Prospect Generation in Forantier Regions

8/2/2019 Prospect Generation in Forantier Regions

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Assessing Prospective Regions

The crucial judgment for an exploration company is deciding whether an unexploredarea is or is not a prospective region. If it is supposed to be prospective, but turnsout not to be, much time and money will have been wasted. If the unexploredprovince is supposed to be non prospective, but it turns out to be prospective, the

exploration company will have forfeited a chance for profit. A province is rarelywritten off, however, before some wildcats are drilled. Indeed, several dozen dryholes may be drilled before a province is called noncommercial.

Assessing prospectivity in producing regions is wholly different from that in frontierregions. In the former, you know you are in oil country, and the question is whetherenough undrilled prospects remain between, beyond, above, and especially belowknown fields in order to justify further exploration. Much well information is usuallyavailable, and the main geological effort is geared toward answering localstratigraphic and structural questions before planning possible detailed geophysicalsurveys. On the other hand, in frontier provinces, the existence of the five essentialfactors (source rocks, reservoir rocks, migration paths, traps, and seals) for

petroleum accumulation is a matter of speculation.

Many, if not most, of the world's remaining frontier provinces lie in offshore regions.Large untested provinces on land are apt to be in areas that are geographically orpolitically inaccessible.

While there are still some untested frontier provinces even in a mature producingregion such as in the United States, several have disappeared from the list ofpotentially commercial provinces. The Lower Cook Inlet, Alaska, is one of these.

Data Needed

The most diagnostic exploratory tools in frontier provinces are wildcat wells andseismic surveys. On land, seismic is relatively expensive, and wildcat wells may berelatively less costly. In water-cove red regions, seismic is relatively less costly, butwildcat wells are very expensive. Photo geology is cheap but useful only over land.Aeromagnetic surveys are cheap and may be used either over land or sea to revealbasement structure and basin configurations. Gravimetric costs a little more and is avaluable prospecting and reconnaissance tool on land. Marine gravimeter surveys areinherently less useful because the magnitude of the corrections commonly exceedsthe amplitudes of the anomalies.

Other tools are helpful in exploring certain provinces. These include:

side-looking radar, used like photo geology; particularly helpful in areas with heavy cloudcover and/or thick vegetation;

side-scan sonar, used for mapping underwater topographic-structuralfeatures;

Marine "sniffer" surveys, used to record and evaluate samples ofhydrocarbon gases leaking from the sea floor;


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soil hydrocarbon surveys, used to detect petroleum fluids leaking to thesurface that produce halo patterns above buried reservoirs;

Radiation surveys, used to detect surface patterns of uranium daughterelements concentrated above buried reservoirs (Morse et al. 1982).

Technical FactorsAssessing a frontier province begins with reconnaissance surveys on land, surface geology,coupled with photo-geology, is often used first. This is followed by aeromagnetic surveys, thengravimetric surveys, and finally seismic surveys. In marine provinces, after an initial aeromagneticsurvey is made, a reconnaissance seismic survey is customary. The purpose of the geophysicalreconnaissance survey is to uncover the kinds, depths, magnitudes, and relative frequency ofburied anomalies in the province and to appraise the sedimentary sequence. It would be desirableat this point to make a preliminary inventory of indicated volumes and depths of potential traps. Inpractice, however, often the best one can do is to make semi quantitative generalizations andeducated guesses about potentially productive closures and the total sediment thickness abovebasement.

One or more of the most obvious of these anomalies is evaluated by detailed seismicsurveys. The most promising is then selected for the initial wildcat test. In mostcases, pronounced structural anomalies are the first to be tested. In some offshorewaters of the United States, "stratigraphic tests" are drilled deliberately off structureto directly observe stratigraphy, prior to federal lease sales. Usually this is acooperative effort by several competing companies. Until these initial tests are drilledin representative locations, it may be difficult to discern the practical significance ofcertain geophysical anomalies.

