Elk Antelope Gas Field 2009 GLJ - FINAL

8/9/2019 Elk Antelope Gas Field 2009 GLJ - FINAL

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INTEROIL CORPORATION

RESOURCE ASSESSMENT

ELK/ANTELOPE GAS FIELDPPL 238, PAPUA NEW GUINEA

Effective December 31, 2009

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ELK/ANTELOPE GAS FIELD

TABLE OF CONTENTS

Page

COVERING LETTER 3

INDEPENDENT PETROLEUM CONSULTANTS' CONSENT 4

INTRODUCTION 5

SUMMARY 6

RESOURCE AND RESERVES DEFINITIONS 8

APPENDIX ICertificates of Qualification 12

APPENDIX IIElk/Antelope Gas Field


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February 17, 2010

Project 1100116

Mr. Wayne Hamal

InterOil CorporationLevel 1, 60-92 Cook Street

Cairns, Queensland 4870

Australia

Dear Sir:

Re: Elk/Antelope Gas Field

Independent Resource Assessment


GLJ Petroleum Consultants Ltd. (GLJ) has completed an independent resource assessment of the

Elk/Antelope Gas Field located in Papua New Guinea for InterOil Corporation (the Company). The

effective date of this evaluation is December 31, 2009.

This report has been prepared for the Company for the purpose of annual disclosure and other financialrequirements. This evaluation has been prepared in accordance with resources definitions, standards and

procedures contained in the Canadian Oil and Gas Evaluation Handbook.

GLJ PetroleumConsultantsPrincipal Officers:

Harry Jung, P. Eng.

President, C.E.O.

Dana B. Laustsen, P. Eng.

Executive V.P., C.O.O.

Keith M. Braaten, P. Eng.

Executive V.P.

Officers / Vice Presidents:

Terry L. Aarsby, P. Eng.

Jodi L. Anhorn, P. Eng.

Neil I. Dell, P. Eng.

David G. Harris, P. Geol.

Myron J. Hladyshevsky, P. Eng.

Bryan M. Joa, P. Eng.

John H. Stilling, P. Eng.

Douglas R. Sutton, P. Eng.

James H. Willmon, P. Eng.


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INDEPENDENT PETROLEUM CONSULTANTS CONSENT

The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada hasprepared an independent resource assessment of the Elk/Antelope Gas Field located in Petroleum

Prospecting License 238 in Papua New Guinea for InterOil Corporation and hereby gives consent

to the use of its name and to the said estimates. The effective date of the assessment is December

31, 2009.

In the course of the analysis, InterOil Corporation provided GLJ Petroleum Consultants Ltd.

personnel with basic information which included land data, well information, geophysical and

geological information, and reservoir studies. Other engineering or geological data required toconduct the assessment and upon which this report is based, were obtained from public records,

other operators and from GLJ Petroleum Consultants Ltd. nonconfidential files. InterOil

Corporation has provided a representation letter confirming that all information provided to GLJ

Petroleum Consultants Ltd. is correct and complete to the best of its knowledge. Procedures

recommended in the Canadian Oil and Gas Evaluation (COGE) Handbook to verify certain interests

and financial information were applied in this evaluation. In applying these procedures and tests,

nothing came to GLJ Petroleum Consultants Ltd.s attention that would suggest that information

provided by InterOil Corporation was not complete and accurate. GLJ Petroleum Consultants Ltd.reserves the right to review all calculations referred to or included in this report and to revise the

estimates in light of erroneous data supplied or information existing but not made available which

becomes known subsequent to the preparation of this report.

The accuracy of any resources estimate is a function of the quality and quantity of available data

and of engineering interpretation and judgment. While resource estimates presented herein are

considered reasonable, the estimates should be accepted with the understanding that reservoir

performance or drilling subsequent to the date of the estimate may justify revision, either upward ordownward.

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INTRODUCTION

GLJ Petroleum Consultants Ltd. (GLJ) was commissioned by InterOil Corporation (the

Company) to prepare an independent resource assessment of the Elk/Antelope Gas Field

effective December 31, 2009. The Elk/Antelope Gas Field is located in Petroleum Prospecting

License (PPL) 238 in Papua New Guinea. InterOil Corporation (the Company) will hold a

57.4751 percent participating interest assuming that all investors and the Papua New Guinea

Government elect to fully participate after a Production Development License has been granted.

The structure was discovered with the drilling of the well Elk-1 which tested gas at 21.7 MMCFD

from DST#2 in 2006. The Elk structure is delineated by the Elk-1 and Elk-2 wells. The Elk-4 well

discovered gas and liquids in the Antelope structure. The reservoir of the Elk/Antelope structure

delineated by the Elk wells is contained within fractured limestones of the Puri and Mendi

Formations. The well Antelope-1 was rig released in 2009 and discovered a dolomitized reeffacies. The dolomitized reef was further delineated by the well Antelope-2 which was drilled with

one DST completed by December 31, 2009. The total gas column defined by the wells drilled to

date is approximately 788 metres in the Elk Block and 688 metres in the Antelope Block.

The resource assessment was initiated in January 2010 and completed by the end of February

2010. Estimates of resources were generally prepared using land, seismic, geological and wellinformation from the Company to approximately December 31, 2009. The Company has confirmed

that, to the best of its knowledge, all information provided to GLJ is correct and complete as of the

ff ti d t

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SUMMARY

Resource volumes presented in this report have categorized as Contingent Resources Economic

Status Undetermined. The following contingencies must be met before the resources can be

classified as reserves:

1) Sanctioning of the facilities required to process and transport marketable natural gas tomarket.

2) Confirmation of a market for the marketable natural gas and condensate.3) Determination of economic viability.

GLJ used risk modelling to determine the probability distribution for the recoverable gas

resources of the Elk/Antelope Gas Field. In a probabilistic approach, key parameters that form the

basis of the resource calculation are assigned a range of values and a corresponding probabilitydistribution. Monte Carlo methods are used to generate a group of realizations from which

resources values at various confidence levels are extracted. The parameters that were assigned a

range of values in this resource assessment consisted of volumetric parameters including

net/gross ratios, porosity, water saturation, gas/fluid contact elevations, reservoir areas and

recovery factor.

The results of the probabilistic analysis are summarized as follows:

Low Best High

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The original gas-in-place (OGIP) and resource estimates for individual geological entities are neither

completely independent nor dependent. Estimates for petrophysical parameters and net/gross ratios

for each rock type are generally independent given the methodology used in the analysis. The gross

rock volumes used in the probabilistic analysis are completely dependent due to common gas/fluid

elevations and structure top interpretation. Recovery factors are dependent since the entities share a

common reservoir pressure system and underlying aquifer. The strength of the aquifer will have

similar impact on the recovery from each geological entity. The risk simulation has been set up to

account for the dependent variables. Each iteration of the model relies on a single free water level or

abandonment pressure throughout each of the geological entities.

All figures referenced herein are included in the Supplementary Data report.

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RESOURCE AND RESERVES DEFINITIONS

GLJ Petroleum Consultants (GLJ) has prepared estimates of resources and reserves in accordancewith the standards contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. The

following are excerpts from the definitions of resources and reserves, contained in Section 5 of the

COGE Handbook, which is referenced by the Canadian Securities Administrators in National

Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

A. Fundamental Resource Definitions

Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is estimated to existoriginally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated,as of a given date, to be contained in known accumulations, prior to production, plus those estimatedquantities in accumulations yet to be discovered (equivalent to total resources).

Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that quantity ofpetroleum that is estimated, as of a given date, to be contained in known accumulations prior toproduction. The recoverable portion of discovered petroleum initially in place includes production,

reserves, and contingent resources; the remainder is unrecoverable.

Reserves are estimated remaining quantities of oil and natural gas and relatedsubstances anticipated to be recoverable from known accumulations, as of a given date,based on the analysis of drilling, geological, geophysical, and engineering data; the use ofestablished technology; and specified economic conditions, which are generally acceptedas being reasonable. Reserves are further classified according to the level of certaintyassociated with the estimates and may be subclassified based on development andproduction status. [Reserves are further defined below].

Contingent Resources are those quantities of petroleum estimated, as of a given date,to be potentially recoverable from known accumulations using established technology ortechnology under development, but which are not currently considered to be commerciallyrecoverable due to one or more contingencies Contingencies may include factors such as

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B. Uncertainty Categories for Resource Estimates

The range of uncertainty of estimated recoverable volumes may be represented by eitherdeterministic scenarios or by a probability distribution. Resources should be provided as low, best,and high estimates as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that willactually be recovered. It is likely that the actual remaining quantities recovered will exceedthe low estimate. If probabilistic methods are used, there should be at least a 90 percentprobability (P90) that the quantities actually recovered will equal or exceed the lowestimate.

