HyDROCARBON RESERVES Of MEXICO

Transcription

2009
Hydrocarbon
Reserves
of Mexico
January 1, 2009
LAS RESERVAS DE HIDROCARBUROS DE MÉXICO
1 DE ENERO DE 2009
PEMEX
www.pemex.com
2009
2009
2009
JANUARy 1, 2009
LAS RESERVAS DE HIDROCARBUROS DE MÉXICO
HyDROCARBON
RESERVES
Of MEXICO
1 DE ENERO DE 2009
PEMEX
 2009 Pemex Exploración y Producción
Copyrights reserved. No part of this publication may be reproduced,
stored or transmitted in any manner or by any electronic, chemical,
mechanical, optical, recording or photocopying means, for either
personal or professional use, without prior written authorization
from Pemex Exploración y Producción.
Contents
Page
Message from the Minister of Energy
v
Message from the General Director of Petróleos Mexicanos
xi
1 Introduction
1
2 Basic Definitions
2.1 Original Volume of Hydrocarbons in Place
2.2 Petroleum Resources
2.2.1 Original Volume of Total Hydrocarbons in Place
2.2.1.1 Original Volume of Undiscovered Hydrocarbons
2.2.1.2 Original Volume of Discovered Hydrocarbons
2.2.2 Prospective Resources
2.2.3 Contingent Resources
2.3 Reserves
2.3.1 Proved Reserves
2.3.1.1 Developed Reserves
2.3.1.2 Undeveloped Reserves
2.3.2 Non-proved Reserves
2.3.2.1 Probable Reserves
2.3.2.2 Possible Reserves
2.4 Oil Equivalent
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3 Prospective Resources as of January 1, 2009
3.1 Mexico’s Most Important Production Basins
3.2 Prospective Resources and Exploratory Strategy
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4 Estimation of Hydrocarbon Reserves as of January 1, 2009
4.1 Hydrocarbon Prices
4.2 Oil Equivalent
4.2.1 Gas Behavior at the PEP Handling and Transport Facilities
4.2.2 Gas Behavior in Processing Complexes
4.3 Remaining Total Reserves
4.3.1 Remaining Proved Reserves
4.3.1.1 Remaining Developed Proved Reserves
4.3.1.2 Undeveloped Proved Reserves
4.3.2 Probable Reserves
4.3.3 Possible Reserves
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5 Discoveries
5.1 Aggregate Results
5.2 Offshore Discoveries
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Contents
Page
5.3 Onshore Discoveries
5.4 Historical Trajectory of Discoveries
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74
6 Distribution of Hydrocarbon Reserves
6.1 Northeastern Offshore Region
6.1.1 Evolution of Original Volumes in Place
6.1.2 Evolution of Reserves
6.2 Southwestern Offshore Region
6.3 Northern Region
6.4 Southern Region
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104
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107
Abbreviations
115
Glossary
117
Statistical Appendix
Hydrocarbon Reserves as of January 1, 2009
Hydrocarbon Production
Distribution of Hydrocarbon Reserves as of January 1, 2009
Northeastern Offshore Region
Southwestern Offshore Region
Northern Region
Southern Region
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132
Message from the Minister of Energy
In an act of profound national impact, President Lázaro Cárdenas rescued the oil industry
for the benefit of the nation on March 18, 1938.
In 1939, Congress passed a Law declaring the inalienable and imprescriptible right of the
Mexican State over its hydrocarbons. In 1940, the concessions regimen was eliminated
and this power was vested solely in the State.
The expropriation of the oil industry triggered an innovative economic development
model that benefited Mexico’s industrialization. Petróleos Mexicanos played a key role
in the new national project: efficiently providing the energy required by the country to
fuel its growth, while being the driving force behind its industrial development.
The state-owned oil industry was consolidated in the 1940s and 1950s, concurrently
with the country’s industrialization. At that time there was a redefinition of the sector’s
energy policy based on the following core principles: conserving and wisely exploiting
oil resources; fully satisfying domestic demand for oil products; exporting only the surplus not required for the domestic market; contributing to public expenditure through
tax payments; ensuring the on-going training of oil workers and creating a collective
benefit wherever oil is exploited.
After more than 70 years since the expropriation of the oil industry, it was necessary to
redesign the nation oil industry model, in order to prepare it to meet new challenges.
In this regard, it is worth noting that over the period from 1980 to 2004, Petróleos Mexicanos’ oil production rose from 1.9 to 3.4 million barrels per day and it peaked in 2004.
Production has been falling off gradually since then, in line with the performance of the
Cantarell complex; daily crude oil production in 2008 was 2.8 million barrels, which is
similar to the level reported in 1982. This means that crude oil production dropped by
around 600,000 barrels per day over a period of just 4 years.
Added to the above, in the period from 2004 to 2007, the proved reserves replacement
rate averaged 35 percent. This figure is far below the 100 percent required to ensure
sustained production in the future.
The challenges facing the national oil industry can only be overcome if the need for an
in-depth change to the Mexican oil industry model is acknowledged, in order to make
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PEMEX the driving force of the economy once again. To this end, President Felipe Calderón
Hinojosa, with a clear sense of responsibility, presented a bill in 2008 to amend the legal
structure governing PEMEX. The main purpose of this bill was to update the regulatory
framework governing PEMEX and to bring it into line with the new conditions prevailing in Mexico and the changes in the oil industry over the last few years, in addition to
providing it with the tools required to regain long-term, sustainable production levels.
After a period of careful and responsible debate, Mexico’s Congress managed to reach
an agreement and passed laws making profound changes based on bills put forth by
diverse political parties, in addition to President Calderón’s proposals. This is the most
significant change in the national oil industry since 1938.
Besides modernizing the regulations applied to PEMEX in order to channel its management towards optimizing the company’s value, increasing its execution capacity and
efficiency levels and also to improve accountability, changes aimed at strengthening the
State’s capacity were also approved. These modifications enable the State to efficiently
exercise its role as an administrator of the country’s hydrocarbon reserves.
In this respect, Congress has given the Ministry of Energy the responsibility of leading,
defining and supervising energy policy. An important part of this managerial process is
the correct administration of Mexico’s hydrocarbons so as to provide long-term energy
sustainability.
In line with strengthening its powers, the new legal structure gives the Ministry of Energy
the responsibility of defining the oil and gas production platform, as well as the restitution policy for hydrocarbon reserves and the elements required to quantify and disclose
hydrocarbon reserves.
The announcement of hydrocarbon reserves is a transparent process in which Mexican
society is informed about the composition of the nation’s oil wealth. It is also an exercise
in the State’s rendering of accounts as it informs the public in greater detail about the
quantification of the resources belonging to the nation. This rendering of accounts satisfies the State’s obligations to correctly administer the country’s hydrocarbons.
The document released to the public for consideration lists the efforts made by PEMEX
in 2008 to increase the incorporation of reserves. Although it is evident that we have
vi
not reached the desired replacement levels, there has been significant progress and it
is clear that, with the new legal tools, it will be possible to accelerate the incorporation
of hydrocarbon reserves into the nation’s reserves, for the benefit of the country and
future generations.
I would now like to make a brief summary of this document’s conclusions and I invite
the reader to peruse it carefully in order to obtain detailed information about the results
of PEMEX’s activities in the exploration and discovery of reserves in 2008.
Total hydrocarbon reserves
As of January 1, 2009, total hydrocarbon reserves (3P), which correspond to the sum of
the proved, probable and possible reserves, amounted to 43,562.6 million barrels of oil
equivalent (MMboe).
1P Reserves
Proved reserves (1P) increased by 803 MMboe in 2007, which includes 182.8 MMboe as
a result of discoveries. 2008 was very positive because 1,041.6 MMboe were added, of
which 363.8 MMboe can be attributed to new discoveries. These figures for the incorporation of 1P reserves also cover developments, delimitation and revisions.
The most important discoveries were in the Southeastern Basins (335.2 MMboe) and the
gas-producing basins of Veracruz (21.3 MMboe) and Burgos (7.4 MMboe).
Noteworthy discoveries include the Tsimin-1 well, which made it possible to incorporate
117.7 MMboe of gas-condensate, as well as the Ayatsil-DL1 and Pit-DL1 wells, incorporating 157.1 MMboe of heavy oil and the Kambesah-1 well, with the incorporation of 20.0
MMboe in proved light oil reserves. All of these findings were in the offshore portion of
the Southeastern Basins.
Besides the 363.8 MMboe incorporated by discoveries, 677.8 MMboe were added through
delimitations, revisions and developments. Bearing these results in mind, as well as the
production of 1,451.1 MMboe in 2008, proved reserves decreased by 409.5 MMboe. This
means that the proved reserves as of January 1, 2009 were 14,307.7 MMboe, that is, a
reserve-production ratio of 9.9 years.
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On the other hand, it is very important to note that the proved reserves replacement rate
in 2008 (including discoveries, revisions, delimitations and developments) was 71.8 percent, which is twice the annual average reported over the period from 2004 to 2007.
2P Reserves
In 2008, 912.4 MMboe in 2P reserves were incorporated through discoveries, of which
548.6 MMboe correspond to probable reserves. Due to revisions, delimitations and
developments, 498.3 MMboe of 2P reserves were de-incorporated, which means a total
of 414.2 MMboe.
These results show that the 2P reserve-production ratio is 19.9 years. Said 2P reserves
are mostly located in Chicontepec and in the offshore and onshore parts of the Southeastern Basins.
3P Reserves
Exploration activities in 2008 led to the discovery of a highest volume of 3P reserves
since 1999 because 1,482.1 MMboe in 3P reserves were incorporated as new discoveries, which is the highest figure reached during the decade as from the adoption of the
international guidelines issued by the Society of Petroleum Engineers, the committees
of the World Petroleum Council and the American Association of Petroleum Geologists.
Concurrently, there was also the disincorporation of 951.2 MMboe through delimitations,
developments and revisions.
Considering the 1,482.1 MMboe were incorporated through new findings, production in
2008 of 1,451.1 MMboe and the disincorporation as a result of delimitations, developments and revisions of 951.2 MMboe, the 3P reserve-production ratio increased from
28.0 years in 2007 to 30.0 years in 2008.
As regards discoveries, there was the outstanding performance of the Ayatsil-DL1 and Pit-DL1
wells, which made it possible to incorporate 782.6 MMboe of 3P heavy oil reserves, as well
as the Tsimin-1 well with the inclusion of 307.6 MMboe in gas-condensate 3P reserves.
In general, this document shows that PEMEX is still making a major effort to increase the
incorporation of 3P reserves in various geological basins in Mexico. This is especially the
viii
case in the onshore and offshore portions of the Southeastern Basins, in water depths
of less than 500 meters.
Although the discoveries made in 2008 are the highest in the last 10 years, there is still a
long way to go to reach the goals established. As mentioned before, Mexico has abundant resources awaiting discovery and this document shows that we are moving in the
right direction. With the new legal structure passed by the Mexican Congress, we now
have the tools to make faster progress.
This Administration’s efforts and commitment to ensure transparency in the operation
of the oil industry and to assist in rendering accounts regarding the country’s strategic
resources, which are the wealth of all Mexicans, are ratified in this first report that is
jointly presented by the Ministry of Energy and Petróleos Mexicanos on hydrocarbon
reserves.
Mexico City March 2009
Dr. Georgina Kessel
Minister of Energy
ix
x
Message from the General Director
of Petróleos Mexicanos
The publication of Hydrocarbon Reserves of Mexico 2009 is particularly symbolic and
important. It has numerous operational implications for Petróleos Mexicanos and it reports
on the progress made in its institutional strategy.
First, it is a reassertion of the company’s commitment with transparency and accountability. Counting this year, it is an exercise that has been carried out systematically for 11
years. Through this publication, the company informs the authorities and public about
the progress made in the administration and management of the natural resources
entrusted to it for their sustainable exploitation. Hydrocarbon Reserves of Mexico 2009
is yet another way in which the company renders accounts, along with other voluntary
reports, such as the Annual Report, Statistical Yearbook and its Social Responsibility
Report, among others.
Second, this edition confirms that the decision made in 1997 to start this audited record
of reserves and its dissemination was indeed ahead of its time. At that time, when just
a few companies were starting to do this, Pemex took the lead by having a third party
review and certify the reserve calculations, which greatly increased the value and credibility of the corresponding estimates.
Third, it was also decided to create a group that was independent of the company, not
connected with the exploration and production areas, and which would be in charge of
the correct application of the definition of reserves, integrating the statistics and then
submitting them to an external validation process. This implied Petróleos Mexicanos’
adopting international “best practices” in order to minimize, if not avoid, a potential
conflict of interests when estimating the reserves.
Fourth, the contribution of sound reserves calculations and their certification by external
third parties was just as important inside Pemex. The systematic and detailed estimation of reserves instilled discipline in the organization by evidencing the implications of
such in exploration and production activities for the decision-making process and also
to establish the corresponding responsibilities.
The fact that for more than a decade it is known that Petróleos Mexicanos will annually
and publically render accounts about how a nonrenewable resource like hydrocarbons
has been exploited and replaced has greatly spurred responsibility within the organization. The results reported in this publication reflect on everybody working at Petróleos
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Mexicanos, sometimes as a source of satisfaction and sometimes as motivation to improve performance.
Fifth, the strict and externally certified accounting of the status of the country’s hydrocarbon reserves has been an essential element in aligning production and exploration
activities. Today’s production goals are inextricably tied to the capacity of the business
units regarding reserves, which in turn becomes a fundamental consideration for exploration strategy.
This is a response to the instruction given by the Mexican President, Felipe Calderón
Hinojosa to Petróleos Mexicanos to “guarantee oil reserves that make it possible for oil
and gas production to play a constant and long-term role”1.
Sixth, Pemex Exploración y Producción has been using a new exploratory strategy with
an integral approach –evaluation of potential reserves, incorporation of reserves and
delimitation of reservoirs– since 2007. Pemex’ portfolio now consists of 22 exploration
projects in 14 priority sectors, as well as the continuation and expansion of non-associated
gas projects. Since 86 percent of the prospective resources are in the Southeastern and
in deep waters of the Gulf of Mexico, the development of a strategy to execute projects
in these regions is essential in order to ensure viability in the country’s future.
Seventh, the results indicate that Petróleos Mexicanos is on the way to replacing at least
1 billion barrels of oil equivalent every year, which is something few companies can
aspire to. When the results are maintained and improved, it will be possible to reach the
goal of replacing 3P reserves at an annual rate of 100 percent. Nevertheless, the volume
of potential reserves still has to be increased to 1.4-1.5 billion barrels of oil equivalent
per year.
