October 9, 2014 The attached report dated September 30, 2014

Transcription

October 9, 2014
The attached report dated September 30, 2014, entitled "In Place Volume Assessment for Designated
Section of Covunco Norte-Sur and El Corte Blocks – Vaca Muerta Formation" (the "Report"), has been
prepared for Argenta Energia S.A., a wholly owned subsidiary of Azabache Energy Inc. (the "Company"),
as of August 26, 2014 by Gaffney, Cline & Associates ("GCA") in accordance with the Canadian Oil and
Gas Evaluation Handbook (COGEH) and National Instrument 51-101 Standards of Disclosure for Oil and
Gas Activities of the Canadian Securities Administrators ("NI 51-101"). GCA is an independent qualified
reserves evaluator as such terms are defined in NI 51-101.
The Report should be read in conjunction with the following reader advisories and the other public
disclosure documents of the Company on file with the Canadian Securities Administrators, which may be
accessed on the Company's issuer profile through the System for Electronic Data Analysis and Retrieval
(SEDAR) website (www.sedar.com).
Reader Advisories
There is no certainty that any portion of the petroleum initially in place volumes disclosed in the Report
will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any
portion of the volumes.
This Report contains forward-looking statements. Such statements and information relate to future
events or the Company's future business prospects or opportunities. More particularly, the Report
contains statements concerning possible future actions to be taken by the Company that are based on
assumptions of management and GCA.
All statements other than statements of historical fact may be forward-looking statements. Statements
concerning resource estimates may also be deemed to constitute forward-looking statements and reflect
conclusions that are based on certain assumptions with respect to whether the resources can be
economically exploited. Any statements that express or involve discussions with respect to predictions,
expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often,
but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate",
"expect, "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should",
"believe" and similar expressions) are not statements of historical fact and may be "forward-looking
statements". Forward-looking statements involve known and unknown risks, uncertainties and other
factors that may cause actual results or events to differ materially from those anticipated in such
forward-looking statements. The Company believes that the expectations reflected in those forwardlooking statements are reasonable, but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements should not be unduly relied upon. The Company does
not intend, and does not assume any obligation, to update these forward-looking statements, except as
required by applicable laws. These forward-looking statements involve risks and uncertainties relating to,
among other things, changes in oil prices, results of exploration and development activities, uninsured
risks, regulatory changes, defects in title, availability of materials and equipment, timeliness of
government or other regulatory approvals, actual performance of facilities, availability of financing on
reasonable terms, availability of third party service providers, equipment and processes relative to
specifications and expectations and unanticipated environmental impacts on operations. Actual results
may differ materially from those expressed or implied by such forward-looking statements.
IN PLACE VOLUME ASSESSMENT FOR DESIGNATED SECTION OF
COVUNCO NORTE-SUR AND EL CORTE BLOCKS
VACA MUERTA FORMATION
Prepared for
ARGENTA ENERGIA S.A.
SEPTEMBER 30, 2014
CONFIDENTIALITY AND DISCLAIMER STATEMENT
This document is confidential and has been prepared for the exclusive use of the Client or
parties named herein. It may not be distributed or made available, in whole or in part, to any
other company or person without the prior knowledge and written consent of Gaffney, Cline &
Associates (GCA). No person or company other than those for whom it is intended may directly
or indirectly rely upon its contents. GCA is acting in an advisory capacity only and, to the fullest
extent permitted by law, disclaims all liability for actions or losses derived from any actual or
purported reliance on this document (or any other statements or opinions of GCA) by the Client
or by any other person or entity.
www.gaffney-cline.com
Argenta Energía S.A.
Copy No. 1
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DOCUMENT APPROVAL & DISTRIBUTION
Copies:
Electronic (1 PDF copy)
Project No:
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Prepared for: Argenta Energía S.A.
This report was approved by the following Gaffney, Cline & Associates personnel:
Project Manager
Daniel Amitrano
Signature
Date
August 26, 2014
Principal Advisor, Reservoir Engineer
Reviewed by
Joshua Oletu
Principal Advisor, Petrophysicist
August 26, 2014
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TABLE OF CONTENTS
INTRODUCTION ........................................................................................................................ 1
BASIS OF OPINION ................................................................................................................... 3
CONCLUSIONS.......................................................................................................................... 5
RECOMMENDATIONS ............................................................................................................... 7
DISCUSSION.............................................................................................................................. 9
1.
GEOLOGY .......................................................................................................................... 9
1.1
1.2
1.3
Lower Zone.............................................................................................................. 11
Transition Zone........................................................................................................ 11
Upper Zone.............................................................................................................. 11
2.
GEOPHYSICS .................................................................................................................. 12
3.
HYDROCARBON WINDOW ............................................................................................. 19
4.
PETROPHYSICS .............................................................................................................. 20
4.1
4.2
4.3
4.4
4.5
4.6
5.
FLUID PROPERTIES ....................................................................................................... 27
5.1
5.2
6.
Evaluation Approach................................................................................................ 20
Total Organic Content.............................................................................................. 21
Clay Volume (Vcl) .................................................................................................... 21
Porosity ................................................................................................................... 23
Water Saturation ...................................................................................................... 24
Summary and Petrophysical Results ....................................................................... 25
Initial Static Reservoir Pressure ............................................................................... 27
Initial Oil Formation Volume Factor (Boi) ................................................................. 27
COMPLETION AND PRODUCTION ................................................................................. 28
6.1
Completion Analysis ................................................................................................ 28
6.1.1 Stage 1 (Clusters: 1,974 - 1,975, 1,990 - 1,991 m) .......................................... 29
6.1.2 Stage 2 (Clusters: 1,914.5/15; 1,933.5/34; and 1,945/46.5 m) ......................... 31
6.1.3 Stage 3 (Clusters: 1,642/42.3; 1,654/54.5; and 1,672/72.7 m) ......................... 33
6.2
7.
Production History ................................................................................................... 36
VOLUMETRIC ESTIMATES ............................................................................................. 38
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Tables
Table 0.1 Summary of Original Oil In Place Estimate ................................................................. 5
Table 0.2 Summary of Solution Original Gas In Place Estimate ................................................. 6
Table 4.1 Inventory of Available Petrophysical Data.................................................................20
Table 4.2 Summary of the Petrophysical Results .....................................................................26
Table 6.1 Summary of the Microseismic and Fracture Parameter Results by Vendor Company
.................................................................................................................................................28
Table 7.1 Oil In Place Input Parameters ...................................................................................38
Table 7.2 Summary of Original Oil In Place Estimate ...............................................................39
Table 7.3 Summary of Solution Original Gas In Place Estimate ...............................................39
Figures
Figure 0.1 Vaca Muerta Study Area as Defined by AESA .......................................................... 1
Figure 1.1 Stratigraphic column ................................................................................................ 9
Figure 1.2 Correlation ..............................................................................................................10
Figure 2.1 S-N 2D Line (20076) Indicating a Rapid Depth Change at the VM Level .................12
Figure 2.2 W-E Spliced 2D Lines Illustrates the Increasing Faulting and Structural Complexity
Off of the Evaluation Area .........................................................................................................13
Figure 2.3 Subvolume of Smoothed Dip of Maximum Similarity Indicating Fault Sets and
Orientation ................................................................................................................................14
Figure 2.4 Depth Map with Fault Pattern Emphasized ..............................................................15
Figure 2.5 Vaca Muerta Upper Rock Volume Cubic Meters .....................................................16
Figure 2.6 Vaca Muerta Transition Volume Cubic Meters ........................................................17
Figure 2.7 Vaca Muerta Lower Section Volume Cubic Meters ..................................................18
Figure 3.1 Hydrocarbon Window According to Production Data Indicating Contract Area in
Volatile Oil Window ...................................................................................................................19
Figure 4.1 TOC versus Core Bulk Density................................................................................21
Figure 4.2 TOC and Vclay EVALUATION in Vaca Muerta (Cvo.x-2) ........................................22
Figure 4.3 Porosity and Sw EVALUATION in Vaca Muerta (Cvo.x-2).......................................23
Figure 4.4 Cut Off definition .....................................................................................................25
Figure 6.1 CVo.x-2 Well -Stage 1 Visual Inspection - Microseismic Events ..............................29
Figure 6.2 CVo.x-2 Well -Stage 1 Treatment Data and Microseismic Event Rate.....................30
Figure 6.3 CVo.x-2 Well -Stage 2 – Visual Inspection - Microseismic events ...........................31
Figure 6.5 CVo.x-2 Well -Stage 3 Visual Inspection - Microseismic events ..............................34
Figure 6.7 Production History OF CVo.x2 Total Fluid, WellHead Flowing Pressure, Oil Rate and
Gas Rate...................................................................................................................................36
Figure 6.8 Production History OF CVo.x2 Gas Oil Ratio ..........................................................37
Appendices
Appendix I:
References
Appendix II: Glossary
Appendix III: Section 5 of volume 1 of the Canadian Oil and Gas Evaluation Handbook
(COGEH)
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INTRODUCTION
Argenta Energía S.A. (AESA) contracted Gaffney, Cline & Associates (GCA) to conduct an
evaluation of hydrocarbon in-place volumes in the Vaca Muerta formation in a designated study
area. This study area covers some 278 km2 within the Covunco and El Corte blocks in the
Neuquén basin in Argentina, operated by AESA, as shown in Figure 0.1.
FIGURE 0.1
VACA MUERTA STUDY AREA AS DEFINED BY AESA
Source: Argenta
GCA was also requested to review the preliminary performance of the Cvo.x-2 well, and
recommend future key activities and new data acquisition. This report presents the results, and
supporting work, from GCA’s assessment of the in-place volumes and review of the Cvo.x-2
well performance.
AESA drilled the Cvo.x-2 well in 2012 and placed it into production in January 2014. The initial
oil rate of the well was about 25 bpd of oil and 320 bpd of water. After approximately two
months, the well was producing 6 bpd of oil with 18 bpd of water. In March 14, 2014, the well
was shut in as production from the well was very low and natural flowing production could not
be sustained.
For the evaluation, AESA provided GCA with the following information after a kick-off and data
collection meeting on June 25, 2014:
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Previous study reports undertaken by Canadian Discovery Ltd
SMT seismic database
Well information, including well logs, core data and production data for Cvo.x-2
Well logs for 6 wells
The list of reports provided to GCA for this study is in Appendix I. GCA requested additional
information, which was supplied during the course of the evaluation. Consequently, all opinions
expressed herein are based on information received by GCA from AESA through July 7, 2014.
It is recognized that additional data not available for the evaluation may change the opinions
stated in this report.
This report relates specifically and solely to the subject matter as defined in the scope of work
and is conditional upon the assumptions described herein. The report must be considered in its
entirety and must only be used for the purpose for which it was intended.
A glossary of abbreviations used in this report is provided in Appendix II
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BASIS OF OPINION
This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation for such work and, as applicable, the data and information provided
by AESA, the limited scope of engagement, and the time permitted to conduct the evaluation.
In line with those accepted standards, this document does not in any way constitute or make a
guarantee or prediction of results, and no warranty is implied or expressed that actual outcome
will conform to the outcomes presented herein. GCA has not independently verified any
information provided by AESA, and has accepted the accuracy and completeness of these data.
GCA has no reason to believe that any material facts have been withheld from it, but does not
warrant that its inquiries have revealed all of the matters that a more extensive examination
might otherwise disclose.
The opinions expressed herein are subject to and fully qualified by the generally accepted
uncertainties associated with the interpretation of geoscience and engineering data and do not
reflect the totality of circumstances, scenarios and information that could potentially affect
decisions made by the report’s recipients and/or actual results. The opinions and statements
contained in this report are made in good faith and in the belief that such opinions and
statements are representative of prevailing physical and economic circumstances.
This assessment has been conducted within the context of GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However,
GCA is not in a position to attest to property title or rights, conditions of these rights including
environmental and abandonment obligations, and any necessary licenses and consents
including planning permission, financial interest relationships or encumbrances thereon for any
part of the appraised properties.
In carrying out this study, GCA is not aware that any conflict of interest has existed. As an
independent consultancy, GCA is providing impartial technical, commercial and strategic advice
within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report. In the preparation of this document, GCA has maintained, and continues to
maintain, a strict independent consultant-client relationship with AESA. Furthermore, the
management and employees of GCA have no interest in any of the assets evaluated or related
with the analysis carried out as part of this report.
Staff members who prepared this report are professionally qualified with appropriate educational
qualifications and the levels of experience and expertise required performing the scope of work.
GCA has not undertaken a site visit and inspection because it was not required within the scope
of work. As such, GCA is not in a position to comment on the operations or facilities in place,
their appropriateness and condition and whether they are in compliance with the regulations
pertaining to such operations. Further, GCA is not in a position to comment on any aspect of
health, safety or environment of such operation.
