2010meta report rubiales-piriri final_rev

8/10/2019 2010Meta Report Rubiales-Piriri Final_Rev

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Reserves Certif ication Reportfor the

Rubiales Field, Colombia

Prepared For:Metapetroleum Corporation

Meta Petroleum Corp.

February 2011

411 North Sam Houston Parkway E., Suite 400, Houston, Texas 77060-3545T+1 281 448 6188 F+1 281 448 6189

E [email protected] www.rpsgroup.com


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RPS Energy 2010 Reserve Certification Report

R01021 i February 2011

Table of Contents

1.0 EXECUTIVE SUMMARY .................................................................................................... 1

2.0 CONCLUSIONS ................................................................................................................. 4

3.0 FIELD OVERVIEW ............................................................................................................. 5

3.1 OWNERSHIP ..................................................................................................................... 53.2 DEVELOPMENT HISTORY ................................................................................................... 5

4.0 GEOSCIENCE .................................................................................................................... 7

4.1 GEOLOGIC WORK PROCESS .............................................................................................. 74.2 GEOLOGIC COMMENTS ..................................................................................................... 84.3 IDENTIFICATION OF ROCK TYPE ......................................................................................... 9

5.0 PETROPHYSICS.............................................................................................................. 13

5.1 PETROPHYSICAL WORK PROCESS ................................................................................... 135.2. PETROPHYSICAL DATA,PARAMETERS AND MODELS......................................................... 14

6.0 STATIC GEOCELLULAR MODEL .................................................................................. 18

7.0 RESERVES DETERMINATION ....................................................................................... 21

7.1 DISCUSSION ................................................................................................................... 217.2 DEVELOPED RESERVES .................................................................................................. 217.3 UNDEVELOPED RESERVES AND RESOURCES ................................................................... 237.4 SUMMARY ....................................................................................................................... 26

8.0 PRODUCTION FORECASTING ...................................................................................... 27

9.0 DETERMINATION OF VALUE ......................................................................................... 299.1 OWNERSHIP ................................................................................................................... 299.2 DETERMINATION OF VOLUMES ......................................................................................... 299.3 MARKETING .................................................................................................................... 319.4 COSTS ........................................................................................................................... 329.5 EVALUATION PARAMETERS ............................................................................................. 379.6 ANALYSIS RESULTS ........................................................................................................ 37

10.0 QUALIFICATIONS AND LIMITATIONS .......................................................................... 40

10.1 INDEPENDENCE AND CONFLICT OF INTEREST ................................................................... 4010.2 PURPOSE,SCOPE AND USE OF THIS REPORT .................................................................. 4010.3 AVAILABLE DATA ............................................................................................................. 40

10.4 PROFESSIONAL QUALIFICATIONS ..................................................................................... 4010.5 FIELD VISIT AND INSPECTION ........................................................................................... 4110.6 LIABILITY WAIVER ........................................................................................................... 41

List of Figures


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RPS 2010 Reserve Certifi cation Report

R01021 ii February 2011

Figure 3.1 Rubiales Field Location MapFigure 3.2 Concession MapFigure 3.3 Rubiales Field Production PlotFigure 3.4 Rubiales Concession Production PlotFigure 3.5 Piriri Concession Production PlotFigure 4.1 Formation Tops (Arenas Basales and OWC)Figure 4.2 Stratigraphic Cross Section (Hung on top Arenas Basales)Figure 4.3 Lithofacies Interpretations using Variogram Analysis (Rubiales Area)Figure 4.4 Meta Petroleum Net to Gross Sand Ratio Map Arenas Basales Reservoir IntervalFigure 4.5 Meta Petroleums Integration of Lithofacies and Petrofacies DataFigure 4.6 Cross Section showing Gamma Ray, Resistivity, and Lithofacies/Petrofacies

CurveFigure 4.7 Meta Petroleums Reservoir ModelFigure 4.8 Meta Petroleums 3D Representation of Petrel Geocellular ModelFigure 4.9 Meta Petroleums STOOIP Map from November, 2010Figure 4.10 Cross Section through Quifa 3Figure 4.11 Meta Petroleums Quifa 3 Location and STOOIP MapFigure 4.12 Residual Trend Surface Isopach Arenas BasalesFigure 4.13 Definition of the Residual MapFigure 4.14 Structure vs Trend Surface Residual Maps Top Arenas BasalesFigure 4.15 Structure vs Trend Surface Residual Maps Oil Water ContactFigure 4.16 Residual Mapping Method to Predict Probable and Possible Reserve AdditionsFigure 5.1 RUBIALES-PIRIRI-QUIFA Base MapFigure 5.2 Pickett Plot for Selected WellsFigure 5.3 Wellbore Geometry Analysis Vertical Wells 2010Figure 5.4 Wells RB-46, 366 and QUIFA-8 Mineral Identification Spectral GRFigure 5.5 Core-Log Porosity Calibration. Well RUBILALES-46Figure 5.6 Neutron-Density Cross Plots Selected RUBIALES-PIRIRI wellsFigure 5.7 Neutron-Density Cross Plots Selected QUIFA wellsFigure 5.8 Composite Log Well RUBIALES-150Figure 5.9 Composite Log Well RUBIALES-151

Figure 5.10 Composite Log Well RUBIALES-152Figure 5.11 Composite Log Well RUBIALES-116Figure 5.12 Composite Log Well RUBIALES-271Figure 5.13 Composite Log Well RUBIALES-355Figure 5.14 Composite Log Well RUBIALES-088Figure 5.15 Composite Log Well RUBIALES-356Figure 5.16 Composite Log Well RUBIALES-360Figure 5.17 Composite Log Well RUBIALES-270Figure 5.18 Composite Log Well RUBIALES-269Figure 5.19 Composite Log Well RUBIALES-359Figure 5.20 Composite Log Well RUBIALES-358Figure 5.21 Composite Log Well RUBIALES-352

Figure 5.22 Composite Log Well RUBIALES-371Figure 5.23 Composite Log Well RUBIALES-372Figure 5.24 Composite Log Well RUBIALES-370Figure 5.25 Composite Log Well RUBIALES-265Figure 5.26 Composite Log Well RUBIALES-274Figure 5.27 Composite Log Well RUBIALES-244Figure 5.28 Composite Log Well RUBIALES-272Figure 5.29 Composite Log Well RUBIALES-245Figure 5.30 Composite Log Well RUBIALES-275


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R01021 iii February 2011

Figure 5.31 Composite Log Well RUBIALES-316Figure 5.32 Composite Log Well RUBIALES-276Figure 5.33 Composite Log Well RUBIALES-243Figure 5.34 Composite Log Well RUBIALES-280Figure 5.35 Composite Log Well RUBIALES-317Figure 5.36 Composite Log Well RUBIALES-281Figure 5.37 Composite Log Well RUBIALES-277Figure 5.38 Composite Log Well RUBIALES-318Figure 5.39 Composite Log Well RUBIALES-397Figure 5.40 Composite Log Well RUBIALES-315Figure 5.41 Composite Log Well RUBIALES-400Figure 5.42 Composite Log Well RUBIALES-273Figure 5.43 Composite Log Well RUBIALES-086Figure 5.44 Composite Log Well RUBIALES-399Figure 5.45 Composite Log Well RUBIALES-396Figure 5.46 Composite Log Well RUBIALES-353Figure 5.47 Composite Log Well RUBIALES-412Figure 5.48 Composite Log Well RUBIALES-409Figure 5.49 Composite Log Well RUBIALES-411Figure 5.50 Composite Log Well RUBIALES-410Figure 5.51 Composite Log Well RUBIALES-413Figure 5.52 Composite Log Well RUBIALES-408Figure 5.53 Composite Log Well RUBIALES-415Figure 5.54 Composite Log Well RUBIALES-416Figure 5.55 Composite Log Well RUBIALES-440Figure 6.1 Structural Model used to create the Geocellular Model of Quifa-Rubiales-PiririFigure 6.2 Example of the Auditing and Validation of the Well Property CorrelationFigure 6.3 Geocellular Model Divided in 60 Layers and More than15 Million CellsFigure 6.4 Parameters for the R1 Rock Type For Zone 1 of the Geocellular ModelFigure 6.5 Petrophysical Volume Generated from the Geocellular ModelFigure 6.6 Map of Barrel per Cell Generated from the Geocellular Model

Figure 8.1 Production Plot - History and ForecastFigure 8.2 Production Plot by Reserve CategoryFigure 9.1 Pipeline Routes

List of Tables

Table 1.1 Summary of Oil and Gas ReservesTable 1.2 Net Present Value of Future Net RevenueTable 1.3 Total Future Net Revenue (Undiscounted)Table 1.4 Future Net Revenue by Production GroupTable 1.5 Future Net Revenue (Unit Value Basis) by Production GroupTable 1.6 Summary of Pricing and Inflation Rate AssumptionsTable 1.7 Summary of Estimated Development Costs Attributable to ReservesTable 1.8 Summary of Production Estimates Proved + Probable + Possible ReservesTable 4.1 Summary of Analysis of Meta 2010 Work FlowTable 7.1 Summary of Reserves and Production to May 31, 2016Table 9.1 Crude Oil Production, Fuel Consumption, Naptha Purchases and SalesTable 9.2 WTI Crude Oil and Rubiales Crude Oil/Naptha Blend Price ForecastTable 9.3 Field Investment Summary


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Table 9.4 Field Expense Summary

List of Appendices

Appendix 1 Reserves Guidelines issued by the Society of Petroleum EngineersAppendix 2 Before Tax Cases Economic Summary ProjectionsAppendix 3 After Tax Cases Economic Summary Projections.


