

1. Multiple large traps in an area tend to lead to the discovery and development of multiplefields with multiple reservoirs (Figures 2-6, 2-7).

2. High-rate, high-ultimate-recovery (HRHU) reservoirs are necessary for economic devel-opment in deep water (Figure 2-11, and discussion below). Thick net-pay sections are aprerequisite for success; other geologic properties are also critical contributors. Eco-nomics also plays an important role.

3. A working charge system is required, with the following components: source rocks withgood potential, late generation, and clear migration pathways (Figure 2-7).

4. Multiple play concepts targeting different trapping styles are necessary for drilling andtesting different kinds of plays. This is important because play concepts can be nearlyidentical in different basins, yet one will prove successful in one area and not in anotherarea of the same basin or in different basins.


2-34

Figure 2-11. Crossplot of well flow rates versus ultimate production from one well. HRHU reser-voirs plot in the upper right part of the graph.

Field sizes in deep water

Deepwater field sizes (ultimate recoverable resources) vary greatly from one basin to thenext. This variability reflects the vagaries of trap geometries, pay thicknesses, and the eco-nomic realities of drilling in remote, expensive frontier areas. Basins with eight or moredeepwater discoveries are shown in Table 2-2.

Mean field size differs greatly for several reasons. First, differences in trap area and netpay, and, to a lesser extent, recovery factor cause differences in mean field size. For example,in confined basin settings, which are often composed of small minibasins, fields often havelarge net-pay thicknesses but limited trap areas (e.g., the suprasalt areas of the northern Gulf ofMexico). In contrast, the less confined basin settings, such as the Campos Basin, have largetrap areas with less restriction between salt bodies, thus causing a larger mean field size butthinner reservoirs. In addition, traps in deepwater Nigeria and Angola are primarily rolloveranticlines and/or diapir flanks that have a large area. These traps are accompanied by stackedsand sequences of high net pay, which lead to large field sizes.

Second, mean field size also corresponds to our ability to economically develop smallerfields after infrastructure is in place. For example, in the northern Gulf of Mexico, the lowermean field size is associated with a smaller mean trap area. The drilling of smaller traps is aneconomic phenomenon that has resulted from favorable contract terms and advancing infra-structure, both of which make it more economical to develop smaller fields. For example,many of the more than 150 northern Gulf of Mexico discoveries are, or will be, developed assubsea tie-ins to existing infrastructure. This small-trap phenomenon is mostly limited to the

0

5000

10000

15000

20000

25000

30000

35000

0 10 20 30 40 50

Well Ultimate (MMBOE)

Well F

low

Rate

(B

OE

PD

)


2-35

*published discoveries onlyn.m. = not meaningful (only 2 discoveries with resources disclosed)tcfe = trillion cubic feet equivalent

traditional suprasalt plays in the ponded minibasin setting, as demonstrated by the discovery-size-versus-play analysis of Rains and Meyers (2001). Nonetheless, the smaller-discovery-size/trap-size observation still holds for the basin as a whole, because the mean of the largest30 Gulf of Mexico discoveries (250 million BOE) is about equal to the mean of all 35 LowerCongo discoveries (247 million BOE), and the mean of the largest 19 Lower Congo discover-ies (350 million BOE) is less than that of all 19 Campos Basin discoveries (631 million BOE).

High-rate, high-ultimate-recovery (HRHU) reservoirs

“High-rate, high-ultimate-recovery reservoirs” (HRHU) is a term that has crept into thegeologic usage for deepwater reservoirs, with no formal definition in the literature. The termwas used internally by Shell geoscientists and refers to reservoirs that can produce initially athigh rates (HR) to help pay for the initial capital investment, as well as with high ultimate(HU) recoveries, meaning the reserves justify the large economic investment of the infrastruc-ture (Figure 2-11). The term is used today primarily for reservoirs in greater than 500 m ofwater depth. HRHU reservoirs are necessary for many deepwater and ultra deepwater discov-eries, to justify the high exploration and development costs.

The best HRHU reservoirs found to date are sheet sands (usually amalgamated sheets)and amalgamated channel fill that have good reservoir drive, good reservoir properties (poros-ity and permeability), and good oil quality. Amalgamated sheets in the northern Gulf of

Table 2-2. Deepwater discovery ultimate recoverable resources for the major producing regions.

RegionTotal

deepwater resources

Number of discoveries

Average discovery

size*Largest discovery

Reservoir age

Campos Basin, Brazil

15.9 million BOE

45385 million BOE

3.2 billion BOE

RoncadorCretaceous, Paleogene,

Miocene

US Gulf of Mexico15.5 million BOE

160+119 million BOE

1.0 billion BOE

ThunderhorseNeogene,

Pleistocene

Lower Congo, Angola/Congo

10.6 million BOE

49216 million BOE

975 million BOE

DaliaPaleogene, Neogene

Niger Delta, Nigeria/Eq. Guinea

8.6 million BOE

34308 million BOE

880 million BOE

Agbami Neogene

Borneo (Mahakam + Baram), Indone-sia/Malaysia

3.9 million BOE

20< 305 million BOE

550 million BOE

Kikeh Neogene

NW Shelf, Australia

60.1 tcfe 15 4.6 tcfe 20.0 tcf JanszJurassic,

Cretaceous

Nile Delta, Egypt 21.0 tcfe 23 0.9 tcfe 4.0 tcf Simian Neogene

Mid-Norway (More + Voring)

15.3 tcfe 4 n.m. 13.9 tcf Ormen LangeCretaceous, Paleocene


2-36

Mexico are the best documented HRHU sheet reservoirs, and the amalgamated channels of theNorth Sea and West Africa are the best channel-fill examples (Chapter 6 andChapter 8).HRHU reservoirs are defined on the basis of economics. Although there are essen-tial geologic conditions that create these kinds of reservoirs, the presence of an amalgamatedsheet sand or amalgamated channel fill does not necessarily guarantee HRHU reservoirs. Res-ervoir quality, connectivity, temperature, depth, fluid pressure, compaction, and oil quality areall concerns that must be considered in evaluating HRHU reservoirs. For example, many of thelarge discoveries in the Campos Basin, offshore Brazil, would probably not be consideredHRHU reservoirs because of these kinds of constraints (Chapter 8).