Best Estimate: This is considered to be the best estimate of the quantity that will actuallybe recovered. It is equally likely that the actual remaining quantities recovered will be

greater or less than the best estimate. If probabilistic methods are used, there should beat least a 50 percent probability (P50) that the quantities actually recovered will equal orexceed the best estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that willactually be recovered. It is unlikely that the actual remaining quantities recovered willexceed the high estimate. If probabilistic methods are used, there should be at least a 10percent probability (P10) that the quantities actually recovered will equal or exceed thehigh estimate.

This approach to describing uncertainty may be applied to reserves, contingent resources, andprospective resources. There may be significant risk that sub-commercial and undiscoveredaccumulations will not achieve commercial production. However, it is useful to consider andidentify the range of potentially recoverable quantities independently of such risk.

C. Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances

anticipated to be recoverable from known accumulations, as of a given date, based on:

analysis of drilling, geological, geophysical, and engineering data;

the use of established technology;

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Possible ReservesPossible reserves are those additional reserves that are less certain to be recovered thanprobable reserves. It is unlikely that the actual remaining quantities recovered will exceedthe sum of the estimated proved plus probable plus possible reserves.

Other criteria that must also be met for the classification of reserves are provided in [Section 5.5 ofthe COGE Handbook].

Development and Production Status

Each of the reserves categories (proved, probable, and possible) may be divided into developedand undeveloped categories.

Developed Reserves

Developed reserves are those reserves that are expected to be recovered from existingwells and installed facilities or, if facilities have not been installed, that would involve a lowexpenditure (e.g., when compared to the cost of drilling a well) to put the reserves onproduction. The developed category may be subdivided into producing and non-producing.

Developed Producing ReservesDeveloped producing reserves are those reserves that are expected to be recovered fromcompletion intervals open at the time of the estimate. These reserves may be currentlyproducing or, if shut in, they must have previously been on production, and the date ofresumption of production must be known with reasonable certainty.

Developed Non-producing ReservesDeveloped non-producing reserves are those reserves that either have not been onproduction, or have previously been on production, but are shut in, and the date ofresumption of production is unknown.

Undeveloped ReservesUndeveloped reserves are those reserves expected to be recovered from knownaccumulations where a significant expenditure (for example, when compared to the cost of

drilling a well) is required to render them capable of production. They must fully meet therequirements of the reserves category (proved, probable, possible) to which they areassigned.

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A quantitative measure of the certainty levels pertaining to estimates prepared for the variousreserves categories is desirable to provide a clearer understanding of the associated risks anduncertainties. However, the majority of reserves estimates are prepared using deterministicmethods that do not provide a mathematically derived quantitative measure of probability. Inprinciple, there should be no difference between estimates prepared using probabilistic or

deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect ofaggregation is provided in Section 5.5.3 [of the COGE Handbook].

E. Commercial Risk Applicable to Resource Estimates

Estimates of recoverable quantities are stated in terms of the sales products derived from adevelopment program, assuming commercial development. It must be recognized that reserves,

contingent resources, and prospective resources involve different risks associated with achievingcommerciality. The likelihood that a project will achieve commerciality is referred to as the chanceof commerciality. The chance of commerciality varies in different categories of recoverableresources as follows:

Reserves: To be classified as reserves, estimated recoverable quantities must beassociated with a project(s) that has demonstrated commercial viability. Under the fiscalconditions applied in the estimation of reserves, the chance of commerciality is effectively100 percent.

Contingent Resources: Not all technically feasible development plans will be commercial.The commercial viability of a development project is dependent on the forecast of fiscalconditions over the life of the project. For contingent resources the risk component relatingto the likelihood that an accumulation will be commercially developed is referred to as thechance of development. For contingent resources the chance of commerciality is equal tothe chance of development.

Prospective Resources: Not all exploration projects will result in discoveries. The chancethat an exploration project will result in the discovery of petroleum is referred to as thechance of discovery. Thus, for an undiscovered accumulation the chance ofcommerciality is the product of two risk components the chance of discovery and thechance of development.

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APPENDIX I

CERTIFICATES OF QUALIFICATION

Keith M. Braaten

David G. Harris

Roger J. Mahoney

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CERTIFICATION OF QUALIFICATION

I, Keith M. Braaten, Professional Engineer, 4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada

hereby certify:

1. That I am a principal officer of GLJ Petroleum Consultants Ltd., which company did prepare

a detailed analysis of the Elk/Antelope Gas Field for InterOil Corporation. The effective date

of this evaluation is December 31, 2009.

2. That I do not have, nor do I expect to receive any direct or indirect interest in the securities of

InterOil Corporation or its affiliated companies.

3. That I attended the University of Saskatchewan and that I graduated with a Bachelor of

Science Degree in Mechanical Engineering in 1979; that I am a Registered Professional

Engineer in the Province of Alberta; and, that I have in excess of thirty years of experience in

engineering studies relating to Canadian and International oil and gas fields.

4. That a personal field inspection of the properties was not made; however, such an inspection

was not considered necessary in view of the information available from public information

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I, David G. Harris, Professional Geologist, 4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada

hereby certify:

1. That I am an employee of GLJ Petroleum Consultants Ltd., which company did prepare a

detailed analysis of the Elk/Antelope Gas Field for InterOil Corporation. The effective date




3. That I attended the University of Calgary and that I graduated in 1981 with a Bachelor of

Science Degree with honours in Geology; that I am a registered Professional Geologist in the

Province of Alberta; and, that I have in excess of twenty-eight years experience in geological

and engineering studies relating to Canadian and International oil and gas fields.



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I, Roger J. Mahoney, Professional Geophysicist, 230 - 38th Avenue S.W., Calgary, Alberta, Canada

hereby certify:

1. That I have been retained by GLJ Petroleum Consultants Ltd., which company did prepare a

detailed analysis of the Elk/Antelope Gas Field for InterOil Corporation. The effective date




3. That I attended the University of Manchester and that I graduated with a Bachelor of Science

Degree in Physics with Honours in 1964; that I am a Registered Professional Geophysicist in

the Province of Alberta; and, that I have in excess of forty-four years experience in

geophysical studies relating to Canadian and International oil and gas fields.



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INTEROIL CORPORATION

RESOURCE ASSESSMENT

ELK/ANTELOPE


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ELK/ANTELOPE

TABLE OF CONTENTS

Page

DISCUSSIONGeneral 3Regional Geology 4Geophysics 7Geology 15Engineering 28

MAPSMap 1 Location Map 33Map 2 Early Miocene Paleogeographic Map 34Map 3 Seismic Control 35Map 4 Depth Structure Map - All Blocks - GLJ 36Map 5 Depth Structure Map - All Blocks - InterOil 37Map 6 Depth Structure Map - Top Puri Reef - GLJ 38Map 7 Depth Structure Map - Top Puri Reef - InterOil 39

PLOTSPlot 1 Regional Pressure versus Depth Plot from InterOil 40Plot 2 Elk/Antelope Pressure versus Depth Plot 41Plot 3 Elk/Antelope Pressure versus Depth Plot - Expanded 42Plot 4 Cumulative Probability Curve - Gas Resources 43Plot 5 Cumulative Probability Curve - Condensate Resources 44

TABLESTable 1 Core Analysis - Routine and Stressed 45Table 2 Petrophysical Summary - Off Reef 46Table 3 Petrophysical Summary - Reef 47


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GENERAL

The Elk/Antelope Gas Field is located in Petroleum Prospecting License (PPL) 238 in Papua New

Guinea as shown on Map 1. The block is approximately 300 kilometres northeast of Port

Moresby. InterOil Corporation (InterOil) will hold a 57.4751 percent participating interest

assuming that all investors and the Papua New Guinea Government elect to fully participate after

a Production Development License has been granted.

The structure was discovered with the drilling of the well Elk-1 which tested gas at 21.7 MMCFD

from DST#2 in 2006. The Elk structure is delineated by the Elk-1 and Elk-2 wells. The Elk-4 well

discovered gas and liquids in the Antelope structure. The reservoir of the Elk/Antelope structure

delineated by the Elk wells is contained within fractured limestones of the Puri and Mendi

Formations. The well Antelope-1 was rig released in 2009 and discovered a dolomitized reef

facies. The dolomitized reef was further delineated by the well Antelope-2 which was drilled with

one DST completed by December 31, 2009. The total gas column defined by the wells drilled to

date is approximately 688 metres in the Antelope Block and 788 metres in the Elk Block.