In the preparation of this report GCA has used, where applicable and appropriate, the Canadian
Oil and Gas Evaluation Handbook (COGEH) and National Instrument (NI) 51-101 Standards of
Disclosure for Oil and Gas Activities (see Appendix [III]).
There are numerous uncertainties inherent in estimating volumes. Oil and gas volume
assessment must be recognized as a subjective process of estimating subsurface
accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and
gas volumes prepared by other parties may differ, perhaps materially, from those contained
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within this report. The accuracy of any estimate is a function of the quality of the available data
and of engineering and geological interpretation. Results of drilling, testing and production that
post-date the preparation of the estimates may justify revisions, some or all of which may be
material.
Oil and gas volumes appearing in this report have been quoted at stock tank conditions. Oil
volumes are reported in millions of stock tank barrels (MMBbl). Natural gas volumes have been
quoted in billions (109) of standard cubic feet (Bscf). Standard conditions are defined as 14.696
psia and 60° Fahrenheit.
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CONCLUSIONS
1. The Vaca Muerta formation is a late Jurassic to early Cretaceous shale (unconventional
resource play), which is pervasive across the Neuquén basin, and is the primary source rock
in the basin.
2. The Vaca Muerta formation in the study area (within Covunco Norte-Sur and the El Corte
Blocks) is located predominantly in the volatile oil window based on available, but limited,
geochemical and production data.
3. GCA defined three zones, Lower, Transition and Upper zones, in the Vaca Muerta formation
based on vertical variability in lithology and total organic carbon (TOC). The study area of
some 278 km2 as defined by AESA is the same for all the three zones.
4. Well test information within the study area indicates that the Vaca Muerta, especially the
Transition zone, is capable of producing hydrocarbons, but commerciality has not been
established. There is no confirmed producible oil in the Upper zone to date, within the study
area.
5. Three stages, one each in the Upper, Transition and Lower zones, were perforated and
hydraulically fractured (stimulated) in the Cvo.x-2 well, the results of which were below
expectations. GCA considers the stages in the Cvo.x-2 well to be under-stimulated.
6. Initial static reservoir pressure has not yet been measured in Cvo.x-2. Based on the
information provided (logs and well head pressure data), GCA considers AESA’s initial static
reservoir pressure estimate of about 4,200 psi (0.69psi/ft) to be reasonable.
7. GCA considers the study area to be an exploration area, and has conducted an estimate of
Petroleum Initially in Place (PIIP) including Original-Oil-In-Place (OOIP) and Solution
Original-Gas-In-Place (OGIP) based on the limited seismic and geological interpretation and
well data. GCA notes that adequate well data for unconventional resource evaluation was
available in one well (Cvo.x-2).
8. Based on the available seismic, geological and well data provided, GCA’s estimates of
OOIP and OGIP within the study area are summarized in Table 0.1 and Table 0.2. (These
tables are also provided in Section 7 as Table 7.2 and Table 7.3.)
TABLE 0.1
SUMMARY OF ORIGINAL OIL IN PLACE ESTIMATE
Zone
Upper
Transition
Lower
P90
1,700
560
1,200
OOIP
(MMBbl)
P50
P10
2,500 3,600
800
1,200
1,500 1,900
5
Mean
2,600
850
1,600
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TABLE 0.2
SUMMARY OF SOLUTION ORIGINAL GAS IN PLACE ESTIMATE
Zone
Upper
Transition
Lower
P90
3,700
1,200
2,600
Associated Gas
(Bscf)
P50
P10
5,600 7,900
1,800 2,600
3,400 4,200
Mean
5,700
1,900
3,400
9. Although the transition zone in the immediate vicinity of the Cvo.x-2 well might be
considered as discovered, such a designation would likely be premature and could be
misleading given that the potential for eventual commercialization is extremely tenuous
based on the data currently available and analyzed. Therefore it is appropriate to consider
the in place volume estimate as undiscovered PIIP.
10. The above zones have different associated risks.
The Upper zone has the risk of hydrocarbon discovery in the absence of proven oil
discovery.
While the Transition zone has been successfully tested with hydraulic stimulation, the
potential for eventual commerciality is yet to be demonstrated.
While there is evidence of hydrocarbon in the Lower zone, significant quantities and
producibility, even with hydraulic stimulation, are yet to be demonstrated.
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RECOMMENDATIONS
On the basis of the technical information made available for this study, GCA recommends the
following to AESA.
1.
Geophysical
Acquire 3D seismic across the study area, since only 2D seismic data exists in most of
the study area. Ensure future seismic acquisition extends at least 2 km past the area to
be imaged to maintain stack and also have high frequency content.
Ensure there is an overlap between proposed 3D seismic in the study area and existing
3D seismic survey outside the study area. Attention should be given to maintaining high
frequency content.
2. Well Data Collection
Acquire relevant well logs and core data to evaluate unconventional resource formation
in all future wells. Well logs should include special logs, such as dipole acoustic,
mineralogy and nuclear magnetic resonance logs.
3. Fluid Property
Take a PVT sample and undertake PVT analysis in the Cvo.x-2 well and future wells.
4. Well Cvo.x-2
Obtain more information from this well to optimize future well design, including:
Install artificial lift and permanent downhole pressure monitoring to estimate input
variables that are necessary to make any production forecast, including the rock volume
connected with the borehole.
GCA considers plunger lift to be a good option for AESA to analyze.
Conduct a detailed post-fracture simulation analysis of the frac jobs performed in this
well, which could then be the basis for improving future hydraulic fracture treatments
either in this well or future wells to be drilled.
Measure a static gradient before resuming production to obtain a new estimate of the
original static reservoir pressure.
5. Future Wells
Horizontal well should be tested in AESA’s area.
-
Horizontal wells drilled and completed by other operators have had a greater initial
oil rate than the vertical wells. These wells are in the same hydrocarbon window as
the Cvo.x-2, but more than 25 miles away from AESA’s area. GCA does not have
any background of those wells (such as natural flowing, size of the choke, landing
point, amount of stages, etc.) to make any assessment or comparison.
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-
Consider placing the landing point for new horizontal wells in the Transition zone
close to the kitchen, the lower Vaca Muerta (LVM), to communicate the Transition
and Lower zones through massive hydraulic fracture jobs.
Vertical well
-
Consider more hydraulic stages to increase the hydrocarbon rock volume to be
contacted and drained through the well. Therefore, a vertical well with more than
three stages should be tested. In addition, consider the following for the future
vertical well:
–
Increase the volume of the fracture treatment in each stage.
–
Minimize the hydraulic communication with underlying Tordillo and overlying
Quintuco formations.
–
Implement artificial lift to produce the well.
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DISCUSSION
1.
GEOLOGY
The Vaca Muerta formation is a late Jurassic to early Cretaceous shale, which is pervasive
across the Neuquén basin, occupying approximately 60,000 km2 and is the primary source rock
in the basin, as shown in Figure 1.1.
FIGURE 1.1
STRATIGRAPHIC COLUMN
The Vaca Muerta formation lies between the carbonate Quintuco formation at the top and the
continental siliclastic Tordillo formation at the bottom. According to the 2011 EIA report, the
Vaca Muerta formation comprises finely-stratified black and dark grey bituminous shale and
lithographic lime-mudstone and marls, with a gross thickness range from 61 to 518 m in the
basin and an average gross thickness of 396 m in the study area.
Internally, Vaca Muerta often exhibits clinothem geometries either in agradational or
progradational packages. In general, the sediment mineralogy consists of equal parts of
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carbonate, silica and clay. Diagenesis in the form of calcite replacement of silica impacts the
reservoir quality and brittleness. Overall, Vaca Muerta TOC varies from 1-8%, with a porosity
range of 3-10% and low permeability.
This is located in the WSW section of the Neuquén basin, where the Vaca Muerta is thinner in
comparison with the center of the basin and shallower to the west of the basin.
The local area comprises what is denominated “Dorsal de Huincul.” The study area is limited to
the west by the “Dorso de los Chihuidos” and to the south by the “Dorsal de Huincul.” This
structure has a notable W-E orientation, and a "spectacular example of structural inversion"
(Vergani et al, 2005, AAPG Memoir 62).
The Dorsal de Huincul is the result of several super-imposed events beginning with extensional
component (Triassic), changing to compressional deformation from the Late Mesozoic to the
present. As a consequence of this complex tectonic history, today there are numerous
unconformities affecting primarily the Jurassic and Cretaceous stratigraphic units (Pángaro et al,
2005).
Based on available core data from the Cvo.x-2 well, the Vaca Muerta formation in the study
area is highly argillaceous, with total clay content of 19-63% (Terratek Petrologic Evaluation). In
addition, the Terratek report also noted that the clays are immature based on the amount of
smectite clay (expandable) interlayers.
GCA reviewed the top and base horizons of the Vaca Muerta shale, provided by Argenta, and
found the top picks to be reasonable so they were adopted for this study. On the basis of the
vertical variability of the lithology and TOC characteristics of the Vaca Muerta in the study area,
supported by well logs analysis, GCA defined three zones: Lower, Transition and Upper, as
shown in Figure 1.2.
FIGURE 1.2
CORRELATION
A’
A
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1.1
Lower Zone
This zone consists of grey bituminous marls laminated with slightly to moderately calcareous
units. It is clearly the most organically rich unit of the Vaca Muerta based on well log response
and geochemical data.
The top and base depths of this zone were provided by AESA, which GCA reviewed and
confirmed to be reasonable. TOC content in this unit ranges from 1-8%, with an average of
~4% in the study area. The gross thickness of this zone ranges from 35 to 50 m in the study
area.
1.2
Transition Zone
The top of this zone is not a distinct geological feature, but reflects the start of an increase in the
organic content, based on log response. The base of this zone is the top of the more distinct
source rock unit designated ‘the Lower zone’ in this study. This zone consists of stratified carbonate, mudstone and marl units. There is evidence of higher
TOC in this zone compared to the Upper zone from cutting analysis in the Cvo.x-2 well.
Furthermore, oil appears to be more continuous, and gas readings are higher across this zone
compared to the Upper zone in Cvo.x-2, which was successfully stimulated and production
tested. The gross thickness in this zone ranges from 45 to 70 m in the study area.
1.3
Upper Zone
This zone is the interval between the top of Vaca Muerta and the top of the Transition zone, and
comprises predominantly lime and mudstone facies (mudstones and wackestones facies, based
on LCV laboratory core description). This zone is organically “lean” compared to the Transition
and Lower zones, with TOC content generally in the order of 2% or less by weight from
available geochemical data.
This zone is about 200 to 360 m in thickness in the study area, and the thickness increase to
the NW. Well logs in most of the wells, except in Cvo.x-2, were generally of very poor quality
because of the hole rugosity. In some wells, well logs are not available across this entire zone.
There are scattered oil shows from mud logs in the Cvo.x-2 well, but no significant gas readings
above the background gas. There was limited flow from this zone unit completed in the Cvo.x-2
well. In summary, there is no confirmed producible oil in this zone to date, within the study area.
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2.
GEOPHYSICS
AESA provided GCA with an SMT project that contained 2D and 3D data sets, as well as the log
LAS files. The evaluation area was covered only with 2D data indicated by the yellow polygon
in all of the maps. AESA provided a base of the Vaca Muerta horizon in depth and time, with a
merged 2D-3D interpretation. The quality of that horizon pick was generally good since it was
mostly a strong clear reflector when the data was good. The data quality of the 2D data set
varied widely, making the 2D line ties difficult. GCA attempted an upper Vaca Muerta horizon
interpretation but the quality of the seismic imaging of that surface was generally poor and not
as reliable as the lower surface (base of the Vaca Muerta).
GCA focused principally on the study area; but to understand the geology of the area, had to
review seismic information of the surrounding area. Generally, the Vaca Muerta plunges deeply
into the basin at a rapid rate to the north, which is shown in the S-N line in Figure 2.1.
FIGURE 2.1
S-N 2D LINE (20076) INDICATING A RAPID DEPTH CHANGE AT THE VM LEVEL
While the area east of the block did not plunge as steeply, the faulting becomes more frequent
and intense than the section within the study area, as shown in Figure 2.2. Over the evaluation
area, changes in depth are more gradual and the intensity of any faulting is less.
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FIGURE 2.2
W-E SPLICED 2D LINES ILLUSTRATES THE INCREASING FAULTING AND
STRUCTURAL COMPLEXITY OFF OF THE EVALUATION AREA
Several attribute volumes were generated on the 3D volume to gain an understanding about the
internal aspects of the Vaca Muerta. Although the 3D data did not cover the study area, it does
give an idea of the structural development of the area, which can be projected into the 2D
areas.