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R01021 1 February 2011

1.0 EXECUTIVE SUMMARY

RPS was engaged by Meta Petroleum Corporation, (Meta) to perform a reserves certification

report effective December 31, 2010 for the Rubiales Field.

The Rubiales field is the name given to the Rubiales and Piriri producing concessions. Rubiales

consists of mostly basal sands, which produce heavy oil of 12.5 API. The field development

program includes producing from a combination of vertical and horizontal wells arranged in

clusters. The strategic partner for this asset is Ecopetrol, which is the Colombian state-owned oil

company. Meta has a 50% working interest with Ecopetrol in the Piriri concession, and a 40%

interest with Ecopetrol in the Rubiales concession.

The field has produced for a number of years and has a significant reserves base remaining. An

aggressive drilling program has been pursued to develop the majority of the reserves prior to the

expiration of the Rubiales and Piriri concessions on May 31, 2016. Given the reservoir

performance to date and the associated development plan, the drilling program should continue

to be successful and oil production will increase considerably as the work proceeds.

All reserves volumes in the field are categorized as proved, probable or possible based on the

definitions in the Petroleum Resource Management System (PRMS) of the Society of

Petroleum Engineers and the Canadian Oil and Gas Evaluation Handbook (COGEH). Many of

the wells to be drilled are in the probable and possible categories some distance from thecurrently developed area; those volumes are unrisked in this report as is the value placed on

those volumes. The present value of the reserves was calculated at discount rates of 0%, 5%,

10%, 15% and 20% using a price forecast developed by the Strategic Planning Department of

RPS in London. All costs associated with the development of the reserves, including drilling,

infrastructure and water disposal wells are included.

The table below provides a summary of the reserves and value by each reserves category:


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Reserves CategoryField GrossReserves

MMbbl

Meta WorkingInterest Reserves

MMbblNPV @ 10%

$MM USGross Net BFIT AFIT

ProvedDeveloped Producing 112.1 47.6 38.1 1,654.5 1,148.3

Developed Non-Producing 36.3 15.6 12.5 390.4 274.8

Undeveloped 245.7 102.3 81.8 2,643.8 1,862.2

Total Proved 394.1 165.5 132.4 4,688.7 3,285.3

Probable 14.5 6.1 4.9 148.6 104.8

Total Proved + Probable 408.6 171.6 137.3 4,837.3 3390.0

Possible 0.5 0.2 0.2 3.1 2.2

Total Pvd + Prob + Poss 409.1 171.8 137.5 4,840.4 3,392.3

The field has an oil initially in place (OIIP) of 4,383 MMstb: Rubiales 3,472 MMstb and Piriri 911

MMstb. The field wide proved, probable and possible reserves volume is 409 million barrels of

which 96 percent is proved. Additional resources that were not included in the evaluation were

identified in areas adjacent to the possible drilling locations and in outlying areas of lower

thickness pay sand.

The series of tables listed below show the results of the reserves, production, cash flow andpresent worth calculations:

Table 1.1 Summary of Oil and Gas Reserves gross and net volumes

Table 1.2 Net Present Value of Future Net Revenue BFIT & AFIT at various discount rates

Table 1.3 Total Future Net Revenue (Undiscounted) revenue and cost cash flows

Table 1.4 Future Net Revenue by Production Group BFIT NPV @ 10%

Table 1.5

Table 1.6

Future Net Revenue (Unit Value Basis) by Production Group BFIT NPV @ 10%

Summary of Pricing and Inflation Rate AssumptionsTable 1.7 Summary of Estimated Development Costs Attributable to Reserves

Table 1.8 Summary of Production Estimates Proved, Probable and Possible Categories


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All references to costs and values in the report are in United States dollars. The net present

value reported is unrisked and does not represent the fair market value of Metas ownership in

the Rubiales Field. The data provided by Meta was the sole source of information for this report.


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2.0 CONCLUSIONS

This reserves certification report was prepared using field data and a field development

investment program as provided by Meta. The conclusions noted below relate to depletion of

the existing wells and implementation of the field development plan as it has been proposed.

Field Gross 3P Reserves at end of concession are 409.1 MMbbls.

Metas Gross and Net 3P Reserves are 171.8 MMbbls and 137.4 MMbbls, respectively.

Three hundred and forty two locations comprise the undeveloped case.

The drilling campaigns in each of the past years have been very successful in finding anddeveloping oil and in validating the geological model and engineering projections from

earlier studies.

Due to Metas higher working interest, the Piriri concession reserves have more value to

Meta than the reserves to be produced from the Rubiales concession.

Certain step-out locations that were some distance from proved reserves have been

drilled successfully, and as a result significant areas of the reservoir have had crudevolumes re-categorized to proved reserves much sooner than if the drilling program been

restricted to the proved undeveloped locations.

Production and cash flow have been maximized since the pipeline capacity has been

developed on schedule and the water disposal wells and facilities are being drilled and

built as needed to avoid or minimize the curtailment of production due to transportation or

processing limitations.


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3.0 FIELD OVERVIEW

3.1 Ownership

The Rubiales Field is located in the Llanos Basin on the eastern side of Columbia as shown inFigure 3.1, the Location Map. The Rubiales field is the name given to the combined Rubiales

and Piriri producing concessions. Metas working interest in the Rubiales Field is comprised of a

50% ownership in the Piriri concession (62,432 acres in size) and a 40% ownership in the

Rubiales concession (88,463 acres in size). The boundaries of the properties are shown in

Figure 3.2, the Concession Map. The Rubiales field is productive from 135,361 acres, which

comprises the majority of the entire extent of the concession area of 150,895 acres.

Meta pays a 20% royalty on working interest production. There are no other burdens or

overriding royalties associated with the concessions. The agreements expire on May 31, 2016.

This relatively close expiry date is the incentive to Meta to develop the field quickly and produce

field reserves as soon as possible.

3.2 Development History

The Rubiales field was discovered in 1981 by Exxon in association with the Tethys operating

group. Three wells were drilled from 1981 to 1982 and on July 1, 1988 a 28 year concession

was granted. Exxon then drilled 14 wells from 1988 to 1993. The field was then acquired by

Coplex Resources in 1994 who drilled 5 additional wells by 1997. Due to financial problems

within the company, the field was shut in until Tethys et al re-acquired it from Coplex in 2000.

Production was re-started in 2001 and two additional wells were drilled for a total of 24 wells at

that time.

In mid-2002 Rubiales Holdings acquired Tethys et al and quickly drilled 14 wells while improving

field operations. In 2004 Meta Petroleum (a wholly-owned subsidiary of Pacific Rubiales)

became the operator of the Rubiales field following a merger of the et al companies with the

result being a 50% ownership in the Piriri concession and a 40% ownership in the Rubiales

concession. In 2005, studies conducted by Meta confirmed the significant potential of the field

and an investment program was approved.


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From 2006 to the present Meta has conducted an aggressive drilling program that has resulted

in a current total of 229 producing wells that are pumping approximately 138,000 barrels of oil

per day at year end. During 2010, the field produced 45.1 MMstb of oil and at year-end had a

cumulative production of 102.7 MMstb. The results of this program are indicated on the field

production plot, Figure 3.3, and on the production plots for the Rubiales and Piriri concessions

on Figures 3.4 and 3.5, respectively. As of year-end 2010, in the fully developed areas of the

field, the wells have been drilled on an average spacing of 81 acres.

Based on a geocelular model constructed by Meta and audited by RPS as part of this reserve

certification process, the field has an oil initially in place (OIIP) of 4,383 MMstb: Rubiales 3,472

MMstb and Piriri 911 MMstb.

Meta has presented a drilling program with 472 additional wells to completely develop the field.

RPS has classified the wells as proved, probable and possible drilling opportunities. Only 344

additional wells were economic and their volume comprises the undeveloped reserves. Other

locations that did not comply with the reserves definitions were classified as contingent

resources.