Once drill cuttings, mud logs, and wire line logs are obtained from one or morewildcat wells, we can recognize the geological sequences present in the basin, detecthydrocarbon shows, and observe thickness and quality of reservoir strata. Moreover,it may be possible to determine the presence (or absence) of commercial source

beds.

Model Prospective Region - Lower Cook Inlet, Alaska

The Lower Cook Inlet of Alaska provides a case study of an offshore prospectiveregion. This province was thought to have commercial potential in the late 1970s.

Figure 1 shows the situation at the time of the 1977 Federal Lease Sale.
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Figure 1

In this case, the major job of geophysics was to map the shape, depth, and majorstructures of the province in order to compare the undrilled southern portion of theCook Inlet basin with the productive northern portion. No attempt is made here togive either a history of the exploration of this province, or a full discussion of itsgeological problems. The only intention is to suggest how the exploratory prospectsin the province were generated and what was learned from drilling.

Several marine seismic programs were undertaken during the 1960s and early1970s. Most were sponsored jointly by a number of exploration companies.Syndication of risk is common in offshore provinces. Some exploration groupspurchased two or more seismic surveys, plus gravimetric and aeromagnetic surveys.Each group sponsored an independent seismic interpretation. Because of the difficult

multiple reflections and velocity problems encountered, supplementary side-scansonar and shallow-penetration sparker seismic surveys were purchased from servicecompanies.

The only published seismic maps of the Lower Cook Inlet were made by the U.S.Geological Survey, since all proprietary maps were kept confidential. Figure 2displays the major positive structural features that were revealed, nearly all of whichwere investigated in much greater detail, revised, and confirmed by proprietary data.
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Figure 2

Interested exploration companies decided which prospects were worth leasing anddrilling partly by making an analogy to the Upper Cook Inlet. At long last, a federallease sale was held. In October 1977, a total of 21 companies and groups ofcompanies bid $398.5 million for 87 tracts (495,000 acres). By the end of 1979, dryholes were drilled on eight major prospects ( Figure 2 ). The Lower Cook Inletprovince was found to be nonproductive.

One can imagine a frontier province being dry or noncommercial because ofinadequacy or absence of reservoir strata, traps, or seals to the traps. By using

reconnaissance seismic surveys, plus drilling a few wildcat wells, the existence ofthese three factors can be determined with considerable reliability. The presence orabsence of these features are fairly straightforward determinations, but it is quitedifferent with source beds, timing, and migration paths.

This point can be illustrated by a brief analysis of why prospects in the Lower CookInlet were dry. Although it is only a skeletal structure map, Figure 2 stronglysuggests that large anticlinal closures (adequate traps) are common. Seismic crosssections, on which major reflection marker surfaces are identified stratigraphically (
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Figure 3 , Seismic line 755, just north of Cape Douglas showing major reflection

marker surfaces for stratigraphic correlation.

Figure 3

A horizon = base of Tertiary; B horizon = base of Lower (?) or Upper (?) Cretaceous;

C horizon = Middle Jurassic (?) and minimum thickness of sedimentary rocks inbasin), and structural sections ( Figure 4 ) both indicate that Tertiary rocks (Kenai

Group) are present but thin in the Lower Cook Inlet.

Figure 4

Furthermore, the major oil pay of the Upper Cook Inlet (the Hemlock Conglomeratewithin the Kenai Group) seems to be present. It would appear then, that traps, seals,
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and reservoir rocks exist, and the abundant faulting, both old and new, which wereshown by seismic lines, should have provided migration paths that were similar tothose in the productive Upper Cook Inlet.

Evidently, source rocks that supply commercial amounts of petroleum are lacking inthe Lower Cook Inlet. One obvious difference between the Upper and Lower Cook

Inlet is that the lower Kenai Group, which is the principal objective, is very shallow(


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source rocks as far upward as the Tertiary reservoirs. Tertiary seismic closures wereregarded by most as secondary objectives at best. The Upper Jurassic clasticsequence was seen as a possible primary reservoir- if microfracturing due to recentuplift was adequate. The wildcat failures were evidence that microfracturing wasinadequate for producing commercial-scale migration.