Eighth, the above will only be possible when the current strategy makes it possible to
substantially expand the portfolio of quality exploratory opportunities. This calls for
continuity in the exploratory drive, as well as the allocation of sufficient human, technical and financial resources to achieve this goal, especially in the more promising basins
(Gulf of Mexico Deepwater) where there is not yet sufficient equipment. The new forms
1. As stated by Felipe Calderón Hinojosa, the President of Mexico, during the event to commemorate the Oil
Expropriation on March 18, 2009.
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of contracting established in the energy reform will permit an increase in exploratory
activity in these basins.
Ninth, for Petróleos Mexicanos it is essential to continue improving quality when quantifying reserves, which, as from next year, will be subject to new controls imposed by
the National Hydrocarbon Commission that will carry out studies to “assess, quantify
and verify” reserves and the Ministry of Energy which will have the new responsibility
of “recording and disclosing (reserves) in accordance with evaluation and quantification
studies, as well as the corresponding certifications”.
Tenth, the incorporations made over 2008 underline the importance of diversification
because they were reported both onshore and offshore.
The results of incorporating reserves in 2008 are a cause for satisfaction for Petróleos
Mexicanos and a stimulus to intensify the corresponding efforts. Last year, 1,482 million
barrels of oil equivalent were added to the total reserves (3P), while 1,042 million barrels
of oil equivalent were incorporated to the proved reserves (1P). As stated by the President of Mexico, Felipe Calderón Hinojosa, on March 18, 2009: “The discovery of new
reservoirs, the incorporation of new reserves and an increase in their replacement rate,
102 percent for total reserves and 72 percent in proved reserves, are undoubtedly good
news for Mexico. This is a major accomplishment by the Pemex work force.”
In essence, the energy reform is a vote of confidence by Mexican society in Petróleos
Mexicanos. In turn, it requires better operational and financial results, as well as more
transparency and account rendering in this activity. The publication of Hydrocarbon
Reserves of Mexico 2009 is a step in this direction, not only because it refers to specific
results, but it also means that Pemex will reassert its commitment with this vote of confidence with deeds.
Mexico City March 2009
Dr. Jesús Reyes Heroles G.G.
General Director of Petróleos Mexicanos
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Hydrocarbon Reserves of Mexico
Introduction
This edition of Mexico’s Hydrocarbon Reserves, Evaluation as of January 1, 2009, includes a description of
prospective (potential) reserves estimated, as well as
the hydrocarbon volumes and reserves concentrated
in Mexico’s oil fields.
The second chapter describes the definitions used
in this publication such as original volume of hydrocarbons in place, petroleum resources, prospective
resources, contingent resources and reserves. The
reserves section lists the most important elements
used to estimate hydrocarbon reserves at Petróleos
Mexicanos, in accordance with the guidelines issued
by the Securities and Exchange Commission (SEC)
for proved reserves and also those used by Society
of Petroleum Engineers (SPE), the World Petroleum
Council (WPC) and the American Association of
Petroleum Geologists (AAPG) for probable and possible reserves. This chapter also briefly explains the
criteria that must be satisfied for a reserve to be classified as proved, probable or possible. The meaning
of the term “oil equivalent”, its use and value in the
total inventory of hydrocarbons, is given at the end
of the chapter.
Chapter 3 shows the evaluation of prospective resources estimated as of January 1, 2009. Their geographic location, extension, general geological characteristics and distribution by basin are also given.
1
Chapter four analyzes the variations in reserves over
2008, as well as their distribution by region according
to the category and hydrocarbon type. The variations in
developed proved, undeveloped proved, probable and
possible reserves are reviewed in reference to reserve
categories. In terms of composition, the analysis is
made by oil type according to its density, that is, light,
heavy and superlight, and in the case of gas reservoirs,
the analysis is made by considering both the associated
and the non-associated gas. The latter is broken down
in terms of dry gas, wet gas and gas-condensate.
The discoveries made in 2008 are given in chapter
five. There is a description of the most important
geological and engineering characteristics of the
reservoirs discovered, together with the associated
reserves in the different categories, at both a regional
and basin level.
Chapter six shows the evolution of hydrocarbon
volumes and reserves in their different categories
in 2008; additionally, their distribution at a regional,
business unit and field level is established. There is a
detailed analysis of the oil, natural gas and oil equivalent reserves, with their evolution in various categories
and a review of the changes they underwent in 2008.
Furthermore, the origin of the changes and their association with discoveries, revisions, development or
production in the period is emphasized.
1
Introduction
2
Basic Definitions
Petróleos Mexicanos uses the definitions and concepts that are based on the guidelines established
by international organizations for the annual updating
of the country’s hydrocarbon reserves. In the case of
proved reserves, the definitions correspond to those
established by the Securities and Exchange Commission (SEC), a US body that regulates America’s
securities and financial markets, while the definitions
established by the Society of Petroleum Engineers
(SPE), the American Association of Petroleum Geologists (AAPG), and the World Petroleum Council (WPC),
technical organizations in which Mexico participates,
are used for the probable and possible reserves.
The establishment of processes to evaluate and classify hydrocarbon reserves according to internationally-used definitions ensures certainty and transparency
in the volume of reserves reported, as well as in the
procedures used in estimating them. Additionally,
the decision made by Petróleos Mexicanos to use
recognized external consultants for the annual certification of its reserves, adds reliability to the figures
reported.
2
The exploitation of reserves requires investment in
well drilling, undertaking major workovers, the construction of infrastructure and other elements. Thus,
the estimation of reserves considers these elements
in order to determine their economic value. If it is
positive, the hydrocarbon volumes are commercially
exploitable, and therefore they constitute reserves.
If this is not the case, these volumes may be classified as possible if they are marginal, that is, if a slight
change in hydrocarbons prices, or a minor decrease
in development or operation and maintenance costs
makes their economic evaluation positive. If this is
not the case either, these volumes are classified as
contingent resources.
This chapter also establishes the criteria to classify
reserves, it explains the definitions and concepts used
throughout this document, it stresses relevant aspects
and in all cases it indicates the dominant elements,
and clearly explains the implications of using these
definitions in estimating reserves.
2.1 Original Volume of Hydrocarbons in Place
The reserves represent an economic value associated with investments, operation and maintenance
costs, production forecasts and the sales price of
hydrocarbons. The prices used to estimate reserves
correspond to December 31, 2008, while the fixed
and variable components of the operation and maintenance costs are those disbursed at a field level over
a period of 12 months. This premise makes it possible
to determine the seasonal nature of such expenditure,
and it is an acceptable measure of future expenses
for the extraction of reserves under current exploitation conditions.
The original volume of hydrocarbons in place is defined as the amount estimated to have initially existed
in a reservoir. This volume is in equilibrium, at the
temperature and pressure prevailing in the reservoir,
and it is expressed at these conditions and also at
atmospheric conditions. The figures published in this
document therefore refer to these latter conditions.
The volume may be estimated through deterministic
and probabilistic procedures. The former mainly
includes volumetric, material balance and numerical
3
Basic Definitions
iii. Reservoir fluids identified, as well as their respective properties, in order to estimate hydrocarbon
volumes at atmospheric conditions, which are also
known as surface, standard or base conditions.
simulation methods. The latter models the uncertainty
of parameters such as porosity, water saturation, net
thickness, among others, as probability functions that
consequently generate a probability function for the
original volume.
The original volumes of both crude oil and natural
gas are given at a regional and business unit level in
the Statistical Appendix of this document. The units
in the former are in millions of barrels and in billions
of cubic feet for the latter; all of which are referred to
at atmospheric conditions, which are also known as
standard, base or surface conditions.
Volumetric methods are the most used in the initial
stages, in which knowledge is being obtained about
the field or reservoir. These techniques are based
on the estimation of the petrophysical properties of
the porous rock and the fluids in the reservoir. The
most commonly used petrophysical properties are
essentially porosity, permeability, fluid saturation and
the shale volume. The geometry of the reservoir is
another fundamental element that is represented in
terms of area and net thickness.
2.2. Petroleum Resources
Petroleum resources are all the volumes of hydrocarbons initially estimated in the subsurface and referred
to at atmospheric conditions. Nevertheless, from the
exploitation point of view, only the potentially recoverable portion of this amount is called a resource.
Within this definition, the amounts estimated at the
beginning are known as the original total volume of
hydrocarbons, which may or may not be discovered.
Additionally, the recoverable portions are known
The following points stand out among the information
necessary in order to estimate the original volume
in place:
i. Rock volume impregnated with hydrocarbons.
ii. Effective porosity and hydrocarbon saturation associated with the above volume.
Original Volume of Total Hydrocarbons in Place
Original Volume of Discovered Hydrocarbons
Range of Uncertainty
Original Volume of Undiscovered
Hydrocarbons
NonRecoverable
P
r
o
s
p
e
c
t
i
v
e
R
e
s
o
u
r
c
e
s
Non-Economic
Low
Estimate
Central
Estimate
High
Estimate
NonRecoverable
C
o
n
t
i
n
g
e
n
t
Economic
Proved
R
e
s
o
u
r
c
e
s
1C
2C
3C
R
e
s
e
r
v
e
s
1P
Probable
2P
Possible
3P
P
r
o
d
u
c
t
i
o
n
Increasing Chance of Commerciality
Figure 2.1 Classification of hydrocarbon resources and reserves (not to scale). Modified from Petroleum Resources Management System, Society of Petroleum Engineers, 2007.
4
as prospective resources, contingent resources
or reserves. In particular, the concept of reserves
constitutes a part of the resources, that is, they are
known, recoverable and commercially exploitable
accumulations.
as non-recoverable may eventually become recoverable resources if, for example, the commercial conditions change, or if new technologies are developed,
or if additional data are acquired.
Figure 2.1 shows the classification of resources and
it also includes the reserve categories. It can be seen
that there are low, central and high estimates for
both resources and reserves, which are classified as
proved, proved plus probable and proved plus probable plus possible, for each one of the three above
estimates, respectively. The degree of uncertainty
that is shown to the left of this figure emphasizes the
fact that the knowledge available on resources and
reserves is imperfect and therefore different estimates
obeying different expectations are generated. Production, which appears on the right, is the only element
of the figure where there is absolutely no uncertainty:
it has been measured, commercialized and turned
into revenues.
2.2.1.1 Original Volume of Undiscovered Hydrocarbons
2.2.1 Original Volume of Total Hydrocarbons in
Place
According to Figure 2.1, the original volume of total
hydrocarbons in place is the quantification referring
to reservoir conditions of all the natural hydrocarbon
accumulations. This volume includes discovered
accumulations, which may or may not be economic
or recoverable, the production obtained from the
fields exploited or being exploited, in addition to the
volumes estimated in the reservoirs that might be
discovered.
All the amounts that make up the total hydrocarbon
volumes in place may be potentially recoverable resources because the estimation of the portion that is
expected to be recovered depends on the associated
uncertainty, and also on the economic circumstances,
the technology used, and the availability of information. Consequently, a portion of the amounts classified
This is the amount of hydrocarbons estimated at a
given date contained in accumulations not yet discovered, but which have been inferred. The estimate
of the potentially recoverable portion of the original
volume of undiscovered hydrocarbons is defined as
a prospective resource.
2.2.1.2 Original Volume of Discovered Hydrocarbons
This is the amount of hydrocarbons estimated at a
given date to be contained in known accumulations
before production. The discovered original volume may be classified as either commercial or not
commercial. An accumulation is commercial when
there is a generation of economic value as a result
of exploiting the hydrocarbons. Figure 2.1 shows
the recoverable part of the discovered hydrocarbon original volume, and it is labeled a reserve or
contingent resources, depending on its commercial
viability.
2.2.2 Prospective Resources
This is the volume of hydrocarbons estimated at a
given date of accumulations not yet discovered, but
which have been inferred, and which are estimated
as potentially recoverable through the application of
future development projects. The quantification of
prospective resources is based on geological and
geophysical information of the area being studied,
and on analogies with areas where a certain original
5
Basic Definitions
volume of hydrocarbons has been discovered, and
on occasion, even produced. Prospective resources
have equal chances of being discovered or developed; additionally, they are subdivided according to
the level of certainty associated with recovery estimates, assuming their discovery and development,
and they may also be sub-classified on the basis of
project maturity.
2.2.3 Contingent Resources
These are the volumes of hydrocarbons estimated at
a given date to be potentially recoverable from known
accumulations, but the project(s) applied is/are not
yet considered sufficiently mature for commercial
development, for one or more reasons. The contingent resources may include, for example, projects
for which there is no current viable market, or where
commercial recovery of hydrocarbons depends on
developing technologies, or where the evaluation
of the accumulation is insufficient to clearly assess
the commercial value. Contingent resources are also
categorized according to the level of certainty associated with estimates and they may be sub-classified
on the basis of project maturity and characterized by
their economic status.
tion status. The certainty essentially depends on the
amount and quality of the geological, geophysical,
petrophysical and engineering information, as well as
the availability of this information when making the
estimation and interpretation. The degree of certainty
may be used to place the reserves in one of the two
major classifications; proved or non-proved. Figure
2.2 shows the classification of the reserves.
The estimated recoverable amounts of known accumulations that do not satisfy commercialization
requirements must be classified as contingent
resources. The concept of commercialization for
an accumulation varies according to the specific
conditions and circumstances of each place. Thus,
proved reserves are accumulations of hydrocarbons
whose profitability has been established under the
economic conditions of the date of evaluation, while
probable and possible reserves may be based on
future economic conditions. Nevertheless, Petróleos
Mexicanos’ probable reserves are profitable under
current economic conditions, while a small part of
the possible reserves is marginal in that a slight
increase in the price of hydrocarbons, or a slight
decrease in operation costs would give them net
profitability.
Original Reserve
(Economic Resource)
2.3 Reserves
Reserves are the volumes of hydrocarbons that are
expected to be commercially recovered through
the application of development projects of known
accumulations, from a certain date onwards, under
defined conditions. Reserves must also satisfy four
other criteria: they must be discovered, recoverable,
commercially viable and be supported (on the date
of the evaluation) by other development projects.
Reserves are also categorized according to the level
of certainty associated with estimates and they may
be sub-classified on the basis of project maturity
and characterized by their development and produc6
Non-Proved
Reserves
Proved Original
Reserves
Accumulated
Production
Developed
Proved
Reserves
Probable
Reserves
Possible
Reserves
Undeveloped
Figure 2.2 Classification of hydrocarbon reserves.
2.3.1 Proved Reserves
Proved hydrocarbon reserves are estimated amounts
of crude oil, natural gas and natural gas liquids, which
through geological and engineering data, show with
reasonable certainty that they are recoverable in
future years, from known reservoirs under current
economic and operation conditions, and at a given
date. Proved reserves may be classified as developed
or undeveloped.