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4.0 Geoscience

4.1 Geolog ic Work Process

A new Petra project was created to compare the new wells drilled in 2010 to previous RPS

audits in the field. The purpose was to incorporate the new well data and investigate Metas

data analysis methods. In this new model, both the Rubiales field and the geologically

contiguous and adjacent Quifa field to the south-west were included. Care was taken to ensure

that the projection system was identical, so that Petrel surfaces could be imported from the

Petrel project to the Petra project and quality controlled. All previous well logs (LAS files) from

older wells were loaded into the new Petra project. All new wells drilled in 2010 were loaded into

the new Petra project. Selected directional surveys were loaded for some key wells to tie to the

cross sections. A network of cross sections was created to check the RPS formation tops and

the OWC in each well. One hundred and eighty seven vertical wells (including a few selected

directional wells) were used in the network of cross sections.

RPS formation tops (Arenas Basales and Oil Water Contacts) were picked following previous

work done by RPS in the field. For new wells, picks were quality controlled by comparing

shallow markers such as the overlying Leon Shale and the significant maximum flooding surface

(hot shale) MFS 17. RPS formation picks were then compared to formation tops provided by

Meta. Any differences under ten feet were disregarded as insignificant. There was 80 percentagreement between the two sets of picks. Wells with significantly different picks such as the

Quifa 3 in the southwestern area of the field were noted. These different structural picks have

the potential to affect the calculation of oil in place.

The Structure Arenas Basales surface was exported from the Petrel project and imported into

the Petra Project. This surface was analyzed for structural tie to the well data. An anomalous

area was noted at the area of the Rubiales 120 and surrounding area, where the Petrel seismic

interpretation did not seem to tie the well control (Figure 4.1). It is recommended that theseismic tie be investigated at these locations as a seismic mis-tie could affect the reserves

calculated from the geocellular model. More discussion of the geophysical aspects of the model

is found in the geophysical section.


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The Meta reports were studied and the work flow was analyzed. The geologic comments below

will discuss the stratigraphic and sedimentologic model workflow presented by Meta, and its

potential effect on the oil in place calculation.

4.2 Geolog ic Comments

Table of comments on Meta Stratigraphic Analysis:

Meta Stratigraph ic Analysis RPS Comments

Strat correlation of wells (CAR9 FY andCAR8 FY markers)

OK - good correlation, marks shale barriers (MFS) for the most part but crosses the OWCso is not a flow unit marker

Core description OK -- good jobCore facies interpretation OK -- good job

Environment of deposition based on core

facies

OK good job stacked fluvial channelenvironment Variogram method appearsrandom lacks predictability?

Yellow highlight denotes topics of discussion.

RPS notes that Meta has done good work in their core description and core facies interpretation

and that the work process meets or exceeds standard industry practices. The Arenas Basales

environment of deposition is a coarse grained stacked fluvial channel environment with many

shale breaks. Well to well correlation is extremely difficult.

The stratigraphic markers picked by Meta called AB, Car8 and Car9 and Paleozoico are a very

reasonable stratigraphic correlation. This work meets or exceeds standard industry practices.

However these stratigraphic markers cross the Oil Water contact as can be seen in Figure 4.2.

Car8 and Car9 markers tie shale beds as possible maximum flooding surfaces. The Oil Water

Contact is not, in most cases, controlled by the shale beds and crosses facies boundaries

indiscriminately.

Meta in its report shows several examples of channel facies developed in the Rubiales field, in

documentation of the section discussing fluvial channel direction. Figure 4.3 (4.3A) shows such

a channel interpretation, or tendency of channel direction, based on close well control. As stated

above, well to well correlation is extremely difficult. In order to predict lithology present in the

next location, Meta used variogram analysis. This is a valid method to predict the statistical

probability of what might be present at a neighboring location. This work process meets a

standard industry practice in areas of poor lateral correlation, random channel distribution and

high reservoir variability.


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Another standard method of analysis would be to create a Gross Sand Isopach of a particular

channel, then a Net Sand Isopach, Net to Gross Sand Ratios, and then to a Net Pay Isopach,

and then to flow units, in order to define channel facies. This method is subject to the geologists

interpretation of channel direction. However, based on Metas drilling experience in the area,

perhaps the true distribution is indeed random.

The two methods end up with very different distributions of lithofacies as Figure 4.3 shows.

Depositional trends appear NW oriented in 4A and north-south in 4B.

It is suggested that mapping methods of Gross Sand and Net Sand isopachs and Net to Gross

sand ratio be used in conjunction with variogram analysis to predict the lithology present in a

particular location.

Figure 4.-4 shows a map from Rubiales 2009 Field Audit, RPS, Net to Gross Sand Ratio, Arenas

Basales Reservoir Interval. In this figure, more sandy areas can be identified in yellow and

orange and more shaly areas in gray.

4.3 Identification of Rock Type

RPS notes that Meta has done high quality work in identification of rock type and

porosity/permeability interaction analysis. The Meta work process meets or exceeds standard

industry practices. Metas integration of Lithofacies and Petrofacies data to create flow unit

divisions based on pore throat size is a very good analysis.

Table of comments on Meta Porosity/Permeability analysis

Well Database, Electric Log Petrophysical Analysis Data

Facies correlation with flow units based on R50

Pittman

OK good job

Core facies tied to petrophysical characteristics

Each facies has particular flow characteristicsbased on PERMEABILITY and pore throat size

OK good job

Flow units are based on type of porosity andPERMEABILITY

OK -- good analysis but then you do not useit in the CAR8CAR9 layer correlation

Yellow Highlight denotes topic of discussion .


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R01021 10 February 2011

The resulting flow unit nomenclature is very useful. The implication of these

porosity/permeability facies definitions is that these facies define the flow units, Figure 4.5.

As can be observed in the cross section in Figure 4.6, the highest quality porosity and

permeability are consistently present in the oil productive interval, and seldom present in the

rock interval below the oil water contact. It is unknown whether this phenomenon is due to

deposition (coarsest grain size and largest pore throats at the top of the Arenas Basales interval)

or to post depositional diagenetic events. The Gamma Ray however appears just as clean in the

interval below the oil water contact as above. It is suggested that Meta consider this

phenomenon when analyzing flow units in the field. Figure 4.6 denotes Cross section showing

Gamma Ray, Resistivity, and Lithofacies/petrofacies curve. Most porous lithofacies/petrofacies

(Gigaporosity, Supermegaporosity, and Megaporosity) are highlighted in orange.

It seems that these units (the Giga/Mega Porosity Unit above the oil water contact and the

interval from Oil water contact to top Paleozoico form natural flow units. However, Meta did not

use these flow unit boundaries in definition of cells for the geocellular model. Meta used the top

Arenas Basales and Top Paleozoico and the Car8 and Car9 stratigraphic markers to define flow

units for the geocellular model.

These markers were used to define a 3 layer layer cake model of the reservoir. Cells in the

layer cake model were defined in the x and y directions as 30 meters by 30 meters. Cells were

defined in the z (vertical) direction by an arbitrary division of 20 cells per layer cake (Figure 4.7).

Each cell was then assigned its particular porosity, lithofacies, and water saturation. Cells not

controlled by well data were assigned lithofacies, porosities, and water saturations based on

variogram prediction of what might occur at that cell.

The resulting 3 layer model is shown in Figure 4.8 as the green, yellow and light blue layers in

the 3 dimensional diagram. Water content of cells in the upper green layer (Zone 1) is shown as

dark blue. Oil in place was then calculated in the Petrel geocellular model based on this cell

properties assignment.

The resulting Oil in Place calculation is dependent on all these input parameters: seismic

structure, well tops, lithofacies determination, porosity and permeability calculation, and water

saturations. The geographic distribution of lithofacies, porosity and permeability, and water

saturation values were governed by the variogram method.


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R01021 11 February 2011

The following three diagrams show distinct different OOIP calculations based on a difference in

structural pick and reservoir properties of a single well, the Quifa 3. Figure 4.9 is an OOIP map

created in November, 2010. After inclusion of the Quifa 3 well with a different structural pick and

different water saturations assigned to the cells (Figure 4.10), a different OOIP map is created in

December, 2010 (Figure 4.11). Note that significant STOOIP is no longer calculated in the

vicinity of the Quifa 3 well.

Table 4.1 shows a summary of analysis of Meta work flow with comments highlighted in yellow

and suggested steps highlighted in blue.

Rubiales Field is a combination hydrodynamic and stratigraphic trap. Hydrodynamic traps can

be defined by residual structure (a paleo structure) differences from a known regional trend, and

by pressure analysis of the aquifer. Water flows regionally to the area of lower regional

pressure. The most common characteristic of a hydrodynamic trap is a tilted oil water contact.