Estimating Hydrocarbon Potential and Calculating Risk

In Alaskas Lower Cook Inlet, an area once thought to have great potential, theindustry drilled eight dry holes. Overall perhaps a total of $750 million dollars wasrisked over more than a decade by at least 30 oil companies. It was all lost.

Assessing the risk and gross hydrocarbon potential of untested regions requirescareful evaluation and complex analysis. A company can make a reliable estimate ofhow much money would be required to obtain a suitable position in a frontierprovince, but prior to taking that position, the company can't accurately forecast theexpected rewards from the money risked. Substantial geophysical and geologicalreconnaissance, acreage acquisition, and wildcatting expenditures must be made

before the region can be proved either commercially productive or barren. A majorpetroleum company must regard its share of the $750 million dollars spent in theLower Cook Inlet as one of the costs of remaining in the exploration business.

The effective exploration technology developed in recent decades has shortened thetime period needed to evaluate a frontier province. It has also made initial wildcatdrilling highly successful where these new provinces have proved productive (insome cases, a 50% success ratio in wildcat drilling). A company would rarely go intoa new province and spend such vast sums as in the Lower Cook Inlet, unless it hadhopes of finding large, and possibly giant fields. The number of giant fields, even inmajor provinces, is relatively small. They are, however, most often found in obvioustraps, such as anticlines, salt domes, or reefs. Often their location can be readily

determined prior to drilling by geological or seismic surveys. Frontier provincescommonly provide the best chances for finding such first class prospects, though therisks and exploration costs are proportionately higher.

The Hepburn prospect (see the Example at the end of this section) is one such primetarget. Its seismically mapped anticlinal closure with a "bright spot" assured it to beone of the first prospects drilled in the hypothetical frontier basin of the SoutheastSpur. Prior to drilling, however, the findings of geological and geophysical surveysmust be summarized in evaluation reports and prospect sheets. These present thefundamental geologic and economic facts concerning a prospect and also the initialestimates of anticipated reserves and economic returns. A sample prospect sheet forthe Hepburn prospect is presented in Appendix A. On other prospect sheets, anattempt is made to assign grades or numerical ratings to the various factors in order

to make the analysis more objective. Some formulas that are commonly used tocalculate reserves, economic returns, and risk prior to drilling are presented below:

Reserves

Reserves = Oil-in-Place Percent Recovery

Oil-in-Place


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Oil-in-Place (OIP) = Gross Reservoir Volume* Net/Gross Porosity

Oil Saturation k** FVF**** Gross reservoir volume = productive areal closure reservoir thickness

** 7758 if acre-ft to bbl conversion

*** Formation volume factor

Potential Return (after tax)Future Net Revenue (FNR) = total reserves average price* - (operating costs +

over total investment** + tax)* Over total payout time

** Cost of wildcat well, completion costs of discovery and any fielddevelopment costs (sometimes this calculation excludes initial risk costs ofwildcat well.)

Return on Risk InvestmentReturn on Risk Investment = Potential Return Risk Investment*

* Predrilling cost + cost of wildcat well to casing point

Risk Adjusted Return on Risk Investment

Risk Adjusted Return = (Potential Return / Risk Investment) Success Rate*

*based on past experience

Return on Investment (ROI)Return on Investment = Potential Return / Total Investment

In summary then, prospective regions that have seen little or no drilling may offer opportunities for

some of the greatest rewards in finding and developing major new prospects and fields. The costsand risks, however, are significantly higher. Although potential traps, and reservoir and seallithologies frequently can be detected through geophysical methods, often there are difficultfundamental questions to be answered. Some of these concern source rocks and their maturity,and the paths and timing of migration. These factors can make or break a potential prospectiveregion. With appropriate planning, the technology is available to evaluate even a large frontier arearapidly, and either prove it to be an oil province or condemn it.