The only attribute that yielded useful information was the smoothed dip of maximum similarity.
That volume indicated a conjugate fault set that is repeated at regular intervals. The vertical
offsets were minor. The importance of those faults is that they may be areas of enhanced
fracturing. Figure 2.3 shows the areal extent of the 3D coverage outlined in purple, and the
study area in yellow in which the gross rock volume was calculated.
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FIGURE 2.3
SUBVOLUME OF SMOOTHED DIP OF MAXIMUM SIMILARITY
INDICATING FAULT SETS AND ORIENTATION
The image on the left is without any annotation so that the orientation of the fracturing can be
seen on the raw volume with no interpretation. The image on the right has the seismic
interpretation of the faulting, provided by AESA, and the red lines have been added to
emphasize the orientations of these breaks.
There appears to be a second set of NE-SW oriented deformation that is related to compressive
folding, and a fault set parallel to those folds. GCA did not look extensively at the folding since it
was out of the study area and not included in the scope of work. Figure 2.4 is a depth map,
provided by AESA, with the same fault pattern emphasized.
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FIGURE 2.4
DEPTH MAP WITH FAULT PATTERN EMPHASIZED
The tops and base picks of the Upper, Transition and Lower zones of the Vaca Muerta were
gridded and contoured. The contours were edited, since there was so little control, and then
were re-gridded to produce the isopach maps from which the gross rock volumes were
generated, as shown in Figure 2.5, Figure 2.6 and Figure 2.7.
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FIGURE 2.5
VACA MUERTA UPPER ROCK VOLUME CUBIC METERS
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FIGURE 2.6
VACA MUERTA TRANSITION VOLUME CUBIC METERS
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FIGURE 2.7
VACA MUERTA LOWER SECTION VOLUME CUBIC METERS
The rock volumes were then integrated with the petrophysical properties to develop OOIP
estimates. The gross rock volumes were only generated within the yellow polygons even
though the data extended beyond the limits of the study area.
18
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3.
HYDROCARBON WINDOW
Production history from all the Operators, obtained from public domain, was loaded monthly into
the Sahara software by Gica Consulting Group.
GCA checked the initial gas oil ratio and production history from the nearest existing wells from
the Cvo.x-2 well, shown in Figure 3.1, and agreed with Gica Consulting that the wells located in
the yellow area correspond to the volatile oil window. (In the aforementioned figure, the green
color corresponds to the black oil window and the red color to the gas window.)
FIGURE 3.1
HYDROCARBON WINDOW ACCORDING TO PRODUCTION DATA
INDICATING CONTRACT AREA IN VOLATILE OIL WINDOW
Contract
Area
Source: Gica Consulting Group
19
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4.
PETROPHYSICS
GCA reviewed some limited wells and also the kerogen quality of the available geochem data in
the study area. The results of this review indicate that the study area is in the volatile oil
window.
AESA provided the wireline and processed logs in LAS format, while well composite logs and
core data were provided in scanned image files and Excel files from key wells in the area of
interest (Cvo.x-1, OA.x-2, SD.x-1, Cvo.x-2, OA.x-1 and Caz.x-1), as shown in Table 4.1.
TABLE 4.1
INVENTORY OF AVAILABLE PETROPHYSICAL DATA
Well
Cvo.x-1
OA.x-2
SD.x-1
Cvo.x-2
OA.x-1
CAz.x-1
Year Drilled
Elevation
KB (m)
1997
1981
1961
2012
1969
1997
779
794
828
776
924
846
Total
Depth
MD (m)
2500
2625
2400
2191
2719
2350
Mudlogs
√
SP
GR
NMR
Caliper
Resistivity
RHOB
Neutron
PEF
Sonic
√ √ √ √ √ √ √ √ no
√ no
√ no
no
no
√ no
no
√ √ √ √ √ √ √ √ √ √ √ √ √ √ no
√ no
√ √ no
no
√ no
√ √ no
no
√ no
√ √ √ √ √ √ √ Core
Borehole
Analysis
Image
data
no
no
no
√ no
no
no
no
no
√
no
no
√ Data available in digital LAS format
√ Log available as scanned image
√ Mudlogs in most of the wells are geological descriptions, with no mention of the hydrocarbon content (except in the
Cvo.x-2 well)
There is limited core data available for this study, 35 m of core across 375 m gross section of
Vaca Muerta in one well (Cvo.x-2). Key core analysis data for unconventional resource
petrophysical evaluation, such as TOC, XRD, effective, total porosity and water saturation, is
available for this well. Additional, but also limited, TOC data from sidewall cores and cutting
were also made available.
Most of the wells have basic logs. Magnetic resonance, borehole image, Spectral Gamma Ray
and ECS logs were also provided for the Cvo.x-2 well, as shown in Table 4.1. Furthermore, in
most of the wells (except Cvo.x-2), the quality of the neutron and density log was strongly
affected by rugosity and washouts, especially across the Upper zone.
GCA generated and compared log depth trends of raw logs from the key wells to assess well
logs that are off trend and require normalization. Log editing was undertaken essentially to
ensure that the best density data available would be used in the evaluation, correcting for
artifacts caused by borehole rugosity and washouts.
4.1
Evaluation Approach
The data necessary to properly evaluate an unconventional resource play was available only in
one well (Cvo.x-2). GCA focused the analysis on this well to calibrate the petrophysical
parameters, and then extrapolate those parameters to the other wells.
GCA integrated the available wireline log and core analysis data to estimate clay volumes,
reservoir porosities, water saturations and TOC content. Emphasis was placed on the
processed data in the Cvo.x-2 well, which has the more complete and adequate suite of logs
and core data.
20
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4.2
Total Organic Content
This analysis was based on TOC versus bulk density correlation established for core data in
Cvo.x-2, as shown in Figure 4.1.
FIGURE 4.1
TOC VERSUS CORE BULK DENSITY
9.00
8.00
7.00
6.00
TOC
5.00
4.00
3.00
2.00
1.00
0.00
2.35
2.40
2.45
2.50
2.55
2.60
2.65
2.70
Bulk Density
TOC vs Bulk density
Linear (TOC vs Bulk density)
The TOC curves were validated with the TOC data points available in each well (from cuttings,
sidewall cores and core data), as shown in Figure 4.2, and the TOC content in Vaca Muerta
seems to gradually decrease upwards.
The TOC content in the Lower zone ranges from 1-8% (average 4.5% based on core data and
4% based on the TOC curve, Table 4.2).
The Transition zone is characterized by a lower TOC content, with an average of 2.2% based
on cutting data (there is no core in this section) and 2.4% based on the TOC curve (Table 4.2).
Finally, in the Upper zone, the TOC content is below 2%, with an average of 1.3% based on the
TOC curve and 1.13% based on core data (Table 4.2).
4.3
Clay Volume (Vcl)
There is a high uncertainty in using the total and uranium-corrected GR for the Vcl estimation.
Therefore, the Vcl was estimated from thorium in the Cvo.x-2 well and compared to the XRD
clay data, as shown in Figure 4.2.
Vcl was also compared to ECS, but ECS only reported illite composition, excluding other clay
minerals. Hence, the ECS mineral volumes provided by Schlumberger were not taken into
account.
21
AB-14-2003.01
There was no thorium curve in the other wells. However, GCA used the end points from the GR
from Cvo.x-2 for calculating Vcl in the surrounding wells, recognizing the uncertainty inherent in
using GR for Vcl estimation.
FIGURE 4.2
TOC AND VCLAY EVALUATION IN VACA MUERTA (CVO.X-2)
GR
Nphi-Rhoz
Potasium
Uranium
Thorium
Vcl (TH)
Vcl (GR)
ECS (*)
TOC
Upper
Zone
Depth
ECS Illite
Volume
Transition
Zone
XRD
Lower
Zone
Core
data
(*) ECS volumes provided by SLB
22
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4.4
Porosity
Total and effective porosities were estimated from logs and compared to core data in Cvo.x-2.
They were also compared to the NMR total and effective porosity in the same well (Figure 4.3).
FIGURE 4.3
POROSITY AND SW EVALUATION IN VACA MUERTA (CVO.X-2)
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AB-14-2003.01
In the other wells (OA.x-2, Caz.x-1, Cvo.x-1), total and effective porosity were also estimated.
However, because of the uncertainty with Vcl estimation in the absence of relevant spectral GR
data, total porosity was considered more reliable for the current level of analysis. Total porosity,
in contrast to effective porosity (Figure 4.3), includes, in addition to free fluid pore space, pore
space occupied by both capillary- and clay-bound water.
To assess the grain density, GCA used average dry density per zone from the core analysis
report, as appropriate, for the total and effective porosity systems. GCA also reviewed the
porosity estimated using the as-received grain density. However, GCA observed that porosity
estimated using as-received grain density excludes intra-kerogen porosity, which is not an
accurate representation of an unconventional play.
GCA applied the fluid density required to match the core data.
4.5
Water Saturation
Water saturation was estimated for the total porosity and effective porosity systems by using the
Archie and Indonesia approaches, as appropriate. GCA compared porosities to core data for
Cvo.x-2, and used the total porosity system for the other wells (Figure 4.3) because of the
uncertainty with Vcl assessment, as previously noted.
For the analysis, GCA assumed an Rw of 0.03 ohm.m, based on fluid samples (salinity of
70,000 - 103,000 mg/l), and regional experience. Porosity exponent ‘m’ and saturation
exponent ‘n’ were selected to match the core measured Sw.
3.6 Cut off definition
Cut off criteria was defined from available core porosity and water saturation data. Based on
experience, intervals with hydrocarbon porosity (Phi*Sh) of less than 0.015 are unlikely to
contribute to flow. Hence, a porosity cut off that corresponds to a Phi*Sh of 0.015 was
determined from available core data (Figure 4.4) and applied in this study.
24
AB-14-2003.01
FIGURE 4.4
CUT OFF DEFINITION
0.06
Phie*Sh (form Core)
0.05
0.04
Upper Section
0.03
Lower Section
0.015 Cut off
0.02
0.01
0.00
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
Core Porosity (%)
The total porosity cut off range is between 3-4%. In the net pay determination for the Upper
zone of the Vaca Muerta, 4% was used, while a porosity cut off of 3% was used for the
Transition and Lower zones. An effective porosity cut off of 3% was applied in the Upper zone
and 2% was used in the Transition and Lower zones.
This review applied a Sw cut off of 50%, and a Vsh cut off of 50% in deriving the net pay
intervals.
4.6
Summary and Petrophysical Results
Table 4.2 summarizes the petrophysical results per zone and per well in the Vaca Muerta. The
summary excludes wells or intervals with bad quality well logs.
25
AB-14-2003.01
TABLE 4.2
SUMMARY OF THE PETROPHYSICAL RESULTS
Flag
Name
PAY
PAY
PAY
Top
Bottom
Gross
Net
1491
1924
1964
1534
1967
2008
43
43
44
28
31
25
28
Net to
Gross
0.65
0.72
0.58
0.65
PAY
PAY
PAY
1429
1866
1904
1491
1924
1964
62
58
59
24
19
21
21
CVO_X-2 VM Upper
PAY
All depths in meters measured depth
1634
1904
271
67
Well
Zone
CAZ_X-1 VM Lower
CVO_x-1 VM Lower
CVO_X-2 VM Lower
Avg. Lower
CAZ_X-1 VM Transition
CVO_x-1 VM Transition
CVO_X-2 VM Transition
Avg. Transition
Avg. Vcl
Avg. Phi
Avg. Sw Avg. TOC
0.30
0.33
0.39
0.07
0.07
0.08
0.07
0.28
0.30
0.29
0.29
3.9
3.7
4.1
0.38
0.33
0.35
0.35
0.26
0.35
0.41
0.06
0.06
0.06
0.06
0.28
0.35
0.36
0.32
2.4
2.4
2.4
0.25
0.35
0.06
0.38
1.3
The following comments highlight the observed characteristics of the different zones from the
petrophysical evaluation:
Upper Zone
-
Organically “lean,” with scattered shows from mud logs in Cvo.x-2, but no significant gas
readings above the background gas.
-
Contains carbonate as mudstone, wackestone and marl facies (based on the core
description).
-
TOC content is poor (lower than 2% based on geochemical data and the TOC curve), as
shown in Table 4.2.
-
Well logs in most of the wells except in Cvo.x-2 are generally of very poor quality
because of hole rugosity. In some wells, well logs are not available across the entire
Upper zone.
Transition Zone
-
Comprised of stratified carbonate, mudstone and marl units.
-
TOC content is above 2%, as shown in Table 4.2.