Another common characteristic is biodegradation of the oil to low gravities, which is also present

in Rubiales field.

Adequate definition of a hydrodynamic trap is normally dependent on sufficient surrounding well

control to establish regional trends. However, the edges of the Rubiales field have not yet been

defined based on the well control provided to RPS.

It is suggested that a hydrodynamic analysis be undertaken to help in predicting hydrocarbon

presence in future wells. The mapping steps are defined in Eric Dahlbergs publication on

Hydrodynamic Oil Traps.

A key mapping technique is the creation of a residual trend surface Isopach. First one creates a

first order trend surface, and then calculates the residual structural differential from that trend

surface. Mapping software can perform this calculation for every well control point. Figure 4.12

is a first order trend surface of the structure at top of Arenas Basales from well control. Figure

4.13 diagrams the definition of a residual.

Figures 4.14A & B and 4.15A & B are structural and trend residual maps on the Top Arenas

Basales and the Oil Water Contact, respectively. Figure 4.14A, Rubiales Structure Top Arenas

Basales was created based on well control. Note the very slight structural nosing across the


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R01021 12 February 2011

field. Figure 4.14B, Trend Surface Residual of the Structure Top Arenas Basales note in the

yellow and rose colors the residual structural highs over much of the producing field. Note also

the lack of closure (lack of data) to the south and southwest. The edge of this trap is not defined

on the map.

Figure 4.15A, Structure Rubiales Oil Water Contact was also created based on well control.

Note the very slight structural depression across the field. In Figure 4.15B, Trend Surface

Residual of the Oil Water contact, note in the yellow colors the residual structural lows over

much of the producing field. This suggests that the Oil/Water contact is slightly depressed

underlying the field, as though the oil deposit is like a lens. Note also the lack of closure (lack of

data) to the south and southwest. The edge of this trap is not defined on the map.

When the two residuals are subtracted from one another in a grid to grid operation performed in

mapping software, the result is a map which has fairly close correlation to the producing limits of

the field (Figure 4.16). This mapping method is dependent upon the amount of well or seismic

structural control in the area. It is also dependent upon the number of data points and

distribution of data documenting the oil water contact. However, one is able to establish some

trends and point to areas of development of probable and possible reserves. The Quifa North

area particularly looks prospective. To the southwest in the Quifa area, there is insufficient data

to clearly define a prospective next location. This may be map edge effect.

These proposed mapping methods may be useful in defining additional field extension or field

limits.


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R01021 13 February 2011

5.0 Petrophysics

From available report: Estudio Integrado de Yacimientos Campo Rubiales. Reporte del Modelo

Estatico 3D, January 2010, it was verified that a deterministic petrophysical study was carried

out following the standards in the Oil & Gas industry, which served as base line to validate all

petrophysical parameters and models used by Meta to build the current static model for

Rubiales, Piriri and Quifa fields.

Petrophysical data provided to RPS by Meta included well logs in an Interactive Petrophysics

Database ver 3.5. The RPS petrophysical work was focused on the review of the vertical wells

drilled during year 2010.

Figure 5.1 shows a base map with the existing wells in Rubiales, Piriri and Quifa fields.

Highlighted are the selected vertical wells drilled during year 2010. Fifty one (51) vertical wells

within Rubiales-Piriri fields were reviewed in this study and fourteen (14) vertical wells within

Quifa field. Reviewed wells are listed in the next two paragraphs.

Rubialess wells:RB-086, RB-088, RB-116, RB-151, RB-152, RB-243, RB-244, RB-245, RB-

265, RB-269, RB-270, RB-271, RB-272, RB-273, RB-274, RB-275, RB-276, RB-277, RB-278,

RB-280, RB-281, RB-315, RB-316, RB-317, RB-318, RB-352, RB-353, RB-355, RB-356, RB-358, RB-359, RB-360, RB-361, RB-370, RB-371, RB-372, RB-396, RB-397, RB-399, RB-400,

RB-408, RB-409, RB-410, RB-411, RB-412, RB-413, RB-415, RB-416, RB-440, RB-441, RB-

442, RB-443, and RB-452.

QUIFAs wells; QUIFA-005, QUIFA-006, QUIFA-007, QUIFA-008, QUIFA-009, QUIFA-010,

QUIFA-011, QUIFA-012, QUIFA-013, QUIFA-14, QUIFA-017, QUIFA-018, QUIFA-031, QUIFA-

032.

5.1 Petrophysical Work Process

The methodology followed in the audit of Metas Petrophysical Model, comprises the review and

validation of all parameters and calculation models used by Meta, to produce the input for the

Geocellular model used for volumetric estimation of OOIP.


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R01021 14 February 2011

5.2. Petrophysical Data, Parameters and Models

In general, all vertical wells include a complete suite of well logs that allow the detailed

correlation of stratigraphic units, as well as the evaluation of Clay Volume (Vcl), Porosity (Phie),

Water Saturation (Sw), Permeability (K), Net Reservoir Thickness (NetRes), Net Pay Thickness

(NetPay) and Oil Water Contacts (OWC), among others. In very few cases operational problems

have limited the acquisition of the complete suite of well logs.

The typical suite of well logs in the wells drilled in year 2006 and beyond comprises: Array

Induction (AIT), High Resolution Density, Thermal Neutron Porosity, Gamma Ray, Photoelectric

Factor, Caliper, Bit Size. An example is shown below:

MNEM.UNIT DESCRIPTION (API Code)DEPT .F DEPTH (BOREHOLE) {F10.1}

AHT10.OHMM: Array Induction Two Foot Resistivity A10 {F13.4}AHT20.OHMM: Array Induction Two Foot Resistivity A20 {F13.4}AHT30.OHMM: Array Induction Two Foot Resistivity A30 {F13.4}AHT60.OHMM: Array Induction Two Foot Resistivity A60 {F13.4}AHT90.OHMM: Array Induction Two Foot Resistivity A90 {F13.4}BS .IN: Bit Size {F13.4}GDEV .DEG: HGNS Deviation {F13.4}GR .GAPI: Gamma-Ray {F13.4}GTEM .DEGF: Generalized Borehole Temperature {F13.4}

HCAL .IN: HRCC Cal. Caliper {F13.4}HDRA .G/C3: HRDD Density Correction {F13.4}HTEM .DEGF: HTC Temperature {F13.4}ICV .F3: Integrated Cement Volume {F13.4}IHV .F3: Integrated Hole Volume {F13.4}PEFZ .: HRDD Standard Resolution Formation Photoelectric Factor {F13.4}RHOZ .G/C3: HRDD Standard Resolution Formation Density {F13.4}RXOZ .OHMM: MCFL Standard Resolution Invaded Zone Resistivity {F13.4}SP .MV: Spontaneous Potential {F13.4}TENS .LBF: Cable Tension {F13.4}TNPH .CFCF: Thermal Neutron Porosity {F13.4}

Along the development cycle of the fields, Meta has recovered about 340 feet of whole cores

and 15 water samples (MDT). Information derived from the core description and analysis has

been integrated into the petrophysical analysis and reservoir model. The unconsolidated nature

of the sediments in the Arenas Basales Interval has limited the recovery of cores in these fields.


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R01021 15 February 2011

Water Resistivity Water resistivity has been measured in 15 samples recovered from MDTs.

High resistivity values indicate fresh water of around 1,000 ppm of equivalent NaCl. Meta

reports the use of Water Salinity value of 1045 ppm NaCl and Water Resistivity (Rw) of 5.85

Ohm-m at 60 oF in the petrophysical evaluation of the wells. This parameter was verified using

the Pickett Plot technique as shown in Figure 5.2.

Wellbore Geometry Relationships between the Bit Size (BS) curve and Caliper (HCAL) define

the presence of Mud Cake and Washouts. Drilling and mud parameter during the drilling

process are set to try to produce the better wellbore geometry to avoid large washouts and lower

the impact of bad hole in the quality of the log data, formation damage and completion costs.

From the 51 vertical wells drilled in Rubiales fields during 2010, a significant number of wells

show moderate to medium washouts along the Arenas Basales Interval, while some wells show

a perfect wellbore geometry. RPS interprets this to mean that different drilling and mud

parameters were applied to the different wells. Since the ideal situation is to have a perfect

wellbore geometry, RPS recommends the review the drilling programs applied in the 2010

drilling campaign in order to identify the best practices to be implemented in the future.

Figure 5.3 shows the histograms of the Caliper curve (HCAL) for the Rubiales, Piriri and Quifa

wells. In the Rubiales-Piriri wells, the nominal BS is 8.5 inches and HCAL varies from 7 to 13

inches, which means that, mud cake reached a maximum thickness of 1.5 inches and washouts

reached a maximum of 4.5 inches. In the Quifa wells, nominal BS is 8.5 inches and HCAL

varies from 8 to 9.8 in, which means that mud cake reached a maximum thickness of 0.5 inches

and washouts reached a maximum of 1.3 inches.