Currently, there is no infrastructure in place to process and transport the natural gas to markets.

The Elk/Antelope Gas Field is expected to form the resource base for a future liquefied natural

gas project to be constructed near Port Moresby.

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REGIONAL GEOLOGY

Papuan Basin

The Papuan Basin contains sediments that range in age from the Late Triassic (~235 million years

before present) to Pliestocene (recent) in age. The main geological events and the principal

formations are described as follows1:

1. Triassic Rifting Regional grabens created by the breakup of Gondwanna formeddepositional lows for the accumulation of the Kana Volcanics, of Triassic age, and the

arkosic (or feldspar-rich) clastics of the Lower Jurassic age Bol and Kanau Sandstones.

2. Middle Jurassic to Upper Jurassic extensional phase The post-rift extensional timeperiod created a wide, passive margin in the south and west towards the emergentAustralian craton, and deep water, basinal conditions to the north and east. In the deeper

parts of the shelf, and in the basin there was widespread deposition of organic rich muds

throughout the Middle Jurassic (Barekewa Mudstone in the south and west on the shelf,

Maril Shale in the deep basin to the north and east). The Upper Jurassic is marked by

regression, and the associated progradation of a coarse clastic sequence (the Koi lange

sandstones) over the shelf mudstones. A marine transgression returned the shelf area to

relatively deeper water conditions, resulting in renewed mud deposition (the Imburu

Mudstone) to the end of the Jurassic. In the basin regions, mud continued to be deposited

i ht t th d f th J i (M il Sh l )

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the Kerabi Formation, sourced from the volcanic mountains to the north, were laid down

on this unconformity.

4. Upper Cretaceous uplift, exposure and erosion The Upper Cretaceous saw the onset ofrifting associated with the opening of the Tasman/Proto-Coral Sea. Significant structural

movement was associated with this event, resulting in regional uplift throughout the west,

and deepening conditions in the east. In the west, the Ieru Formation was exposed,

undergoing erosion from the late Aptian until the Middle Oligocene.

In the east, the Kerabi sandstones were covered by a thick sequence of mudstone and

shale (the Upper Cretaceous aged Chim Formation). This period was also complicated by

continued volcanism, brief times of increased sediment influx, and further periods of

uplift. These events created several transitional (barrier island/strand plain),

progradational sand sequences throughout the Upper Cretaceous (Cenomanian aged Subu

Sandstone and the Campanian aged Pale Sandstone). The Pre-Tertiary unconformity,which, as mentioned above, extends from the Late Aptian to the Middle Oligocene in the

West, becomes less definitive in the east; Maastrichtian to Mid-Eocene in the western

portion of the eastern basin, to absent in the far east (Kubor Anticline) where the

Paleocene aged Moogil Mudstone is present.

5. Early to Middle Miocene Carbonate Platform Development The Middle Oligocene sawtwo important geological events; firstly, the conversion of the tectonic regime from a

divergent to a convergent system, and secondly, the overall migration of the region from a

t t l tit d t t i l i

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the shelf edge. Large reefs were also established on structural highs in front of

the main trend (three of these, the Uramu, Pasca and Pandora reefs, located

offshore in the Gulf of Papua, contain significant gas resources). With

continued loading from the thrust sheet to the north, the basin deepened and

sediment influx increases. This caused backstepping of the reef trends into

shallower, cleaner waters to the south.

ii. Northward Movement Following separation from Antarctica, the Australiancontinent started to move northward from temperate areas towards tropical

climactic zones. By early to Mid-Miocene times, the region was tropical,which assisted in the development of the reefs.

6. Middle to Late Miocene, carbonate platform demise A regional fall in sea-levelterminated carbonate deposition. Clastic sediments from the north begin to bury the

northern edge of the platform

7. Late Miocene to Early Pliocene, regional clastic sedimentation A major rise in sea levelinitially greatly expanded the area of the foredeep, resulting in the deposition of shales

over the area (lower part of the Orubadi). However, with the encroachment of the

emerging mountain belt to the north, the foredeep and platform was eventually infilled

with clastic sediment. Compressional deformation associated with the southward

movement of the mountain belt created the faults and anticlines that trapped migrating

gas.

Th b t bi d t t l t t l t Th k th

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GEOPHYSICS

This interpretation of the seismic data includes information from the Elk-4 well, together with

data from the Antelope-1 and Antelope-2 wells. The work has been concentrated on obtaining a

depth structure map to the top of the Puri Limestone, top of potential reservoir, and also the

mapping of the extent of the porous facies involved in the reef development in the area.

Basic Data

The seismic grid consists of 2D data that has been acquired in 2005 and 2007 (Map 3). The

majority of the lies trend east-northeast to west-southwest, which is the direction that is

approximately normal to the dominant strike of the thrust sheets. Three more lines trend northeast

-southwest, and these combined set of lines are best positioned to map the thrusting in the area.

There is a redundancy of seismic control in the vicinity of the Elk-1 well and some of these lines,

if they had been moved to areas with no current control, would have helped improve the

interpretation. All the data has been acquired with large split spreads, a minimum of 10 kilometre

offset, which is an important consideration in the migration of the data in a structured area. The

group interval used in the 2005 survey was 30 metres, and this was reduced to 15 metres during

the 2007 acquisition. Presumably there may have been a concern with aliasing in the processing

of the 2005 data and subsequently the decision was made to half the group interval in the 2007

data set. Steep dips are apparent in the shallow part of the data, but at the Puri Limestone level the

most pronounced dips appear to be on the splay thrust, the Bevan Elk North, near the Elk-1 well.

When measured on the line E2IOL05, the dip on the Puri Limestone was measured to have a

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considered interpretive. The same applies to the event from the top of Dolomite, it is also not

considered a reliable event. Seismo-stratigraphic work and analysis will be important in

attempting to map the distribution of the best quality reservoir facies within the reef section.

Using the information from the seis-strat work development wells could be positioned to target

preferred reservoir facies. Acquisition of a 3D survey that was positioned over the area of the

currently mapped area of gas accumulation would be advantageous in the facies analysis of the

reef (however, this seismic acquisition may prove cost prohibitive owing to surface

considerations). The interpreted main reef is thick, (on Line e17iol07 the thickness is ~0.350

seconds; using an estimated intra reef velocity of 5000 metres/second (m/s), this computes to areef isopach of ~ 875 metres) and it would be possible to undertake some seismo-stratigraphic

analysis in this interval, especially when a future well has been drilled into this section and would

provide the data to hopefully calibrate the seismic.

Velocity information in the form of Vertical Seismic Profiles (VSP) and/or checkshots is

available at the wells. GLJ tied the seismic data to the wells, with only Elk-2 not providing adirect tie to the seismic. The independent identifications of the seismic events made by GLJ agree

with the identifications made by InterOil. Consequently the interpretation that was supplied to

GLJ by InterOil was used as the framework for the GLJ interpretation.

Tectonics

The main thrusts in the area of interest are reasonably well defined at the zone of interest, but less

well defined in the shallow section. They are oriented in an approximate north-northwest to

th th t di ti i l i th t th i i l f i t th t

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structure. However, the Puri Limestone event is continuous on the eastern side of the structure,

there does not appear to be a fault present. On line e09IOL07, to the south, both the Mena Fault

and the Puri Antelope Cross Fault are clearly present and separate; on line E1IOL05 and lines to

the north, these two faults have been merged. Additional seismic control in this area would help

resolve the relationship between the two faults in the area of the Mule Deer Structure.

On the interpreted set of data that GLJ received from InterOil a transfer fault, named the Bevan

Elk Transfer Fault, had been interpreted, southeast of ELK-1, and trending northeast to southwest.

It was difficult to confirm the presence of this transfer fault on the GLJ work so that it has beenomitted from the interpretation. GLJ has used another fault, the Bevan North Elk Thrust, in order

to explain the structuring in the vicinity of the Elk-1 well. The Elk-1 well has penetrated a

thrusted sheet that appears to carry a partial carbonate section at the well location. This fault has

been interpreted by GLJ as a splay thrust off the Antelope Front Fault, merging with the Antelope

Front Fault north of the Elk-1 well. The throw on this fault, the Bevan Elk North dissipates to the

southeast with the fault merging with the northwest to southeast trending Bevan South Fault. Onthe InterOil interpretation, the Bevan Elk Transfer Fault ties the Bevan South Fault, (the

northeasternmost fault), and as a result separates the northeast designated interpreted carbonate

block from the southeast block. It is possible that the section penetrated by the Elk-1 well has

become detached as a result of compression. This would be similar to the detached Laramide

blocks, like the Heart River block, found in Wyoming.