-
Successfully stimulated and production tested in Cvo.x-2.
-
Gross thickness ranges from 50 to more than 60 m in the study area.
Lower Zone
-
Main source rock section with high TOC content based on well log response and
geochemical data.
-
TOC content in this unit ranges from 1-8%, with an average of ~4% in the study area.
-
Gross thickness ranges from 40 to 45 m in the study area.
26
AB-14-2003.01
5.
FLUID PROPERTIES
5.1
Initial Static Reservoir Pressure
Initial static pressure in the Vaca Muerta formation was not measured in any well in AESA’s area, including the Cvo.x-2 well. GCA validated and considers AESA’s estimated minimum
initial reservoir pressure of about 4,200 psi (0.69 psi/ft) to be reasonable.
The minimum initial reservoir pressure was determined from the following:
The dynamic gradient taken in Cvo.x-2, the producing well, on March 13, 2014, before being
shut in. The average density of the produced fluid through the tubing on March 13, 2014
(dynamic gradient measurements) was around 0.966 g/cm3.
The well head static pressure was measured on May 14, 2014 after two months of being
closed (from March 14 to May 14). The well head showed a pressure of 1,593 psi on May
14, 2014.
-
No static gradient was taken by the Operator.
Using the above information, the minimum static pressure was estimated to be 4,199 psi at
1,914 m MD (1,878.5 m TVD), that accounted for 86% of the total production from production
logging (PLT) data.
5.2
Initial Oil Formation Volume Factor (Boi)
There is no PVT data at the time of this report. Therefore, the Boi range was estimated based
on the available production data and GCA’s regional experience.
GCA considered a Bo of 1.6 rb/stb as a mid-case. Low and high estimates were considered
with a variation of ±10% of the aforementioned mid-case value.
Low Boi = 1.44 rb/stb
Mid Boi = 1.6 rb/stb
High Boi = 1.76 rb/stb
In addition, GCA conducted some calculations using Standing and Vasquez and Beggs
correlations that confirm the reasonability of the range adopted by GCA, as indicated above.
GCA recommends AESA to acquire a downhole sample in Cvo.x-2 for PVT analysis, and refine
the estimate of the initial oil formation volume factor.
27
AB-14-2003.01
6.
COMPLETION AND PRODUCTION
6.1
Completion Analysis
The Cvo.x-2 well was drilled and completed some 350 m from the Cvo.x-1 well. The latter well
was used as a monitor well for microseismic acquisition while fracturing the Vaca Muerta
formation in the Cvo.x-2 well.
Three stages were perforated, and hydraulic fracture jobs were conducted in each stage, the
results of which were below expectation, as discussed in the following sections. GCA considers
that the stages in well Cvo.x-2 were under-stimulated.
GCA recommends AESA to consider the following for either the Cvo.x-2 well or future vertical
wells:
Increase the volume of the fracture treatment in each stage.
Increase the number of hydraulic stages to increase the rock volume to be contacted and
drained through the well.
Minimize the hydraulic communication with underlying Tordillo and overlying Quintuco
formations.
Table 6.1 summarizes the microseismic and fracture parameter results in the Cvo.x-2 well for
the three stages conducted and interpreted by Schlumberger.
GCA’s independent
interpretation, matching the variables during the hydraulics fracture jobs to estimate the
geometry of the fracture created and areal proppant concentrations distribution, was not part of
the current scope of work.
TABLE 6.1
SUMMARY OF THE MICROSEISMIC AND FRACTURE PARAMETER RESULTS
BY VENDOR COMPANY
Stage
1
2
3
Clusters
(m)
1974-1975;
1990-1991
1914.5-1915;
1933.5-1934;
1945-1945.5
1642-1642.3;
1654-1654.5;
1672-1672.7
Total
Fluid
3
(m )
Total
Proppant
(sacks)
Avg.
Rate
(bpm)
Avg.
Propped
Fracture
Height
(m)
Max
Fracture
Height
(m)
Total
MS
Length
(m)
Total
MS
Height
(m)
Fracture
Azimuth
(deg)
876
461
39
na
na
240
187
93
1259
4,026
49.9
28
275
428
242
93
1538
4,653
57.2
23
145
471
207
88
Source: Argenta (StimMAP Evaluation Report – Schlumberger, January 2014) and Design/Execution/Evaluation – Schlumberger,
January 13, 2014)
28
AB-14-2003.01
6.1.1
Stage 1 (Clusters: 1,974 - 1,975, 1,990 - 1,991 m)
The microseismic events and treatment data are shown in Figure 6.1 and Figure 6.2.
Minimal or no oil production came from this stage based on available production logging tool
(PLT) information.
The stimulation treatments did not succeed because of the following:
-
It was not possible to pump the designed treatment (3,500 sacks planned vs. 461 sacks
actual)
-
Height growth of the hydraulic fracture in Tordillo formation
-
High surface pressure during the fracture job
FIGURE 6.1
CVO.X-2 WELL -STAGE 1
VISUAL INSPECTION - MICROSEISMIC EVENTS
Source: Argenta (StimMAP Evaluation Report – Schlumberger, January 2014)
29
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FIGURE 6.2
TREATMENT DATA AND MICROSEISMIC EVENT RATE
Source: Argenta (Design - Execution - Evaluation –Schlumberger – January 13th 2014)
30
AB-14-2003.01
6.1.2
Stage 2 (Clusters: 1,914.5/15; 1,933.5/34; and 1,945/46.5 m)
Almost all the oil production in the well came from this stage based on PLT information. The
PLT data showed more than 86% of the production came for the 1914.5 - 1915 m cluster.
Although in this stage the proppant was placed completely, and fluids during the fracture
treatment have been propagated more than 200 m upwards, the estimated average propped
fracture height (as interpreted by the fracture service company, Schlumberger) is only 28 m
and the conductive zone would be around the perforations.
GCA recommends a detailed post-fracture simulation analysis to be carried out in the Cvo.x2 well, which would be the basis for improving future hydraulics stimulation treatments,
including the definition of the number of stages to achieve an overlap between the different
stimulated rock volumes generated.
Cement Conditions
Communication during the fracture jobs could have been established through the annulus
space between cement and casing in the intervals 1914 to 1845 m.
FIGURE 6.3
CVO.X-2 WELL -STAGE 2 –
Source: Argenta (StimMAP Evaluation Report – Schlumberger, January 2014)
31
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FIGURE 6.4
Source: Argenta (Design - Execution - Evaluation –Schlumberger – January 13, 2014)
32
AB-14-2003.01
6.1.3
Stage 3 (Clusters: 1,642/42.3; 1,654/54.5; and 1,672/72.7 m)
The PLT indicates that less than 10% of liquid production was coming from this zone.
As in Stage 2, there were no operational problems during the fracturing.
Poor quality cement bond in the upper zone of this stage:
-
Surface pressure presented a decline of almost 50% during the pumping. This decline
rate is unusual and was probably a result of the communication behind the pipe between
the Vaca Muerta and Quintuco.
-
Microseismic shows the treatment was placed mostly in the Quintuco formation.
Besides the stress contrast between both formations, bad isolation could have been
bypassed (broken) during the fracturing operation.
Proppant settling has been around 23 m, based on the interpretation of the fracturing
company, which indicates that this zone of the Vaca Muerta formation has been poorly
stimulated, although the estimated height growth is 145 m according to Schlumberger.
33
AB-14-2003.01
FIGURE 6.5
Source: Argenta (StimMAP Evaluation Report - Schlumberger - January 2014)
34
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FIGURE 6.6
Source: Argenta (Design - Execution - Evaluation –Schlumberger – January 13, 2014)
35
AB-14-2003.01
6.2
Production History
The Cvo.x-2 well is the only well completed by AESA in the Vaca Muerta formation. The initial
oil rate of the well was about 25 Bbl/d oil and 320 Bbl/d of water. After approximately two
months, the well was producing 6 Bbl/d of oil, with 18 Bbl/d of water, and a GOR of 5,800
scf/Bbl. Then, the well almost stopped flowing naturally and was shut in. (See Figure 6.7 and
Figure 6.8.)
FIGURE 6.7
PRODUCTION HISTORY OF CVO.X2
TOTAL FLUID, WELLHEAD FLOWING PRESSURE, OIL RATE AND GAS RATE
Total Fluids [Bbl/d]
60
WHFP [psi], Liquid Rate [Bbl/d]
1,800
50
1,600
1,400
40
1,200
1,000
30
800
20
600
400
10
200
0
0
Date
Liquid Rate [Bbl/d]
WHFP [psi]
Gas Rate [Mscf/d]
36
Oil Rate [Bbl/d]
Gas Rate [Mscf/d], Oil Rate [Bbl/d]
2,000
AB-14-2003.01
FIGURE 6.8
PRODUCTION HISTORY OF CVO.X2
GAS OIL RATIO
18,000
GOR
16,000
GOR [scf/Bbl]
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Date
GCA notes that the high gas oil ratios depicted in Figure 6.8, until about February 9, 2014, are
not representative since the ratio corresponds to measurements during the initial flow back of
the well.
Initial static reservoir pressure had not yet been measured in the Cvo.x2 well at the time of this
study.
As previously noted, the PLT run of March 2013 has shown that more than 86% of production
was coming from Stage 2.
37
AB-14-2003.01
7.
VOLUMETRIC ESTIMATES
GCA has conducted an independent review and evaluation, as of June 2014, of the OOIP and
OGIP in the Vaca Muerta formation within the study area. In view of limited geological and well
data, GCA used the probabilistic approach in estimating the in-place volumes based on the
following, as earlier discussed:
The GRV was derived from isopach maps generated using well tops and base Vaca Muerta
horizon interpretation. The study area of 278 km2, as defined by AESA, is the same for
Upper, Transition and Lower zones. Hence, uncertainty in GRV reflects uncertainty in
average gross thickness for the study area.
Petrophysical properties were estimated from well data for three wells in the Lower zone
and Transition zone (Cvo.x-2, Cvo.x-1 and CAz.x-1) and one well in the Upper zone (Cvo.x2). The OA.x-2 well was excluded from the estimate due to poor data quality.
The parameter range for variation was defined as ±3 porosity units for porosity, ±10
saturation units for Sw and 25-50% for N/G ratio, using different methods and technologies,
and by comparing the well results.
The Boi range was estimated from available production data and GCA’s regional
experience, in the absence of actual PVT information.
A solution gas-oil ratio of 2,184 scf/Bbl was estimated from the reliable initial production
GOR of the Cvo.x-2 well.
The amalgamation of this data provided the basis for the probabilistic volumetric estimate of the
oil-in-place.
In summary, the input parameters for the probabilistic estimate are shown in Table 7.1.
TABLE 7.1
OIL IN PLACE INPUT PARAMETERS
Zone
Upper
3
UZ GRV MMm
UZ N/G
UZ PhiT
UZ Sw
UZ Bo
Transition
3
TZ GRV MMm
TZ N/G
TZ PhiT
TZ Sw
TZ Bo
Lower
3
LZ GRV MMm
LZ N/G
LZ PhiT
LZ Sw
LZ Bo
Low
Best
High
73787
0.12
0.03
0.48
1.76
77671
0.25
0.06
0.38
1.6
81555
0.37
0.09
0.28
1.44
15148
0.18
0.03
0.42
1.76
15946
0.35
0.06
0.32
1.6
16743
0.53
0.09
0.22
1.44
11141
0.49
0.04
0.39
1.76
11727
0.65
0.07
0.29
1.6
12313
0.81
0.10
0.19
1.44
38
AB-14-2003.01
GCA’s estimate of the OOIP and solution OGIP are shown in Table 7.2 and Table 7.3. (These
tables are also provided in Conclusions as Table 0.1 and table 0.2.) Although the transition
zone in the immediate vicinity of the Cvo.x-2 well might be considered as discovered, such a
designation would likely be premature and could be misleading given that the potential for
eventual commercialization is extremely tenuous based on the data currently available and
analyzed. Further, the in place volume associated with this very small area would be
insignificant in relation to the total estimates shown below. Therefore it is appropriate to
consider the in place volume estimates as undiscovered PIIP.
TABLE 7.2
SUMMARY OF ORIGINAL OIL IN PLACE ESTIMATE
Zone
Upper
Transition
Lower
P90
1,700
560
1,200
OOIP
(MMBbl)
P50
P10
2,500 3,600
800
1,200
1,500 1,900
Mean
2,600
850
1,600
TABLE 7.3
SUMMARY OF SOLUTION ORIGINAL GAS IN PLACE ESTIMATE
Zone
Upper
Transition
Lower
P90
3,700
1,200
2,600
Associated Gas
(Bscf)
P50
P10
5,600 7,900
1,800 2,600
3,400 4,200
Mean
5,700
1,900
3,400
The above zones have different associated risks.