The determination of reasonable certainty is supported by geological and engineering data. Consequently,
there must be data available that justify the parameters used in the evaluation of the reserves, such as
initial and declining production, recovery factors,
reservoir limits, recovery mechanisms and volumetric
estimations, gas-oil ratios or liquid yields.
The current economic and operation conditions include prices, operation costs, production methods, recovery techniques, transport, and commercialization
arrangements. There must be reasonable certainty
that a predicted change in conditions will happen for
the corresponding investment and operation costs to
be included in the economic feasibility study in the
appropriate time span. These conditions include an
estimate of the well abandonment costs that would
be incurred.
The SEC establishes that the sales price of crude
oil, natural gas and natural gas products to be used
in the economic evaluation of the proved reserves
must correspond to December 31. The justification
is based on the fact that this method is required for
consistency among all international producers in their
estimates as a standardized measure when analyzing
project profitability.
In general, reserves are considered as proved if the
commercial productivity of the reservoir is supported
by actual data or by conclusive production tests. In
this context, the term proved refers to the amounts of
recoverable hydrocarbons and not the productivity of
the well or reservoir. In certain cases, proved reserves
may be assigned in accordance with the well logs and
core analysis records, which show that the reservoir
being studied is impregnated with hydrocarbons and
it is analogous to producing reservoirs in the same
area or to reservoirs that have shown commercial
production in other areas. Nevertheless, an important
requirement in classifying the reserves as proved is to
ensure that the commercialization facilities do actually
exist, or that it is certain they will be installed.
The volume considered as proved includes the
volume delimited by drilling activity and by fluid
contacts. Furthermore, it includes the non-drilled
portions of the reservoir that could reasonably be
judged as commercially productive, according to the
geological and engineering information available. If
the fluid contact level is unknown, then the deepest
known occurrence of hydrocarbons controls the limit
of proved reserve.
It is important to mention that the reserves to be
produced by means of applying secondary and/or enhanced recovery methods are included in the category
of proved reserves when there is a successful result
based on a representative pilot test, or when there is a
favorable response to a recovery process operating in
the same reservoir or in another analogous reservoir
in terms of age, rock and fluid properties, when such
methods have been effectively tested in the area and
in the same formation, and which provide documentary evidence for the technical feasibility study on
which the project is based.
Proved reserves provide the production and have a
higher degree of certainty than the probable and possible reserves. From the financial point of view, they
support the investment projects, hence the importance of adopting the definitions issued by the SEC. It
should be mentioned and emphasized that for clastic
sedimentary environments, that is, sandy deposits,
the application of these definitions considers as a
7
Basic Definitions
prove of the continuity of the oil column, not only the
integration of the geological, petrophysical, geophysical and reservoir engineering information, among
other elements, but also the measuring of inter-well
pressure, which is absolutely decisive. These definitions acknowledge that if there is reservoir faulting,
each sector or block must be evaluated independently
considering the information available; consequently,
in order to consider one of the blocks as proved,
there must be a well with a stabilized production test,
with an oil flow that is commercially viable according
to the development, operation, oil price and facility
conditions prevailing at the time of the evaluation. In
the case of minor faulting, however, the SEC definitions establish that the conclusive demonstration of
the continuity of the hydrocarbon column may only
be reached by means of above-mentioned pressure
measurements. In the absence of such measurements
or tests, the reserve that may be classified as proved is
the one associated with producing wells on the date of
evaluation, plus the production associated with wells
to be drilled in the immediate vicinity.
2.3.1.1 Developed Reserves
Reserves that are expected to be recovered in existing
wells, including reserves behind casing, that may be
extracted with the current infrastructure through additional activities with moderate investment costs. In
the case of reserves associated with secondary and/
or enhanced recovery processes, said reserves will be
regarded as developed only when the infrastructure
required for the process is installed or when the costs
implied in doing so are considerably lower and the
production response is as predicted in the planning
of the corresponding project.
2.3.1.2 Undeveloped Reserves
These are reserves with an expected recovery
through new wells in un-drilled areas, or where a
8
relatively large expenditure is required to complete
the existing wells and/or construct the facilities to
commence production and transport. The above applies to both the primary, secondary and enhanced
recovery processes. In the case of fluid injection
into the reservoir, or other enhanced recovery techniques, the associated reserves will be considered
as undeveloped proved when such techniques have
been effectively tested in the area and in the same
formation. Additionally, there must be a commitment
to develop the field according to an approved exploitation and budget plan. An excessively long delay in
the development program could give rise to doubts
about the exploitation of such reserves and lead to the
exclusion of such volumes from the proved reserve
category. As can be noted, an interest in producing
such volumes of reserves is a requirement to call
them undeveloped proved reserves. If this condition
is not satisfied on repeated occasions, it is common
to reclassify these reserves to a category in which
their development in the immediate future is not
considered; for example, probable reserves. Thus,
the certainty regarding the occurrence of subsurface
hydrocarbon volumes must be accompanied by the
certainty of developing them within a reasonable
period of time. If this condition is not satisfied, the
reserves are reclassified because of the uncertainty
regarding their development and not because of
doubts about the volume of hydrocarbons.
2.3.2 Non-proved Reserves
They are the volumes of hydrocarbons evaluated at
atmospheric conditions, resulting from the extrapolation of the characteristics and parameters of the
reservoir beyond the limits of reasonable certainty,
or from assuming oil and gas forecasts with technical
and economic scenarios other than those prevailing at the time of the evaluation. In non-immediate
development situations, the discovered volumes of
commercially producible hydrocarbons may well be
classified as non-proved reserves.
2.3.2.1 Probable Reserves
These are the non-proved reserves where the analysis of geological and engineering information of the
reservoirs suggests there is greater feasibility for
commercial recovery than the contrary. If probabilistic
methods are used for their evaluation, there is the
chance that at least 50 percent of the amounts to be
recovered are equal to or greater than the total of the
proved plus probable reserves.
Probable reserves include those volumes beyond the
proved volume, where the knowledge of the producing horizon is insufficient to classify these reserves as
proved. This classification also includes those reserves
in formations that seem to be producers and are inferred through well logs, but which lack core data or
definitive production tests, besides not being analogous with proved formations in other reservoirs.
In reference to secondary and/or enhance recovery
processes, the reserves suitable for these processes
are probable when a project or pilot test has been
planned but has not yet been implemented, and when
the characteristics of the reservoir seem favorable for
a commercial application.
The following conditions lead to the classification of
such reserves as probable:
i. Reserves located in areas where the producing
formation appears to be separated by geological faults, and the corresponding interpretation
indicates that this volume is in a higher structural
position than the one of the area corresponding
to proved reserve.
ii. Reserves eligible for future workovers, stimulations, equipment change or other mechanical
procedures, when such measures have not been
successfully applied in wells that exhibit similar
behavior and have been completed in analogous
reservoirs.
iii. Incremental reserves in producing formations
where a reinterpretation of the behavior or the
volumetric data indicates the existence of reserves,
in addition to those classified as proved.
iv. Additional reserves associated with infill wells,
and which would have been classified as proved
if development with less spacing at the time of
evaluation had been authorized.
2.3.2.2 Possible Reserves
These are hydrocarbon volumes whose geological
and engineering information suggest that commercial
recovery is less certain than in the case of probable
reserves. According to this definition, when probabilistic methods are used, the total of the proved plus
probable plus possible reserves will have a probability
of at least 10 percent that the amounts actually recovered will be the same or greater. In general, possible
reserves may include the following cases:
i. Reserves based on geological interpretations and
which may exist in areas adjacent to the areas classified as probable and within the same reservoir.
ii. Reserves in formations that seem to be impregnated with hydrocarbons, based on core analyses
and well logs.
iii. Additional reserves from intermediate drilling that
are subject to technical uncertainty.
iv. Incremental reserves attributable to enhanced recovery mechanisms when a project or pilot test is
planned but not in operation, and the characteristics
of the reservoir’s rock and fluid are such that there is
doubt about whether the project will be executed.
v. Reserves in an area of the producing formation
that seem to be separated from the tested area
by geological faults, and where the interpretation
9
Basic Definitions
Sweet Wet Gas
isf
Flaring
Natural
Gas
plsf
Self-Consumption
hesf
Compressor
Gas to be delivered to
processing complexes
Dry
Gas
cedglf
Dry Gas
Equivalent
to Liquid
tlsf
Sweetening
Plant
Cryogenic
Plant
plrf
Plant
Liquids
Oil
Equivalent
Sulfur
crf
Condensate
Crude Oil
Figure 2.3 Elements to calculate oil equivalent.
indicates that the study area is structurally lower
than the tested area.
2.4 Oil Equivalent
Oil equivalent is the internationally-used method of
reporting the total hydrocarbon inventory. This value
is the result of the addition of the crude oil volumes,
condensates, plant liquids and dry gas equivalent to
liquid. The latter corresponds, in terms of heat value
power, to a certain volume of crude oil. The dry gas
considered in this procedure is an average mix of
dry gas produced in the Cactus, Ciudad Pemex and
Nuevo Pemex processing complexes, while the crude
oil considered equivalent to this gas corresponds to
the Maya type. This evaluation requires updated information on the processes to which the natural gas
is subjected, from its separation and measurement to
its exit from petrochemical plants. Figure 2.3 shows
the elements used to calculate oil equivalent.
Crude oil does not undergo any change to become
oil equivalent. Natural gas, however, is produced and
its volume is reduced by self-consumption and flaring. This reduction is known as fluid shrinkage and
10
it is called handling efficiency shrinkage factor, or
simply hesf. Gas transportation continues and there
is another volume alteration when it passes through
compression stations where the condensates are
extracted from the gas; this alteration in volume is
called transport liquefiables shrinkage factor, tlsf.
The condensate is therefore directly accounted as
oil equivalent.
The gas process continues inside the petrochemical
plants where it is subject to various treatments that
eliminate non-hydrocarbon compounds and where
liquefiables and plant liquids are extracted. This
additional reduction in the volume of gas is conceptualized through the impurities shrinkage factor, or
isf, and by the plant liquefiables shrinkage factor,
plsf. Given their nature, the plant liquids are added
as oil equivalent, while the dry gas obtained at the
plant outlet becomes a liquid with an equivalence
of 5.201 thousand cubic feet of dry gas per barrel of
oil equivalent. This value is the result of considering
5.591 million BTU per barrel of crude oil and 1,075
BTU per cubic foot of sweet dry gas as calorific
equivalents. Consequently, the factor mentioned is
192.27 barrels per million cubic feet, or the opposite
given by the aforementioned value.
3
Prospective Resources
as of January 1, 2009
and Gulf of Mexico Deepwater basins stand out
with 88.3 percent of the country’s total prospective
resources.
Mexico’s prospective resources and their distribution
in the most important producing basins are listed in
this chapter. Petróleos Mexicanos has continued and
intensified its exploratory activities on the coastal
plain, the continental shelf and in the deep waters of
the Gulf of Mexico, where the acquisition and interpretation of geological and geophysical information
have made it possible to estimate the magnitude of
Mexico’s oil potential.
The prospective resources are used to define the
exploratory strategy and thus program the physical
and investment activities aimed at discovering new
hydrocarbon reserves, which would make it possible
to replace the reserves of the currently producing
fields and to provide medium- and long-term sustainability for the organization.
Consequently, this potential resource, also known
as a prospective resource, amounted to a volume of
52,300 million barrels of oil equivalent as of January
1, 2009. The distribution of prospective resources
is described in Figure 3.1, where the Southeastern
In this context, the exploratory strategy is focused on
the Southeastern and Gulf of Mexico Deepwater basins, mostly in the search for oil, while in the Sabinas,
Producer Basins
N
Crude Oil and Associated Gas
W
Non-associated Gas
E
S
1
2
6
Prospective
Resource
Bboe
1. Sabinas
3.1
3. Tampico-Misantla
1.7
4. Veracruz
0.7
5. Southeastern
16.7
6. Gulf of Mexico Deepwater
29.5
7. Yucatan Shelf
7
0.3
2. Burgos
Total
3
4
5
0.3
52.3
0
100 200 300 400 500 Km
Figure 3.1 Distribution of Mexico’s prospective resources.
11
Geologically, the Sabinas Mesozoic Basin corresponds
to an intracratonic basin formed by three paleoelements; the Tamaulipas paleopeninsula, the Coahuila
paleoisland and the Sabinas Basin.
Burgos and Veracruz basins, the effort is still centered
on discovering new fields of non-associated gas.
3.1 Mexico’s Most Important Production Basins
Five fracturing patterns have been identified in the
Sabinas Basin associated with compressive forces,
of which only two are considered important for the
generation of naturally fractured hydrocarbon reservoirs and they are: a) Fractures as a result of the compression, parallel to the direction of the dipping layer
extending along great distances, laterally as wells as
vertically, b) Fractures due to extension, perpendicular
to the fold axis, Figure 3.2.
Sabinas Basin
Oil exploration in the basin was initiated by foreign
companies in 1921 and later continued as a nationalized industry after 1938. The first discovery was made
in 1974 in the Monclova-Buena Suerte field with nonassociated gas production in Lower Cretaceous rock;
to date, four plays have been established, two in the
Upper Jurassic (La Gloria and La Casita) and two in the
Lower Cretaceous (Padilla and La Virgen), which have
produced 434 billion cubic feet of gas extracted from 23
fields discovered, 18 of which are active with a remaining
total reserve of 53 million barrels of oil equivalent.
102º
N
W
The total prospective resource of the Sabinas Basin
has been estimated at 300 million barrels of oil equivalent, of which 279 million barrels of oil equivalent have
been documented, which means 93 percent. Thus,
101º
E
S
100º
Salt Dome
A
USA
Anticline
28º
Inverse Fault
B
A
C
A
27º
D
Monclova
C
B
B
D
A
B
C
D
Salt Detachment
Basement Inverse Faulting
Smooth Folding
Domes and Salt Detachments
26º
Monterrey
Saltillo
Figure 3.2 Structural styles of the Sabinas Basin.
12
0
80 km
Table 3.1 Prospective resources documented in the Sabinas Basin by hydrocarbon type.
Hydrocarbon Type
Exploratory Wells Prospective Resources
number
MMboe
Dry Gas
Total
88
88
279
279
88 exploratory opportunities have been recorded;
the remaining 7 percent is still being documented,
Table 3.1.
forms part of the Río Bravo basin that regionally covers
the southeastern tip of Texas and the northern part of
the states of Tamaulipas and Nuevo León.