Although HRHU is a commonly used term, HRHU reservoirs are not necessary for theeconomic completion of deepwater reservoirs. Many sedimentary basins of the world aremature basins with a well-developed infrastructure (either onshore or offshore). As a conse-quence, lower rates of production can still be economic.

Thickness versus confinement of reservoirs

Deepwater discoveries have variable relationships of area versus thickness, as shown inFigure 2-12. These variations result from the level of confinement, as described previously.HRHU reservoirs commonly develop in ponded basins, where “high kH” reservoirs develop(the result of permeability and thickness) in conjunction with excellent porosity values. Theseconditions are often found in undercompacted Neogene deepwater reservoirs. For example, theMars field in the northern deep Gulf of Mexico represents an extreme case of high reserves ina small ponded area (Figure 2-12) (Mahaffie, 1994). Overpressures and strong water driveoften contribute to high flow rates in individual cases of these thick, confined reservoirs. Also,drive enhancement from reservoir compaction during production can occur in some cases.Advances in drilling and completion techniques have played an additional role in achievinghigh individual well-flow rates— often greater than 15,000 BOPD (Figure 2-11)—despite thefact that deepwater well flows are often constrained by tubing size.

In areas where confinement is low and sands do not stack vertically within small trapareas, development economics are more problematic and sometimes require high-angle devi-ated wells and subsea tiebacks. It is therefore not surprising that some of the “unconfined”discoveries remain undeveloped or only partially developed many years after discovery, or aredeveloped only after similar or smaller discoveries in the basin (e.g., Ram Powell, Scarbor-ough, Marlim Sul, and Albacora East, although Scarborough gas has been complicated byremoteness and Albacora East by heavy oil).

Direct hydrocarbon indicators

Seismic direct hydrocarbon indicators (DHIs), including amplitude variation with offset(AVO), have been critical in our understanding of reservoir and charge risk (Figure 2-13)(Society of Exploration Geophysicists, 2000). Because of the associated risk reduction, DHIswere a major driving force behind the initiation of significant deepwater drilling in the 1980s.

Although there has clearly been a “winning formula” in mobile-substrate basins contain-ing Cenozoic deepwater reservoirs with excellent DHI support (Figures 2-14 to 2-17), leadingexploration companies are moving into other geologic settings and non-DHI plays, includingpre-Cenozoic objectives and areas lacking major updip reserves. For example, Thunder Horse,a major discovery in the deepwater northern Gulf of Mexico, is partially overlain by salt andlacks DHI support. With respect to emerging geologic settings, Mesozoic discoveries haverecently been made in Equatorial Guinea and Mauritania, both in basins lacking updipproduction.

Future deepwater frontiers and exploration trends

2-37

Figure 2-12. Deepwater giant fields with field area and net pay (vertical bar) drawn at identical scales. In gen-eral, those reservoirs deposited in confined basins have smaller trap areas and larger net pay values than doreservoirs deposited in unconfined settings. Reservoirs deposited in unconfined settings include Scarborough(northwestern Australia) and the Marlim complex (Campos Basin, Brazil). Reservoirs deposited in confinedsettings include Maenad-Orthus-Geryon (offshore North West Australia), Girassol (offshore Angola), Agbami(offshore Nigeria), Mars (northern Gulf of Mexico, Ormen Lange and Barden (offshore central Norway),Roncador (Campos Basin, Brazil), Scarab-Saffron (offshore Nile). Modified from Pettingill and Weimer(2001).

Seismic imaging

Advances in seismic-reflection imaging have arguably been the most important elementin allowing companies to explore deep water, because seismic imaging often reduces geologicrisk to acceptable levels (Rudolph, 2001). Prestack depth migration (PSDM) of seismic hasbecome critical for imaging deepwater traps, particularly along steeply dipping salt flanks andunderneath salt. Recently, PSDM was cited as a critical success factor during discovery andappraisal, because it imaged reservoir architecture and field extent in multistoried channelsthat were stratigraphically trapped.


Most of the world’s established deepwater play areas are at a relatively immature state ofexploration. As of year end 2000, 900 wells had been drilled in 81 basins in greater than 400 mof water depth, with most wells being drilled in six basins globally (Worrall et al., 2001). Thisrelative paucity in drilling means that there is still considerable potential in the global deepwa-ter play that has not been adequately tested. Nine general play trends or concepts are reviewedhere that illustrate the emerging and future areas for deepwater exploration.

221

m

Unconfined Confined

10 km

45 m :

.

30

m

.

15

0 m

147

m

113

m

High reserves per well

are critical to offshore

economics.

Therefore, high net

thick per area is critical.

10 km

150

m93

m

Partially

develo

ped.

14 yr a

fter

disc.

Fast T

rack

ed

Agbami: 890 MMBOEGirassol:

883 MMBOE

Mars:

700

MMBOE

Orman Lange

& Barden:

Barden:

Scarab-Saffron:

4.5 TCFRoncador:

3.2 BBO

O. Lange:

11 TCF

Maenad-Orthus-

Geryon:

10 TCF?

Scarborough:

8 TCF

Marlim: 2.8 BBOEMarlim

Leste

Underdeve

loped

27 yr a

fter d

isc.