The Upper zone has the risk of hydrocarbon discovery in the absence of proven oil
discovery.
While the Transition zone has been successfully tested with hydraulic stimulation, the
potential for eventual but commerciality is yet to be demonstrated.
While there is evidence of hydrocarbon in the Lower zone, significant quantities and
producibility, even with hydraulic stimulation, are yet to be demonstrated.
GCA did not undertake any study to estimate recovery factors for the Vaca Muerta formation
as that was not part of the current scope of work. However AESA requested GCA to include
a range of recovery factors as reported in the public domain. Based on a report from the US
Energy Information Administration (June 2013), the technically oil recovery factor estimates
range between 3% to 7% for producing shale oil formations (Reference: U.S Energy
Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources:
An Assessment of 137 Shale Formations in 41 Countries outside the United States, June
2013). These recovery factors should not be construed as being applicable to these
estimates of PIIP nor should they be taken as b for the purpose of this report.
39
AB-14-2003.01
APPENDIX I
References
AB-14-2003.01
AAPG Memoir 62, Petroleum Basins of South America. Tankard A.J., Suarez Soruco R.,
Welsink, H.J. 1995. Pg. 383-401.
Design, Execution, Evaluation – Schlumberger (January 13, 2014).
Informe de Avance de Evaluación e Interpretación Estratigráfica Covunco – Jose Ranalli
(June 2014).
Modelo Geomecanico Post Drill Cvo.x-2 (January 2013).
Report of Resource Potential of Vaca Muerta – Canadian Discovery Ltd Consulting
Company (March 2012).
Reservoir Engineering – Project Update Presentation – Argenta (June 18, 2014).
Sistemas Hidrocarburiferos No Convencionales en El Bloque El Corte, Covunco, Neuquén –
Dr. Miguel Ezpeleta and Daniel Boggetti.
StimMAP Evaluation Report – Schlumberger (January 2014).
USIT Cement Log – Schlumberger (May 2012).
VI Congreso de Exploración y Desarrollo de Hidrocarburos, Simposio “Las trampas de hidrocarburos en las cuencas productivas de Argentina.” Editores E. Koslowski, G. Vergani,
A. Boll. 1a Edición. Buenos Aires. IAPG, 2005. Pg 331-368.
U.S Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas
Resources: An Assessment of 137 Shale Formations in 41 Countries outside the United
States, June 2013.
AB-14-2003.01
APPENDIX II
Glossary
Glossary – Standard Oil Industry Terms and Abbreviations
%
Percentage
CO2
1H05
First half (6 months) of 2005
(example)
CAPEX
Capital Expenditure
CCGT
Combined Cycle Gas Turbine
Second quarter (3 months) of 2006
(example)
cm
centimetres
CMM
Coal Mine Methane
CNG
Compressed Natural Gas
Cp
Centipoise (a measure of
viscosity)
2Q06
Carbon Dioxide
2D
Two dimensional
3D
Three dimensional
4D
Four dimensional
1P
Proved Reserves
CSG
Coal Seam Gas
2P
Proved plus Probable Reserves
CT
Corporation Tax
3P
Proved plus Probable plus
Possible Reserves
D1BM
Design 1 Build Many
DCQ
Daily Contract Quantity
ABEX
Abandonment Expenditure
ACQ
Annual Contract Quantity
o
Degrees API (American Petroleum
Institute)
Deg C
Degrees Celsius
Deg F
Degrees Fahrenheit
DHI
Direct Hydrocarbon Indicator
American Association of
Petroleum Geologists
DST
Drill Stem Test
DWT
Dead-weight ton
AVO
Amplitude versus Offset
E&A
Exploration & Appraisal
A$
Australian Dollars
E&P
Exploration and Production
API
AAPG
9
B
Billion (10 )
EBIT
Earnings before Interest and Tax
Bbl
Barrels
EBITDA
/Bbl
per barrel
Earnings before interest, tax,
depreciation and amortisation
BBbl
Billion Barrels
EI
Entitlement Interest
BHA
Bottom Hole Assembly
EIA
Environmental Impact Assessment
BHC
Bottom Hole Compensated
ELT
Economic Limit Test
Bscf or Bcf
Billion standard cubic feet
EMV
Expected Monetary Value
Bscfd or
Bcfd
Billion standard cubic feet per day
EOR
Enhanced Oil Recovery
EUR
Estimated Ultimate Recovery
3
Billion cubic metres
FDP
Field Development Plan
bcpd
Barrels of condensate per day
FEED
Front End Engineering and Design
BHP
Bottom Hole Pressure
FPSO
blpd
Barrels of liquid per day
Floating Production Storage and
Offloading
bpd
Barrels per day
FSO
Floating Storage and Offloading
boe
Barrels of oil equivalent @ xxx
mcf/Bbl
FWL
Free Water Level
ft
Foot/feet
boepd
Barrels of oil equivalent per day @
xxx mcf/Bbl
Fx
Foreign Exchange Rate
g
gram
BOP
Blow Out Preventer
g/cc
grams per cubic centimetre
bopd
Barrels oil per day
gal
gallon
bwpd
BS&W
Barrels of water per day
Bottom sediment and water
gal/d
gallons per day
G&A
General and Administrative costs
BTU
British Thermal Units
GBP
Pounds Sterling
bwpd
Barrels water per day
GCoS
Geological Chance of Success
CBM
Coal Bed Methane
Bm
3
GDT
Gas Down to
md
Cubic metres per day
GIIP
Gas initially in place
mD
GJ
Gigajoules (one billion Joules)
Measure of Permeability in
millidarcies
GOC
Gas Oil Contact
MD
Measured Depth
GOR
Gas Oil Ratio
MDT
Modular Dynamic Tester
GRV
Gross Rock Volumes
Mean
GTL
Gas to Liquids
Arithmetic average of a set of
numbers
GWC
Gas water contact
Median
Middle value in a set of values
HDT
Hydrocarbons Down to
HSE
Health, Safety and Environment
HSFO
High Sulphur Fuel Oil
HUT
Hydrocarbons up to
H2S
Hydrogen Sulphide
IOR
Improved Oil Recovery
IPP
Independent Power Producer
IRR
Internal Rate of Return
J
Joule (Metric measurement of
energy) I kilojoule = 0.9478 BTU)
k
Permeability
KB
Kelly Bushing
KJ
Kilojoules (one Thousand Joules)
kl
Kilolitres
km
Kilometres
km
2
Square kilometres
kPa
Thousands of Pascals
(measurement of pressure)
KW
Kilowatt
KWh
Kilowatt hour
LKG
Lowest Known Gas
LKH
Lowest Known Hydrocarbons
LKO
Lowest Known Oil
LNG
Liquefied Natural Gas
LoF
Life of Field
LPG
Liquefied Petroleum Gas
LTI
Lost Time Injury
LWD
Logging while drilling
m
Metres
M
m
Thousand
3
Cubic metres
Mcf or
Mscf
Thousand standard cubic feet
MCM
Management Committee Meeting
MMcf or
MMscf
Million standard cubic feet
MFT
Multi Formation Tester
mg/l
milligrams per litre
MJ
Megajoules (One Million Joules)
Mm
3
Thousand Cubic metres
3
Thousand Cubic metres per day
Mm d
MM
Million
MMBbl
Millions of barrels
MMBTU
Millions of British Thermal Units
Mode
Value that exists most frequently in
a set of values = most likely
Mscfd
Thousand standard cubic feet per
day
MMscfd
Million standard cubic feet per day
MW
Megawatt
MWD
Measuring While Drilling
MWh
Megawatt hour
mya
Million years ago
NGL
Natural Gas Liquids
N2
Nitrogen
NTG
Net/Gross Ratio
NPV
Net Present Value
OBM
Oil Based Mud
OCM
Operating Committee Meeting
ODT
Oil-Down-To
OOIP
Original Oil in Place
OPEX
Operating Expenditure
OWC
Oil Water Contact
p.a.
Per annum
Pa
Pascals (metric measurement of
pressure)
P&A
Plugged and Abandoned
PDP
Proved Developed Producing
PI
Productivity Index
PIIP
Petroleum Initially-In-Place
PJ
Petajoules (10 Joules)
PSDM
Post Stack Depth Migration
15
psi
Pounds per square inch
US$
psia
Pounds per square inch absolute
VLCC
Very Large Crude Carrier
psig
Pounds per square inch gauge
VSP
Vertical Seismic Profiling
PUD
Proved Undeveloped
WC
Water Cut
PVT
Pressure, Volume and
Temperature
WI
Working Interest
WPC
World Petroleum Council
P10
10% Probability
WTI
West Texas Intermediate
P50
50% Probability
wt%
Weight percent
P90
90% Probability
Rf
Recovery factor
RFT
Repeat Formation Tester
RT
Rotary Table
R/P
Reserve to Production
Rw
Resistivity of water
SCAL
Special core analysis
cf or scf
Standard Cubic Feet
cfd or scfd
Standard Cubic Feet per day
scf/ton
Standard cubic foot per ton
SL
Straight line (for depreciation)
so
Oil Saturation
SPM
Single Point Mooring
SPE
Society of Petroleum Engineers
SPEE
Society of Petroleum Evaluation
Engineers
SPS
Subsea Production System
SS
Subsea
stb
Stock tank barrel
STOIIP
Stock tank oil initially in place
sw
Water Saturation
T
Tonnes
TD
Total Depth
Te
Tonnes equivalent
THP
Tubing Head Pressure
TJ
Terajoules (10 Joules)
12
Tscf or Tcf
Trillion standard cubic feet
TCM
Technical Committee Meeting
TOC
Total Organic Carbon
TOP
Take or Pay
Tpd
Tonnes per day
TVD
True Vertical Depth
TVDss
UFR
True Vertical Depth Subsea
Umbilical Flow Lines and Risers
USGS
United States Geological Survey
United States Dollar
AB-14-2003.01
APPENDIX III
Section 5 of volume 1 of the Canadian Oil and Gas
Evaluation Handbook (COGEH)
DEFINITIONS OF OIL AND GAS
RESOURCES AND RESERVES
CSA Staff Notice 51-324 - Glossary to NI 51-101 Standards of Disclosure
for Oil and Gas Activities sets out the reserves and resources definitions
derived from Section 5 of volume 1 of the Canadian Oil and Gas Evaluation
Handbook (COGEH).
To further assist users of NI 51-101, an updated version of Section 5 of
volume 1 of the COGEH, "Definitions of Resources and Reserves", is
attached. (The copyright holders of COGEH have given the Alberta
Securities Commission, and users of NI 51-101, authority to reproduce
Section 5 of volume 1 of COGEH.) This version reflects updated resource
classification and terminology that is provided in the recently published
second edition of COGEH.
The COGEH itself can be obtained from the Petroleum Society of the
Canadian Institute of Mining, Metallurgy and Petroleum, Calgary Chapter at
www.petsoc.org.