Example:

An Evaluation of Hepburn Prospect, Southeast Spur, Block 35, District #2

Petroleum Exploration Co.Exploration Dept.5 Morrill PlaceHouston, TX 77036

Summary

i) Prospect is an anticline with four-way closure partially bounded by faults. Target isprobably Jurassic sandstone.


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ii) Seismic configuration is very promising. Five seismic lines pass through theprospect. The potential reservoir is a good reflector. The larger of the twoculminations shows a "bright spot."

iii) Prospect is moderate to low risk with potential reserves of several tenmillion barrels.

IntroductionThis report describes the geologic and economic assessment of the Hepburn prospect carried outin November of the previous year. Five seismic lines delineate the prospect. Figure 1(seismic line

1) shows a possible gas accumulation at 1.9 sec with a two-way time thickness of about 10 ms.

Figure 1

Figure 2 is a structural contour map on the top of the reservoir (Unit A) based on the seismic data.
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Figure 2

Geology

StructureLow relief ESE-WNW trending anticline with two culminations. The structure is on aminor horst, bounded to the north and south by normal faults. Four-way closure,based on seismic data, has an estimated area of 4500 acres (18 km2) with 250 ft(76 m) of vertical closure.

ReservoirUnit A, a Middle to Upper Jurassic sequence of uniformly bedded alternating sand-shales throughout the 250 ft (76 m) of vertical closure.

Unit thickness: 150 ft (46 m)Net/Gross Pay: Ranging from 0.3 to 0.7, most likely 0.5-0.6Porosity: 12%-22%, most likely 17%

SealShales in the basal part of Unit B are required to provide a vertical seal for theprospect. Reflectors indicate good continuity in this unit. Assessment of laterallysealing faults is difficult.

SourceOverlying Unit B shales. Prospect is well-situated for migration from these shalesalong down-to-basin faults.

Reserve Potential

Reservoir is estimated to be half-full to spill point (based on experience in Fowlerbasin):Productive areal closure* = 3050 acres (12 km2)Gross reservoir volume = 228,750 acre-ft (282 106m3)


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Field Averages Minimum Estimate Maximum

Net/Gross ratio 0.3 0.6 0.7

Porosity 0.12 0.17 0.22

Oil saturation 0.6 0.65 0.7

FVF** 1.5 1.25 1.1

Net Reservoir Volume = Gross Reservoir Volume Net/Gross Ratio

Volume of Oil-in-Place = Net Reservoir Volume Porosity Oil Saturation k***/FVF

*Measured from maps by means of planimeter.

**Formation Volume Factor is a factor that quantifies the change in volume of

oil and gas when it is produced at the surface. It is mainly dependent onreservoir temperature and pressure.

*** k= 7758 bbl/acre-ft

Oil-in-Place

Minimum Estimate Maximum

106bbl 25.6 94.1 173.9

(106m3) (4.1) (15.0) (27.6)

Reserves (for estimated recovery of 28 %)

106 bbl 7.2 26.3 48.7

(106m3) (1.1) (4.2) (7.7)

Economic Analysis

Recovery is estimated at 26.3 million bbl with limited water drive.Life of field = 30 yrs

Investmentmillion $

Cost of 3000 m exploration well to casing point1.95(includes lease, geological, and geophysical costs)


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Exploration well completioncosts 2.32Total costs, discoverywell 4.27Field development costs (estimate 10 wells) plus surface equipment 50.00

TotalInvestment54.27

Potential ReturnPotential gross revenue (based on 26.3 x 106 bbl @ $30/bbl)789.00

Less: Operating Costs @$2/bbl 52.60

Investment54.27

Tax (50% net income after operating costs and investment)341.07

Potential Future NetRevenue 341.07

Potential Return/Risk Investment341.07 /1.95175/1

Risk Adjusted Return (based on 1.6 success rate)175/11/6

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Return on Investment341.07/ 54.276.3/1

Prospect Generation in Forantier Regions

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