Marlim Sur:

1.5 BBOE


2-38

-

Figure 2-13. Graph showing the percentage of global deepwater reserves with DHI support ver-sus those lacking DHI support.

Figure 2-14. Pie diagram showing the relative percentages of failures using DHI in exploration fordeepwater sands. Data from Noble Energy and Rocky Roden.

0

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1978

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Year

Cu

mu

lati

ve D

isco

vere

d R

eso

urc

es

(BB

OE

)

DHI-Supported

Non-DHI Supported

83%

Low-Sat.Oil2%

Clean WetSand35%

Ash6%

Shale / Marl14%

Thin or Non-Reservoir

Sand15%

Other Non-Reservoir

8%

Low Sat.Gas20%


2-39

Figure 2-15. Graph showing the global success rate of wildcat wells when drilled by Exxon withDHI support and without DHI support. After Rudolph (2001). Reprinted with permission ofAAPG and Kurt Rudolph.

Figure 2-16. Graph showing the global success rate of wildcat wells identified on flat spots whendrilled by Exxon with DHI support and without DHI support. After Rudolph (2001). Reprintedwith permission of AAPG and Kurt Rudolph.

DHI TECHNOLOGY

APPLICABLE

DHI TECHNOLOGY

NOT APPLICABLEGEOL.

SUCCESSECON.

SU

CC

ES

S R

AT

E

N=95

0

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HIGH DHI

QUALITY (>=3) MED-LOW DHI

QUALITY (<3)

POOR/NO FLAT SPOT

GOOD FLAT SPOT

0

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60

80

100

SUCCESS RATE

(%)


2-40

Figure 2-17. Graph showing the global success rate of wildcat wells when drilled by Exxon withAVO support . After Rudolph (2001). Reprinted with permission of AAPG and Kurt Rudolph.

Continued exploration in proven basins

The simplest play with high chances for success in global deep water is one with contin-ued drilling in the proven plays. Some basins with substantial shallow-water production lacksubstantial deepwater reserves (Figure 2-18). In some areas, such as southeast Asia, deepwater is moderately leased. Consequently, reserves found to date are modest (Figure 2-19),partially because of low drilling density. Most of the Asian deepwater plays are gas-prone, andthis has limited drilling to date.

Immediate future success will most likely be from drilling deeper in proven basins,especially in basins below the mobile substrate. In this case, development infrastructure isalready present, thus reducing the cycle time and lowering development costs. Brazil and thenorthern Gulf of Mexico are the two best examples. Source rocks mature below the salt, andlarge discoveries have been made in the northern Gulf of Mexico (Thunder Horse, Atlantis, St.Malo) and in offshore Angola. A few dry holes have been drilled in the Campos Basin belowthe autochthonous Aptian salt; however, there is still considerable potential. Good depth-imag-ing seismic techniques are mandatory for this kind of play to be successful.

Undrilled, mobile-substrate basins

Many mobile-substrate basins in the world are similar to those described above, but arestill unexplored. Basins with mobile salt and shale substrates are shown in Figure 2-20. Saltbasins include: Brazil, north of the Campos Basin: Sergipe-Alagoas and north along the Bra-zilian coast; East Africa; Red Sea; Madagascar; Nova Scotia; northwest Africa; the Nile; andseveral Mediterranean basins. Deepwater basins with large shale masses include southern Bra-zil, Columbus Basin (Trinidad), Mexico, Colombia, Mackenzie Delta in northwestern Canada,Krishna Godavari (offshore southern India), southeast Asia, Indus, large portions of theMahakam Delta, and Brunei.

HIGH DHI

QUALITY (>=3) MED-LOW DHI

QUALITY (<3)

NEGATIVE OR FLAT AVO

POSITIVE AVO

0

20

40

60

80

100

SUCCESS

RATE (%)


2-41

Figure 2-18. Map showing deepwater frontier basins with the fraction of the basin’s ultimate discovered resources found to date in deep water. Updatedfrom Pettingill and Weimer (2001).


US Gulf o fMexico

15%

Niger 10%

NW Europe4%

Nile 50%

NW Shel f29%

NW Borneo2%

Santos43%

Indus

NorthSakhal in0%

Talara0%

Taranaki0%

Potigar

Sicil y0%15

11

16

8

55

5

12

2

28

1

1.10.5

12

6

2.2

1.7

0.9

0.8

0.6

0.5

0.5

4.4

0.02

17

<0.1

3.5

<0.2

SouthBarents

0%

42

79

4

24

ApenninesSouthCaspian0%

Campos78%

Gabon0.3%

L. Congo48%

R. Muni100%

Total ult. reserves(BBOE)

DW ult. reserves(BBOE)

42

12

78

24

7

1 0.54

0.2

3

Scotian0%

1

NW Palawan50%

Mahakam17%

Trin idad5%

Nwflnd-J. d ’Arc0%

Serg.-Al.


2-42

Figure 2-19. Map showing global deepwater future frontier areas in terms of discovered resources per leasedarea. Leased area taken from Cook (1999, used with permission); resource estimates from Pettingill andWeimer (2001). Asia has had the fewest deepwater wells drilled per area, which may or may not account forthe current low deepwater resource density. Updated from Pettingill and Weimer (2001).