The InterOil structure map shows a high on Line-e12iol07, abutting the Antelope Front Fault, and

a profile for a portion of this line has been included in order to demonstrate the differences in the

i t t ti (Fi 2) I th i i it f th li t f lt th A t l F t d th P i

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identification of any surface information. 2) It is sometimes possible to identify discontinuities/

faults by examining the refraction data that was used in the first break analysis as part of the

statics computations. It might be worthwhile inspecting the refraction profiles that have been

generated in order to determine if there is any evidence for the presence of faulting in the shallow

part of the section.

GLJ has placed the Antelope Front Fault to coincide with the termination of the coherent events.

Faulting is not the only mechanism that can affect the loss of continuity and/or signal/noise ratio

on the data. In order to attempt to eliminate the possibility of other causes it is suggested that thecritical part of Line e12ioL07 be reprocessed to find out if changes in, e.g. 1) the mute, 2) the

offset range of traces in the stack , 3) the applied NMO, or 4) changes in the bandpass, have the

effect of improving the data quality. It is not advocated that any velocity filtering, or similar

technique, that will create lateral continuity on the data be carried out. By undertaking this

reprocessing it may be possible to better resolve the placement of the Antelope Front Fault. This

is not only important from a gas-in-place perspective, but also because an additional well may beplaced in this area.

It should be emphasized that interpreting fault patterns using a sparse 2D grid of data will

probably not result in the optimum fault configuration. This was demonstrated by Shell Canada

Limited in a paper that was published a number of years ago which reported on the changing

interpreted fault pattern, onshore The Netherlands, when sparse 2D, then detailed 2D, and finally

3D seismic was available. Additional 2D control, or better still, some 3D data over the Elk area

will modify the existing InterOil and GLJ fault patterns. The interpreted fault configurations that

i t b id d th b t ff t i th t d t t

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event has been identified as a strong trough that lies immediately below the Top Puri Limestone

event. The Base Main Reef/Mendi Limestone top event has been picked as a strong peak; the

original Mendi identification having been made with a tie to the Elk-2 well. These two events

have been identified on the assumption that the data set has been recorded and processed adhering

to the SEG polarity convention, i.e. a compressional wave is displayed as a trough. The top reef

has therefore been identified as a strong trough; a compressional wave, and the base reef has been

identified as a strong peak, a rarefaction, a high to low velocity interface. Note that the original

Top Puri event is three quarters of a cycle above the top reef pick, but the two picks track each

other in the area of the reef. No stratigraphic relevance or significance should be placed on theseparation of the top Puri and top reef picks.

The Top Puri Limestone was identified and correlated on both the upthrown and downthrown

sides of each thrust fault. This was the reason for compartmentalizing the Puri picks into areas

assigned to each fault block. In this manner the structure on the Top Puri was mapped in the areas

of overlapping picks beneath the fault planes.

The top of the reef penetrated in the Antelope-1 well ties to a weaker event on the seismic. When

the interpreted version of Line-E4Iol05 (Figure 3) is examined the reef slope of the main reef,

between CDPs 490-550, is clearly visible. The reef that has been penetrated in Antetlope-1

appears to be a younger reef that has been formed to the northwest of the main reef, probably

after a brief hiatus in carbonate deposition. The location of the younger reef has been controlled

by the differential structuring that was ongoing during the reef building time, with there being a

structural tilting, approximately northwest to southeast. There is a possibility that a third phase of

f b ildi h d d t t d Li 09i L07 (Fi 4) h th ibl f

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that have porosities in the 28 percent range. The conclusion to be drawn from inspecting the

seismic lines across the mapped reef is the deposition has been cyclical, and that the porous units

present are discrete and separated by non-reservoir units, or reservoir units of lower porosity.

The GLJ fault pattern together with the reef distribution is shown on Map 3. The positions shown

for the faults are at the terminations of the Top Puri event on the upthrown side of a fault. The

light blue outline shown is an attempt to map the areal extent of the development of the porous

Limestone unit that was penetrated in Antelope-2. The darker blue line is the interpreted limit of

reef build up, where the top and base reef events merge. It is difficult to map the limit of the reefto the east, with the data quality deteriorating near the Bevan Fault. To the west the reef abuts the

Antelope Front Fault, which if active could have limited reef growth in this direction. Note that

thin reef is interpreted to be present at the location of Elk-4, but the well did not drill deep enough

to encounter the interpreted reef. The mauve line on the map indicates the interpreted extent of

the upper dolomite section, as penetrated in Antelope-1 and Antelope-2.

Depth Conversion

The Top Puri Limestone two-way time (TWT) structure map was converted to depth using a

velocity map that was constructed by employing a number of ghost wells positioned to provide

additional velocity control. The positions of the ghost wells that were used are shown by crosses

on Map 3. All the ghost wells are directly tied to the seismic data in order that a Top Puri

Limestone time could be measured. In Tertiary basins, the velocity in the clastic section is

directly related to the depth of burial, with the value measured usually being in the range of 0.5-

0 7 / / Th th ti l l ti hi d i f ll

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In undertaking this depth conversion it would be preferable to map a value of K derived from the

wells, and obtain the average velocity map to the Puri Limestone in this manner by employing a

variable K. However, the four wells are clustered in a north-south line with, with no spatial

distribution, preventing employing a variable K. For the first set of depth maps that GLJ

produced, a constant K was been used , which was derived from the data in Antelope-1, and this

value of K was used in all the ghost wells. In the three remaining drilled wells the average

velocity to the Puri Limestone/top carbonate is obtained using the depth and time value at the

particular well. The first step in the calculation is to obtain a depth to the Puri Limestone at a

particular ghost well. This is done using the following relationship.

Z = 2VoT/ (4-KT)

In order to obtain a velocity value at a ghost well this depth was used together with the TWT to

the Puri at the well tie. Once the velocities at all the wells were obtained, a map of the average

velocity to the Top Puri Limestone was gridded and contoured. This velocity map was then

integrated with the Top Puri TWT map in order to produce a structure map to the top of the

carbonate (Map 4).

The ghost wells were placed so as to provide spatial velocity control, but should also honour

critical TWT highs and lows.

A potential problem in employing this technique in areas that have been structured is that portions

of the section could have been deeply buried prior to the tectonic phase. Being deeply buried and

subsequently being uplifted would result in a higher velocity section being positioned at a

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order to expand the mapping. A new K map was then produced and extrapolations carried out to

the next closest dummy wells until K values were obtained over the entire map. The formula for

converting to depth Z is shown above. GLJ obtained an average velocity to the Puri Limestone by

using the Puri depth and time maps.

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GEOLOGY

Elk/Antelope

The Elk/Antelope gas field is located in the Puri fold and thrust belt of the Foreland portion of the

Papuan Basin, Papua New Guinea. Gas in this field is structurally trapped within a complex pore

system that is developed within carbonates of the Early Miocene age Puri Formation (also known

as the Darai Carbonate). As shown on the depth structure map presented herein as Map 4, drillingto date has proved gas in two fault blocks (Elk and Antelope), with a third fault block to the west

that is structurally high enough to contain gas (Mule Deer). Based on new pressure-depth data

and a re-interpretation of older data points, GLJ now interprets that the drilled blocks may not be

in direct hydraulic communication. The free water level in the Elk Block appears to be lower than

in the Antelope Block, and additional data regarding condensate yields suggest that the fluids are

also of different compositions (see the engineering sections of this report). This would require theBevan Fault to be sealing; possible reasons for a fault sealing in this situation could be fault

gouge, fault cementation and/or bitumen (which has been noted in some tests), and will have a

tendency to seal regions against fluid flow.

The top seal is provided by the marls, siltstones and shales of the overlying Orubadi Formation.

The reservoir is not sealed at the base. The down dip limit of the gas reservoir is controlled by the

intersection of declining structure on the flanks, and a gas/water contact that will vary according

to the quality of the reservoir in the region of the free water level (FWL)2. Based on the most

lik l FWL t l ti f 2228 t i th A t l Bl k d t iti f 0 0

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cryptocrystalline and microcrystalline limestone, low permeability intercrystalline pores in more

microsucrosic limestones, and very high permeability created by the fracture system.

The Antelope-1 well penetrated a thick, Early Micoene Reef development. A study of the samples

by Dr. Moyra Wilson3 has confirmed that pervasive dolomitisation of an original reef facies has

occurred. The uppermost carbonate section (1754 1779 metres) is described as mudstone,

wackestone and coral floatstone, containing Common coral fragments together with rare

imperforate foraminifera (Borelis) and micritised coralline algae. The dominant depositional

environment is interpreted to be a shallow photic zone in close proximity to coral growth.