SECTION 5
DEFINITIONS OF RESOURCES AND RESERVES
5-2
Volume 1 — Reserves Definitions and Evaluation Practices and Procedures
TABLE OF CONTENTS
Section 5 DEFINITIONS OF RESOURCES AND RESERVES ................................................ 5-1
5.1
Preface.......................................................................................................................... 5-3
5.1.1
Background........................................................................................................... 5-3
5.1.2
Introduction .......................................................................................................... 5-3
5.2
Definitions of Resources .............................................................................................. 5-5
5.3
Classification of Resources .......................................................................................... 5-7
5.3.1
Discovery Status................................................................................................... 5-8
5.3.2
Commercial Status................................................................................................ 5-8
5.3.3
Commercial Risk .................................................................................................. 5-9
5.3.4
Economic Status, Development, and Production Subcategories ........................ 5-10
a. Economic Status ..................................................................................................... 5-10
b. Development and Production Status....................................................................... 5-10
5.3.5
Uncertainty Categories ....................................................................................... 5-11
5.4
Definitions of Reserves .............................................................................................. 5-12
5.4.1
Reserves Categories............................................................................................ 5-12
a. Proved Reserves ..................................................................................................... 5-13
b. Probable Reserves .................................................................................................. 5-13
c. Possible Reserves ................................................................................................... 5-13
5.4.2
Development and Production Status................................................................... 5-13
a. Developed Reserves ............................................................................................... 5-13
b. Undeveloped Reserves ........................................................................................... 5-14
5.4.3
Levels of Certainty for Reported Reserves......................................................... 5-14
5.5
General Guidelines for Estimation of Reserves ......................................................... 5-15
5.5.1
Uncertainty in Reserves Estimation ................................................................... 5-15
5.5.2
Deterministic and Probabilistic Methods ........................................................... 5-16
a. Deterministic Method............................................................................................. 5-16
b. Probabilistic Method .............................................................................................. 5-16
c. Comparison of Deterministic and Probabilistic Estimates ..................................... 5-16
d. Application of Guidelines to the Probabilistic Method .......................................... 5-16
5.5.3
Aggregation of Reserves Estimates.................................................................... 5-17
5.5.4
General Requirements for Classification of Reserves ........................................ 5-18
a. Ownership Considerations...................................................................................... 5-18
b. Drilling Requirements ............................................................................................ 5-19
c. Testing Requirements............................................................................................. 5-19
d. Regulatory Considerations ..................................................................................... 5-20
e. Infrastructure and Market Considerations .............................................................. 5-20
f. Timing of Production and Development ................................................................ 5-20
g. Economic Requirements......................................................................................... 5-21
5.5.5
Procedures for Estimation and Classification of Reserves ................................. 5-21
a. Volumetric Methods............................................................................................... 5-21
b. Material Balance Methods...................................................................................... 5-22
c. Production Decline Methods .................................................................................. 5-23
d. Future Drilling and Planned Enhanced Recovery Projects..................................... 5-23
5.5.6
Validation of Reserves Estimates ....................................................................... 5-25
Canadian Oil and Gas Evaluation Handbook
©SPEE (Calgary Chapter)
Section 5 — Definitions of Resources and Reserves
5.1
5.1.1
5-3
Preface
Background
The Petroleum Society of CIM (Petroleum Society) Standing Committee on Reserves
Definitions (Standing Committee) released revised Definitions and Guidelines For
Estimating and Classifying Oil and Gas Reserves in January 2002. Later in 2002
these reserves definitions were adopted as the foundation for reserves estimation in
the Canadian Oil and Gas Evaluation Handbook (COGEH).
The authors of COGEH and the Standing Committee each developed separate
definitions of resources, incorporating terminology and concepts published in
February 2000 by the Society of Petroleum Engineers (SPE), the World Petroleum
Council (WPC), and the American Association of Petroleum Geologists (AAPG)
(hereafter referred to as the 2000 SPE Resources Definitions). The COGEH version
was published in COGEH in 2002, with the Standing Committee version being
published in the second edition of the Petroleum Society’s Monograph No. 1,
Determination of Oil and Gas Reserves, in 2004.
The Standing Committee has now reviewed its definitions for both resources and
reserves. Simultaneously, the Society of Petroleum Engineers (SPE), the World
Petroleum Council (WPC), the American Association of Petroleum Geologists
(AAPG), and the Society of Petroleum Evaluation Engineers (SPEE) reviewed the
2000 SPE Resources Definitions and released revised definitions in April 2007 in its
Petroleum Resources Management System (SPE-PRMS) document. This revision to
COGEH has given due consideration to the SPE-PRMS and has resulted in notable
changes to resources definitions, with only minor editorial changes to the previous
reserves definitions and guidance.
There is now a broad alignment between the COGEH and SPE-PRMS definitions and
guidelines, but some minor differences remain. Currently neither the sponsors of
COGEH nor those of SPE-PRMS have fully endorsed all aspects of the other party’s
definitions, nor has such endorsement been requested.
5.1.2
Introduction
Petroleum is defined as a naturally occurring mixture consisting predominantly of
hydrocarbons in the gaseous, liquid, or solid phase. The term “resources”
encompasses all petroleum quantities that originally existed on or within the earth’s
crust in naturally occurring accumulations, including discovered and undiscovered
(recoverable and unrecoverable) plus quantities already produced. Accordingly, total
resources is equivalent to total Petroleum Initially-In-Place (PIIP). It is recommended
Second Edition — September 1, 2007
5-4
that the term “total PIIP” be used rather than “total resources” in order to avoid any
confusion that may result from the mixed historical usage of the term “resources” to
mean the recoverable portion of PIIP or total PIIP.
The concept that a recovery or development project is required in order to recover
resources from a petroleum accumulation is fundamental to the SPE-PRMS. One or
more exploration, delineation, or development projects may be applied to an
accumulation, and each project will provide additional technical data and/or recover
an estimated portion of the PIIP. In the early stage of exploration or development,
project definition will not be of the detail expected in later stages of maturity. For the
purposes of government/regulatory resource management or for basin potential
studies, projects will typically be defined with lesser precision. Regardless of the end
use of estimates, a basic requirement for the assignment of recoverable resources in
any category is that it must be possible to define a technically feasible recovery
project.
Figure 5-1, taken from the SPE-PRMS, illustrates the main resources classification
system. Additional operational subcategories may also be optionally used (see
Section 5.3.4 a).
The vertical axis of Figure 5-1 represents the chance of commerciality. The key
vertical categories relate to the quantities that are estimated to be remaining and
recoverable; that is
•
reserves, which are discovered and commercially recoverable;
•
contingent resources, which are discovered and potentially recoverable but
sub-commercial;
•
prospective resources, which are undiscovered and potentially recoverable.
The range of uncertainty indicated on the horizontal axis of Figure 5-1 reflects that
remaining recoverable quantities can only be estimated, not measured. Three
uncertainty categories, or scenarios, are identified for estimates of recoverable
resources — low estimate, best estimate, and high estimate (abbreviations for
contingent resources are 1C, 2C, and 3C, respectively) — with the corresponding
reserves categories of proved (1P), proved + probable (2P), and proved + probable +
possible (3P).
Formal definitions for each element of Figure 5-1 are provided in Section 5.2.
5-5
Figure 5-1 Resources classification framework (SPE-PRMS, Figure 1.1).
5.2
Definitions of Resources
The following definitions relate to the subdivisions in the resources classification
framework of Figure 5-1 and use the primary nomenclature and concepts contained
in the 2007 SPE-PRMS, with direct excerpts shown in italics.
Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is
estimated to exist originally 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 estimated quantities in accumulations
yet to be discovered (equivalent to “total resources”).
Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that
quantity of petroleum that is estimated, as of a given date, to be contained in known
accumulations prior to production. The recoverable portion of discovered petroleum
5-6
initially in place includes production, reserves, and contingent resources; the
remainder is unrecoverable.
Production is the cumulative quantity of petroleum that has been recovered at a
given date.
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 the analysis of drilling, geological, geophysical, and
engineering data; the use of established technology; and specified economic
conditions, which are generally accepted as being reasonable. Reserves are
further classified according to the level of certainty associated with the estimates
and may be subclassified based on development and production status. Refer to
the full definitions of reserves in Section 5.4.
Contingent Resources are those quantities of petroleum estimated, as of a given
date, to be potentially recoverable from known accumulations using established
technology or technology under development, but which are not currently
considered to be commercially recoverable due to one or more contingencies.
Contingencies may include factors such as economic, legal, environmental,
political, and regulatory matters, or a lack of markets. It is also appropriate to
classify as contingent resources the estimated discovered recoverable quantities
associated with a project in the early evaluation stage. Contingent Resources are
further classified in accordance with the level of certainty associated with the
estimates and may be subclassified based on project maturity and/or
characterized by their economic status.
Unrecoverable is that portion of Discovered or Undiscovered PIIP quantities
which is estimated, as of a given date, not to be recoverable by future
development projects. A portion of these quantities may become recoverable in
the future as commercial circumstances change or technological developments
occur; the remaining portion may never be recovered due to the
physical/chemical constraints represented by subsurface interaction of fluids and
reservoir rocks.
Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is
that quantity of petroleum that is estimated, on a given date, to be contained in
accumulations yet to be discovered. The recoverable portion of undiscovered
petroleum initially in place is referred to as “prospective resources,” the remainder as
“unrecoverable.”
5-7
Prospective Resources are those quantities of petroleum estimated, as of a given
date, to be potentially recoverable from undiscovered accumulations by
application of future development projects. Prospective resources have both an
associated chance of discovery and a chance of development. Prospective
Resources are further subdivided in accordance with the level of certainty
associated with recoverable estimates assuming their discovery and development
and may be subclassified based on project maturity.
Unrecoverable: see above.
Reserves, contingent resources, and prospective resources should not be combined
without recognition of the significant differences in the criteria associated with their
classification. However, in some instances (e.g., basin potential studies) it may be
desirable to refer to certain subsets of the total PIIP. For such purposes the term
“resources” should include clarifying adjectives “remaining” and “recoverable,” as
appropriate. For example, the sum of reserves, contingent resources, and prospective
resources may be referred to as “remaining recoverable resources.” However,
contingent and prospective resources estimates involve additional risks, specifically
the risk of not achieving commerciality and exploration risk, respectively, not
applicable to reserves estimates. Therefore, when resources categories are combined,
it is important that each component of the summation also be provided, and it should
be made clear whether and how the components in the summation were adjusted for
risk.
5.3
Classification of Resources
For petroleum quantities associated with simple conventional reservoirs, the divisions
between the resources categories defined in Section 5.2 may be quite clear, and in
such instances the basic definitions alone may suffice for differentiation between
categories. For example, the drilling and testing of a well in a simple structural
accumulation may be sufficient to allow classification of the entire estimated
recoverable quantity as contingent resources or reserves. However, as the industry
trends toward the exploitation of more complex and costly petroleum sources, the
divisions between resources categories are less distinct, and accumulations may have
several categories of resources simultaneously. For example, in extensive “basincenter” low-permeability gas plays, the division between all categories of remaining
recoverable quantities, i.e., reserves, contingent resources, and prospective resources,
may be highly interpretive. Consequently, additional guidance is necessary to
promote consistency in classifying resources. The following provides some
5-8
clarification of the key criteria that delineate resources categories. Subsequent
volumes of COGEH provide additional guidance.
5.3.1
Discovery Status
As shown in Figure 5-1, the total petroleum initially in place is first subdivided based
on the discovery status of a petroleum accumulation. Discovered PIIP, production,
reserves, and contingent resources are associated with known accumulations.
Recognition as a known accumulation requires that the accumulation be penetrated
by a well and have evidence of the existence of petroleum. COGEH Volume 2,
Sections 5.3 and 5.4, provides additional clarification regarding drilling and testing
requirements relating to recognition of known accumulations.
5.3.2
Commercial Status
Commercial status differentiates reserves from contingent resources. The following
outlines the criteria that should be considered in determining commerciality:
•
economic viability of the related development project;
•
a reasonable expectation that there will be a market for the expected sales
quantities of production required to justify development;
•
evidence that the necessary production and transportation facilities are
available or can be made available;
•
evidence that legal, contractual, environmental, governmental, and other
social and economic concerns will allow for the actual implementation of the
recovery project being evaluated;
•
a reasonable expectation that all required internal and external approvals will
be forthcoming. Evidence of this may include items such as signed contracts,
budget approvals, and approvals for expenditures, etc.;
•
evidence to support a reasonable timetable for development. A reasonable
time frame for the initiation of development depends on the specific
circumstances and varies according to the scope of the project. While five
years is recommended as a maximum time frame for classification of a
project as commercial, a longer time frame could be applied where, for
example, development of economic projects are deferred at the option of the
producer for, among other things, market-related reasons or to meet
contractual or strategic objectives.
5-9
COGEH Volume 2, Sections 5.5 to 5.8, provides addition details relating to the
foregoing aspects of commerciality relating to classification as reserves versus
contingent resources.
5.3.3
Commercial Risk
In order to assign recoverable resources of any category, a development plan
consisting of one or more projects needs to be defined. In-place quantities for which a
feasible project cannot be defined using established technology or technology under
development are classified as unrecoverable. In this context “technology under
development” refers to technology that has been developed and verified by testing as
feasible for future commercial applications to the subject reservoir. In the early stage
of exploration or development, project definition will not be of the detail expected in
later stages of maturity. In most cases recovery efficiency will be largely based on
analogous projects.
Estimates of recoverable quantities are stated in terms of the sales products derived
from a development program, assuming commercial development. It must be
recognized that reserves, contingent resources, and prospective resources involve
different risks associated with achieving commerciality. The likelihood that a project
will achieve commerciality is referred to as the “chance of commerciality.” The
chance of commerciality varies in different categories of recoverable resources as
follows:
•
Reserves: To be classified as reserves, estimated recoverable quantities must
be associated with a project(s) that has demonstrated commercial viability.
Under the fiscal conditions applied in the estimation of reserves, the chance
of commerciality is effectively 100 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 fiscal conditions over the life of the project. For
contingent resources the risk component relating to the likelihood that an
accumulation will be commercially developed is referred to as the “chance of
development.” For contingent resources the chance of commerciality is equal
to the chance of development.
•
Prospective Resources: Not all exploration projects will result in
discoveries. The chance that an exploration project will result in the
discovery of petroleum is referred to as the “chance of discovery.” Thus, for
an undiscovered accumulation the chance of commerciality is the product of
5-10
two risk components — the chance of discovery and the chance of
development.