Figures 5.8 to 5.55 show the wellbore geometry of each vertical wells analyzed. Well

RUBIALES-151 (Figure 5.12) is a good example of good wellbore geometry while RUBIALES-

360 (Figure 5.19) is a good example of bad wellbore geometry. All Quifa wells analyzed, show

good wellbore.

Clay Volume Clay volume has been determined using the Gamma Ray Index Method, based

on the excellent definition of the GR curve as lithology discriminator in this fluvial environment,

and that GR curve is available in all wells.

Vcl = IGR = [(GRlog Grmin)/(GRmax Grmin)]


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R01021 16 February 2011

Vcl: Clay Volume (v/v)

IGR: Gamma Ray Index (adm)

GRlog Gamma Ray reading of formation

GRmin; Minimun Gamma Ray (Sand)

GRmax: Maximum Gamma Ray (Shale)

Composited Logs, prepared for each of the 51 wells analyzed in this report, show the GR curve

and GR derived Vcl. Neutron-Density derived Vcl compare very close with GR derived Vcl.

Borehole washout observed in a number of vertical wells drilled in the 2010 drilling campaign,

limits the application of the Neutron-Density cross plot as Vcl indicator.

Mineral Identification from Spectral Gamma Ray- Three wells: QUIFA-8, RUBIALES-46 and

RUBIALES-366 have Spectral Gamma Ray Logs available. Figure 5.4 shows the Potasium and

Thorium concentration Crossplot with predominance of high Thorium values and low Potassium

(Wells RUBIALES-46 and QUIFA-8). Well RUBIALES-366 (Core data) shows values in a range

of Thorium, Clorite, Montmorillonite and Illite minerals.

Effective Porosity - Meta calculated Effective Porosity (PHIE) from Neutron-Density derived

total porosity corrected by shale. Hydrocarbon effect is insignificant, since it is heavy oil (12.5

oAPI). Core-Log calibration in well RUBIALES-46 shown in Figure 5.5, demonstrates the validity

of the Neutron-Density method.

The reservoir quality of Rubiales, Piriri and Quifa fields varies from well-developed clean thick

sandstones to more shaly thin sandstones. The reservoir is composed of high quality rock in

terms of porosity and permeability. Porosity ranges between 21% - 38%, with 28% average.

Permeability averages 16,400 mD (Cored well RUBIALES-46). Porosity is lightly affected by the

weight of the sediments and fluids. The better rock quality from the porosity and permeability

point of view is in the oil zone between the Top of Arenas Basales and the Oil-Water contact.

This indicates that hydrocarbon infilling the pore space preserves the porosity by preventing

digenesis by clay minerals precipitation. The sedimentary environment is described as fluvial

near shoreline, with complex vertical and lateral relationship between sand bodies and shales.

The Oil Water Contact (OWC) is observed at a different depth in each well, indicating a tilted

OWC. Composited Logs of the 51 wells analyzed are shown in Figures 5.8 to 5.55.


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R01021 17 February 2011

Figures 5.6 and 5.7 show Neutron-Density Crossplots as examples of the high porosity observed

in the Arenas Basales interval in selected wells located in Rubiales, Piriri and Quifa fields.

Water Saturation A Dual Water Model was used by Meta for calculation of Water Saturation

(Sw). The dual-water concept was developed for the interpretation of resistivity in shaly sands.

This model considers there to be two waters in the pore space: far water, which is the normal

formation water; and near water (or clay-bound water) in the electrical double layer near the clay

surface. The clay-bound water consists of clay counter-ions and the associated water of

hydration. This model has been well accepted by the industry. Rubiales, Piriri and Quifa fields fit

into the category of shaly sand reservoir.

Specific parameters for this Dual Water Model are supported by core analysis and industry

standard cross plot methods.

Net Reservoir & Net Pay Thicknesses Cut offs used by Meta for NetRes and NetPay

thicknesses are well calibrated with the definition of the Oil Zone in the Arenas Basales from the

petrophysical evaluation in each well.

NET RESERVOIR NET PAY

VCL= 20% 20%

SW


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R01021 18 February 2011

6.0 Static Geocellular Model

The geocellular model of the Rubiales-Pirir-Quifa field utilized in this evaluation was generated

by Meta. RPS performed the auditing and validation of the model on the last trimester of 2010.

The geocellular model was built using 2D and 3D seismic interpretation, well log correlations,

defined stratigraphic units, lithofacies data, petrofacies data, and petrophysical evaluation. More

than 185 wells, four well tops, and 41 fault surfaces were used in the building of the geocelular

model. The Petrel application was used as the database and to build the geocellular model.

RPS carried out a detailed analysis, auditing, and validation of the structural frame created in the

model, as well as of the log information loaded and the approaches and algorisms used to carry

out the spatial distribution of the data. Finally, the volumes created from the properties of facies,

net to gross, porosity, and water saturation were visualized tridimensionally and used as input to

calculate the STOIIP. In conclusion, the geocelular model of Rubiales-Pirir-Quifa is consistent

and honors all the original input data.

The following process was conducted to support the objective of reserves certification and

validate and improve field development drilling program.

The review and analysis of the geocellular model was done in five steps:

First, the geometric and structural frame of the model was analyzed and validated. The

correlation between geological tops, seismic surfaces and fault surfaces was analyzed,

validated and visualized. In the same way, the fault pillar gridding, layering, gridding,

boundaries, etc. were reviewed and tested. The geometry of the model is very consistent

with the input data. Figure 6.1 shows, tridimensionally, the top of basement together with

fault surfaces used to generate the structural framework.

Second, log wells, especially, the gamma ray, SP, v shale, porosity, water saturation,

R50, and facies were diagramed and evaluated the correlation among logs and wells.

Also, properties on the model were used to validate the correlation on cell label. Several

cross sections involving almost all the vertical wells were generated to validate the well

correlations among geological tops, petrophysical parameters and properties of cells cut

by wells. Figure 6.2 shows an example of a cross section with the well-correlation of GR,

porosity, water saturation, and facie parameters together with the population of the cells

cut by wells, and the geological tops. The match among log data and cell population is

very satisfactory.


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R01021 19 February 2011

Third, the volume of rock was limited within the structural frame, divided by three zones

according with the well 4 geological tops, 60 layers, and 41 fault surfaces, creating more

than 15.000.000 cells of 100 by 100 meters. Particular attention was paid to the

histogram distribution of data in the cells cut by wells (Cell-wells) and the method used

for the population of well-cells as arithmetic mean, root mean square, midpoint pick, etc.

Finally, well log histograms presented a consistent correlation of data distribution in

original wells and upscaled data. It is important to point out that the facies population of

cells and spatial distribution was done combining lithofacies and petrofacies data. Figure

6.3 shows the model divided into 60 layers and more than 15 million cells. The structural

effect has been removed, to make possible the visualization of the cells. The concession

limits (red polygons) are shown as references.

Fourth, vertical distribution of well data, normalization of data, stochastic parameters,

geostatistics algorithms and results of the spatial distribution of data was reviewed.

Hundreds of variograms and vertical distribution functions were generated and tested. A

particular analysis was carried out in the petrofacies and lithofacies spatial distributions.

All the available algorithms were analyzed as Sequential Gaussian Simulation (SGS)

Stochastic, Kriging Interpolation, Kriging by GSLIB (Geostatistical Software Library),

Truncated Gaussian Simulation, etc. Finally, the spatial distribution throughout the 15

million of cells of the model was carried out applying Truncated Gaussian simulation for

the facies distribution and the Sequential Gaussian Simulation for the petrophysical

properties. Figure 6.4 shows the vertical distribution of the facies for zone 1, variogram

analysis for zone 1 and facie R1, and the algorithm-mathematical parameter for the zone

1 of the geocellular model, and the facie R1. This process was repeated for each zone

and facie of the model. The final result of this step was the generation of volumes of

petrophysical properties with information in each cell of the model.

Fifth, several runs of the geocelular model were done to calculate and analyze the Stock

Tank Oil Initially In Place (STOIIP) values. STOOIP was calculated for the Rubiales,

Pirir and Quifa concession boundaries, as well for each facies, and each segment.

Tables of results were passed to RPS engineering personnel, to be used in the reserve

volume calculation and the categorization of the proved, probable and possible reserves.

Based on a geocelular model constructed by Meta and audited by RPS as part of this

reserve certification process, the Rubiales field has an oil initially in place (OIIP) of 4,383

MMstb: Rubiales 3,472 MMstb and Piriri 911 MMstb.