Ultradeep water, unstructured abyssal plain

The downdip, unstructured abyssal plain (“ultradeep water”) remains a large undrilledfrontier. This frontier presents many challenges in identifying a working petroleum system.Challenges include low thermal gradients and the presence of traps. Oceanic crust has a lowthermal gradient, which causes slower maturation of source rocks. Source rocks will all beopen marine in their origin. Source-rock maturation along these margins requires a fairly largesediment load for burying the source rocks sufficiently to elevate temperature into the oil-gen-eration window. An example of an active petroleum system in this setting is the Congo Fan.

Traps are also a major challenge. Because of the lack of structural development, trapsdevelop from compaction relief. Examples include Odin and Frigg fields of the North Sea(deepwater reservoirs that are not at deepwater depths today), and the North West Shelf ofAustralia. Stratigraphic traps are a possibility but require homoclinal dip and updip seals.Deepwater systems tend to be leaky traps because of channels continuing updip.

Unstructured, deepwater margins

The challenges of exploring in less-structured, deepwater divergent margins are the needto access petroleum charge, lack of structural traps, and lack of updip seal to petroleum migrat-ing updip. Examples include offshore Venezuela west of Trinidad, offshore east Africa, andlarge portions of the deepwater margins of Australia.

Reserves Per Leased Area

0

0

5

10

15

200 400 600 800 1000

Dis

co

ve

red

Re

serv

es

(BBO

E)

Leased Area in > 500m Water

GoM

South

America

Africa

Australia

Europe Asia

Red: >50% gas

Higher reserves per

leased area

(1000’s km2)


2-43

fi

Figure 2-20. Map showing the global distribution of deepwater basins with mobile substrates: salt (numbers) and shale (letters). See Chapter 15 fornames of basins, discussion of the structural styles, associated traps, and ages of autochthonous salt.

Salt

Shale

A

1

2

3

C

B

DE

FG

4

5

6

7

8

H

16

15

14

I

13

12

11

10

9

J

18

KL

M

N

R

QP

O

17

20

19

18


2-44

Rift/transform/active margins

These kinds of margins have had little exploration to date, but will grow in importance(e.g., Bird et al., 2001; Nibblelink and Huggard, 2002). The presence of traps and migrationpathways is generally not a problem, because there are abundant faults and traps. An updipseal and the presence of a working charge system are the main risks in these basins.

Deeper drilling

Drilling deeper has two meanings: (1) drilling deeper in the subsurface and (2) drillingin deeper water depths. Although current Gulf of Mexico deepwater exploration wells rou-tinely have total depths exceeding 6000 m, relatively few exploration wells in other deepwaterfrontiers have drilled beyond 4000 m of total depth. Subsalt objectives occur in several deep-water basins around the globe. However, only the northern Gulf of Mexico has seen deepwatersubsalt drilling, in both turtle trends as well as a subsalt foldbelt (Sumner and Shinol, 2001).Ultradeepwater frontiers occur along several margins of the world, as shown in Weimer andPettingill (2000). This would include ultradeepwater and deeper drilling depths, including sub-salt, subdetachment, and subvolcanic targets.

Emerging trends

Going beyond the established geologic formula described above, exploration isextremely immature in basins that lack updip production, for obvious reasons. The risk fordrilling in unproven provinces is high and greater than some companies are willing to tolerate.Plays with pre-Cenozoic deepwater reservoirs are expected to increase. To date, most deepwa-ter production occurs in Cenozoic reservoirs (Figure 2-8). Non-DHI exploration is expected toincrease, particularly in pre-Cenozoic and deeply buried objectives. In several cases, petro-leum systems have been established updip of deep water but produce only marginal ornoncommercial accumulations. The recent success in the deep water Rio Muni Basin of Equa-torial Guinea is an example of such a setting and also includes pre-Cenozoic targets.

Finally, contractional settings have, to date, been very lightly explored in deep water.Drilling activity has, for the most part, been limited to the terminal foldbelts that constitutecontraction downdip of the main extensional areas of passive margins (e.g., Nigeria, northernGulf of Mexico). However, some classic contractional continental margins have had recentleasing and seismic activity—for instance, those in southern Italy, Mexico, Cuba, and southernArgentina.

Deliberate gas exploration

As pipeline networks and liquefaction technologies advance, deepwater gas explorationshould increase in conjunction with increased worldwide consumption. Many of the world’sdeepwater basins are gas-prone, but many of them currently lack markets. Others that are oil-bearing have large amounts of associated gas (e.g., Nigeria, U.S. Gulf of Mexico). LNG plantsto accept deepwater gas are currently being planned in at least four locations, and a floatingLNG plant has recently been proposed for the North West Shelf of offshore Australia.

Political openings

New opportunities may arise in areas that were previously closed because of monopo-lies, moratoriums, and boundary disputes. In Brazil, the removal of a monopoly has resulted insequential offerings of prospective deepwater areas for licensing. In several West Africanations, Egypt, and Indonesia, the opening of new areas during the past decade has led to

Business and technology trends of deep water: Key learnings and future challenges

2-45

many significant discoveries and expanded reserves. In the northeastern deep Gulf of Mexico,a 10-year leasing moratorium ended in late 2001. The subsequent leasing has already led todiscoveries, although a large portion of the surrounding area remains off limits. Thus, there isconsiderable potential for increased deepwater activities, provided that select countries maketheir deepwater margins available for exploration.


The deepwater play has a unique set of business and technology issues that push the lim-its of what geoscientists can do. Companies have learned that they must be innovative toadvance the deepwater play and make it economically viable. The following is a summary ofthe key learnings and challenges for the business models and technologic needs for deep andultradeep water. This summary is based on presentations by Lawrence and Bosman-Smits(2000), Weimer et al. (2000), and many public sources in different trade journals, as well asthe authors’ own opinions. Some of these items represent critical success factors in the mana-gerial aspects of deepwater exploration and production.