Burgos Basin
The Mesozoic geological structure of the Burgos
Basin corresponds to a shallow marine basin with
broad platforms, where there were deposits of sandstone, evaporites, limestone and shale starting from
the Upper Jurassic to the end of the Mesozoic. This
sedimentary carpet was lifted and folded to the west
of the basin in the Late Cretaceous as a result of the
Laramide Orogeny event that gave rise to the huge
structural folds of the Sierra Madre Oriental.
This basin was first explored in 1942 and production
commenced in 1945 with the discovery and development of the Misión field, near the city of Reynosa,
Tamaulipas. Since then, 227 fields have been discovered, of which 194 are currently active.
Reactivation of the basin commenced in 1994 with the
application of new work concepts and technologies
that made it possible to increase the average daily
production from 220 million cubic feet of natural gas
in 1994 to 1,383 billion cubic feet per day on average
in 2008, which means a cumulative production of
10,020 billion cubic feet. The remaining total reserves
amount to 910 million barrels of oil equivalent.
The Burgos Basin is defined by a powerful sedimentary
package of Mesozoic and Tertiary rocks accumulated
on the western margin of Gulf of Mexico. Geologically it
Múzquiz
Presa Falcón
Herreras
This rise was accompanied by the development of
basins parallel to the folded belt, including the Burgos
Basin to the front of the Sierra Madre Oriental, where
the paleoelements of the Tamaulipas peninsula and
Isla de San Carlos were the western limit of the depocenter, which operated as a reception center for a
large volume of tertiary sediments and where the limit
is established regarding the structural styles that acted
in the conformation of the Burgos Basin structural
framework, with normal listric growth faulting and
Camargo
Yegua
Reynosa
Miocene
Queen City
O. Vicksburg
O. Frío
O. Anáhuac
P. Midway
Figure 3.3 Schematic structural section of the Burgos Basin.
13
Table 3.2 Prospective resources documented in the Burgos Basin by hydrocarbon type.
Hydrocarbon Type
Exploratory Wells
number
Light Oil
MMboe
33
261
Dry Gas
107
Wet Gas
364
1,478
Total
504
2,000
and Arenque fields (the latter is offshore). Production
was established in the southern part of the basin in
1908 in the area which is now known as the Faja de
Oro, which, after the discovery of its southern and
offshore extensions has produced more than 1,500
million barrels of oil equivalent from calcareous reef
later reactivations of the terminal part of the Laramide
Orogeny at the end of the Oligocene.
The sequences of sandstone and shale environments
that vary from marginal to marine, prograded over
the edge of the Cretaceous platform and a Cenozoic
sedimentary column was deposited, that
is approximately 10,000 meters thick,
Figure 3.3.
261
N
W
Tamaulipas
Arch
The Burgos Basin has a total prospective
resource of 3,100 million barrels of oil
equivalent, of which 2,000 million barrels
have been documented, which means 65
percent of the potential recorded in 504
exploratory opportunities; the remaining
35 percent is still being documented,
Table 3.2.
E
S
TamaulipasConstituciones
Gulf of
Mexico
Arenque
Tampico
0
20
m
Ebano
Pánuco
Tampico-Misantla Basin
er
Faja de Oro
Atoll
ra
M
ad
re
rie
O
nt
al
14
Chicontepec
Si
The Tampico-Misantla Basin, with an area
of 50,000 square kilometers, including the
offshore portion, is Mexico’s oldest oilproducing basin. Activity began in 1904
with the discovery of the Ébano-Pánuco
province, which has produced more than
1,000 million barrels of heavy oil from the
calcareous rocks of the Late Cretaceous.
The basin also produces from the oolitic
limestones of the Upper Kimmeridgian
and chalk of the Lower Cretaceous in the
Tamaulipas-Constituciones, San Andrés
Poza Rica
San Andrés
0
100 km
Figure 3.4 Map of the Tampico-Misantla Basin showing the most
important areas.
Table 3.3 Prospective resources documented in the Tampico-Misantla Basin
by hydrocarbon type.
Hydrocarbon Type
Exploratory Wells Prospective Resources
number
MMboe
Heavy Oil
4
44
Light Oil
64
645
Dry Gas
50
434
Total
118
1,123
rocks of the Middle Cretaceous that surround the atoll
developed on the Tuxpan Platform. Bordering the Faja
de Oro fields, there is a second strip that produces from
rocks in the platform deposited as debris flows on the
reef slopes. The famous stratigraphic trap known as the
Poza Rica field, with a cumulative production of 1,731
million barrels of oil equivalent is the most important
accumulation within this play.
In this basin, the Paleocanal de Chicontepec covering
an area of 3,000 square kilometers was developed to
the west of the Faja de Oro, Figure 3.4. The paleocanal
is mostly made up of siliciclastic sediments of the
Paleocene and Eocene.
The Tampico-Misantla Basin reported an average production of 85,038 barrels of oil per day in December
2008, after having reached a maximum of 600,000
barrels per day in 1921. The remaining total reserves
are 18,497 million barrels of oil equivalent.
The Tampico-Misantla Basin has a total prospective
resource of 1,700 million barrels of oil equivalent,
of which 1,123 million barrels of oil equivalent have
been documented, this represents 66 percent of the
total recorded in 118 exploratory opportunities; the
remaining 34 percent is in the process of being documented, Table 3.3.
Veracruz Basin
The Veracruz Basin, Figure 3.5, is made up of two
well-defined geological units:
• The Córdoba Mesozoic Platform consisting of
Mesozoic calcareous rocks whose stratigraphy
is the result of processes related to relative sea
water level cycles and/or tectonic pulses. These
processes started to form limestone platforms
(Córdoba Platform) and associated basins (Veracruz Tertiary Basin) in the Lower Cretaceous that
constituted the fundamental stratigraphic domains
which began during the Mesozoic. The buried
structural front of the folded and faulted belt that
forms the Sierra Madre Oriental, also known as the
Córdoba Platform, is made up of limestones of the
Middle-Upper Cretaceous that produce middle to
heavy oil and sour wet gas.
• The Veracruz Tertiary Basin that is made up of by
Tertiary siliciclastic rocks was formed during the
Paleocene-Oligocene. The sedimentation comes
from igneous events (Alto de Santa Ana), metamorphic (La Mixtequita, Sierra Juárez and Macizo
de Chiapas), and carbonated (Córdoba Platform)
and correspond to an alternating sequence of
widely-distributed shale, sandstone and conglomerates (debris, fan and channel flows). The
sedimentary column includes the established
and hypothetical plays of the Paleogene and the
Neogene, ranging from a few dozen meters on the
western edge to more than 9,000 meters in the
depocenter. The Veracruz Tertiary Basin produces
dry gas in the Cocuite, Lizamba, Vistoso, Apertura,
Madera, Arquimia and Papán fields, and oil to a
lesser extent in the fields on the western edge
such as Perdíz-Mocarroca. Additionally, there is
15
N
W
673 Km²
E
S
Veracruz
181 Km²
Fo
ld e
d
st
ru
Th
Cocuite
lt
Be
3D Seismic
286 Km²
0
25 km
Tezonapa
2 1
Mata Pionche Field
Cocuite Field
Miocene-Pliocene
5
Lower Miocene
Paleocene-Eocene-Oligocene
10
Km
Figure 3.5 Subprovinces of the Veracruz Basin.
considerable hydrocarbon accumulation potential
in the areas geologically analogous to the areas
currently producing.
As a result of Pemex’s strategy focused on the search
for non-associated gas, the basin was reactivated
through an intense campaign of seismic acquisition
and exploratory drilling, which led to discoveries that
now make it Mexico’s second most important produc-
er of non-associated gas; with an average production
of 957 million cubic feet per day in 2008.
The remaining total reserves of the Veracruz Basin
amount to 265 million barrels of crude oil equivalent.
The Veracruz Basin has a total prospective resource
of 700 million barrels of oil equivalent, of which 571
million barrels have been documented, that is, 82
Table 3.4 Prospective resources documented in the Veracruz Basin by hydrocarbon type.
Hydrocarbon Type
16
Heavy Oil
Light Oil
Dry Gas
Wet Gas
Total
Exploratory Wells
number
6
9
203
19
237
MMboe
52
54
408
57
571
ments intruded by salt that produces light oils, mostly
from the plays that underlay, overlay or terminate
against the allochthonous salt of Jurassic origin.
percent of the potential recorded in 237 exploratory
opportunities; the remaining 18 percent is still being
documented, Table 3.4.
• The Macuspana province extends over approximately 13,800 square kilometers; it is a producer of
non-associated gas in reservoirs of the Tertiary age
formed by rain delta and platform sandstones, associated with stratigraphic and structural traps.
Southeastern Basins
The basins cover an area of 65,100 square kilometers,
including the offshore portion, Figure 3.6. Exploratory
jobs date back to 1905 when the Capoacán-1 and
San Cristóbal-1 wells were drilled. These basins have
been Mexico’s most important oil producers since the
1970s. They are made up of five provinces:
• The Chiapas-Tabasco-Comalcalco province was
discovered in 1972 with the Cactus-1 and Sitio
Grande-1 wells; it covers an area of 13,100 square
kilometers and it mostly produces light oil and its
reservoirs correspond to calcareous rocks of the
Upper Jurassic and Middle Cretaceous.
• The Sonda de Campeche includes an area of approximately 15,500 square kilometers and it is
by far the most prolific in Mexico. The Cantarell
complex forms part of this province, together with
the Ku-Maloob-Zaap complex, the area’s second
most important oil-producing field. Most of the reservoirs of the Sonda de Campeche lie in breccias
of the Upper Cretaceous to Lower Paleocene age,
and in oolitic limestones of the Upper Jurassic.
• The Salina del Istmo province, with an area of around
15,300 square kilometers is a pile of siliciclastic sedi-
• The Litoral de Tabasco province covers an area
of approximately 7,400 square kilometers. The
N
1,500 m
W
E
S
1,000 m
Gulf of
Mexico
Sonda de
Campeche
200 m
Litoral de
Tabasco
Salina del
Istmo
ChiapasTabascoComalcalco
Macuspana
Figure 3.6 Location of the Southeastern Basins.
17
Table 3.5 Prospective resources documented in the Southeastern Basins
by hydrocarbon type.
Hydrocarbon Type
Exploratory Wells
number
Heavy Oil
Light Oil
Superlight Oil
Dry Gas
Wet Gas
Total
reservoirs are fractured Cretaceous limestones
that mostly produce superlight oil.
The Southeastern Basins have a cumulative production of 40,685 million barrels of oil equivalent, and
remaining reserves of 23,290 million barrels of oil
equivalent. The total prospective resource is 16,700
million barrels of oil equivalent, of which 8,186 million barrels have been documented, which means 49
percent of the potential recorded in 629 exploratory
opportunities; the remaining 51 percent is in the process of being documented, Table 3.5.
Gulf of Mexico Deepwater Basin
This is the portion of the Gulf of Mexico Basin that is
at water depths exceeding 500 meters and it covers
an area of approximately 575,000 square kilometers.
Based on the information acquired so far, nine geological provinces distributed over three exploratory
projects have been identified: Golfo de México B,
Golfo de México Sur, and Área Perdido, Figure 3.7.
Some of the geological characteristics are:
• Perdido Folded Belt dipping under the allochthonous salt strip, a folded and faulted belt was formed
as a result of salt settlement and gravitational
displacement over the top of Jurassic salt cap that
involves the Mesozoic sequence. These structures
seem to be cored by salt and are elongated, very
big (more than 40 kilometers) and close together.
18
53
284
209
38
45
629
MMboe
1,076
3,508
2,648
297
657
8,186
This belt lies at water depths of 2,000 to 3,500 meters. Recently a consortium of various companies
drilled a well on the US side of the area known as
Alaminos Canyon in the northern protrusion of
the folded belt that, according to some sources,
found hydrocarbons. Oil is the hydrocarbon type
most expected, and the storage rocks would be
deepwater fractured limestone in the Mesozoic
column, and siliciclastic turbidities in the Tertiary.
• The Mexican Ridges province is characterized by
the presence of elongated folded structures, whose
axes lie north-south. The origin is related to gravity
slippage of the sedimentary cover. These structures
correspond to the southward extension of the Mexican Ridges folded belt, which are associated with a
regional uplift located in the Eocene clay sequence.
The most important potential hydrocarbons in the
sector are gas and possibly superlight oils.
• In the Saline province of Deep Gulf (Salina del Istmo Basin), the Mesozoic and Tertiary sedimentary
column has been highly affected by the presences
of large salt canopies and deep-rooted saline intrusions that cause deformation and in some cases
a rupture of the Mesozoic and Tertiary structures,
which played an active role in the sedimentation,
giving rise to the formation of mini-basins caused
by salt evacuation where the Pliocene sediments
are confined, which make it possible to reach
stratigraphic traps. This sector of the Salina del
Istmo Basin has lots of evidence supporting the
N
W
E
S
1
2 3
9
7
4
5
8
6
Geologic Provinces:
1. Rio Bravo Delta
2. Allochthonous Salt Strip
3. Perdido Folded Belt
4. Distensive Lane
5. Mexican Ridges
6. Saline Basin of Deep Gulf
7. Edge of Campeche
8. Veracruz Canyon
9. Abyssal Plain
0
100 200 300 400 500 Km
Figure 3.7 Geological provinces identified in the Gulf of Mexico Deepwater Basin.
presence of oil that is being squeezed up to the
seafloor through faults. This evidences lead to the
expectation of mostly light oil hydrocarbons in the
sector.
• The southern-eastern and eastern end of the area
contains part of the compressive tectonic front that
generated the most important producing structures
in the Sonda de Campeche (Reforma-Akal folded
belt), with a prevalence of low angle reverse faults
lying in a northwestern-southeastern direction and
whose transport direction is to the northeastern.
Furthermore, the Tertiary sedimentary cover in
this zone tends to be thinner, while the Mesozoic
structures are relative shallower, which means that
heavy oil is especially expected.
Well drilling started at the beginning of 2004 in the
Gulf of Mexico B project where eight exploratory wells
have been drilled to date, and the following have been
successful: Nab-1, extra-heavy oil producer and the
Noxal-1, Lakach-1 and Lalail-1 non-associated gas
wells, Figure 3.8. Jointly, these wells added a total
reserve of 548 million barrels of oil equivalent.
The prospective resources studies carried out in this
basin indicate that it has the highest oil potential, with
an estimated mean prospective resource of 29,500
19
Lakach-1
Noxal-1
Leek-1
Tabscoob-1
Pleistocene
Pliocene
Middle Miocene
Lower Miocene
Figure 3.8 Representative seismic section of the Lakach-Noxal area of the Gulf of Mexico.
million barrels of oil equivalent, which accounts for 56
percent of the country’s total, that is, 52,300 million
barrels of oil equivalent.