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R01021 20 February 2011

This geocelular model described above is a scaled representation of the real oilfield where

the geological characteristics and fluid conditions can be studied, analyzed, quantified,

simulated and predicted. Figure 6.5 presents the volumes of facies, porosity, and water

saturation generated in the geocellular model. These volumes were multiplied one each

other, to get the Stock Tank Oil Initially In Place (STOIIP) volume as depicted in Figure 6.5.

Also, for the support of reserve calculation net sand and barrels per cell maps were

generated. Figure 6.6 shows the barrels per cell map.


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R01021 21 February 2011

7.0 Reserves Determination

7.1 Discussion

The Rubiales field produces low gravity, highly viscous oil. The recovery mechanism in the field

is primary recovery, with strong pressure support from a bottom water aquifer. In such a field,the recovery factors under traditional oil field developments using vertical wells can be expected

to be relatively low, in the range of 10 percent to 20 percent of OIIP. To maximize the recovery

efficiency, Meta has pursued a development drilling plan that will increase the well density and

incorporate a significant number of horizontal wells.

The Rubiales field crude oil has low solution gas content, as represented by the gas-oil-ratio that

is estimated to be 5 scf/stb. As a result, there is insufficient produced gas to warrant gas sales.

Some produced gas is used as field fuel and the balance is flared. RPS has not attributed any

gas reserves to the field.

Two separate concessions hold the reserves in the Rubiales field: Rubiales and Piriri. Each

concession has a unique operating and net revenue interest, thus the reserves and economics

are calculated separately for each concession and then summed to get the fieldwide figures.

7.2 Developed Reserves

Reserves estimates were made using production performance analysis, volumetric estimates

and production analogues. Analysis of the change in production rates, water-oil ratio and oil cut

as a function of cumulative production and time was performed to predict the ultimate

recoverable volumes for the producing wells. Parameters used to specify the shut in conditions

were two percent oil cut at a producing rate of 30 and 150 barrels of oil per day for vertical and

horizontal wells, respectively. These minimum operational production rates are dictated by

water handling capacity limitations and not due to an economic limit or flow assurance problems.

An exponential decline curve shape was used for the rate forecasts, with application of

hyperbolic performance where well performance supports the projection after the initial flush

production. Plots of the oil rate versus cumulative production, oil cut versus cumulative

production and water oil ratio versus cumulative production for the producing wells were

analyzed.


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R01021 22 February 2011

Reserves for proposed wells and wells that were completed within the past few months that have

not had sufficient production decline performance were determined by using the average

estimated ultimate recovery and peak production rate values determined for existing wells with

sufficient history, and applying those to the drilling locations and the locations of the recently

completed wells. All of the wells used in determining these averages are located in the field,

have perforated the subject sand interval, and have sufficient performance history to be a good

basis for rate projections. Further detailed discussion of the analysis method follows in Section

7.3.

The Rubiales field has been developed with 362 wells: 154 verticals, 206 horizontal and 2

deviated wells. The typical drilling program involves a centralized vertical well with five

horizontal wells drilled outward from the same pad location. A well cluster of this design typically

drains an area of 485 acres. The horizontal wells typically drill a distance between 500 and

1,200 feet through the reservoir. The recovery from the horizontal wells exceeds that of the

vertical wells by a factor of more than three. The wells have different performance

characteristics also. The vertical wells initially exhibit a lower average annual exponential

decline rate, and the horizontal wells initially produce at over four times the rate of vertical wells

and exhibit a hyperbolic decline.

The cumulative field production to year end 2010 was 102.7 MM barrels of oil, an increment of

45.1 MM barrels of oil with respect to year end 2009. The proved reserves for the producing

wells on December 31, 2010 are 112.1 MM barrels of oil. The ultimate recovery (to the end of

the concession term on May 31, 2016) from all wells drilled to date is estimated to be 214.8 MM

barrels of oil.

As of December 2010 there were 112 wells with shut in status. Some of the wells have prior

production history, a lesser number have been tested only and have no cumulative production.

Meta has advised that 55 of these wells are scheduled to be placed on production in 2011.

These wells were forecasted and scheduled according to Metas guidelines, and the reserves

were included in the proved developed non-producing category. A total of 36.3 MMBbls were

assigned to the proved developed non-producing category for both Rubiales and Piriri fields:

25.8 MMBbls and 10.6 MMBbls, respectively. The 57 remaining shut in wells are assumed to

have no potential since they were not part of the re-vitalization program, and have not been

assigned reserves..


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R01021 23 February 2011

7.3 Undeveloped Reserves and Resources

To estimate the reserves potential of Metas drilling program, a statistical analysis of past

production was used in combination with the Petrel static model. The net pay sand of the wells

that have sufficient performance to perform decline curve analysis was plotted against the

estimated ultimate recovery for both the vertical and horizontal wells. Correlations between the

estimated ultimate recovery and the STOIIP contour map from the Petrel model were considered

for both verticals and horizontal wells. Analysis of the initial production rate and estimated

ultimate recovery was also considered. Forty vertical wells and 87 horizontals wells with

sufficient history were used to calculate the average recovery per well type. As a result the

horizontal wells have an average recovery that is higher than the vertical wells: 1,223,000 stb

versus 476,000 stb, respectively.

A total of 472 locations that were included in Metas development plan have been evaluated.The wells were reviewed separately for each concession (Rubiales with 398 and Piriri with 74)

since the ownership is different for each concession. The reserves determination was done in

two phases:

1. Assignment of reserves category based on proximity to existing production wells, and

2. Assignment of reserves volumes based on Petrel STOIIP cell values.

Phase 1

A base map containing the existing producing wells and Metas proposed drilling locations was

used to assign the reserve classification based on proximity to production. Proved reserves

were assigned to new locations in areas that are undrilled and adjacent to existing wells within

the proved area of the reservoir that could reasonably be judged as continuous and being

commercially productive on the basis of available geoscience and engineering data. Probable

reserves were assigned to areas of the reservoirs that were adjacent to proved areas but where

data control or interpretations of available data was less certain. Possible reserves were

assigned to areas of the reservoirs adjacent to probable areas where data control and

interpretations of available data were progressively less certain.

Areas of the reservoir where the Petrel model indicated the reservoir should be present outside

of the proved, probable and possible areas were designated as areas in which Metas proposed

wells would be drilled for oil volume in the resource category. The wells needed to develop


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R01021 24 February 2011

these resources were given drilling location names and volumes, but production and cash flow

projections were not made.

The four hundred seventy two locations in Metas development program were classified asfollows:

Proved 370 locations

Probable 70 locations

Possible 22 locations

Resources 10 locations

Phase 2

Each of the proposed locations was identified on a fieldwide Petrel map that showed contours of

stock tank oil initially in place (STOIIP), Figure 6.5. The contours represent the STOIIP for a 100

meter by 100 meter cell surface area with a vertical capture of the entire net pay sand thickness

for the one to five sand members in the cell.

The estimated ultimate recovery and STOOIP contour value for each existing well with sufficient

history was analyzed to determine if a useful correlation exists. The scatter to the data suggests

that a definitive relationship between the parameters is not present at this time and that the

recovery from proposed locations is difficult to predict from the STOOIP contour map. Despite

the scatter in the data, the average relationships are reflective of the historical production data

and are valid for the prediction of estimated reserves for large numbers of locations such as

those within the Meta drilling program. The average estimated recovery for each STOIIP cell

value for a vertical and horizontal well is 3.83 and 13.6 barrels, respectively.

To estimate the initial producing rate for new wells, the peak rate and STOOIP contour value for

each existing well with sufficient history was also analyzed to determine if a useful correlation

exists. Again, the scatter to the data suggests that a definitive relationship between the

parameters is not present at this time and that the initial rate from proposed locations is difficult

to predict from the STOOIP contour map. Despite the scatter in the data, the average

relationships are reflective of the historical production data and are valid for the prediction of

initial rate for large numbers of locations such as those within the Meta drilling program. The

average estimated initial production rate for each STOIIP cell value for a vertical and horizontal

well is 4.80 and 20.58 barrels per day, respectively.


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R01021 25 February 2011

The determination of reserves and production forecasts was made following the next steps:

1. The estimated ultimate recovery per STOIIP contour for vertical and horizontal wells

having production history was determined to be 3.83 and 13.60 barrels per STOIIP

contour per cell unit.

2. The estimated reserves for future locations were calculated using the above

recoveries multiplied by the discrete STOIIP contour where the wells are spotted to

be drilled.