InterOil obtained a Formation MicroScanner Image (FMI) of the Antelope-1 borehole. This

proved invaluable in logging the entire well for a depositional profile. InterOil provided GLJ with

a copy of the interpretation of this log suite conducted by Schlumberger, Data & Consulting

Services Division, Perth, dated February 6, 2009. Schlumberger divided the Puri carbonate into

five facies based on FMI image texture, dolomite content and BorTex outputs:

1. Back Reef Reef Fringe (2454.0 2246.6 metres)2. Reef Flat Reef Crest, rough water (2246.6 2060.3 metres)3. Reef Flat, calm water (2060.3 1976.2 metres)4. Reef Flat, rough water (1976.2 1935.0 metres)5. Dolomitized Reef (1935.0 1732.0 metres).

Special Core Studies and the Assessment of the Porosity Cutoff

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fracturing; some would argue that a porosity cutoff should not be used at all in a fractured system

because the pores tend to be such a short distance away from a channel of communication. GLJ is

not in agreement with this interpretation, and submits that a porosity cutoff is still necessary since

the gas still must flow in the matrix in order to get to a fracture. However, the porosity cutoff that

is applied should be lower than for typical reservoir with more conventional matrix permeability.

At a permeability cutoff of 0.005 to 0.01 md., a porosity cutoff ranging between 2.0 and 6.0

percent is suggested. GLJ reviewed additional special core data in order to narrow this range.

Capillary Pressure Data

The core samples from Elk-2 were subjected to both mercury and air-brine capillary pressure

tests. The mercury injection data has been converted to an equivalent height above the free water

level using typical lab to reservoir, and mercury to gas contact angles and interfacial tension

constants. These results are presented as Figure 7.

Of six samples tested, it is noted that three samples (#2, 30 and 45) had entry pressures that are so

high that gas is not likely to be present in rock of this quality, even at 2000 feet above the FWL.

The highest porosity and permeability observed in these three samples is 2.1 percent, and 0.002

millidarcies, respectively. This lower limit is consistent with what was suggested by the

overburden corrected core data above. The remaining three samples (#82, 83 and 88) all show

that reasonable gas saturations (>35 percent) can be expected at distances greater than about 163

feet above the FWL (i.e. the thickness of the lower transition zone, where gas saturations are too

low to allow gas movement, is expected to exceed 163 feet). The lowest porosity and

bilit b d i th l i 5 1 t d 0 041 illid i ti l

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should be well above this value. The midpoint of these end points would seem to be a reasonable

value for a most likely case, which can be rounded down to 3.5 percent. GLJ has utilized a

porosity cutoff of 3.5 percent in the low and most likely cases, and has dropped it to 3.0 percent

in the high case.

J Function

A method of normalizing capillary pressure functions has been established; it is referred to as the

Leverett J Function. This is a useful way of estimating the water saturation that is independentfrom log analysis. The equation is as follows:

J = [0.2166 x Pc x (k/)]/(T cos )

Where:

Pc = Capillary Pressure (psi)K = permeability (md)

= Porosity (v/v)T = Interfacial Tension (dynes/cm)

= Contact angle, degrees.

Capillary pressure data from the laboratory is used to establish a correlation of J against Sw. The

J is then calculated in the reservoir, and the correlation is used to estimate the Sw. However, the

main drawback of this method is that it is based on the ratio of permeability to porosity, and as

such can have misleading results in low permeability rocks. As an extreme example, this method

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Archie Parameters

Twelve samples were analyzed to determine the cementation factor (m) and the saturation

exponent (n). This analysis showed that m varies between a low of 1.79 and a high of 2.23,

with an average value of 2.00. The saturation exponent varies between a low of 1.68 and a high of

2.23, with an average of 1.89. The average factors were used in the petrophysical study conducted

herein.

Petrophysical Analysis

GLJ has conducted a detailed petrophysical analysis of all of the wells that delineate the

Elk/Antelope reservoir as of December 31, 2009. All digital files, including the open-hole logs

and the directional surveys were obtained directly from InterOil. Horizon picks supplied by

InterOil were verified by GLJ. This data was loaded into the GEOLOG software used by GLJ,

and was analyzed using deterministic methods.

Given the complexity of the reservoir, the varied pore types, and the need to define ranges for

later use in the risk analysis, GLJ directed the petrophysical study towards defining a low case,

most likely case, and a high case set of well bore parameters, using the following procedure:

Based on sample and log descriptions, it is interpreted that there is very little clay in thePuri carbonate. The Volume of shale (Vsh) was determined using both the Gamma Ray

and the Sigma logs. For the Gamma Ray, the Clavier transform was used. The exact

th d f bi i th V h d t i d f h f th l l l d d t

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The PHIE was determined using a neutron-density cross plot. A comparison of the variousraw neutron log suites to the overburden corrected core porosity suggested that the APLC

log was the appropriate curve to utilize. It was later discovered that this was the preferred

tool used by Schlumberger in the analysis they presented. For the basinal limestones, the

PHIE was limited by a maximum value of (1-Vsh) x 0.11. Due to the amount of bad hole

present, a detailed review of this value was conducted to ensure that the bad hole

processing, and this upper limit were appropriate. In the reef, this value was increased to

0.40, however, the density log was altered where necessary based on the sonic and the

neutron porosity log, so the bad hole was processed somewhat differently. The PHIE determined by GLJ was compared to that determined by Schlumberger, and it

was noted that the Schlumberger analysis was slightly more pessimistic. It is difficult to

determine the accuracy of either porosity curve using the overburden corrected core data

due to great uncertainty in the depth adjustment that should be made. However, on at least

a qualitative basis, the overburden corrected core porosity suggests that both may be a

slightly low. However, substantial additional core analysis must be obtained before anyconcrete conclusions can be made.

With the petrophysical analysis geared towards determining appropriate inputs for theRisk Analysis, GLJ determined three porosity curves; a low case PHIE curve which was

based on the minimum value of the GLJ and the Schlumberger curves, a most likely value

which was the average of the two, and a high case which took the maximum of the two

curves.

Log based water saturation was determined using the PHIE from the most likely case, theArchie parameters from the special core study, and the deep resistivity log. This Sw curve

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Reef Model

Depth Structure

The depth structure map on the top of the reef was determined using the following procedure:

1. An isochron map of the interval between the top of the Puri Formation and the top of thereef was created.

2. This map was converted to an isochore map using the pseudo-seismic interval velocitydetermined at the Antelope-2 well.

3. This Isochore map was then subtracted from the depth structure map created on the top ofthe Puri.

Reef Isochore and Layer Depth Structure Maps

The gross thickness isochore map for the total reef was generated by stacking three layers (in

stratigraphically descending order): the high porosity limestone that caps the reef in the Antelope-

2 well, the dolomitic portion of the reef penetrated by both the Antelope-1 and Antelope-2 wells,

and the reef limestone below the dolomite that is continuous to below the gas-water contact

(GWC).

The upper porous limestone isochore was generated using the same procedure described above

for the limestone above the reef. The isochron map was converted using the pseudo-seismic

l it t t d f th A t l 2 ll Si il l th i h f th hi h it

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Volumetric Risk Analysis

The volumetric analysis of the Elk/Antelope field involved splitting the structure into three fault

blocks (Elk, Antelope and Mule Deer, as shown on Maps 4-7). The Antelope Fault Block was

further subdivided into a Reef and a Non-Reef facies, and the reef itself was split into a high

porosity limestone cap, and high porosity dolomite and a medium porosity lower reef limestone

volume. Within each of these fault blocks, the pore system was further subdivided into a matrix

and a fracture component. Each of these pore systems was analyzed individually, as follows:

Free Water Level/Gas-Water Contact

As noted previously, the FWL in the Elk Block has been placed at an elevation of -2248

metres, whereas the FWL in the Antelope Block is placed at an elevation of -2228 metres

based on the pressure-depth work. The highest known water occurs at the top of the Puri

Limestone in the Elk-2 well, at an elevation of -2261.0 metres, whereas the lowest known gas

(somewhat reliably picked based on all three Sw curves) occurs at an elevation of -2199.7 in

the Elk-4 well. These elevations are consistent with the FWL identified in the pressure-depth

work.