Of the total prospective resource estimated for this
basin, 7,222 million barrels of oil equivalent have been
documented and recorded in 126 exploratory opportunities, which means 24 percent of the potential;
the remaining 76 percent has yet to be documented,
Table 3.6.
Yucatan Platform
This province, with an approximate area of 130,000
square kilometers is formed by sediments developed
on a calcareous platform, where the geological-geophysical studies and the information of the subsoil have
made it possible to establish an active oil system; nevertheless, the prospective resource has been estimated
at 300 million barrels of oil equivalent, of which 271
million barrels of oil equivalent have been documented
with 16 heavy oil exploratory opportunities.
3.2 Prospective Resources and Exploratory Strategy
The knowledge currently available about the geographic distribution of Mexico’s prospective resources
has made it possible to direct the exploratory strategy
towards the search for oil, without neglecting the
search for non-associated gas in accordance with
the economic value and/or hydrocarbon volumes
estimated for all of the basins.
Exploratory activities will therefore be mostly focused
on the Southeastern Basins, which are traditional oil
producers, where oil production is expected to continue in the short and medium term. In the same period,
Table 3.6 Prospective resources documented in the Gulf of Mexico Deepwater Basin by hydrocarbon type.
Hydrocarbon Type
20
Heavy Oil
Light Oil
Dry Gas
Wet Gas
Total
Exploratory Wells
number
6
91
17
12
126
MMboe
289
5,143
607
1,183
7,222
the Burgos and Veracruz basins will make a sizeable
contribution to the production of non-associated gas.
Additionally, exploratory works have been programmed in the Gulf of Mexico Deepwater Basin
where the highest volumes of hydrocarbons are also
expected to be discovered, albeit with a higher risk
factor. Due to the above, it is estimated that the basin will make a significant contribution to oil and gas
production in the medium and long term.
In order to reach these production objectives, the
exploratory strategy considers the addition of an average prospective resource of 6,300 million barrels of
oil equivalent over the next five years, and to reach
a total reserves replacement rate of 100 percent by
the year 2012.
In this context, the exploratory drive will be aligned
with the following strategies in the next few years:
• Oil projects: focused on the Southeastern Basins
in order to add oil and gas reserves as of 2010 and
to intensify the exploration of the Gulf of Mexico
Deepwater Basin, without neglecting the rest of
the basins. This will support the activities aimed
at maintaining the current production platform and
reaching the reserve replacement goal.
• Gas projects: focused on maintaining the production platform for this kind of hydrocarbon and
helping reach the reserve replacement goals. The
activities will mostly be centered on the Burgos and
Veracruz basins. Furthermore, the development of
the non-associated gas reserves discovered in the
Holok area of the Gulf of Mexico Deepwater Basin
will be consolidated.
Reaching the above goals is based on the efficient
execution of the activities programmed, where the
acquisition of information, processing of seismic data
and the geological-geophysical interpretation will
make it possible to identify new opportunities and
generate exploratory locations, as well as to assess
the geological risk associated with these, and thus
strengthen the portfolio of exploratory projects.
Considerations
Given the nature of the exploratory projects, the
estimation of the prospective resources is an ongoing activity that calls for the incorporation of results
from exploratory wells drilled, and the geologicalgeophysical information acquired. Consequently,
the characterization of Mexico’s oil potential must
be updated as new information is obtained or new
technologies are applied.
21
22
Estimation of Hydrocarbon Reserves
as of January 1, 2009
This chapter gives an evaluation of the country’s hydrocarbon reserves in 2008, with an analysis of the
distribution by region, category, and fluid type composition. There is also an analysis of the classification of
the reserves according to the quality of the oil and the
origin of the gas, that is, associated or non-associated.
The latter is broken down into reservoir type: dry gas,
wet gas or gas-condensate.
It is important to stress that hydrocarbon reserves
are the result of investment project strategies that
are translated into production forecasts associated
with the behavior of the reservoirs and operation
and maintenance costs, as well as hydrocarbon sales
prices, in addition to the associated investments.
Furthermore, the current trends in reservoir behavior,
major workovers in wells, programmed wells drilling,
new development projects, secondary and enhanced
recovery projects, the results of exploratory activity
and the combined production of the wells all contribute to the updating of reserves.
This chapter also gives Mexico’s position in the
international petroleum industry concerning the category of proved reserves for both dry gas and total
liquids, which include crude oil, condensates and
plant liquids.
4
of each one of the categories of reserves calls for the
use of production forecasts for oil, condensate, and
gas, hydrocarbon sales prices, operation costs and
development-associated investments. With these four
elements it is possible to determine the economic limit
of the exploitation of such reserves, that is, the point
in time is determined when income and expenditure
are matched, where the income is simply a production
forecast multiplied by the price of the hydrocarbon in
question. In this respect, the reserves are the volumes
of production of each well until the economic limit
is reached. Hence the importance of hydrocarbon
prices, and the other elements involved.
The variations in the sales price of the Mexican crude
oil mixture and sour wet gas over the last three years
are shown in Figure 4.1. There is an evident upward
trend in prices in the first half of 2008, reaching maximum values of 120.3 dollars per barrel of oil in July,
and 11.2 dollars per thousand cubic feet of gas. The
annual average of 84.4 dollars per barrel was 36.7
percent higher than in 2007. In the case of sour wet
gas, the prices in 2008 increased 32.2 percent when
compared with the previous year, with an average of
7.7 dollars per thousand cubic feet, and a minimum
of 5.6 dollars per thousand cubic feet in December
and a maximum of 11.0 dollars per thousand cubic
feet in July.
4.1 Hydrocarbon Prices
4.2 Oil Equivalent
The profitability of investment projects is determined
by considering the sales prices of the hydrocarbons
to be produced, in addition to the development, operation and maintenance costs necessary to carry out
the exploitation of the reserves. Specifically, the value
Oil equivalent is the way of representing the total
hydrocarbon inventory. Oil equivalent includes
crude oil, condensates, plant liquids and dry gas in
its equivalent to liquid. The latter is obtained by re23
Estimation as of January 1, 2009
Crude Oil
dollars per barrel
140
120
100
80
60
40
20
0
12
Sour Wet Gas
dollars per thousand cubic feet
10
8
6
4
2
0
Jan
Mar
May
Jul
2006
Sep
Nov
Jan
Mar
May
Jul
2007
Sep
Nov
Jan
Mar
May
Jul
2008
Sep
Nov
Figure 4.1 Historic evolution of prices for the Mexican crude oil mix and sour wet gas over the last three years.
lating the heat value of the dry gas, in our case, the
average residual gas in the Ciudad Pemex, Cactus,
and Nuevo Pemex gas processing complexes (GPCs),
with the heat value of the crude oil corresponding
to the Maya type; the result is an equivalence that is
normally expressed in barrels of oil per million cubic
feet of dry gas.
The evaluation of the oil equivalent considers the
ways in which the facilities for handling and transporting natural gas from the fields of each region to
the gas processing complexes were operated over
the period of analysis, in addition to considering the
process to which the well gas was submitted at these
petrochemical plants. During the operation, the gas
shrinkage and yields at the Pemex Exploración y Producción facilities are recorded, with an identification of
the atmospheric behavior of gas up to its delivery at
the petrochemical plants for processing. The volumes
of condensates are also measured simultaneously in
various surface facilities. Similarly, the gas processing
complexes record the shrinkage and yields of the gas
delivered by Pemex Exploración y Producción in order
to obtain dry gas and plant liquids.
24
4.2.1 Gas Behavior at the PEP Handling and Transport Facilities
The natural gas is transported from the separation
batteries, if it is associated gas, or from the well, if it is
non-associated gas, to the gas processing complexes
when it is wet gas and/or it contains impurities. The
sweet dry gas is distributed directly for commercialization.
In some facilities, a fraction of the gas is used as
fuel to compress the gas actually produced, in other
situations, a part of the gas is re-injected into the
reservoir or it is used in artificial production systems,
such as gas lift, and this part is referred to as selfconsumption. The case may also arise when there
are no facilities available for the handling and transporting of associated gas, and consequently the gas
produced, or part of it, is flared, thus reducing the
gas sent to the processing complexes, or directly for
commercialization.
Additionally, the gas sent to the processing complexes undergoes temperature and pressure changes
in transit, which gives rise to liquid condensation in
the pipelines and a consequent reduction in volume.
The remaining gas after this potential third reduction,
after self-consumption and flaring, is what is actually delivered to the plants. Additionally, the natural
gas liquids obtained in transportation and which are
known as condensates, are also delivered to the gas
processing complexes.
These reductions in the handling and transportation
of gas to the processing complexes are quantitatively
expressed by means of two factors. The first is the
handling efficiency shrinkage factor, hesf, which includes gas flaring and self-consumption. The other is
the transport liquefiables shrinkage factor, tlsf, which
represents the volume decrease caused by condensa-
tion in the pipeline. Finally, there is the condensate
recovery factor, crf, which relates the condensate
obtained to the gas sent to the plants.
The natural gas shrinkage and condensate recovery
factors are calculated every month by using operative
information at a field level in the Northeastern Offshore, Southwestern Offshore and Southern regions,
and the group of fields with shared processing for the
Northern Region. The regionalization of the gas and
condensate production sent to more than one gas processing complex is also considered. Figure 4.2 shows
the behavior over the last three years of these three
factors for all of the Pemex Exploración y Producción
regions. The utilization of natural gas is shown in the
handling efficiency shrinkage factor, hesf, graph. The
Handling efficiency shrinkage factor (hesf)
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
Transport liquefiables shrinkage factor (tlsf)
1.1
1.0
0.9
0.8
0.7
0.6
0.5
Condensate recovery factor (crf)
barrels per million cubic feet
120
110
100
90
80
70
60
50
40
30
20
10
0
Jan
Mar
May
Jul
Sep
Nov
Jan
2006
Mar
May
Jul
Sep
Nov
Jan
Mar
May
2007
Northeastern Offshore
Southwestern Offshore
Jul
Sep
Nov
2008
Northern
Southern
Figure 4.2 Gas shrinkage and condensate recovery factors, by region, of the national petroleum system.
25
Northeastern Offshore Region reported a decrease
compared with 2007. The Southwestern Offshore
Region evidenced almost constant behavior in gas
utilization, with a marked decrease in September 2008
because production in the May field was affected by
a loss of control in the separation battery of the Dos
Bocas sea terminal in Tabasco. The Northern and
Southern regions showed stable and efficient behavior throughout 2008.
reductions in these processes are expressed quantitatively through two factors; the impurities shrinkage factor, isf, that considers the effect of removing
non-hydrocarbon compounds from the gas, and the
plant liquefiables shrinkage factor, plsf, which considers the effect of separating liquefiable hydrocarbons
from the wet gas. The liquids obtained are therefore
related to the wet gas by means of the plant liquids
recovery factor, plrf.
In terms of liquefiables shrinkage, shown in Figure 4.2,
the behavior is practically constant for the Northern
and Southern regions. The Northeastern Offshore
Region reported high liquefiable behavior at the beginning of the year, followed by a decrease in February,
a partial recovery in March and April despite faults
in the modules of two platforms, and was then more
stable for the rest of 2008. In 2008, the Southwestern Offshore Region showed gradually decreasing
liquefiables shrinkage over the first four months as a
result of failures in the modules of the Pol-Alfa platform, and it was then constant for the rest of the year.
The condensates yield in the Northeastern Offshore
Region increased in February 2008, the Southwestern Offshore Region reported a gradual and almost
constant decrease over the year. The Northern and
Southern regions, however, were practically constant
in terms of yield throughout 2008.
These factors are updated every month with the operation information furnished by all the gas processing complexes mentioned above and their behavior
is shown in Figure 4.3, which reveals the evolution of
the impurities shrinkage factor of the Cactus, Ciudad
Pemex, Matapionche, Nuevo Pemex, Poza Rica, and
Arenque GPCs, that receive sour gas. The La Venta,
Reynosa, and Burgos GPCs receive sweet, wet gas;
consequently, they are not shown in said figure. The
intermediate part of Figure 4.3 shows the behavior
of the liquefiables shrinkage factor in all the gas processing complexes. In reference to the plant liquids
recovery factor, the information is given in the lower
part of Figure 4.3. In particular, the Poza Rica GPC
reported a value of zero in November because it
was out of operation for maintenance. The La Venta
GPC reported a decrease in the recovery of liquids
in March.
4.2.2 Gas Behavior in Processing Complexes
4.3 Remaining Total Reserves
The gas produced by the four Pemex Exploración y
Producción regions is delivered to the Pemex Gas y
Petroquímica Básica processing complexes in Aren
que, Burgos, Cactus, Ciudad Pemex, La Venta, Mata
pionche, Nuevo Pemex, Poza Rica, and Reynosa. The
gas received at the processing complexes undergoes
a sweetening process if the gas is sour; and absorption and cryogenic processes are applied, when the
gas is wet. The plant liquids, which are liquefied hydrocarbons, and dry gas also known as residual gas,
are obtained by means of these processes. The gas
As of January 1, 2009, the remaining total reserves,
also known as 3P, which correspond to the addition of the proved, probable and possible reserves,
amounted to 43,562.6 million barrels of oil equivalent.
Specifically, the proved reserves accounted for 32.8
percent, the probable reserves were 33.3 percent and
the possible reserves were 33.8 percent, as can be
seen in Figure 4.4.
26
The classification by fluid type of remaining total
reserves of Mexico’s oil equivalent is shown in Table
Impurities shrinkage factor (isf)
0.99
0.98
0.97
0.96
0.95
0.94
0.93
0.92
0.91
0.90
1.00
Plant liquefiables shrinkage factor (plsf)
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
140
Plant liquids recovery factor (plrf)
barrels per million cubic feet
120
100
80
60
40
20
0
Jan
Mar
May
Jul
Nov
Sep
Jan
Mar
2006
Arenque
Burgos
May
Jul
Sep
Nov
Jan
Mar
2007
Cactus
Cd. Pemex
May
Jul
Sep
Nov
2008
La Venta
Matapionche
Nuevo Pemex
Poza Rica
Reynosa
Figure 4.3 Gas shrinkage and liquids recovery factors in gas processing complexes where natural gas is delivered
from the country’s reservoirs.
4.1. Consequently, as of January 1, 2009, crude oil
accounted for 71.0 percent of the total, dry gas
19.7 percent, plant liquids added 8.0 percent, and
condensates provided 1.3 percent. In a regional
context, 3P reserves are distributed as follows;
Bboe
the Northern Region accounts for 45.3 percent,
the Northeastern Offshore Region has 29.4 percent, the Southwestern Offshore Region holds
11.9 percent, and the Southern Region contains
13.5 percent.
particular, the Northeastern Offshore Region provides
68.7 percent of the nation’s total heavy oil, while the
Northern Region furnishes 61.6 percent of the light
oil, and 47.2 percent of the total superlight oil.