Deepwater versus shelf plays

Deep water, in all aspects, is not a simple extension of the petroleum plays that exist oncontinental shelves around the world (e.g., northern Gulf of Mexico, Nigeria, Brazil). In sev-eral basins, additional marine source rocks are present in deep water that are either not presentor not active under the updip shelfal part of the basin. Trapping styles are usually different,particularly for basins that have a mobile substrate and/or are associated with salt evacuationsurfaces, and contractional structures become more prevalent; there is also an increasedemphasis on stratigraphic trap components. Deepwater reservoirs are different from those flu-vial-deltaic and shallow-marine sands that constitute the bulk of the reservoirs on continentalshelves (Figure 2-21). Although fluvial-deltaic reservoirs on the shelf can have total trap areasas large or larger than deepwater fields, drainage areas tend to be larger in deepwater reser-voirs. For example, in the northern GOM, deltaic traps are generally developed on 320-acrespacing or less, whereas deepwater reservoirs tend to be developed at 640-acre spacing ormore. However, the reserves per area of individual deepwater fields are considerably larger,because of larger net pay per area, larger net-to-gross ratio, stacked pays, and/or thick individ-ual sands (Figure 2-21).

All this implies that development planning and facilities are different for deepwater res-ervoirs. The deepwater reservoir can produce at much higher rates than shallow to marginalmarine reservoirs can, with some individual wells producing in excess of 30,000 bbl/day.Development scenarios must handle different reservoir geometries and greater thicknesses toperforate, with fewer slots in platforms with which to develop the fields. Finally, pressureregimes are radically different in deepwater counterparts of basins and can affect petroleummigration, trapping, and containment because of relatively shallow development ofoverpressure.

Work in integrated teams

To reduce the amount of time between exploration and development, most of the com-panies exploring and producing in deep water today work in integrated teams of geoscientistsand specialized engineers (reservoir, drilling, and production facilities). Each group has a dif-ferent set of roles, challenges, technical languages, and risks. Successful integrated teams


2-46

Figure 2-21. Log-log graph showing trap area versus reserves for deltaic and deep water reser-voirs for the northern Gulf of Mexico. In general, deepwater reservoirs have higher net/area thandeltaic reservoirs in the same basin (necessary).

f

require that the right people be involved and that they work well together. Because of theextremely high operating costs, industry now considers development and production plans aspart of the exploration workflow. This forward-planning significantly reduces the cycle-time indeveloping these kinds of fields.

Most deepwater projects have the traditional risks, such as the presence of a good reser-voir, the commerciality of the project, and long-term political stability of an area. A uniquerisk in deeper water is marine processes—bottom currents, loop currents, eddies, associatedvibration—that may impact the development facilities. Thus, oceanographers and naval archi-tects will have increasingly important roles in the team. These deep-marine processes allclearly affect development structures being installed, sometimes adversely.

Drilling technology for deep water

Advances in drilling technology, for exploration and especially for development, remainthe impetus for increased drilling in deep water. Industry can currently drill in greater than 3km of water depth, and will soon be able to produce in these water depths. To date, the deepestwell was drilled in 10,011 ft of water (>3 km), and the deepest production facility is the NaKika development in northern Gulf of Mexico in 1900 m (6300 ft) of water. During the past 17years, there have been rapid changes in the increase in water depths for drilling. In 1987, thedeepest water drilled in was 2310 m (7590 ft) (Coulomb field; Mississippi Canyon 657). ByApril 1996, water depths were extended to 2320 m (7612 ft) (Baha #1, Alaminos Canyon 601),and by early 2002, the deepest water was 3000 m (9800 ft) (Trident #2, Alaminos Canyon

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903); as of November 2003, the deepest well was in 3051 m (10,011 ft) of water (Toledo well,Alaminos Canyon 951). Innovative systems are also being developed for production facilitiesand production techniques for these extraordinary water depths. Innovation must continue ifdeep water is to be economic.

Reduction in drilling costs

Reducing total development costs, including drilling costs, is essential to future successfor the deepwater play. Rig costs are routinely $250,000–$400,000/day for the larger drillingfacilities. Significant improvement in drill times (via bits, fluids, pore-pressure prediction,etc.) and dual-activity drill ships (reducing drilling times by 20–30% alone) are two significantareas in which costs can be reduced. Cheaper and more numerous production wells are neces-sary for larger fields and for increased ultimate recovery. In some wells, such as thoseinvolving subsalt drilling, the development wells can be extremely expensive because of thedifficulty in predicting pressure regimes below salt and the need to insure the robustness of thewellbore against the mobility of the salt body over time.

Fast-track development

Fast-track development is becoming critical for many companies, to assure a quickerreturn on the enormous up-front cash investment. This direction, however, potentially conflictswith important development decisions that must be based on learnings and observations ofperformance of the reservoir made throughout the life of a field. The need to minimize costsalso is of paramount importance. Thus, the tradeoff between data collection and developmentcosts is difficult.

Within companies, there is a real need for frankly discussing the kinds of data that mustbe collected to maximize long-term production but minimize time between discovery andstart-up. Much of the data that are collected will be field and basin dependent. More-maturebasins, where generic issues concerning the development of different play types are wellknown, require different data sets and analytical approaches, compared with new frontiers orlightly explored plays. For instance, the approach to a new development of the PaleoceneNorth Sea reservoirs will be different from the new fan plays in deepwater West Africa, north-ern Gulf of Mexico, or Brazil.