In this reservoir, the exact elevation of the GWC will depend on the quality of the rock in the

transition zone. In the fracture system, the GWC is equal to the FWL. In a highly porous and

permeable rock, such as in the reef in the Antelope Block, the GWC could be a few metres

above the FWL. However, throughout the non-reef portions of this reservoir, the matrix is of

lit h th t th GWC ill b ll b th FWL ( di d i th li

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Residual Oil

An examination of the tests that were run in the sidetrack wells at Antelope-1 show the rare

recovery of both black oil and some bitumen. However, as discussed in the test review, the

existence of pure gas tests in equivalent structural intervals suggests that this oil saturation is

not a continuous phase across the field. GLJ has modeled this as a sporadically distributed oil

saturation that comes into play at an elevation of between -2195 metres and -2210 metres.

Although this has been handled as a reduction in the average gas saturation below these

elevations (of between 5 and 20 saturation units), it should be noted that it is likely that the oilsaturation reaches values both above the high end of this distribution (probably where oil was

recovered) and below the low end (where it is immobile and only gas is recovered). The

values used in this analysis are considered a reasonable average for the structural interval

when taken as a whole unit. To date, there has been no data supplied that would assist in

defining both the distribution of the oil and the actual oil saturations.

Oil saturations have not been applied outside the Antelope Block.

Fracture System

GLJ has conducted a detailed study of the fracture system as discussed in the Engineering

section. This review has indicated that the fracture net/gross ratio varies between about 0.5

and 0.7, and the fracture porosity varies between 0.07 and 0.15 percent. The water saturationin the fracture system is estimated to be between 1.0 and 5.0 percent.

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Matrix System Reef

GLJ conducted a petrophysical study on the reef penetrated by the Antelope-1 and Antelope-2

wells, as noted on Table 3. These properties were used in the volumetric assessment of the

OGIP in the reef.

A full summary of the input parameters is presented on Table 4.

Volumetric Model

The model is set up to first calculate the OGIP in each pore system assuming that no reef is

present, then it calculates the OGIP in the reef. The final process is to add these two together and

subtract the duplicated volume. The following example, using the mean values from Table 4

and the InterOil Depth Structure Maps, illustrates how the Risk Model works (more significant

digits in the model result in some slight differences in the products noted below):

Gas-Water Contacts

FWL = -2228 = GWC in fracture system in the Antelope Block (-2248.0 in the otherBlocks).

Non Reef GWC - Basal transition zone thickness in micritic limestone matrix = 46.3metres, giving a matrix GWC at -2181.7 metres in the Antelope Block and -2201.7 metres

in the other Blocks.

Reef GWC

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Micritic limestone Matrix: Antelope GVr above Sor zone = Antelope GVr aboveGWC = 13.13 MM ac-ft, Elk = 3.99 MM ac-ft, Mule Deer = 11.01 MM ac-ft.

Matrix N/G = 0.111, PHIE = 0.061, Sg = 0.61, Bgi = 204.1; OGIP in matrix inAntelope if there was no reef = 479.5 BCF, in Elk = 144.6 BCF and in Mule Deer =

399.1 BCF, for a total of 1023.2 BCF in the micritic limestone matrix if no reef was

present.

Fracture System in the micritic Puri Limestone:

Antelope GVr in Puri above Sor zone = 12.37 MM ac-ft, Elk = 3.89 MM ac-ft, MuleDeer = 10.59 MM ac-ft. Please note that even though the GWC is lower in the fracture

system, in some cases the fracture system GVr is lower than the matrix GVr because

the net rock volume included in the matrix system must be excluded (the PHIE of the

matrix was calculated using neutron-density tools, therefore the fracture porosity is

included here). Fracture net/gross = 0.6, PHIE = 0.0011, Sg = 0.972; the OGIP in the fracture system

below the matrix porosity cutoff in Antelope = 68.4 BCF, Elk = 21.3 BCF and in Mule

Deer = 58.1 BCF for a total of 147.8 BCF. The OGIP in the fracture system below the

top Sor zone in the Antelope Block is calculated at 4.6 BCF, for a total of 152.4 BCF

in the fracture system.

Mendi Limestone:

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Static model GVr rock of porous limestone cap between Sor top and GWC =0.2 MM ac-ft., when multiplied by 0.8 gives a value of 0.16 MM ac-ft. Using

the parameters in Table 4, the OGIP is estimated at 134.4 BCF.

Dolomite: Static model GVr of dolomite above Sor zone = 6.91 MM ac-ft. Whenmultiplied by the continuity uncertainty factor of 0.8 a value of 5.53 MM ac-ft is

calculated. Using the petrophysical parameters presented in Table 4, the OGIP is

estimated at 6055 BCF.

Static model GVr rock of the dolomite between the Sor top and GWC = 0.5MM ac-ft., when multiplied by 0.8 gives a value of 0.4 MM ac-ft. Using the

parameters in Table 4, the OGIP is estimated at 370.3 BCF.

Lower Reef Limestone: The static model GVr of Lower Reef limestone above top ofthe Sor zone = 2.27 MM ac-ft. However, the gross rock excluded in the above facies

by the application of the lateral uncertainty factor of 0.8 must be included with this

volume. Therefore, the final GVr of this facies is estimated at 4.23 MM ac-ft. Using

the petrophysical parameters presented in Table 4, the OGIP is estimated at 1613 BCF.

The mean estimated OGIP in the reef = 2253.8 + 134.4 + 6055.0 + 370.3 + 1613.0 =

10426.5 BCF.

3. Must subtract OGIP in the duplicated rock volume: OGIP in micritic limestone volume replaced by reef = 516.8 BCF.

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Elk/Antelope structure was connected to this system, then an infinite-acting aquifer would be

expected. However, as shown on Plot 1, the Elk/Antelope aquifer is approximately 460 psi higher

in pressure, proving a disconnection. The over pressuring of this aquifer could be related to asealed fault block or series of fault blocks being elevated during tectonic movement, which would

result in a limited water drive, or a higher recharge area (approximately 500+ metres above sea

level, which would be in the mountains to the north). This second option would require a

regional, north-south oriented permeability barrier to the west of the structure. If this was the

case, then a strong aquifer would exist.

Given that there are no production analogues for this field, GLJ has considered the above

information in assessing the recovery factor. At this point in time, GLJ interprets that the first

possibility discussed above is the more likely scenario, and that reasonably good recovery is

likely. A detailed discussion on the derivation of the recovery factor within the probabilistic

model is presented in the Engineering section.

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ENGINEERING

Well Test Results

Drill stem tests (DSTs) have been analyzed by Focal Petroleum Engineering Pty Ltd. or

Knowledge Reservoir, LLC. The results of the individual DSTs are presented in Table 5.

There exists some uncertainty in the extrapolated reservoir pressures due to the limited shut-intimes and the mechanical problems experienced during the pressure buildup periods. This

uncertainty is partially reflected in the range of pressures interpreted by the two referenced firms.

The uncertainty gives rise to a range in the interpreted free water levels in the Antelope Block as

will be discussed further on in this report. GLJ did not conduct an independent pressure test

analysis for these DSTs.

It is noted that DSTs that straddled the FWL did not conclusively recover significant volumes of

formation water. The data reviewed to date suggest that most of the water recovered was

completion fluid. This could mean that water influx may not be a significant factor in the

reservoir depletion mechanism, at least at the points penetrated by wells thus far.

Initial Reservoir Conditions and Fluid Properties

The initial reservoir conditions and fluid properties used in the best estimate case in this study are

i d f ll

g

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The calculated condensate yields on the four PVT analyses are summarized in the following

table:

Well DST

Interval

Top Elevation

m

Interval

Base Elevation

m

Condensate

Yield1

BBL/MMCFraw

Elk-4 DST 4 -2063.9 -2189.1 19.8

Antelope-1 DST 6 -1537.3 -2129.1 17.0

Antelope-1 DST 12 -2125.2 -2203.1 18.5

Antelope-1 DST 14 -2220.3 -2252.7 17.0

Notes:

1) Calculated from recombined well stream composition.

The difference in pressure and gas composition between the Elk and Antelope Blocks suggests

that these are two separate gas accumulations. The condensate yields observed to date suggest

that there is not a significant compositional gradient within the Antelope Block.

The volumetric risk analysis uses the following triangular distributions for the reservoir pressure,

condensate yields and shrinkage for removal of CO2, condensate and fuel gas requirements:

Parameter

Low

Estimate

Best

Estimate

High

Estimate

Elk BlockReservoir Pressure (PSIA) 3680 3693 3706

Condensate Yield (BBLS/MMCF) 5.0 6.0 7.0

g

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the Elk-4 and Antelope wells and a gas gradient of 0.071 psi/foot was used to define the

minimum and maximum FWL of -2219 and -2237 metres for the Antelope Block.