The classification of total crude oil reserves according to density is shown in Table 4.2. Total
oil reserves as of January 1, 2009, amounted to
30,929.8 million barrels, with heavy oil accounting for 54.4 percent of this volume, light oil 35.4
percent, and superlight with 10.2 percent. In
14.3
Proved
14.5
28.8
Probable
2P
14.7
43.6
Possible
3P
Figure 4.4 Integration by category of the remaining oil equi
valent reserves of Mexico.
27
Table 4.1 Historic distribution by fluid and region of remaining total reserves.
Remaining Hydrocarbon Reserves
Year
Region
Crude Condensate
Plant
Oil
Liquids
MMbbl
MMbbl
MMbbl
Remaining Gas Reserves
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
33,093.0
Northeastern Offshore 13,566.4
Southwestern Offshore 2,773.1
Northern
12,877.3
Southern
3,876.1
863.0
509.6
185.2
51.5
116.6
3,479.4
421.1
360.2
1,659.4
1,038.7
8,982.2
696.4
724.9
5,950.9
1,610.0
46,417.5
15,193.5
4,043.5
20,539.1
6,641.4
62,354.8
6,188.5
5,670.9
39,055.1
11,440.3
55,080.8
4,580.8
4,653.1
34,860.8
10,986.1
46,715.6
3,621.7
3,770.1
30,950.5
8,373.3
2007
31,908.8
Northern
12,769.4
Southern
3,727.9
941.2
635.4
175.4
39.4
91.0
3,417.5
350.2
407.6
1,711.4
948.1
9,108.9
589.8
1,163.0
5,876.7
1,479.4
45,376.3
14,086.0
4,647.0
20,397.0
6,246.3
63,045.2
5,716.7
7,961.9
38,910.0
10,456.6
55,364.2
3,853.7
6,936.0
34,721.4
9,853.1
47,367.9
3,067.5
6,048.5
30,564.5
7,687.3
2008
31,211.6
Northern
12,546.0
Southern
3,801.0
879.0
616.4
147.3
19.4
95.8
3,574.7
283.5
422.3
1,970.5
898.4
8,817.4
521.0
1,262.5
5,613.0
1,420.9
44,482.7
13,357.7
4,759.9
20,149.0
6,216.1
61,358.5
5,382.7
8,269.3
37,546.1
10,160.4
54,288.1
3,384.8
7,602.0
33,741.6
9,559.6
45,858.8
2,709.7
6,566.2
29,193.0
7,389.9
2009
30,929.8
Northern
12,402.9
Southern
3,652.9
561.7
368.9
84.5
19.1
89.2
3,491.3
256.6
509.7
1,918.2
806.8
8,579.7
503.7
1,377.8
5,384.6
1,313.6
43,562.6
12,785.9
5,189.4
19,724.8
5,862.5
60,374.3
4,892.9
9,571.8
36,503.1
9,406.5
53,382.5
3,317.0
8,566.0
32,614.5
8,885.0
44,622.7
2,619.7
7,165.8
28,005.0
6,832.1
Total reserves of natural gas as of January 1, 2009,
amount to 60,374.3 billion cubic feet, with the Northern Region accounting for 60.5 percent. The gas
reserves to be delivered to processing plants total
53,382.5 billion cubic feet and the dry gas reserves
amount to 44,622.7 billion cubic feet. This information
and its historic evolution can be seen in Table 4.1.
gas reservoirs; the Southwestern Offshore Region
contains 40.5 percent, most of which is found in wet
gas reservoirs. The Southern Region has 16.9 percent
of the total, mainly located in the gas-condensate
reservoirs, and the Northeastern Offshore Region
with 0.4 percent of the dry gas reservoirs completes
this volume.
The classification of total reserves of natural gas by
association with oil in the reservoir is shown in Table
4.2. It can be seen that the 3P reserves of associated
gas as of January 1, 2009, total 44,710.0 billion cubic
feet of gas, which is 74.1 percent of the total, because
most of the reservoirs in Mexico are oil reservoirs, and
the remaining 25.9 percent covers non-associated gas
reserves. In particular, the Northern Region provides
42.3 percent of these reserves, mostly located in wet
The evolution of Mexico’s total oil equivalent reserves
is shown in Figure 4.5, including the details of the
most important elements that generate variations in
said reserve. As of January 1, 2009, there was a slight
decrease of 2.1 percent compared with the total reserves of the previous year. A large part of the decline
is explained by the production of 1,451.1 million barrels of oil equivalent in 2008, where the Northeastern
Offshore Region provided 47.5 percent. Discoveries
28
Table 4.2 Classification of total reserves, or 3P, of crude oil and natural gas.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Non-associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
2006
18,786.6
667.6
Northern
4,326.4
Southern
305.2
11,523.3
78.9
1,538.4
7,040.3
2,865.7
2,783.0
0.0
567.1
1,510.6
705.3
48,183.0
6,130.7
2,961.6
31,726.6
7,364.1
2007
17,710.4
650.2
Northern
4,303.4
Southern
312.8
11,317.7
66.5
1,622.2
6,954.6
2,674.4
2,880.6
0.0
628.6
1,511.4
740.7
2008
17,175.7
740.0
Northern
4,211.9
Southern
323.5
11,166.1
36.5
1,692.5
6,824.6
2,612.5
2009
16,836.2
739.9
Northern
4,177.0
Southern
350.1
10,948.1
87.6
1,793.1
6,740.3
2,327.1
Total
Bcf
5,149.1
0.0
1,938.0
97.4
3,113.8
4,219.5
0.0
0.0
3,990.3
229.2
4,803.3
57.8
771.4
3,240.9
733.3
14,171.8
57.8
2,709.3
7,328.5
4,076.2
47,403.1
5,658.9
3,280.4
31,436.5
7,027.2
4,791.2
0.0
2,020.0
97.4
2,673.9
5,766.3
0.0
1,301.8
4,290.3
174.1
5,084.7
57.8
1,359.7
3,085.8
581.4
15,642.1
57.8
4,681.5
7,473.5
3,429.4
2,869.9
0.0
495.3
1,509.5
865.0
46,067.0
5,325.0
3,163.0
30,594.1
6,984.9
4,157.2
0.0
1,734.3
88.8
2,334.1
5,922.3
0.0
2,010.6
3,795.9
115.8
5,212.1
57.8
1,361.4
3,067.4
725.6
15,291.6
57.8
5,106.3
6,952.0
3,175.5
3,145.5
0.0
684.4
1,485.5
975.6
44,710.0
4,835.1
3,232.9
29,883.7
6,758.4
5,052.5
0.0
2,968.5
87.4
1,996.6
5,545.8
0.0
2,010.7
3,413.3
121.8
5,065.9
57.8
1,359.7
3,118.7
529.7
15,664.3
57.8
6,338.9
6,619.4
2,648.2
* G-C: Gas-Condensate reservoirs
added 1,482.1 million barrels of oil equivalent, thus
replacing production in 2008 by 102.1 percent. Developments increased reserves by 206.6 million barrels
of oil equivalent, while revisions reduced the reserves
by 1,157.8 million barrels. Considering additions, revisions and developments, 530.9 million barrels of oil
equivalent in 3P reserves were replaced, which means
an integrated replacement rate of 36.6 percent.
Bboe
46.4
2006
45.4
2007
44.5
2008
1.4
-1.2
0.3
-1.5
43.6
Additions
Revisions
Developments Production
2009
Figure 4.5 Historic evolution of Mexico’s total oil equivalent reserves.
29
The reserve-production ratio, which is obtained by
dividing the remaining reserve as of January 1, 2009,
by the production in 2008, is 30.0 years for the total
reserves, 19.9 years for the proved plus probable
reserves (2P) aggregate, and 9.9 years for proved
reserves. This ratio does not envisage a decrease in
production, the discovery of reserves in the future
or variations in hydrocarbon prices and changes in
operation and transport costs.
4.3.1 Remaining Proved Reserves
Mexico’s proved hydrocarbon reserves are evaluated
in accordance with the criteria and definitions of the
Securities and Exchange Commission (SEC) of the
United States, with remaining reserves as of January
1, 2009, being reported as 14,307.7 million barrels
of oil equivalent. In terms of the hydrocarbons that
make up the above figure, crude oil contributes 72.7
percent of the total proved reserves, dry gas accounts
for 17.1 percent, while plant liquids and condensates
represent 7.6 and 2.6 percent, respectively. In regional
terms, the Northeastern Offshore Region accounts
for 46.9 percent of the total national oil equivalent
reserve, the Southern Region has 28.3 percent, while
the Northern Region provides 11.5 percent, and the
Southwestern Offshore Region furnishes the remaining 13.2 percent. Table 4.3 shows the distribution of
the remaining proved reserve classified by region
and fluid type.
As of January 1, 2009, the proved crude oil reserves
totaled 10,404.2 million barrels, heavy oil being the
Table 4.3 Distribution by fluid and region of remaining proved reserves.
Year
Region
Crude Condensate
Oil
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
11,813.8
7,106.2
Northern
888.1
Southern
2,808.2
537.9
341.2
76.4
21.1
99.3
1,318.8
289.1
148.4
106.5
774.9
2,799.0
473.0
276.8
848.4
1,200.8
16,469.6
8,209.4
1,513.0
1,864.0
4,883.2
19,956.9
4,190.4
2,245.8
4,964.4
8,556.3
17,794.0
3,118.2
1,803.5
4,657.8
8,214.5
14,557.3
2,459.9
1,439.6
4,412.4
6,245.3
2007
11,047.6
6,532.0
Northern
888.9
Southern
2,588.7
608.3
443.2
68.1
18.2
78.9
1,193.5
254.3
161.1
106.4
671.6
2,664.8
422.7
360.0
832.9
1,049.2
15,514.2
7,652.2
1,627.2
1,846.4
4,388.4
18,957.3
4,038.8
2,643.7
4,856.4
7,418.4
16,558.4
2,769.2
2,227.6
4,570.4
6,991.1
13,855.8
2,198.4
1,872.6
4,331.8
5,452.9
2008
10,501.2
6,052.8
994.9
Northern
840.7
Southern
2,612.8
559.6
407.5
61.2
8.2
82.8
1,125.7
200.7
176.7
102.4
645.9
2,530.7
363.6
397.3
770.2
999.5
14,717.2
7,024.6
1,630.1
1,721.5
4,341.1
18,076.7
3,635.6
2,787.4
4,479.7
7,174.0
15,829.7
2,369.3
2,478.7
4,223.3
6,758.5
13,161.8
1,891.2
2,066.4
4,005.7
5,198.5
2009
10,404.2
5,919.3
Northern
828.7
Southern
2,480.2
378.4
256.1
38.0
8.0
76.3
1,082.9
183.0
221.2
105.5
573.1
2,442.3
353.9
458.8
710.1
919.5
14,307.7
6,712.3
1,893.9
1,652.4
4,049.1
17,649.5
3,365.8
3,462.9
4,218.7
6,602.1
15,475.2
2,337.7
2,973.0
3,922.4
6,242.2
12,702.0
1,840.4
2,386.0
3,693.3
4,782.2
30
Table 4.4 Classification of proved reserves, or 1P, of crude oil and natural gas.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Non-associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
2006
Northern
Southern
7,557.4
7,060.2
113.8
358.6
24.8
3,550.4
46.0
718.5
523.5
2,262.4
706.0
0.0
179.0
6.0
521.0
13,274.2
4,176.7
1,442.9
1,430.4
6,224.2
2007
Northern
Southern
7,009.4
6,493.4
110.0
366.1
39.8
3,402.9
38.6
750.4
513.6
2,100.3
635.3
0.0
177.6
9.1
448.5
2008
Northern
Southern
6,545.7
6,016.3
120.9
357.6
50.9
3,258.7
36.5
669.4
473.9
2,078.8
2009
Northern
Southern
6,381.4
5,868.5
120.9
342.4
49.5
3,237.6
50.7
808.2
468.5
1,910.2
Total
Bcf
2,191.3
0.0
598.7
34.5
1,558.0
1,657.9
0.0
0.0
1,472.5
185.4
2,833.5
13.7
204.1
2,027.1
588.7
6,682.7
13.7
802.9
3,534.1
2,332.1
12,578.1
4,025.6
1,585.9
1,316.4
5,650.2
1,819.9
0.0
541.8
34.5
1,243.6
2,179.4
0.0
308.5
1,739.9
131.1
2,379.8
13.2
207.4
1,765.7
393.5
6,379.2
13.2
1,057.8
3,540.0
1,768.2
696.9
0.0
204.6
9.2
483.1
11,793.2
3,622.1
1,385.0
1,235.2
5,550.9
2,042.2
0.0
886.0
35.9
1,120.2
1,844.8
0.0
308.5
1,435.0
101.3
2,396.5
13.4
207.9
1,773.5
401.6
6,283.5
13.4
1,402.5
3,244.5
1,623.1
785.2
0.0
246.9
17.8
520.5
11,473.1
3,352.3
1,616.0
1,282.0
5,222.8
2,335.7
0.0
1,330.7
34.9
970.2
1,734.5
0.0
308.6
1,319.3
106.7
2,106.1
13.4
207.7
1,582.5
302.5
6,176.4
13.4
1,846.9
2,936.7
1,379.3
dominant component with 61.3 percent, followed by
light oil with 31.1 percent and superlight oil providing
7.5 percent of the national total. The Northeastern
Offshore Region provides 92.0 percent of the total
heavy oil, while the Southern Region has 59.0 percent
of the light oil and 66.3 percent of the superlight oil.
Table 4.4 shows the proved reserves of crude oil as
classified by density.
Bboe
16.5
15.5
14.7
2006
2007
2008
0.5
-0.4
1.0
-1.5
14.3
Additions
Revisions
2009
Figure 4.6 Historic behavior of Mexico’s remaining proved oil equivalent reserves.
31
The historic evolution of Mexico’s proved natural gas
reserves is shown in Table 4.3. These reserves totaled
17,649.5 billion cubic feet of gas as of January 1, 2009,
which means a decrease of 2.4 percent compared with
the previous year. The reserves of gas to be delivered
to plant totaled 15,475.2 billion cubic feet. The proved
dry gas reserve was 12,702.0 billion cubic feet, of
which the Southern Region holds 37.6 percent and
the Northern Region provides 29.1 percent.
The classification of proved natural gas reserves by association with oil in the reservoir is shown in Table 4.4.