3. The initial (peak) production rate for each well was determined using the average

peak rate for each STOOIP cell value of 4.80 and 20.58 barrels per day for vertical

and horizontal wells, respectively. The production forecast was based on recovery of

the estimated reserves to abandonment rates of 30 bopd and 150 bopd for vertical

and horizontal wells, respectively. The horizontal wells were forecast using a

hyperbolic decline exponent of 0.5

4. These production and reserves forecasting methods were used for each location that

was scheduled to be drilled prior to the end of the concession period.

5. The wells were scheduled according to Metas drilling program of 5 horizontal wells

and 2 vertical wells per month, starting in January 2011 and finalizing the drilling

program in December 2015.

6. The well schedule had to comply with a production plateau of 210 MBOPD.

As part of the year-end 2009 report, the future wells with the lowest expected reserves were

analyzed to determine profitability; and all forecasted wells were found to be profitable. A similar

analysis was not deemed necessary for this report since drilling costs are lower, operating

expenses per barrel are lower and forecasted average oil sales prices are approximately the

same as last year.

In summary, there are 342 scheduled locations having 261 MMbbls of proved, probable and

possible oil reserves and 114 locations having 96 MMbbls of contingent resources. Twelve

locations had a STOOIP contour of zero and four were uneconomic, therefore no reserves were

assigned to these fourteen locations.

One condition for undeveloped reserves potential to be included as reserves in this report is to

have a stated intention by the operator to drill and produce the wells. It is noted that Meta has

consistently met or exceeded the number of wells it has budgeted in a given year. Meta has


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R01021 26 February 2011

indicated their intention to drill the wells and has provided the drilling schedule for 2011, which

was used as guidance to continuing the drilling program through 2015. The majority of the

locations in the earlier years are proved wells, with the majority of the probable and possible

locations being drilled in the later years.

7.4 Summary

Reserves to End of Concession Term

Table 7.1 shows the reserves and annual production forecast by concession with a field total

until contract expiration on May 31, 2016. Approximately 72% of the fields 3P potential ultimate

recovery, or 511.8 MM barrels, should be produced by that date. A summary of the reserves is

shown below:

Rubiales Field Reserves at December 31, 2010 (to Expiration of Concessions)

MMBOProved

Developed 148.4Undeveloped 245.7

1P Reserves 394.1

Probable Undeveloped 14.5

2P Reserves 408.6

Possible Undeveloped 0.5

3P Reserves 409.1

Rubiales Field Potential Ultimate Recovery (to depletion)

MMstbCUM

MMstb RE (%)CUM

RE (%)

Cumulative Production @ Dec 31, 2010 102.7 102.7 2.3 2.3Total 3P Reserves @ Jun 2016 409.1 511.8 9.4 11.7Resource Volumes 95.9 607.7 2.2 13.9

Forecast Production from June 2016 todepletion

105.5 713.2 2.4 16.3


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R01021 27 February 2011

8.0 Production Forecasting

The Rubiales field was discovered in 1981; however produced only periodically until 2002 when

production was reported continuously. After Meta obtained control of the operation of the field in

2004 the production increased until it reached 138 MBOPD in December 2010 from 229 wells.

The production for the Rubiales field was forecasted from January 1, 2011 to the expiration of

the concession on May 31, 2016 to reach a production plateau of 210 MBOPD, as specified by

Meta, Figure 8.1. The field has 229 producing wells in the concessions with the associated

reserves volumes during the concession license period as shown in the table below. These

wells comprise the proved producing field wide case.

Fifty five shut in wells were scheduled to be back on production in 2011. The production from

these wells during the concession period was scheduled following Metas guidelines. The

volumes are classified as proved non-producing reserves as shown in the following table:

The Rubiales field has 342 locations in the drilling program that is forecasted to continue into

2015. The locations are expected to generate 261 MM barrels of oil before the end of the

concession period. The table below shows the reserves volume split between the proved,

probable and possible categories as well as the number of locations in each.

Proved Developed Producing Reserves

Rubiales Field Produc ing Wells ForecastProduction, MMbbls

Rubiales Concession 146 84.4

Piriri Concession 83 27.7

Total Field 229 112.1

Proved Developed Non-Producing Reserves

Rubiales Field Shut in Wells ForecastProduction, MMbbls

Rubiales Concession 41 25.7

Piriri Concession 14 10.6

Total Field 55 36.3


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R01021 28 February 2011

Undeveloped Reserves

Proved UndevelopedLocations

Probable UndevelopedLocations

Possible UndevelopedLocations

Rubiales Field Count Forecast

ProductionMMbbls

Count Forecast

ProductionMMbbls

Count Forecast

ProductionMMbbls

Rubiales Concession 251 205.5 23 11.1 3 0.5

Piriri Concession 56 40.1 9 3.4 - -

Total Field 307 245.6 32 14.5 3 0.5

The production forecasts for each of the drilling programs are shown in the cash flow forecast

evaluations to be discussed in Section 9.0 Determination of Value. Forecasts of the production

performance by reserves category were created following the list of new locations and the 2011

drilling schedule provided by Meta as shown on Figure 8.2. This schedule of development has

assumptions that include the number of rigs that would be contracted by year as well as the time

it would take to drill and complete a typical well. The production forecasts of the field

development plan were scheduled on an unrisked basis.

A total of 91 water disposal wells are planned to be drilled from 2011 through 2015 by Meta as

shown in the following drilling schedule:

Water Disposal Well Count

2011 2012 2013 2014 2015 2016 Total

Horizontal 17 22 15 15 9 - 78

Vertical 3 3 3 3 1 - 13

Total 20 25 18 18 10 - 91


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R01021 29 February 2011

9.0 Determination of Value

9.1 Ownership

Time Period

The assessment of value for the Rubiales field was calculated for the production forecast from

January 1, 2011 through to the end of the Piriri and Rubiales concession contracts on May 31,

2016. Both of the concessions expire on the same date; and any reserves that remain after this

date are not recoverable by Meta Petroleum. The effective date for discounting of field value in

the evaluation is January 1, 2011.

Interests

Meta has different working and revenue interests in the two concessions as follows:

Rubiales Piriri

Working interest 40% 50%

Net Revenue interest 32% 40%

The royalty due from crude oil production that is sold from each concession is 20 percent.

Natural gas production is negligible and is not metered or sold. The economic analysis includes

the crude oil / naptha blend as the sales product. Royalty is paid on the crude oil but not on the

naptha. Thus, the royalty in the economic model is based on a ratio of crude oil at 20 percent

royalty and the naptha that has no royalty obligation. The net revenue share that was input into

the model to properly reflect the ownership of pipeline volume to sales is 82.45 percent.

9.2 Determination of Volumes

Production

The Piriri and Rubiales concessions each have value in the proved producing, proved non-

producing, and proved, probable and possible undeveloped categories. All volumes in this

report are presented unrisked. Appendix 1 is an exhibit that is taken from the Petroleum

Resources Management System (PRMS) report that was issued in 2007 by the Oil and Gas


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R01021 30 February 2011

Reserves Committee of the Society of Petroleum Engineers and was reviewed and jointly

sponsored by the World Petroleum Council (WPC), the American Association of Petroleum

Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). The PRMS

report contains guidelines regarding the relative risk and uncertainty of recovery for the various

reserves categories that are contained within this reserves certification report. The reserves and

economics evaluations that were performed in this report followed the guidelines that were

provided in this exhibit. A summary of the well count that is associated with each reserves

category is as follows:

Proved Producing As of year-end 2010 there were 229 wells producing oil.

Proved Non-Producing There are 55 wells with past production or tests that are

scheduled to be re-completed in 2011.

Proved Undeveloped 307 locations are in close proximity to prior production.

Probable Undeveloped 32 locations offset the proved undeveloped locations.

Possible Undeveloped 5 locations offset the probable undeveloped locations.

Table 7.1 shows the annual production forecast that is developed from the above re-completion

and drilling program for the Rubiales field by concession and reserves category.

Lease Fuel

Some of the oil production is consumed as fuel in the field to heat the crude and enable the

separation of the oil from the water to be more efficient. While the produced volumes have

increased as the field is developed, the fuel volume has increased also. The current projection

of fuel consumption in 2011 is 1,732 barrels per day, rising to 3,395 barrels per day in 2016.

Table 9.1 shows the forecasted annual crude volume to be consumed as fuel. The fuel volume

was scheduled by allocation to the proved, probable and possible reserves categories for each

concession.

Sales


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The annual production volumes from 2010 through 2016 in each reserves category, by

concession, were reduced by subtracting the oil consumed for lease fuel to determine the crude

volume that is to be sold. The oil volumes that are trucked or pipelined to sales at Covenas for

export are diluted by blending with naptha to increase the API gravity to meet pipeline and/or

sales specifications. This naptha volume plus the crude sales volumes (field production less

lease fuel consumption) comprise the total sales volumes. Table 9.1 shows the annual naptha

purchases and the annual net sales volumes. These sales volumes are the volumes that are

entered into the economic analysis. The costs of naptha purchase and transportation to the field

are treated as a field operating cost. Also, from the present through December 2011 Meta

forecasts the sale of 4,160 barrels per day of 12.5 degree API gravity crude to the local

Colombian market via trucking without the addition of naptha.