The risk simulation uses a fixed FWL for the Elk Block and a triangular distribution for the

Antelope Block with a most likely FWL at -2228 metres and the minimum and maximum case

FWLs at -2219 and -2237 metres, respectively.

Fracture Porosity

Fracture porosity has been estimated using the flow capacity calculated from the DSTs for wells

Elk-1 and Elk-2 and the fracture frequency determined from the Formation Micro Imager (FMI)

log. The flow capacity has been related to the fracture permeability using the following equation:

f= [kf/(1.04 a2)]

1/3

Where;

f= fracture porosity

kf= fracture permeability (Darcies)

a = distance between fractures (cm)

For all of the intervals tested in wells Elk-1 and Elk-2, it is assumed that the entire flow capacity

is related to the fracture porosity. The fracture porosity for the Elk-1 and Elk-2 wells are

calculated to be 0.070 and 0.078 percent with net fractured to gross interval ratios of 59 and 63

t ti l Th ti t f f t it i d t il d i T bl 6

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A discussion regarding aquifer strength was included in the geological section of the report. In the

most likely case, the aquifer strength is expected to be moderate to weak resulting in limited

water influx and a relatively low reservoir abandonment pressure.

The Arun Gas Field located in Indonesia is considered to be a potential analog for the

Elk/Antelope Gas Field. Gas recovery from the Arun Gas Field is expected to reach

approximately 94 percent of the OGIP. This has been used to define the upper limit for the

recovery factor distributions.

The following parameters have been used as inputs for calculating the recovery factors:

Parameter

Low

Estimate

Best

Estimate

High

Estimate

Abandonment Pressure (psia) 2750 800 250

Residual Gas Saturation

Non-Reef Matrix 50% 35% 20%

Non-Reef Fractures 15% 10% 5%

Reef Limestone 30% 20% 10%

Reef Dolomite 30% 20% 10%

Water Swept Volume 80% 50% 20%

Recovery Factors

Non-Reef Matrix 24% 83% 94%

Non Reef Fractures 75% 88% 95%


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Petroleum ConsultantsGLJ

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5fpremig

(ID

3155)

99

199

299

399

499

99

508

E2IO

5

(31

2

401

501

601

701

801

807

300

4

E4IO

L05

fprem

ig(ID

3174) 100

200

300

400

500

100

bh0

1iol07

_fpremig_jun

e6(ID

2065

1100

1200

1100

e08iol0

7_fprem

ig_oct22

(ID23

e09iol0

7_fpre

mig_oc

t23(ID

2328)

1099

1199

1299

1399

1499

1599

1699

1799

99

1099

e11iol07_fpremig_oct22( ID 2320) e11i l 7 _f r m i _ ct22(I 232)

1100

1200

13

0

1

0

15

0

1

0

17

0

1100

1779

e12iol07_fpremig_may22(ID2063)

1100

1200

1300

1 4 0 0

1 5 0 0

1 6 0 0

1 7 0 0

1800

1900

1100

e13iol07_fpremig_july19(ID2064

1100

1200

1300

1400

1500

1600

1700

1800

1100

e14iol07_fpremig_oct4(ID2225)

1100

1200

1300

1400

1500

1600

1100

e 1 6 i o l 0 7 _

fp re

m i g _

no v 1 4 (ID

2 4 9 6

)

2310

2410

2510

2597

1800

1900

2

E1IOL0

5fp

(3155

E2IOL0

5fp

remig

(ID

3162)101

201

301

101

E3IOL0

5fpremig

(ID31

68)100

200

100

E4IO

L05fprem

ig(ID

3174)

600

700

799

Map 3

Papuan Basin

Elk/Antelope Gas Field

Seismic Control

Company: InterOil Coporation

Property: Elk/Antelope

Effective Date: December 31, 2009

Scale: 1:164000

S1100116/drafting/Map3 Seismic dftg.pdf

N N FAULT TRACE

e06iol

07_fpre

mig_no

v14(ID

2502)

2200

2203

e07iol

07_fpre

mig_no

v14(ID

2500)

2200

2300

2355

ei l0

7_fprem

ig_oct22

(ID232

3)

e09iol

07_fpre

mig_oc

t23(ID

2328)

2599

2699

2788

e10iol07_fpremig_nov14(ID2498)

2200

2300

2400

25

00

25

39

11i l 7 _f r m i _ ct22(I 232)

e12iol07_fpremig_may22(ID2063)

23

2400

2500

2515

2IOL0

5fp

remig

(ID

3162)

E3IOL0

5fp

remig

(ID31

68)

400

500

600

617

GHOST WELL

POROUS LIMESTONE OUTLINE

POROUS DOLOMITE OUTLINE

LIMIT REEF BUILD UP

bh0

1iol07

_fpr

emig_

june

6(ID

2065

1300

1400

1500

1600

1700

1800

1900

2000

2051

11iol07_fpremig_oct22(ID 2320)

2000

2100

2200

00

e13iol07_fpremig_july19(ID2064

1900

2000

2100

22

00

2300

2400

2500

2515

e14iol07_fpremig_o

ct4(ID2225)

1700

1800

1900

2000

2100

2200

2300

2400

2500

2515

e17iol07_fpremig_sept20

(ID2115

2000

2100

2200

2300

2400

2469


Page: 36 of 51


51/66

-5600

-5400

-5400

-5200

-5200

-5000

-5000

-4800

-4800

-4600

-4400

-4200

-4000

-3800

-3600

-3400

-3200

-300

0

-3300

-3100

-

3100-3100

-2900

-2900

-2900

-2700

-2700

-2500

-2500

-2300

-2300-2100-1900-1700

-1500

-5800

-5600

-5400

-5400

-5200

-5200

-5000

-5000

-4800

-4800

-460

0

-460

0

-4600

-4600

-4400

-4400

-4400

-4200

-4200

-4200

-4000

-4000

-4000

-3800

-3800

-3800

-3600

-3600

-360

0

-3400

-3400

-340

0

-3200

-3200

-320

0

-3000

-3000

-300

0

-2800

-2

800

-2800

-2600

-260

0

-2600

-2400

-2400

-2200

-2200

-2000

-2000

-1800

-1600

-330

0

-3100

-2900

-2700

-2500

-2300

-2100-1

900

-1700

Elk-4a

Elk-1

Elk-2

Elk-4

Antelope-1

Antelope-2

2 82 00 0 2 84 00 0 2 86 00 0 2 88 00 0 2 90 00 0 2 92 00 0 2 94 00 0 2 96 00 0 2 98 00 0 3 00 00 0 3 02 00 0 3 04 00 0 3 06 00 0 3 08 00 0 3 10 00 0

2 82 00 0 2 84 00 0 2 86 00 0 2 88 00 0 2 90 00 0 2 92 00 0 2 94 00 0 2 96 00 0 2 98 00 0 3 00 00 0 3 02 00 0 3 04 00 0 3 06 00 0 3 08 00 0 3 10 00 0

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000

9220000

9222000

9224000

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000

9220000

9222000

9224000

-1576.4

-2262.8

-2038.9

-1550.3

-1685.1

Elk Block

AntelopeBlock

Mena Block

Mule DeerBlock

Free Water Level

@ -2228 metres

A

A'

Line of schematicCross Section

Papuan BasinElk/Antelope Structure

Depth Structure Map (metres)Top Puri LimestoneGLJ Interpretation

Map 4

Company: InterOil CorporationProperty: Elk / Antelope

Effective Date: December 31, 2009Scale: 1:130,000s1100116/drafting/Map4 DStr GLJ dftg.pdf

Free Water Level@ -2248 metres



52/66

M 6

Page: 38 of 51


53/66

-5800

-5800

-5800

-5600

-5600

-5600

-540

0

-5400

-5400

-5200

-5200

-5200

-5000

-5000

-5000

-4800

-4800

-4800

-4600

-4600

-4

600

-4400

-4400

-440

0

-4400

-4200

-4200

-4200

-4000

-4000

-40

00

-4000

-3800

-3800

-3800

-3800

-3600

-3600

-3600

-3600

-3400

-3400

-3400

-3400

-3200

-3200

-3200

-320

0

-3000

-3000

-3000

-2800

-280

0

-2800

-2800

-2600

-2600

-2600

-2400

-2400

-240

0

-2200

-2200

-2200

-2000

-2000

-1800

-1800

-1

600

Elk-4a

Elk-1

Elk-4

Antelope-1

Antelope-2

Off Reef

DE

-1550.3

-1685.1

292000 294000 296000 298000 300000 302000 304000 306000 308000 310000

292000 294000 296000 298000 300000 302000 304000 306000 308000 310000

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000


Papuan BasinAntelope Block

Depth Structure Map (metres)Top Puri Reef

GLJ Interpretation

Map 6


Effective Date: December 31, 2009Scale: 1:100,000s1100116/drafting/Map6 DStr GLJ reef.pdf