Data collection during field development

Technical judgment must be exercised early about what kinds of data must be collectedduring the appraisal and development of discoveries. Often this decision may determine theperformance of the field. Two types of reservoir data collection—static and dynamic—are rec-ognized as being critical to maximize long-term production. Both are needed from the earlystage of a discovery’s appraisal and should be fully integrated to get maximum value. Twogeneral considerations for appropriate data collection and management in a field are (1) good-practice data, which are data collected at various stages in field life that produce good invest-ment returns, and (2) problem-solving data, which can provide appropriate information forcontingencies when something goes wrong in the production of a well.

Static data are crucial early in the development of a field, especially when dynamic dataare sparse and indicators of major reservoir heterogeneities are equivocal. Static rock datacome from cores, sidewall cores, and full-suite conventional wireline logs. The importance ofspecialized logs, such as borehole images and nuclear magnetic resonance logs, is just nowbeing realized. Other data that are important to capture include initial potentials (IPs), fluid


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distribution data, fluid properties, initial reservoir pressure data, productivities, and hydrocar-bon and water chemistries.

Collection of dynamic data during the life of a field is also of paramount importance,particularly to maximize production as the field matures. In the future, the need for pressuremonitoring through downhole gauges will be essential to subsea tiebacks and similar produc-tion scenarios that minimize intervention. The use of time-lapse 3D seismic imaging formonitoring fluid movement is increasing and has been used successfully in areas only wherefavorable reservoir properties exist (Calvert, 2005). This seismic monitoring can be accom-plished in two primary ways: by placing permanent geophones on the seafloor and acquiringdata at different times (e.g., Foinaven field, West of Shetland; Entralgo and Spitz, 2001) or byconducting repeated 3D seismic surveys using similar acquisition parameters (e.g., Fortiesfield, U.K. North Sea; Leonard et al., 2000).

Reduction in cycle time

Continuous cycle-time reduction is critical for the economic and business success of adeepwater play (Figures 2-22, 2-23). In many areas, production can occur as soon as 1–2 yearsafter the initial discovery (for the small subsea cases). However, the industry’s track record onmeeting schedules has not been especially good. Fewer than 25% of recent projects are onschedule.

Figure 2-22. Oil flow rates for West Africa discoveries in >100-m water depth, ordered by year. Note the initialsteady increase in flow rate as the industry moved into deeper water. A decrease has occurred during the lasttwo recorded years, probably reflecting both the limits of learning and a maturing prospect inventory inAngola. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

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Figure 2-23. Discovery to first production for deepwater developments: (a) northern Gulf of Mexico, (b) inter-national: Brazil, northwest Europe offshore, and West Africa. Much of the reduction in development timesince 1990 in the northern Gulf of Mexico resulted from advancing infrastructure and subsea developments;however, the remaining reduction represents the learning curve for industry. The other areas use floating pro-duction schemes. Therefore, most of the reduction in Brazil is due to the learning curve. Unconfined reservoirsin the West of Shetlands are problematical for development economics, and minor advances have been madein reduction time. West Africa is in its earliest years and may soon achieve a learning curve similar to those forBrazil and the Gulf of Mexico. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Reduced cycle time is illustrated by two pairs of fields discovered 14–16 years apart intwo different provinces. The Jolliet field (discovered in August 1981) and Bullwinkle field(discovered in October 1983) were two of the initial deepwater discoveries in the northernGulf of Mexico. Both fields were developed as if they held deltaic reservoirs like those in theshelf fields to the north. In the case of Bullwinkle, the reservoirs consist of sheets and channelfill (Holman and Robertson, 1994; Shew, 1997); for Jolliet, reservoirs are channel fill and thin-bed levees (Schneider and Clifton, 1995). Development facilities were designed with manydrilling slots that were never used, because both fields performed far better than expected. Forboth fields, full production was reached 8–9 years after discovery. In general, the rigs wereoverengineered and were never used to their full capacity. After reaching its productiondecline, Bullwinkle platform was used as a hub for subsea tiebacks for other fields (Rocky,Troika, Angus, Manatee).

In contrast, two large fields discovered offshore Equatorial Guinea in West Africa in themiddle to late 1990s illustrate how lessons were learned in development and design. TheZafiro field, discovered by Mobil and partners in March 1995, was fast-tracked for develop-

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ment, with initial oil produced 17 months later (Humphreys et al., 1999). The Ceiba field wasdiscovered in October 1999 by Triton and partners, and development was fast tracked (Daillyet al., 2002). The first oil was produced from an FPSO (Floating Production, Storage and Off-loading) unit 13-1/2 months after initial discovery. Continued production of both fieldseventually led to the development of platforms being set, in addition to the initial FPSO units.However, there are problems in developing a geologic model that later may be wrong.

Subsea development

Subsea wells will increasingly be used for development in two main areas: single-welltiebacks from small discoveries, and where several smaller fields can be tied back to one gath-ering production facility. Subsea development has had an important impact on how andwhether small discoveries can be developed without large investment. Subsea developmenttechniques are becoming standard in basins with a modest to well-developed infrastructure.Current records for length of the tieback are 48 km (30 mi) for oil and 100 km (65 mi) for gas(Mensa field, northern deep Gulf of Mexico; Pfeiffer et al., 2000). What makes subsea devel-opment unique is that investment can be done in a staged fashion, where the initial investmentis smaller and can be increased with favorable learnings. However, as a total investment, sub-sea development is costlier than a central processing facility.