The associated gas reserves account for 65.0 percent
of the total and the non-associated gas is 35.0 percent.
The Southern and Northeastern Offshore regions provide 45.5 percent and 29.2 percent, respectively, of
the proved associated gas reserves. Additionally, the
highest non-associated gas reserve contribution is in
the Northern and Southwestern Offshore regions, with
47.5 and 29.9 percent, respectively. Some 53.9 percent
of these reserves in the Northern Region are in dry gas
reservoirs. Regarding the Southern and Southwestern
Offshore regions, Most of their proved non-associated
gas reserves, are in gas condensate reservoirs.
Bboe
4.1
14.3
Undeveloped
Proved
10.2
Developed
Figure 4.7 Classification by category of the remain
ing proved oil equivalent reserves.
The historic behavior of proved oil equivalent reserves
of the country is shown in Figure 4.6, where there was
a decrease of 2.8 percent as of January 1, 2009, when
compared with the previous year. Nevertheless, it is important to note that the highest volume of new proved
reserves replaced by discoveries, delimitations, developments and revisions was reached in 2008, amounting
to 1,041.6 million barrels of oil equivalent, which means
71.8 percent of the production in 2008. Additions and
developments increased proved reserves by 363.8
and 1,068.7 million barrels, respectively. Revisions,
Table 4.5 Proved crude oil and dry gas reserves of the most important producing countries.
Ranking
Country
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Saudi Arabia
Canada
Iran
Iraq
Kuwait
Venezuela
United Arab Emirates
Russia
Libya
Nigeria
Kazakhstan
United States of America
China
Qatar
Brazil
Algeria
Mexico
Crude Oila
Ranking
Country
MMbbl
264,210
178,092
136,150
115,000
101,500
99,377
97,800
60,000
43,660
36,220
30,000
21,317
16,000
15,210
12,624
12,200
11,865
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
35
Russia
Iran
Qatar
Saudi Arabia
United Arab Emirates
Nigeria
Venezuela
Algeria
Iraq
Indonesia
Turkmenistan
Kazakhstan
Malaysia
Norway
China
Mexico
Source: Mexico, Pemex Exploración y Producción. Other countries, Oil & Gas Journal, December 22, 2008
a. Includes condensates and liquids from natural gas
32
Dry Gas
Bcf
1,680,000
991,600
891,945
257,970
237,726
214,400
184,160
170,920
159,000
111,940
106,000
94,000
85,000
83,000
81,680
80,000
12,702
however, reduced reserves by 390.9 million barrels
of oil equivalent. Finally, production in 2008 totaling
1,451.1 million barrels of oil equivalent explains the
most important decrease in this category of reserves.
The classification by category of proved reserves as of
January 1, 2009, is shown in Figure 4.7. The developed
proved reserves therefore represent 71.3 percent of
the national total, and the remaining 28.7 percent is
made up of undeveloped proved.
In the international context, Mexico is ranked 17th
in reference to the proved reserves, including oil,
condensate and plant liquids. In terms of dry gas,
Mexico is in the 35th place. Table 4.5 shows the proved
reserves of crude oil and dry gas of the most important
producing countries.
4.3.1.1 Remaining Developed Proved Reserves
As of January 1, 2009, the developed proved reserves
totaled 10,196.3 million barrels of oil equivalent,
which means an increase of 1.9 percent compared
with the previous year. Additions, developments, and
revisions, amounted to 1,642.1 million barrels of oil
equivalent, which means a replacement rate of 113.2
percent of the production of 1,451.1 million barrels
of oil equivalent.
Table 4.6 shows the distribution by region and fluid
type of developed proved reserves. As of January 1,
2009, crude oil accounted for 74.9 percent of the total,
followed by dry gas with 15.5 percent, plant liquids
with 6.7 percent and 2.9 percent for condensates. The
Northeastern Offshore Region has 54.4 percent of the
Table 4.6 Historic distribution by fluid and region of the remaining developed proved reserves.
Plant
Liquids
MMbbl
Year
Region
Crude Condensate
Oil
MMbbl
MMbbl
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
Northern
Southern
8,565.1
5,586.0
547.4
395.7
2,036.1
273.8
161.2
42.3
16.2
54.1
777.6
141.1
82.0
63.3
491.3
1,709.0
229.5
131.0
591.0
757.4
11,325.6
6,117.8
802.6
1,066.2
3,338.9
11,945.4
2,033.5
1,121.3
3,379.5
5,411.1
10,801.3
1,515.1
882.3
3,219.2
5,184.7
8,888.2
1,193.8
681.1
3,074.0
3,939.3
2007
Northern
Southern
7,930.8
5,124.6
598.2
349.0
1,859.0
327.8
229.0
39.4
14.1
45.3
718.9
140.8
94.0
57.0
427.1
1,670.6
232.6
155.1
606.2
676.7
10,648.1
5,727.0
886.8
1,026.3
3,008.0
11,631.0
2,174.0
1,261.3
3,431.2
4,764.5
10,315.8
1,525.6
1,018.0
3,276.2
4,496.0
8,688.2
1,209.6
806.9
3,152.9
3,518.8
2008
Northern
Southern
7,450.3
4,773.3
533.1
303.1
1,840.7
319.7
238.9
30.8
6.2
43.7
665.8
130.2
88.5
44.8
402.3
1,569.5
234.2
165.2
540.3
629.8
10,005.3
5,376.7
817.8
894.4
2,916.5
11,027.8
2,245.3
1,227.5
3,058.1
4,497.0
9,735.6
1,528.2
1,065.1
2,898.5
4,243.8
8,162.9
1,218.1
859.4
2,809.8
3,275.6
2009
Northern
Southern
7,638.3
4,837.5
673.7
407.8
1,719.4
297.8
229.2
20.4
6.0
42.2
682.4
164.3
112.2
60.3
345.6
1,577.8
315.4
198.5
494.9
569.0
10,196.3
5,546.4
1,004.8
969.0
2,676.1
11,450.0
2,892.0
1,604.6
2,890.5
4,062.8
9,954.5
2,087.0
1,330.6
2,701.4
3,835.6
8,206.1
1,640.5
1,032.4
2,573.9
2,959.3
33
oil equivalent reserves, the Southern Region holds 26.2
percent, and the Northern and Southwestern Offshore
regions have 9.5 and 9.9 percent, respectively.
Developed proved natural gas reserves as of January
1, 2009, total 11,450.0 billion cubic feet, as can be
seen in Table 4.6. Gas reserves to be delivered to plant
amount to 9,954.5 billion cubic feet, 38.5 percent of
which is produced by the Southern Region. Dry gas
reserves are 8,206.1 billion cubic feet, with the Southern Region holding 36.1 percent of this reserve.
As of January 1, 2009, the developed proved reserves
of crude oil totaled 7,638.6 million barrels. Heavy oil
accounted for 66.1 percent of the national total, light oil
27.0 percent, and superlight 6.9 percent. The Northeast-
ern Offshore Region provides 95.5 percent of the total
heavy oil, while the Southern Region has 64.1 percent
of the light oil and 71.8 percent of the superlight oil.
Table 4.7 shows the classification of developed proved
crude oil reserves according to density.
The classification of developed proved reserves of
natural gas by association with crude oil in the reservoir is given in Table 4.7. As of January 1, 2009,
the developed proved reserves of associated gas
accounted for 67.4 percent of the natural gas, while
non-associated gas represented 32.6 percent. Most
of the developed reserves of associated gas are in
the Southern Region and the Northeastern Offshore
Region, with 37.9 and 37.5 percent, respectively. As
regards developed non-associated gas reserves, the
Table 4.7 Classification of developed proved crude oil and natural gas reserves.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Non-associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
G-C*
Bcf
2006
Northern
Southern
5,746.8
5,552.7
0.0
176.6
17.5
2,390.4
33.2
488.1
218.6
1,650.4
427.9
0.0
59.3
0.5
368.2
7,190.0
2,033.5
1,013.9
746.0
3,396.6
2007
Northern
Southern
5,279.6
5,098.7
0.0
158.1
22.7
2,240.3
25.9
524.0
190.4
1,500.0
411.0
0.0
74.2
0.5
336.3
2008
Northern
Southern
4,909.8
4,749.6
0.0
132.1
28.2
2,095.6
23.7
437.3
170.5
1,464.0
2009
Northern
Southern
5,046.5
4,820.8
0.0
208.2
17.6
2,064.8
16.7
527.8
196.7
1,323.5
34
Wet Gas
Bcf
Dry Gas
Bcf
Total
Bcf
1,603.3
0.0
107.4
11.1
1,484.8
1,260.7
0.0
0.0
1,077.7
183.0
1,891.3
0.0
0.0
1,544.7
346.6
4,755.4
0.0
107.4
2,633.6
2,014.4
6,947.5
2,174.0
1,103.4
525.7
3,144.3
1,355.5
0.0
157.9
11.1
1,186.5
1,411.2
0.0
0.0
1,282.8
128.4
1,916.8
0.0
0.0
1,611.5
305.3
4,683.6
0.0
157.9
2,905.5
1,620.2
444.9
0.0
95.8
0.5
348.6
6,745.4
2,245.3
956.5
458.4
3,085.2
1,310.7
0.0
271.0
10.6
1,029.1
1,152.3
0.0
0.0
1,053.6
98.7
1,819.5
0.0
0.0
1,535.5
284.0
4,282.4
0.0
271.0
2,599.7
1,411.8
527.0
0.0
145.8
3.0
378.2
7,720.4
2,892.0
1,218.6
681.1
2,928.6
1,173.1
0.0
386.0
10.7
776.4
1,070.2
0.0
0.0
967.8
102.4
1,486.3
0.0
0.0
1,230.9
255.4
3,729.6
0.0
386.0
2,209.4
1,134.2
Northern Region has 59.2 percent of the national total,
mostly in dry and wet gas reservoirs. The Southern
Region provides 30.4 percent, largely in gas-condensate reservoirs, and the remaining percentage of these
reserves is in the Southwestern Offshore Region, with
10.3 percent related to gas-condensate reservoirs.
4.3.1.2 Undeveloped Proved Reserves
As of January 1, 2009, the undeveloped proved reserves totaled 4,111.4 million barrels of oil equivalent,
which means a decrease of 12.7 percent compared
with the previous year. Discoveries added 349.7 million barrels of oil equivalent; delimitations provided
74.7 million barrels, developments meant a decline
of 424.5 million barrels of oil equivalent, and the revi-
sions reduced this reserve by 600.4 million barrels of
oil equivalent, mainly because of the reclassification
of these reserves to developed proved.
The historical distribution of the undeveloped proved
reserves by fluid and region can be seen in Table 4.8.
As of January 1, 2009, crude oil accounted for 67.3
percent of the national total, dry gas equivalent to liquid
21.0 percent, plant liquids added 9.7 percent, and the
condensate completed the figure with 2.0 percent. The
Northeastern Offshore Region provides 28.4 percent
of the oil equivalent, the Southern Region has 33.4
percent, and the Southwestern Offshore and Northern
regions have 21.6 and 16.6 percent, respectively.
Undeveloped proved natural gas reserves, as of January 1, 2009, amounted to 6,199.5 billion cubic feet, as
Table 4.8 Historic distribution by fluid and region of undeveloped proved reserves.
Plant
Liquids
MMbbl
Year
Region
Crude Condensate
Oil
MMbbl
MMbbl
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
Northern
Southern
3,248.7
1,520.2
463.9
492.4
772.2
264.1
179.9
34.1
4.9
45.2
541.2
148.0
66.5
43.2
283.6
1,090.0
243.4
145.8
257.3
443.4
5,144.0
2,091.6
710.3
797.8
1,544.3
8,011.5
2,156.9
1,124.5
1,584.9
3,145.2
6,992.7
1,603.1
921.1
1,438.6
3,029.8
5,669.0
1,266.1
758.5
1,338.4
2,306.1
2007
Northern
Southern
3,116.7
1,407.4
439.7
539.9
729.7
280.5
214.2
28.7
4.0
33.6
474.6
113.5
67.1
49.5
244.5
994.2
190.1
204.9
226.7
372.5
4,866.1
1,925.2
740.4
820.1
1,380.4
7,326.3
1,864.8
1,382.3
1,425.3
2,653.9
6,242.5
1,243.7
1,209.7
1,294.2
2,495.0
5,167.5
988.8
1,065.7
1,179.0
1,934.0
2008
Northern
Southern
3,050.9
1,279.5
461.8
537.6
772.1
239.9
168.5
30.3
2.0
39.1
459.9
70.5
88.2
57.6
243.6
961.2
129.4
232.1
229.9
369.7
4,711.9
1,647.9
812.3
827.1
1,424.5
7,048.9
1,390.2
1,560.0
1,421.6
2,677.1
6,094.1
841.1
1,413.5
1,324.8
2,514.7
4,998.9
673.1
1,207.0
1,195.9
1,922.9
2009
Northern
Southern
2,765.9
1,081.8
502.3
420.9
760.9
80.6
26.9
17.5
2.0
34.1
400.5
18.7
109.1
45.2
227.5
864.4
38.4
260.3
215.2
350.5
4,111.4
1,165.8
889.2
683.4
1,373.0
6,199.5
473.7
1,858.2
1,328.2
2,539.3
5,520.7
250.7
1,642.4
1,221.0
2,406.6
4,495.9
199.9
1,353.6
1,119.4
1,822.9
35
Table 4.9 Classification of undeveloped proved crude oil and natural gas reserves.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
Non-associated
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
Total
Bcf
2006
Northern
Southern
1,810.6
1,507.4
113.8
182.0
7.3
1,160.1
12.8
230.4
304.9
612.0
278.1
0.0
119.7
5.5
152.8
6,084.2
2,143.2
429.0
684.4
2,827.5
588.0
0.0
491.4
23.4
73.2
397.2
0.0
0.0
394.8
2.4
942.2
13.7
204.1
482.4
242.1
1,927.3
13.7
695.5
900.5
317.7
2007
Northern
Southern
1,729.8
1,394.6
110.0
208.1
17.1
1,162.6
12.8
226.4
323.2
600.3
224.2
0.0
103.4
8.6
112.3
5,630.6
1,851.6
482.4
790.7
2,506.0
464.4
0.0
383.9
23.4
57.1
768.2
0.0
308.5
457.1
2.6
463.1
13.2
207.4
154.2
88.3
1,695.6
13.2
899.9
634.6
148.0
2008
Northern
Southern
1,635.9
1,266.7
120.9
225.5
22.7
1,163.1
12.8
232.1
303.4
614.9
252.0
0.0
108.8
8.7
134.5
5,047.8
1,376.8
428.5
776.8
2,465.7
731.5
0.0
615.0
25.3
91.1
692.5
0.0
308.5
381.5
2.6
577.0
13.4
207.9
238.1
117.6
2,001.0
13.4
1,131.5
644.8
211.3
2009
Northern
Southern
1,334.8
1,047.7
120.9
134.2
32.0
1,172.8
34.1
280.3
271.8
586.6
258.2
0.0
101.0
14.9
142.3
3,752.7
460.3
397.3
600.9
2,294.2
1,162.7
0.0
944.7
24.2
193.8
664.3
0.0
308.6
351.4
4.3
619.8
13.4
207.7
351.6
47.1
2,446.8
13.4
1,460.9
727.3
245.2
can be seen in Table 4.8. The gas to be delivered to
plant is 5,520.7 billion cubic feet; the Southern Region
accounts for 43.6 percent of this total. The dry gas
reserve totals 4,495.9 billion cubic feet, of which 40.5
percent is located in the Southern Region.