Map 7

Page: 39 of 51


54/66

292000 294000 296000 298000 300000 302000 304000 306000 308000 310000

292000 294000 296000 298000 300000 302000 304000 306000 308000 310000

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000

9196000

9198000

9200000

9202000

9204000

9206000

9208000

9210000

9212000

9214000

9216000

9218000

-4000

-4000

-4000

-3800

-3800

-3800

-3800

-3600

-3600

-3600

-3600

-340

0

-3400

-3400

-3400

-3400

-3200

-3200

-3200

-320

0

-3000

-3000

-3000

-300

0

-2800

-2800

-2800

-2600

-2600

-2

600

-2400

-2400

-2400

-2400

-2200

-2200

-2200

-2000

-2

000

-2000

-1800

-180

0

-1600

Elk-4a

Elk-1

Elk-4

Antelope-1

Antelope-2

Off Reef

DE

-1550.3

-1685.1


Papuan BasinAntelope Block

Depth Structure Map (metres)Top Puri Reef

InterOil Interpretation

Map 7


Effective Date: December 31, 2009Scale: 1:100,000s1100116/drafting/Map7 DStr Intoil reef.pdf



55/66

Elk/AntelopeDataan

-1500

-1000

-500

00 500 1000 1500 2000 2500

PSI

-3500

-3000

-2500

-2000

Depth(m)A

Pressur

OffsetWellDSTdata

3000 3500 4000 4500 5000KuruGasField

Puri1_1A

Bwata1

Triceratops1

Elk-2

Antelope-1DST#1

Antelope-1DST#3(2626mbkb)

Antelope-1DST#6

Elk-1DST#2

Elk-4DST#1

Elk-4DST#2

-

SL

-

Antelope-1SGSGradientPlot

LoadWater

Page:40

of51


Plot

1


56/66

-2500

-2400

-2300

-2200

-2100

-2000

-1900

-1800

-1700

-1600

-1500

Elevationmetres

ELK/ANTELOPE STRUCTURE

Pressure versus Depth

Elk-1 appears to be completed in a

separate reservoir based on both

pressure and gas composition

-3000

-2900

-2800

-2700

-2600

3300 3500 3700 3900 4100 4300 4500 4700

Reservoir Pressure psia

Elk 1 Gas (Elk-1, 0.071 psi/ft) FWL (Elk-1 -2248 m) Elk 2

Elk 4 Elk 4A Antelope 1 Antelope 1ST1

Antelope 1ST2 Antelope 2 Gas (Min, 0.079 psi/ft) Gas (Max, 0.079 psi/ft)

Water Min FWL -2219 m Max FWL -2237Page:41

of51


Plot

2


57/66

-2500

-2400

-2300

-2200

-2100

-2000

-1900

-1800

-1700

-1600

-1500

3500 3600 3700 3800 3900 4000 4100 4200

Elevationmetres

Reservoir Pressure psia

ELK/ANTELOPE STRUCTURE

Pressure versus Depth (Expanded)

Elk 1 Gas (Elk-1, 0.071 psi/ft) FWL (Elk-1 -2248 m) Elk 2

Elk 4 Elk 4A Antelope 1 Antelope 1ST1

Antelope 1ST2 Antelope 2 Gas (Min, 0.079 psi/ft) Gas (Max, 0.079 psi/ft)

Water Min FWL -2219 m Max FWL -2237

Elk-1 appears to be completed in a

separate reservoir based on both

pressure and gas composition

Page:42

of51


Plot

3


58/66

40%

50%

60%

70%

80%

90%

100%

robability>=

XA

xis

Antelope/Elk/MuleDeer

Best Estimate Resources

OGIP = 11.03 TCF

Recoverable Raw Gas = 9.08 TCF

Recoverable Sales Gas = 8.18 TCF

Low Estimate Resources

OGIP = 9.65 TCF



0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2000 4000 6000 8000 10000 12000 14000 16000

Probability>=

XA

xis

Gas(BCF)


OGIP SalesGas

Best Estimate Resources

OGIP = 11.03 TCF




OGIP = 9.65 TCF



High Estimate Resources

OGIP = 12.54 TCF

Recoverable Raw Gas = 11.04 TCFRecoverable Sales Gas = 9.94 TCF

Page:43

of51


Plot

4


59/66

40%

50%

60%

70%

80%

90%

100%

robability>=

XA

xis



Recoverable Condensate

= 117.1 MMBBLS

Best Estimate ResourcesRecoverable Condensate

= 156.5 MMBBLS

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 50 100 150 200 250 300 350

Probability>=

XA

xis

Condensate(MMBBLS)



Recoverable Condensate

= 117.1 MMBBLS

Best Estimate ResourcesRecoverable Condensate

= 156.5 MMBBLS

High Estimate Resources

Recoverable Condensate= 194.7 MMBBLS

Page:44

o

f51


Plot

5

Elk-2SUMMARYOFROUTINEANDSTRESSEDDATA

TABLE1

Page: 45 of 51

Table 1


60/66

D ep th (m ) T VD ( m) R ou ti n e O B E st In -s it u K a i r K a ir EstIn-SituK air GDens

calcfromBFL OB calcfromBFL (kg/m3)

2 32 1. 40 2 31 6. 69 0 .0 42 0 .0 34 0 .0 36 0 .0 04 < 0 .0 01 0 .0 02 2 72 0

2355.80 2350.77 0.021 0.016 0.002 0.001 2700

2416.00 2410.14 0.013 0.009 2690

2416.60 2410.72 0.085 0.076 2730

2 55 7. 60 2 54 9. 32 0 .0 03 0 .0 02 0 .0 02 0 .0 01 < 0 .0 01 0 .0 01 2 68 0

2584.00 2575.30 0.014 0.010 2680

2 60 7. 40 2 59 8. 15 0 .0 12 0 .0 08 0 .0 08 0 .0 10 < 0 .0 01 0 .0 05 2 65 0

2620.40 2610.80 0.023 0.018 0.002 0.001 2690

2622.80 2613.13 0.056 0.049 0.014 0.007 2670

2 62 5. 40 2 61 5. 66 0 .0 05 0 .0 03 0 .0 03 0 .0 01 < 0 .0 01 0 .0 01 2 70 0

2635.50 2625.49 0.008 0.005 2690

2657.48 2646.96 0.003 0.002 0.161 0.089 2700

2659.13 2648.58 0.002 0.001 0.001 0.001 2700

2659.93 2649.37 0.003 0.002 5.500 3.232 2700

2660.05 2649.48 0.007 0.005 2700

2679.00 2668.11 0.062 0.055 2720

2685.00 2674.03 0.010 0.007 2710

2687.20 2676.20 0.062 0.055 2710

2691.40 2680.35 0.065 0.058 2710

2698.80 2687.67 0.080 0.072 2590

2 70 8. 90 2 69 7. 66 0 .0 43 0 .0 36 0 .0 37 0 .0 01 0 .0 01 0 .0 01 2 70 0

2 70 9. 09 2 69 7. 85 0 .0 30 0 .0 24 0 .0 25 0 .0 02 0 .0 01 0 .0 01 2 72 0

2709.48 2698.24 0.004 0.003 0.003 0.002 2700

2 70 9. 89 2 69 8. 64 0 .0 17 0 .0 12 0 .0 13 0 .0 01 < 0 .0 01 0 .0 01 2 69 0

2 71 0. 09 2 69 8. 84 0 .0 48 0 .0 42 0 .0 42 0 .0 05 0 .0 02 0 .0 03 2 71 0

2 71 0. 42 2 69 9. 17 0 .0 48 0 .0 40 0 .0 42 0 .0 01 < 0 .0 01 0 .0 01 2 71 0

2 71 1. 60 2 70 0. 34 0 .0 89 0 .0 79 0 .0 80 0 .0 16 0 .0 07 0 .0 09 2 71 0

2714.40 2703.11 0.121 0.110 2710

2 73 1. 00 2 71 9. 56 0 .1 03 0 .0 94 0 .0 93 0 .0 48 0 .0 29 0 .0 26 2 71 0

2 73 1. 20 2 71 9. 76 0 .0 96 0 .0 85 0 .0 87 0 .0 40 0 .0 32 0 .0 22 2 71 0

2

Documents

Elk Antelope Gas Field 2009 GLJ - FINAL