The Na Kika subsea development in the northern deep Gulf of Mexico (Mississippi Can-yon protraction area) illustrates this important development. Na Kika Development consists ofsix oil and gas fields discovered during the past 15 years in different water depths: Kepler(1987, 5600 ft [1700 m]; oil), Fourier (1989, 6000 ft [1800 m], oil and gas), Ariel (1995, 6500ft [1980 m], oil), Herschel (1996, 6000 ft [1800 m], oil), East Antsey (1997, 7000 ft [2100 m],dry gas), and Coulomb (1988, 7592 feet [2314 m] gas). None of the fields has large enoughreserves to warrant a stand-alone development structure. Instead, a host platform was estab-lished, consisting of a permanently moored, floating and development system. Differentpipelines are used for oil and gas. Initial production began in November 2003. Total ultimateproduction is estimated to be 300 million BOE. The Coulomb gas field was brought on line in2004.

The use of subsea wells is an application that has grown substantially during the pastdecade, yet significant problems remain. Reliability of this process is essential because theindustry, as a whole, has experienced many mechanical failures on subsea wells during thefirst year of production. In the future, a number of issues must be addressed with more rigor-ous requirements: the use of these facilities in remote areas, an utmost reliability, andnonintervention, once the wells are turned on.

Reservoir monitoring

The future possibilities for intelligent oil-field development, using automation of reser-voir monitoring of the field, have been summarized by Entralgo and Spitz (2001), Hottmanand Curtis (2001), and Lumley (2001). This will include a number of technologies capable ofmeasuring fluid movement through time, both with seismic monitoring and downhole pressuregauges. Downhole pressure gauges have been essential for development, yet they have a his-tory of breaking down after a few years of use.


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Exploration workflow for deep water

What is the best workflow for deepwater explorationists? For a person working deepwater for the first time, this task may be daunting because of the complexity and enormity ofdeepwater geology and the high cost of exploration in this environment.

The remaining chapters in this book will address the technical geological, geopyhysical,and certain engineering aspects of the deepwater play in greater detail. Summarized below aretypical steps that use modern exploration techniques with the geologic concepts for working indeep water. This discussion is based on our own experience plus that reported by Mitchum etal. (1990), Richards et al. (1998), and R. Mitchum (personal communication, 2003).

In general, one begins to work at the large scale (regional) and then narrows the work’sfocus to progressively smaller scales (from play to prospect). We use the same general work-flow in the organization of this book.

Regional scale

1. Establish the major plate-tectonic setting, basin evolution, patterns of basin fill, and bas-inwide controls on the following petroleum parameters: source-rock deposition, matura-tion, migration, trap formation, reservoir and seal deposition.

2. Establish the approximate areal extent of petroleum source rock(s), their richness, andtheir maturation. This can be difficult in frontier areas, where the source rock has notbeen penetrated and can only be estimated from seismic data.

3. Recognize the basinwide sequence stratigraphic framework (second- to fourth-orderrelationships) and its relationship to tectonostratigraphic packages (Chapter 3).

4. Recognize basin-scale depositional environments: shelf-slope-basin transitions, sand-rich provenances, and entry areas for coarser-grained sediment into the deepwaterbasins.

5. Map regional patterns and trends of deepwater deposition: channels, levees, and sheets(Chapter 6 through Chapter 8)

Play scale

1. Recognize sequences with coarse deepwater systems (usually third-order sequences(Chapter 3).

2. Define the tectonic trends of the structural traps that are present (Chapter 15).3. Map depositional patterns in specific sequences (second- to fourth-order depositional

sequences (Chapter 3), and link them to tectonic controls of deposition, when appropri-ate.

4. Study any previous production in the area, looking for additional information about theplay, and carry out a thorough dry-hole post-mortem analysis to understand key risksand critical success factors.

5. Establish the mechanisms required for petroleum maturation, generation, and migrationinto prospects.

6. Establish the pressure regime for the interval that encompasses the source rock horizonup to the prospective trapped reservoir interval.

7. Check analogs from other deepwater basins and test for common elements betweenthose established plays and the deepwater play.

8. Conduct shallow analog studies, where appropriate and possible. One technique that hasbeen used successfully is to study the distribution of upper Pleistocene slope deposi-


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tional systems using 3D seismic data. These systems commonly are good analogs for theunderlying deep, buried-slope deepwater systems that are the prospects. After initialexploration drilling, the seismic response is calibrated to the rock physics of the sedi-ments.

Prospect scale

1. As we discussed above, most companies still stress structural prospects (e.g.. salt andshale structures, strike-slip faults, foldbelts, growth faults) in their portfolios, eventhough most prospects are combined stratigraphic-structural traps (Figures 2-1a to 2-1c).Good stratigraphic control is necessary for mapping sand-prone portions of structures.In certain cases, well control somewhat delimits the reservoir’s extent. However, in mostdeepwater cases, 3D seismic data are employed to fully delimit the extent of the reser-voir. Additional 3D analyses of seismic attributes, such as amplitude extractions, fre-quency, continuity cubes (“edge” cubes), artificial intelligence, or combinations ofthese, help develop map views of deepwater architecture such as channels, sheets, andthin beds in overbank settings. Commonly, detailed analyses will reduce the amount ofreservoir placed in these structures, much to the chagrin of the exploration team.

2. The recovery factor used for this reservoir analysis is most important, as is the portion ofthe mapped trap that is “effectively recoverable,” that is, limits of reservoir continuityand connectivity may reduce the effective size of the prospect. In some cases, the pro-portion of the in-place resources that will be recovered is further reduced when the mostprofitable development plan is one that would only develop part of the field (most com-monly, in subsea production tie-ins).