9.3 Marketing

Oil Price

The forecasted annual price of WTI benchmark oil was provided by the RPS Strategic Planning

Department in London in January 2011. The produced oil from Rubiales is 12.5 degrees API

gravity, a low gravity that has downward price adjustments due to quality. The oil sale price

realized by Meta is less than WTI and is dependent on the gravity (quality) and volume of crude

which reaches the various sales points. Meta provided the sales prices it realized in 2010.

A volume-weighted average price differential was calculated annually for future years using the

volumes projected to be sold at the various sales points and the differentials actually incurred at

those points in 2010. This differential was applied as a percentage to the forecasted annual WTI

price and the resulting price, shown in Table 9.2, was used in the cash flow analysis. A

significant volume of oil is still being trucked as pipeline capacity expansion continues. Trucking

of the oil is scheduled to end in December 2011; afterwards all the oil will be transported through

the pipelines.

Transportation

From field discovery through mid 2009, all of the production from the Rubiales field was trucked

to sales. However, as trucking is very expensive and the excessive traffic damages the dirt

roads within the field, Meta opted to install a pipeline to export the crude sales. During 2009,


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Meta constructed and commissioned a 235 km 24 inch pipeline to increase export capacity,

increase safety and lower transportation costs for crude oil from the field.

The pipeline originates in the Rubiales Field and initially transported 65,000 barrels per day in its

first phase. The pipeline route goes from the field to Monterrey where it ties into existing pipeline

facilities which transport oil to the Pacific coast at Covenas where the oil is loaded onto oil

tankers for export. In the near future, approximately 50,000 barrels per day of diluted Rubiales

oil will also flow from Monterrey through Cusiana to Banadia and then to Covenas. The pipeline

routes are shown schematically on Figure 9.1. Because Metas and Ecopetrols field production

will be sold in the pipeline together, the gross field production plus blended naptha is used to

determine transported pipeline volumes. The scheduled growth of pipeline capacity, to be

accomplished by adding more pumping horsepower as the field volume requires, is as follows:

Added Pumping

Capacity Completion

Pipeline Capacity

Barrels per day

January 2011 170,000

February 2011 180,000

April 2011 220,000

September 2011 330,000

9.4 Costs

The investment program to develop the Rubiales field reserves with the associated infrastructure

was created in 2007 when the field potential was established. Subsequent drilling and

construction to this date has generally followed the original plan and resulted in a substantial

investment and increase in production during the past three years. The forecasted expenditures

appear to be sufficient to optimize field recovery prior to the expiration of the concessions on

May 31, 2016.

The field development has included drilling oil production and water disposal wells, re-

completing shut in wells, building facilities to process produced fluids and to dispose of produced

water, an extensive system of flowlines and water disposal lines, and the construction of tankage

and lines for the purchase, handling and blending of naptha which is necessary to increase the

oil gravity to pipeline specifications.


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Investments - Drilling

A typical producing well program consists of one vertical well in a centralized pad location with

up to five horizontal wells drilled outward from the same pad area. Costs for the location

preparation, generators and pipelines are included in the well costs. The drilling well costs were

provided by Meta as follows:

Well Type Cost per well

Production well horizontal $1,550,000

Production well vertical $1,600,000

Disposal well horizontal $1,250,000

Disposal well vertical $1,400,000

These costs have been reviewed by RPS, including comparison with Metas historical drilling

cost in the field, and deemed to be reasonable.

The producing well drilling program investments and locations through the end of the concession

were provided by Meta. RPS scheduled the timing of wells, honoring Metas budgeted drilling

program in the early phases of the program, recognizing that Meta has consistently met its

production goals by adjusting the drilling schedule as development progresses. The costs were

assigned by the location of each well to its concession and reserves category. The schedule for

drilling the disposal wells (timing and well type) was provided by Meta. Disposal well costs were

distributed to each concession and split by the proportional reserves volume in each reserves

category. No disposal well cost was distributed to the proved producing reserves cases because

these volumes already have water disposal capacity.

The drilling program is scheduled to continue uninterrupted into 2015. As part of the year-end

2009 report, the future wells with the lowest expected reserves were analyzed to determine

profitability. All forecasted wells were found to be profitable with payouts of six months or less,

making it attractive to continue the drilling program through 2015. A similar analysis was not

deemed necessary for this report since drilling costs are lower, operating expenses per barrel

are lower and forecasted average oil sales prices are approximately the same as last year.

The cost for a well re-completion was provided by Meta to be $250,000. A review of the shut in

wells across the field by Meta personnel resulted in a list of 55 re-work opportunities that were


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reviewed by RPS. An analysis of the past performance of these wells indicates the potential to

re-establish production. Some of these wells were returned to production in 2010 and the

remaining re-completions are scheduled to be completed in 2011.

The forecasted annual drilling and re-completion investments are shown on Table 9.3.

Investments - Facility

The work to expand the capacity of the field infrastructure continues concurrently with the drilling

program. The metering and processing facilities, water injection pumps and lines, and naptha

blending tanks and equipment to accommodate the increasing production are under

construction. New areas, as developed, will also benefit from infrastructure projects to process

higher volumes of produced fluids. These facility investments were scheduled by Meta and are

shown on Table 9.3. The costs were allocated to each concession and reserves category based

on the percentage of reserves to be recovered. The escalation rate applied to these costs was

two percent.

The costs to manage the rising water production are substantial and projected to increase into

the future. At the various water injection sites, clusters of horizontal injection wells are drilled

around a single vertical injection well, and pump capacity is designed based on the expected

water production in the area. If additional capacity is required due to higher than planned water

production, more pumping capacity is installed rather than the drilling of additional wells. Wells

are planned to dispose of 45,000 bwpd, but are capable of disposing of up to 70,000 bwpd.

Produced water is fresh with essentially no contaminants, and the continued disposal of 300,000

bwpd into the nearby river is expected.

Expenses - Operating Costs

The operating cost history for the past several years for the Rubiales field has been provided by

Meta. The cost schedules have been reviewed by RPS, compared with historical costs and

deemed to be reasonable.

In the year-end 2009 report, direct lifting costs were forecast to reach $3.75 per barrel of oil in

December 2009 and average $4.00 per barrel in 2010. Concurrent with oil production increases

of over 230 percent since 2008, direct lifting costs have decreased from $5.20 per barrel in 2008


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to $3.20 per barrel in 2010, a decrease of over 38 percent for the two-year period. Direct lifting

costs for 2011 are estimated to be $3.20 per barrel.

The monthly direct costs in 2010 from January through November steadily increased as

produced volume increased from 3.4 to 4.1 million barrels of oil per month. In November the

operating cost was $14.5 million, or $3.56 per barrel. The forecast generated by RPS for this

analysis indicates an average 2011 production volume of 210,144 barrels of oil per day. As a

result, the total operating cost forecast for 2011 is $245,448,000 which is substantially above the

costs in the prior years.

The cost noted above was split at a 35% / 65% ratio between fixed and variable cost

components, respectively. The fixed cost of $85,907,000 that is shown on Table 9.4 represents

the annual operating cost that is independent of the well count or the production volume. To

reflect the growth in field facilities, the fixed cost was increased by five percent in 2012, followed

by no increase in 2013. The variable cost of $159,541,000 represents operating costs that will

vary with well count and production volume. The variable cost was split at a 35% / 65% ratio

between well count and production volume. Variable costs of $175,000 per well (based on the

average 2011 forecasted well count) and $1.35 per barrel (based on the estimated cost allocated

to the forecasted 2011 production) were determined. All operating costs were escalated at an

annual rate of two percent.

Additional variable costs are Metas overhead and administration, field inventory and IVA. These

costs were $0.26 per barrel for the period January through November 2010. They were added

to the variable cost of $1.35 to determine the total variable cost of $1.61 per barrel of produced

oil.

Expenses Naptha Purchase

The produced crude oil has 12.5 degree API gravity, and due to its high viscosity it does not

meet pipeline specifications. Naptha at 82 degree API gravity is trucked to the field and blended

with the crude oil to lower the viscosity. The blended oil has a minimum of 18.5 degree API

gravity, meets pipeline specifications and sells for a higher price than the unblended produced

crude oil. The oil that is transported by trucks and sold locally is heated in the trucks to reduce

its viscosity and is not blended with naptha.


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The required naptha volume is a function of the relative crude oil quality and produced volume

2010meta report rubiales-piriri final_rev

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