5.3.4
a.
Economic Status, Development, and Production Subcategories
Economic Status
By definition, reserves are commercially (and hence economically) recoverable. A
portion of contingent resources may also be associated with projects that are
economically viable but have not yet satisfied all requirements of commerciality.
Accordingly, it may be a desirable option to subclassify contingent resources by
economic status:
Economic Contingent Resources are those contingent resources that are currently
economically recoverable.
Sub-Economic Contingent Resources are those contingent resources that are not
currently economically recoverable.
Where evaluations are incomplete such that it is premature to identify the economic
viability of a project, it is acceptable to note that project economic status is
“undetermined” (i.e., “contingent resources – economic status undetermined”).
In examining economic viability, the same fiscal conditions should be applied as in
the estimation of reserves, i.e., specified economic conditions, which are generally
accepted as being reasonable (refer to COGEH Volume 2, Section 5.8).
b.
Development and Production Status
Resources may be further subclassified based on development and production status.
For reserves, the terms “developed” and “undeveloped” are used to express the status
of development of associated recovery projects, and “producing” and “nonproducing” indicate whether or not reserves are actually on production (see Section
5.4.2).
Similarly, project maturity subcategories can be identified for contingent and
prospective resources; the SPE-PRMS (Section 2.1.3.1) provides examples of
subcategories that could be identified. For example, the SPE-PRMS identifies the
highest project maturity subcategory as “development pending,” defined as “a
discovered accumulation where project activities are ongoing to justify commercial
development in the foreseeable future.”
5.3.5
5-11
Uncertainty Categories
Estimates of resources always involve uncertainty, and the degree of uncertainty can
vary widely between accumulations/projects and over the life of a project.
Consequently, estimates of resources should generally be quoted as a range according
to the level of confidence associated with the estimates. An understanding of
statistical concepts and terminology is essential to understanding the confidence
associated with resources definitions and categories. These concepts, which apply to
all categories of resources, are outlined in Sections 5.5.1 to 5.5.3.
The range of uncertainty of estimated recoverable volumes may be represented by
either deterministic 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 will actually be recovered. It is likely that the actual remaining
quantities recovered will exceed the low estimate. If probabilistic methods
are used, there should be at least a 90 percent probability (P90) that the
quantities actually recovered will equal or exceed the low estimate.
•
Best Estimate: This is considered to be the best estimate of the quantity that
will actually be 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 be at least a 50 percent
probability (P50) that the quantities actually recovered will equal or exceed
the best estimate.
•
High Estimate: This is considered to be an optimistic estimate of the
quantity that will actually be recovered. It is unlikely that the actual
remaining quantities recovered will exceed the high estimate. If probabilistic
methods are used, there should be at least a 10 percent probability (P10) that
the quantities actually recovered will equal or exceed the high estimate.
This approach to describing uncertainty may be applied to reserves, contingent
resources, and prospective resources. There may be significant risk that subcommercial and undiscovered accumulations will not achieve commercial
production. However, it is useful to consider and identify the range of potentially
recoverable quantities independently of such risk.
5-12
5.4
Definitions of Reserves
The following reserves definitions and guidelines are designed to assist evaluators in
making reserves estimates on a reasonably consistent basis, and assist users of
evaluation reports in understanding what such reports contain and, if necessary, in
judging whether evaluators have followed generally accepted standards.
The guidelines outline
•
general criteria for classifying reserves,
•
procedures and methods for estimating reserves,
•
confidence levels of individual entity and aggregate reserves estimates,
•
verification and testing of reserves estimates.
The determination of oil and gas reserves involves the preparation of estimates that
have an inherent degree of associated uncertainty. Categories of proved, probable,
and possible reserves have been established to reflect the level of these uncertainties
and to provide an indication of the probability of recovery.
The estimation and classification of reserves requires the application of professional
judgement combined with geological and engineering knowledge to assess whether
or not specific reserves classification criteria have been satisfied. Knowledge of
concepts including uncertainty and risk, probability and statistics, and deterministic
and probabilistic estimation methods is required to properly use and apply reserves
definitions. These concepts are presented and discussed in greater detail within the
guidelines in Section 5.5.
The following definitions apply to both estimates of individual reserves entities and
the aggregate of reserves for multiple entities.
5.4.1
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;
•
5-13
specified economic conditions, which are generally accepted as being
reasonable, and shall be disclosed.
Reserves are classified according to the degree of certainty associated with the
estimates.
a.
Proved Reserves
Proved reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities recovered
will exceed the estimated proved reserves.
b.
Probable Reserves
Probable reserves are those additional reserves that are less certain to be recovered
than proved reserves. It is equally likely that the actual remaining quantities
recovered will be greater or less than the sum of the estimated proved + probable
reserves.
c.
Possible Reserves
Possible reserves are those additional reserves that are less certain to be recovered
than probable reserves. It is unlikely that the actual remaining quantities recovered
will exceed the sum of the estimated proved + probable + possible reserves.
Other criteria that must also be met for the classification of reserves are provided in
Section 5.5.4.
5.4.2
Development and Production Status
Each of the reserves categories (proved, probable, and possible) may be divided into
developed and undeveloped categories.
a.
Developed Reserves
Developed reserves are those reserves that are expected to be recovered from existing
wells and installed facilities or, if facilities have not been installed, that would
involve a low expenditure (e.g., when compared to the cost of drilling a well) to put
the reserves on production. The developed category may be subdivided into
producing and non-producing.
Developed producing reserves are those reserves that are expected to be recovered
from completion intervals open at the time of the estimate. These reserves may be
5-14
currently producing or, if shut in, they must have previously been on production, and
the date of resumption of production must be known with reasonable certainty.
Developed non-producing reserves are those reserves that either have not been on
production, or have previously been on production but are shut in and the date of
resumption of production is unknown.
b.
Undeveloped Reserves
Undeveloped reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure (e.g., when compared to the cost of
drilling a well) is required to render them capable of production. They must fully
meet the requirements of the reserves category (proved, probable, possible) to which
they are assigned.
In multi-well pools, it may be appropriate to allocate total pool reserves between the
developed and undeveloped categories or to subdivide the developed reserves for the
pool between developed producing and developed non-producing. This allocation
should be based on the estimator’s assessment as to the reserves that will be
recovered from specific wells, facilities, and completion intervals in the pool and
their respective development and production status.
5.4.3
Levels of Certainty for Reported Reserves
The qualitative certainty levels contained in the definitions in Section 5.4.1 are
applicable to “individual reserves entities,” which refers to the lowest level at which
reserves calculations are performed, and to “reported reserves,” which refers to the
highest level sum of individual entity estimates for which reserves estimates are
presented. Reported reserves should target the following levels of certainty under a
specific set of economic conditions:
•
at least a 90 percent probability that the quantities actually recovered will
equal or exceed the estimated proved reserves,
•
equal or exceed the sum of the estimated proved + probable reserves,
•
equal or exceed the sum of the estimated proved + probable + possible
reserves.
5-15
A quantitative measure of the certainty levels pertaining to estimates prepared for the
various reserves categories is desirable to provide a clearer understanding of the
associated risks and uncertainties. However, the majority of reserves estimates are
prepared using deterministic methods that do not provide a mathematically derived
quantitative measure of probability. In principle, 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 of aggregation is provided in Section 5.5.3.
5.5
General Guidelines for Estimation of Reserves
The following is a summary of fundamental guidelines that should be followed by
reserves evaluators. These general guidelines provide guidance that should aid in
improving consistency in reserves reporting, but provide only a brief summary of the
issues that may arise in applying the reserves definitions. It must be recognized that
reserves definitions and associated guidelines cannot address all possible scenarios,
nor can they remove the conditions of uncertainty that are inherent in all reserves
estimates. It is the responsibility of the reserves evaluator to exercise sound
professional judgement and apply these guidelines appropriately and objectively.
5.5.1
Uncertainty in Reserves Estimation
Reserves estimation has characteristics that are common to any measurement process
that uses uncertain data. An understanding of statistical concepts and the associated
terminology is essential to understanding the confidence associated with reserves
definitions and categories.
Uncertainty in a reserves estimate arises from a combination of error and bias:
•
Error is inherent in the data that are used to estimate reserves. Note that the
term “error” refers to limitations in the input data, not to a mistake in
interpretation or application of the data. The procedures and concepts dealing
with error lie within the realm of statistics and are well established.
•
Bias, which is a predisposition of the evaluator, has various sources that are
not necessarily conscious or intentional.
In the absence of bias, different qualified evaluators using the same information at
the same time should produce reserves estimates that will not be significantly
different, particularly for the aggregate of a large number of estimates. The range
5-16
within which these estimates should reasonably fall depends on the quantity and
quality of the basic information and the extent of analysis of the data.
5.5.2
Deterministic and Probabilistic Methods
Reserves estimates may be prepared using either deterministic or probabilistic
methods.
a.
Deterministic Method
The deterministic approach, which is the one most commonly employed worldwide,
involves the selection of a single value for each parameter in the reserves calculation.
The discrete value for each parameter is selected based on the estimator’s
determination of the value that is most appropriate for the corresponding reserves
category.
b.
Probabilistic Method
Probabilistic analysis involves describing a range of possible values for each
unknown parameter. This approach typically consists of employing computer
software to perform repetitive calculations (e.g., Monte Carlo simulation) to generate
the full range of possible outcomes and their associated probability of occurrence.
c.
Comparison of Deterministic and Probabilistic Estimates
Deterministic and probabilistic methods are not distinct and separate. A deterministic
estimate is a single value within a range of outcomes that could be derived by a
probabilistic analysis. There should be no significant difference between reported
reserves estimates prepared using deterministic and probabilistic methods.
d.
Application of Guidelines to the Probabilistic Method
The following guidelines include criteria that provide specific limits to parameters for
proved reserves estimates. For example, volumetric estimates are restricted by the
lowest known hydrocarbon (LKH). Inclusion of such specific limits may conflict
with standard probabilistic procedures, which require that input parameters honour
the range of potential values.
Nonetheless, it is required that the guidelines be met regardless of analysis method.
Accordingly, when probabilistic methods are used, constraints on input parameters
may be required in certain instances. Alternatively, a deterministic check may be
made in such instances to ensure that aggregate estimates prepared using probabilistic
5-17
methods do not exceed those prepared using a deterministic approach including all
appropriate constraints.
5.5.3
Aggregation of Reserves Estimates
Reported reserves typically comprise the aggregate of estimates prepared for a
number of individual wells, reservoirs, and/or properties/fields.
When deterministic methods are used, reported reserves will be the simple arithmetic
sum of all estimates within each reserves category. Evaluators and users of reserves
information must understand the effect of summation on the confidence level of
estimates. The confidence level associated with the arithmetic sum for a number of
individual estimates may be different from that of each of the individual estimates.
Arithmetic summation of independent high-probability estimates will result in a total
with a higher confidence level; arithmetic summation of low-probability estimates
will yield a total with a lower confidence level.
Because the definitions and guidelines require a conservative approach in the
estimation of proved reserves, the minimum probability target for proved reported
reserves will be satisfied with a deterministic approach as long as there are enough
independent entity estimates in the aggregate. Where a very small number of entities
dominate in the reported reserves, a specific effort to meet the probability criteria
may be required in preparing deterministic estimates of proved reserves. Since
proved + probable reserves prepared by deterministic methods will approximate
mean values, the probability associated with the estimates will essentially be
unaffected by aggregation.
When probabilistic techniques are used in reserves estimation, statistically based
mathematical aggregation is performed within the probabilistic model. It is critical
that such models appropriately include all dependencies between variables and
components within the aggregation. Where dependencies and specific criteria
contained in the guidelines have been treated appropriately, reserves for the various
categories would be defined by the minimum probability requirements contained in
Section 5.4.3, subject to the following considerations.
Reported reserves for a company will typically not be the aggregate results from a
single probabilistic model, since reserves estimates are used for a variety of purposes,
including planning, reserves reconciliation, accounting, securities disclosure, and
asset transactions. These uses will generally necessitate tabulations of reserves
estimates at lower aggregation levels than the total reported reserves. For these
reasons and due to the lack of general acceptance of probabilistic aggregation up to
5-18
the company level, reserves should not be aggregated probabilistically beyond the
field (or property) level.
Statistical aggregation of a tabulation of values, which does not result in a
straightforward arithmetic addition, is not accepted for most reporting purposes.