3. Analyses of direct hydrocarbon indicators (DHIs), such as seismic amplitude anomaliesincluding bright spots, seismic flat spots, and amplitude-variation-with-offset (AVO)anomalies are most important in obtaining management’s approval for a prospect(Rudolph, 2001; Brown, 2004). Although some companies are moving into non-DHIplays, most deepwater prospects still live and die with these analyses. Many companiesare recognizing more-subtle “low-amplitude” plays, including prospects that lack full-stack anomalies but have far-angle anomalies. Two recent symposia on exploration dryholes have revealed notable failures in DHI analyses (Houston Geological Society, 2000,2003). Although AVO’s success is unequivocal in some basins, such as the northern Gulfof Mexico, its overall success in basins worldwide has been limited (e.g., West of Shet-lands, Loizou, 2003). Common prospect-scale evaluation steps to define the quality of aseismic anomaly that is thought to be a DHI include (a) calibration to well control inboth positive and negative examples, including, but not limited to, synthetic seismo-grams, fluid substitutions, and wedge models; (b) presence of a downdip conformanceof the anomaly to a structural contour, indicating a hydrocarbon-water contact; (c) pres-ence of a flat spot (Rudolph, 2001); (d) visual inspection of near- and far-angle gathers,crossplots, and sophisticated analyses (Society of Exploration Geophysicists, 2000); and(e) understanding DHI pitfalls in the prospect area (Figure 2-11).

4. In addition to the aforementioned use of seismic anomalies to detect fluid indicators,seismic amplitude is also a reliable predictor of lithology in most deepwater basins.Hence, it is employed to define reservoir and seal. In several oil-bearing deepwaterbasins, amplitude anomalies are indicators of lithology only but are still a critical aspectof defining a stratigraphic trap and a drillable prospect location.

5. Technological improvements have helped to analyze bed-bed subsequence architecture(amplitude extractions, amplitude seeding in volume visualization products, quantified

Summary: Lessons learned

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seismic facies mapping, other attribute analyses) for individual sand mapping. Often, theuse of these tools leads explorationists to avoid a thorough stratigraphic analysis, some-times to the long-term detriment of the prospect.

Final prospect risking

Most prospects receive a rigorous, formalized, quantitative probability and risk analysisfor the following factors: (1) analyzing source-rock presence, thickness, and richness; (2)modeling maturation and migration history, and tying to the timing of structural growth of theprospect; (3) reservoir analyses, as described above; (4) evaluating the structural versus strati-graphic trap components and the integrity of the traps through time (pressures often play a rolein trap integrity). Four-way dip closures are considered lower-risk than three-way closuresagainst a fault, where fault seals are commonly high-risk; (5) seal: evaluating the top seal, lat-eral seal, and faults: in the deepwater environment, condensed-section shales may serve asexcellent seals, separating sands in different third-order sequences, although sands within asequence may commonly be in pressure and fluid communication. All of these factors are usedto establish the ranking in prospect portfolios for probable size, cost, and profit of prospects. Inmany cases, we rely heavily on seismic-amplitude anomalies to define both the risk and thesize of a prospect; and (6) risking deepwater prospects, acknowledging the high degree ofinterdependence between the prospect elements described above. All elements of the petro-leum system generally develop during the same stage of basin evolution (e.g., mature passivemargin) and share a common syntectonic control. Therefore, petroleum maturation and gener-ation, reservoir-seal deposition, and development of pressures that affect migration andtrapping might all be interrelated by the same basin-scale forces.

Summary: Lessons learned

1. Global exploration in deepwater settings has significantly increased during the pastdecade, adding 74 billion BOE discovered. However, globally deep water remains animmature frontier, accounting for less than 5% of the current worldwide total oil-equiva-lent resources. Only about 20% of the discovered deepwater resources are developed,and less than 5% have been produced.

2. Most of the exploration activity has concentrated in only three areas of the world, with amajority of the discovered resources in the northern Gulf of Mexico, Brazil, and WestAfrica. Consequently, large portions of the world’s deepwater margins remain lightlyexplored. Deepwater gas exploration is extremely immature, reflecting current infra-structure and economic limitations, but it is destined to become a major future focus.

3. The petroleum systems of deepwater margins are highly variable among differentbasins. Successful exploration efforts will depend on an understanding of the differencesboth within and among basins. Oil source rocks include synrift lacustrine, open-marine(postrift), and transported delta-plain material. Gas source rocks include disseminatedorganic material and biogenic gas. Timing of petroleum generation and migration is acrucial factor in deep water and is highly variable, depending on the margins’ geologicevolution, basin heat-flow history, and the distribution of fetch areas in space and time.Migration conduits (faults, carrier beds) must also be in place at the crucial moment. Oilquality is a major issue for economics in many basins, most often because of immatureheavy oils but occasionally because of sulfur and wax contents.

4. Most reservoirs in deep water are associated with gravity deposits, although in somebasins, shallow-water carbonates and siliciclastics are potential reservoirs. Trappingstyles vary considerably in the deep water associated with faulting, salt and shale defor-


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mation, and contractional features. Purely stratigraphic traps occur infrequently; how-ever, many traps have a stratigraphic component and some are reduced or enlarged by astratigraphic pinch-out. Adequate seals are present because shale dominates in thesebasins, although potential leakage can be a significant risk.

5. Five main themes will drive deepwater exploration in the future: (a) a continuation ofestablished trends; (b) emerging trends that include basins lacking updip production,unconfined basins, compressive margins, pre-Cenozoic targets, nondeepwater targets,and non-DHI targets; (c) increased exploration specifically for gas; (d) going deeper:ultradeepwater and deeper drilling; and (e) politically driven opportunities.

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