Consequently, discrete estimates for each reserves category resulting from separate
probabilistic analyses, which may, as appropriate, include aggregation up to the field
or property level, should be summed arithmetically. As a result, reported reserves
will meet the probability requirements in Section 5.4.3 regardless of dependencies
between separate probabilistic analyses and may be summed with deterministic
estimates within each reserves category.
It is recognized that the foregoing approach imposes an additional measure of
conservatism when proved reserves are derived from a number of mathematically
independent probabilistic analyses, because the sum of independent 90 percent
confidence level estimates has an associated confidence level of greater than 90
percent. Nonetheless, this is considered to be an acceptable consequence given the
need for a discrete accounting of component proved reserves estimates.
Conversely, this approach will cause the sum of proved + probable + possible
reserves derived from a number of probabilistic analyses to fail to meet the 10
percent minimum confidence level requirement. Given the limited application for
proved + probable + possible reported reserves, this is also considered to be an
acceptable consequence.
5.5.4
General Requirements for Classification of Reserves
The following general conditions must be satisfied in the estimation and
classification of reserves. More detailed guidance can be found in Chapter 5 of
COGEH Volume 2.
a.
Ownership Considerations
Assigning reserves to a company requires the company to own the subsurface
mineral rights or have the contractual right to exploit and produce. This may be
ascertained by reviewing land records and verified in financial records.
Internationally, in Production Sharing Contracts, the company will not usually own
the mineral rights, but reserves may be assigned if the company has the right to
extract the oil or gas. Further qualifications are
•
the right to take volumes in kind,
5-19
•
exposure to market and technical risk,
•
the opportunity for reward through participation in producing activities.
Reserves would not be booked for companies participating in projects where their
rights are limited to purchasing volumes or service agreements that do not contain
aspects of technical and price risk and reward. Pure service contracts are an example
of this type.
Company gross reserves are the working interest share of reserves prior to deduction
of payments to others such as royalties (burdens).
Company royalty interest reserves are the net reserves received as a result of a
royalty or carried interest.
Company interest reserves are the sum of company gross plus company royalty
interest reserves. To avoid double accounting of reserves reported by a company,
company royalty interest reserves must include only royalty volumes derived from
non-related working interest owners.
Company net reserves are the working interest reserves after payment of burdens.
Received royalty interests and carried interests are included in net reserves.
Internationally, net reserves are after payments to governments. Depending on the
PSC, they may be before or after payment of income tax.
b.
Drilling Requirements
Proved, probable, or possible reserves may be assigned only to known accumulations
that have been penetrated by a wellbore. Potential hydrocarbon accumulations that
have not been penetrated by a wellbore may be assigned to prospective resources.
c.
Testing Requirements
Confirmation of commercial productivity of an accumulation by production or a
formation test is required for classification of reserves as proved. In the absence of
production or formation testing, probable and/or possible reserves may be assigned to
an accumulation on the basis of well logs and/or core analysis that indicates that the
zone is hydrocarbon bearing and is analogous to other reservoirs in the immediate
area that have demonstrated commercial productivity by actual production or
formation testing.
5-20
d.
Regulatory Considerations
In general, proved, probable, or possible reserves may be assigned only in instances
where production or development of those reserves is not prohibited by governmental
regulation. This provision could, for instance, preclude the assignment of reserves in
designated environmentally sensitive areas. Reserves may be assigned in instances
where regulatory restraints may be removed subject to satisfaction of minor
conditions. In such cases the classification of reserves as proved, probable, or
possible should be made with consideration given to the risk associated with project
approval.
e.
Infrastructure and Market Considerations
In order to assign reserves there should be an identifiable transportation infrastructure
and a market to sell the oil or gas. The market requirement could vary from highly
transparent spot markets such as exist in North America or the UK to long-term
contracts in more remote areas of the world. If there is no existing market, the
evaluator has to assess the level of confidence that one will be available within a
reasonable time frame.
If there is no infrastructure in place, or the company has no ownership in nearby
infrastructure, the evaluator has to assess the level of confidence that access to
suitable infrastructure will be available within a reasonable time frame.
f.
Timing of Production and Development
Non-producing reserves should be planned to be developed within a reasonable time
frame. For projects requiring minor capital expenditures, two years is a recommended
guideline unless the non-producing reserves are awaiting depletion of another
producing zone or production levels are constrained by facility or market limitations.
For larger capital expenditures, three years is a recommended guideline for assigning
proved reserves and five years for assigning probable reserves. Exceptions to these
guidelines are possible but should be clearly documented.
For producing reserves, extrapolating reserves over very long periods should take
into account the uncertainties in forecasting volumes, fiscal terms, market factors,
and infrastructure. It is recommended that reserves be limited to less than a 50-year
forecast period unless there are clear reasons to extend beyond this.
g.
5-21
Economic Requirements
Proved, probable, or possible reserves may be assigned only to those volumes that are
economically recoverable. The fiscal conditions under which reserves estimates are
prepared should generally be those considered to be a reasonable outlook on the
future. Securities regulators or other agencies may require that constant or other
prices and costs be used in the estimation of reserves and value. In such instances the
estimated reserves quantities must be recoverable under those conditions and should
also be recoverable under fiscal conditions considered to be a reasonable outlook on
the future. In any event, the fiscal assumptions used in the preparation of reserves
estimates must be disclosed.
Undeveloped recoverable volumes must have a sufficient return on investment to
justify the associated capital expenditure in order to be classified as reserves as
opposed to contingent resources.
5.5.5
Procedures for Estimation and Classification of Reserves
The process of reserves estimation falls into three broad categories: volumetric,
material balance, and decline analysis. Selection of the most appropriate reserves
estimation procedures depends on the information that is available. Generally, the
range of uncertainty associated with an estimate decreases and confidence level
increases as more information becomes available and when the estimate is supported
by more than one estimation method. Regardless of the estimation method(s)
employed, the resulting reserves estimate should meet the certainty criteria in Section
5.4.
a.
Volumetric Methods
Volumetric methods involve the calculation of reservoir rock volume, the
hydrocarbons in place in that rock volume, and the estimation of the portion of the
hydrocarbons in place that ultimately will be recovered. For various reservoir types at
varied stages of development and depletion, the key unknown in volumetric reserves
determinations may be rock volume, effective porosity, fluid saturation, or recovery
factor. Important considerations affecting a volumetric reserves estimate are outlined
below:
•
Rock Volume: Rock volume may simply be determined as the product of a
single well drainage area and wellbore net pay or by more complex
geological mapping. Estimates must take into account geological
characteristics, reservoir fluid properties, and the drainage area that could be
expected for the well or wells. Consideration must be given to any limitations
5-22
indicated by geological and geophysical data or interpretations, as well as
pressure depletion or boundary conditions exhibited by test data.
b.
•
Elevation of Fluid Contacts: In the absence of data that clearly define fluid
contacts, the structural interval for volumetric calculations of proved reserves
should be restricted by the lowest known structural elevation of occurrence
of hydrocarbons (LKH) as defined by well logs, core analyses, or formation
testing.
•
Effective Porosity, Fluid Saturation, and Other Reservoir Parameters:
These are determined from logs and core and well test data.
•
Recovery Factor: Recovery factor is based on analysis of production
behaviour from the subject reservoir, by analogy with other producing
reservoirs, and/or by engineering analysis. In estimating recovery factors the
evaluator must consider factors that influence recoveries, such as rock and
fluid properties, PIIP, drilling density, future changes in operating conditions,
depletion mechanisms, and economic factors.
Material Balance Methods
Material balance methods of reserves estimation involve the analysis of pressure
behaviour as reservoir fluids are withdrawn, and they generally result in more reliable
reserves estimates than volumetric estimates. Reserves may be based on material
balance calculations when sufficient production and pressure data are available.
Confident application of material balance methods requires knowledge of rock and
fluid properties, aquifer characteristics, and accurate average reservoir pressures. In
complex situations, such as those involving water influx, multi-phase behaviour,
multi-layered or low-permeability reservoirs, material balance estimates alone may
provide erroneous results.
Computer reservoir modelling can be considered a sophisticated form of material
balance analysis. While modelling can be a reliable predictor of reservoir behaviour,
the input rock properties, reservoir geometry, and fluid properties are critical.
Evaluators must be aware of the limitations of predictive models when using these
results for reserves estimation.
The portion of reserves estimated as proved, probable, or possible should reflect the
quantity and quality of the available data and the confidence in the associated
estimate.
c.
5-23
Production Decline Methods
Production decline analysis methods of reserves estimation involve the analysis of
production behaviour as reservoir fluids are withdrawn. Confident application of
decline analysis methods requires a sufficient period of stable operating conditions
after the wells in a reservoir have established drainage areas. In estimating reserves,
evaluators must take into consideration factors affecting production decline
behaviour, such as reservoir rock and fluid properties, transient versus stabilized
flow, changes in operating conditions (both past and future), and depletion
mechanism.
Reserves may be assigned based on decline analysis when sufficient production data
are available. The decline relationship used in projecting production should be
supported by all available data.
The portion of reserves estimated as proved, probable, or possible should reflect the
confidence in the associated estimate.
d.
Future Drilling and Planned Enhanced Recovery Projects
The foregoing reserves estimation methodologies are applicable to recoveries from
existing wells and enhanced recovery projects that have been demonstrated to be
economically and technically successful in the subject reservoir by actual
performance or a successful pilot. The following criteria should be considered when
estimating incremental reserves associated with development drilling or
implementation of enhanced recovery projects. In all instances the probability of
recovery of the associated reserves must meet the criteria for commerciality (Section
5.3.2), the general requirements (Section 5.5.4), and certainty criteria contained in
Section 5.4.
If interpretations are such that no proved or probable reserves are assigned to a
development project involving significant future capital expenditures, then the
potentially recoverable quantities should be classified as contingent resources rather
than stand-alone possible reserves.
i.
Additional Reserves Related to Future Drilling
Additional reserves associated with future commercial drilling projects in known
accumulations may be assigned where economics support, and regulations do not
prohibit, the drilling of the location.
5-24
Aside from the criteria stipulated in Section 5.4, factors to be considered in
classifying reserves estimates associated with future drilling as proved, probable, or
possible include
•
whether the proposed location directly offsets existing wells or acreage with
proved or probable reserves assigned,
•
the expected degree of geological continuity within the reservoir unit
containing the reserves,
•
the likelihood that the location will be drilled.
In addition, where infill wells will be drilled and placed on production, the evaluator
must quantify well interference effects, that portion of recovery that represents
accelerated production of developed reserves, and that portion that represents
incremental recovery beyond those reserves recognized for the existing reservoir
development.
ii.
Reserves Related to Planned Enhanced Recovery Projects
Reserves that can be economically recovered through the future application of an
established enhanced recovery method may be classified as follows.
Proved reserves may be assigned to planned enhanced recovery projects when the
following criteria are met:
•
Repeated commercial success of the enhanced recovery process has been
demonstrated in reservoirs in the area with analogous rock and fluid
properties.
•
The project is highly likely to be carried out in the near future. This may be
demonstrated by factors such as the commitment of project funding.
•
Where required, either regulatory approvals have been obtained or no
regulatory impediments are expected, as clearly demonstrated by the
approval of analogous projects.
Probable reserves may be assigned when a planned enhanced recovery project does
not meet the requirements for classification as proved; however, the following
criteria are met:
•
The project can be shown to be practically and technically reasonable.
5-25
•
Commercial success of the enhanced recovery process has been
demonstrated in reservoirs with analogous rock and fluid properties.
•
It is reasonably certain that the project will be implemented.
Additional possible reserves may be assigned in a planned enhanced recovery project
considering factors such as greater effective hydrocarbons in place or greater
recovery efficiencies than those estimated in the proved + probable reserves scenario.
As previously noted, stand-alone possible reserves should not be assigned to a
potential future enhanced recovery project where conditions are such that no proved
or probable reserves could be assigned. In such cases the potentially recoverable
quantities would be classified as contingent resources, with a corresponding low,
best, and high estimate.
5.5.6
Validation of Reserves Estimates
A practical method of validating that reserves estimates meet the definitions and
guidelines is through periodic reserves reconciliation of both entity and aggregate
estimates. The tests described below should be applied to the same entities or groups
of entities over time, excluding revisions due to differing economic assumptions:
•
Revisions to proved reserves estimates should generally be positive as new
information becomes available.
•
Revisions to proved + probable reserves estimates should generally be
neutral as new information becomes available.
•
Revisions to proved + probable + possible reserves estimates should
generally be negative as new information becomes available.
These tests can be used to monitor whether procedures and practices employed are
achieving results consistent with certainty criteria contained in Section 5.4. In the
event that the above tests are not satisfied on a consistent basis, appropriate
adjustments should be made to evaluation procedures and practices.

October 9, 2014 The attached report dated September 30, 2014

Transcription

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