The undeveloped proved crude oil reserves as of
January 1, 2009, amounted to 2,765.9 million barrels,
with heavy oil representing 48.3 percent of the total,
light oil 42.4 percent and the superlight 9.3 percent. In
particular, the Northeastern Offshore Region provides
78.5 percent of the heavy oil, the Northern Region
has 10.1 percent, the Southwestern Offshore Region
9.1 percent, and the Southern Region 2.4 percent.
As regards light oil, the Southern Region contributes
50.0 percent, the Southwestern Offshore Region
36
23.9 percent, and the Northern Region 23.2 percent.
Additionally, the Southern Region provides 55.1
percent of the superlight oil and the Southwestern
Offshore Region has 39.1 percent. The classification
of undeveloped proved crude oil reserves by density
is shown in Table 4.9.
The natural gas undeveloped proved reserves classified by association with crude oil in the reservoir
are also shown in Table 4.9. As of January 1, 2009,
the undeveloped proved reserves of associated gas
accounted for 60.5 percent of the total, while the nonassociated gas represented 39.5 percent. The Southern
Region contributes 61.1 percent of the associated gas
undeveloped proved reserves. In terms of non-associated gas, the Southwestern Offshore Region has 59.7
Table 4.10 Historic distribution by fluid and region of probable reserves.
Year
Region
Crude Condensate
Oil
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
11,644.1
4,112.4
740.7
Northern
6,213.9
Southern
577.1
166.6
105.7
33.7
12.7
14.5
1,046.5
86.8
65.0
727.7
167.1
2,931.4
141.6
158.5
2,370.4
260.9
15,788.5
4,446.5
997.8
9,324.7
1,019.6
20,086.5
1,230.6
1,167.1
15,849.1
1,839.8
17,730.7
934.1
983.6
14,042.2
1,770.8
15,246.0
736.5
824.2
12,328.1
1,357.2
2007
11,033.9
3,444.7
744.2
Northern
6,099.7
Southern
745.3
159.0
103.1
36.8
9.5
9.5
1,071.0
53.5
81.0
751.9
184.6
2,993.6
88.8
254.0
2,360.5
290.3
15,257.4
3,690.1
1,116.0
9,221.6
1,229.7
20,485.7
863.0
1,706.4
15,874.2
2,042.2
18,116.6
582.2
1,495.1
14,109.5
1,929.8
15,567.9
462.1
1,320.8
12,276.8
1,508.2
2008
10,819.4
3,085.0
911.9
Northern
6,056.7
Southern
765.8
155.6
98.6
40.9
5.0
11.0
1,198.4
37.9
115.3
883.0
162.3
2,971.0
68.6
336.6
2,289.5
276.2
15,144.4
3,290.2
1,404.7
9,234.1
1,215.3
20,562.1
784.7
2,214.3
15,624.9
1,938.2
18,269.2
447.3
2,036.8
13,955.0
1,830.0
15,452.0
357.0
1,750.5
11,907.7
1,436.7
2009
10,375.8
2,844.5
985.5
Northern
5,845.0
Southern
700.8
81.6
42.1
23.7
4.6
11.1
1,174.6
30.9
146.3
838.4
159.0
2,884.9
59.7
381.3
2,174.6
269.4
14,516.9
2,977.1
1,536.9
8,862.6
1,140.3
20,110.5
631.1
2,675.9
14,901.3
1,902.2
17,890.4
394.2
2,388.4
13,302.2
1,805.7
15,004.4
310.3
1,983.2
11,310.0
1,400.9
percent of the national total, of which 64.7 percent is
in gas-condensate reservoirs, 21.1 percent in wet gas
and 14.2 percent in dry gas reservoirs. The Northern
Region has 29.7 percent of the non-associated gas
reserves, mostly (96.7 percent) in dry and wet gas
reservoirs. The Southern Region provides 10.0 percent
of the non-associated gas reserves, largely in gascondensate reservoirs, and the Northeastern Offshore
Region complements this with 0.6 percent of the total
non-associated gas in dry gas reservoirs
4.3.2. Probable Reserves
The probable reserves as of January 1, 2009, totaled
14,516.9 million barrels of oil equivalent. Table 4.10
shows regional distribution and by fluid type of this
reserve, which is made up as follows: 71.5 percent is
crude oil, 19.9 percent dry gas equivalent to liquid, 8.1
percent is plant liquids, and 0.6 is percent is condensate. At a regional level, the Northern Region accounts
for 61.1 percent, the Northeastern Offshore Region
20.5 percent, the Southern Region 7.9 percent, and
the Southwestern Offshore Region 10.6 percent.
The probable natural gas reserve, as of January 1,
2009, amounts to 20,110.5 billion cubic feet. The
gas probable reserves to be delivered to plant are
17,890.4 billion cubic feet, 74.4 percent of which is
concentrated in the Northern Region. The dry gas
reserves total 15,004.4 billion cubic feet; 75.4 percent
of these reserves are in the Northern Region. Table
4.10 shows the historic evolution of Mexico’s probable
natural gas reserves.
37
Table 4.11 Classification of probable crude oil and natural gas reserves.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Non-associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
2006
Northern
Southern
6,774.9
4,112.4
220.2
2,405.3
37.0
3,891.7
0.0
416.3
3,068.0
407.4
977.5
0.0
104.1
740.6
132.8
16,770.6
1,228.3
552.5
14,234.9
754.9
2007
Northern
Southern
6,127.5
3,444.7
215.2
2,337.8
129.8
3,815.8
0.0
409.9
3,023.7
382.2
1,090.6
0.0
119.1
738.2
233.3
2008
Northern
Southern
5,730.8
3,085.0
216.3
2,299.5
130.0
3,948.5
0.0
585.5
3,020.0
342.9
2009
Northern
Southern
5,402.1
2,807.7
216.3
2,232.7
145.3
3,646.1
36.8
567.1
2,815.2
227.0
Total
Bcf
1,319.6
0.0
330.9
35.0
953.7
1,149.4
0.0
0.0
1,140.2
9.2
847.0
2.2
283.7
439.1
122.0
3,316.0
2.2
614.6
1,614.3
1,084.9
16,414.6
860.8
498.8
14,056.3
998.8
1,485.9
0.0
549.9
35.0
901.0
1,562.5
0.0
364.4
1,189.7
8.5
1,022.7
2.2
293.3
593.3
133.9
4,071.1
2.2
1,207.6
1,817.9
1,043.4
1,140.1
0.0
110.1
737.2
292.8
16,457.6
782.5
795.9
13,869.8
1,009.5
1,239.2
0.0
517.8
36.4
684.9
1,701.5
0.0
607.0
1,084.3
10.3
1,163.8
2.3
293.6
634.3
233.6
4,104.5
2.3
1,418.4
1,755.1
928.7
1,327.6
0.0
202.1
797.1
328.5
15,744.8
628.8
903.8
13,152.9
1,059.2
1,579.9
0.0
871.9
36.1
671.9
1,610.3
0.0
606.9
992.5
10.9
1,175.4
2.3
293.2
719.8
160.2
4,365.7
2.3
1,772.1
1,748.4
842.9
The crude oil probable reserves as of January 1, 2009,
are 10,375.8 million barrels; heavy oil accounts for
52.1 percent of the national total, light oil 35.1 percent, and superlight 12.8 percent. The Northeastern
Offshore Region provides 52.0 percent of the heavy
oil, and the Northern Region has 41.3 percent. Additionally, the latter contributes 77.2 and 60.0 percent
of the total light and superlight oil, respectively. Table
Bboe
15.8
2006
15.3
2007
15.2
2008
0.6
Additions
-1.3
Revisions
0.1
14.5
Developments
2009
Figure 4.8 Historic behavior of Mexico’s probable oil equivalent reserves.
38
4.11 shows the classification of probable crude oil
reserves by density.
The classification of natural gas probable reserves by
association with oil is shown in Table 4.11. As of January 1, 2009, the associated gas probable reserves accounted for 78.3 percent of the national total for natural
gas probable reserves, and the non-associated gas
reserves represented 21.7 percent. The Northern Region holds 83.5 percent of the associated gas probable
reserves. In reference to the reserves of non-associated
gas, 40.0 percent of such are located in the Northern
Region, mostly coming from wet gas reservoirs; 40.6
percent of the non-associated gas is in the Southwestern Offshore Region, largely in gas-condensate reservoirs. Finally, 19.3 percent is located in the Southern
Region, also in gas-condensate reservoirs.
The historic evolution of Mexico’s oil equivalent probable reserves over the last three years is shown in
Figure 4.8. As of January 1, 2009, there was a decrease
of 627.4 million barrels of oil equivalent, that is, 4.1
percent, compared with the previous year. The additions contributed 548.6 million barrels of oil equivalent; the revisions of existing fields led to a decrease
of 1,297.4 million barrels of oil equivalent, and the
developments reported an increase of 121.3 million
barrels of oil equivalent, due to the reclassification of
reserves to this category.
4.3.3. Possible Reserves
As of January 1, 2009, Mexico’s oil equivalent possible
reserves amounted to 14,737.9 million barrels. The dis-
Table 4.12 Historic distribution by fluid and region of possible reserves.
Year
Region
Crude Condensate
Oil
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Total
Natural Gas
Gas to be
Dry Gas
Equivalent
Delivered to Plant
MMboe MMboe
Bcf
Bcf
Bcf
2006
Northern
Southern
9,635.0
2,347.8
1,021.1
5,775.3
490.8
158.5
62.8
75.1
17.7
2.9
1,114.1
45.3
146.8
825.2
96.8
3,251.8
81.8
289.6
2,732.2
148.2
14,159.4
2,537.7
1,532.7
9,350.4
738.7
22,311.4
767.5
2,258.0
18,241.6
1,044.2
19,556.1
528.5
1,866.0
16,160.8
1,000.8
16,912.3
425.3
1,506.3
14,210.0
770.8
2007
Northern
Southern
9,827.3
2,533.9
1,118.8
5,780.8
393.9
173.9
89.1
70.5
11.7
2.6
1,153.0
42.4
165.6
853.1
91.9
3,450.4
78.3
549.0
2,683.3
139.9
14,604.7
2,743.7
1,903.8
9,328.9
628.2
23,602.2
814.9
3,611.9
18,179.4
996.0
20,689.2
502.2
3,213.3
16,041.4
932.2
17,944.2
407.0
2,855.1
13,955.9
726.3
2008
Northern
Southern
9,891.1
2,799.0
1,020.9
5,648.7
422.4
163.9
110.3
45.2
6.3
2.0
1,250.5
44.8
130.4
985.1
90.2
3,315.8
88.7
528.6
2,553.3
145.1
14,621.2
3,042.9
1,725.1
9,193.4
659.8
22,719.7
962.4
3,267.6
17,441.5
1,048.2
20,189.1
568.2
3,086.5
15,563.2
971.2
17,245.0
461.4
2,749.2
13,279.6
754.8
2009
10,149.8
2,892.8
Northern
5,729.2
Southern
471.8
101.7
70.7
22.8
6.5
1.8
1,233.8
42.8
142.1
974.3
74.7
3,252.6
90.2
537.7
2,499.9
124.8
14,737.9
3,096.5
1,758.5
9,209.9
673.0
22,614.3
896.1
3,433.0
17,383.0
902.2
20,016.9
585.1
3,204.7
15,389.9
837.2
16,916.3
468.9
2,796.6
13,001.8
649.0
39
Table 4.13 Classification of possible crude oil and natural gas reserves.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Non-associated
Year
Region
MMbbl
MMbbl
MMbbl
Bcf
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
2006
Northern
Southern
4,454.3
2,315.0
333.6
1,562.4
243.4
4,081.1
32.9
403.6
3,448.8
195.9
1,099.5
0.0
284.0
764.1
51.5
18,138.2
725.6
966.1
16,061.4
385.0
2007
Northern
Southern
4,573.6
2,506.0
325.0
1,599.5
143.1
4,099.0
27.9
461.9
3,417.2
191.9
1,154.7
0.0
331.9
764.0
58.8
2008
Northern
Southern
4,899.2
2,799.0
402.7
1,554.9
142.6
3,959.0
0.0
437.5
3,330.7
190.8
2009
Northern
Southern
5,052.7
2,892.8
402.7
1,601.9
155.3
4,064.4
0.0
417.9
3,456.7
189.9
Total
Bcf
1,638.3
0.0
1,008.3
27.9
602.1
1,412.2
0.0
0.0
1,377.6
34.6
1,122.7
41.9
283.6
774.7
22.5
4,173.2
41.9
1,291.9
2,180.2
659.2
18,410.4
772.6
1,195.8
16,063.8
378.2
1,485.4
0.0
928.2
27.9
529.2
2,024.3
0.0
628.9
1,360.8
34.6
1,682.1
42.3
858.9
726.9
54.0
5,191.8
42.3
2,416.1
2,115.6
617.8
1,032.9
0.0
180.7
763.2
89.1
17,816.1
920.4
982.2
15,489.1
424.5
875.9
0.0
330.5
16.4
529.0
2,375.9
0.0
1,095.1
1,276.6
4.3
1,651.8
42.1
859.8
659.5
90.4
4,903.6
42.1
2,285.4
1,952.5
623.7
1,032.6
0.0
235.4
670.6
126.6
17,492.1
854.0
713.1
15,448.7
476.3
1,136.9
0.0
765.9
16.4
354.5
2,201.0
0.0
1,095.1
1,101.5
4.3
1,784.4
42.0
858.9
816.4
67.1
5,122.2
42.0
2,719.9
1,934.3
425.9
tribution by region and by fluid type is shown in Table
4.12. The Northern Region provides 62.5 percent of
these reserves, the Northeastern Offshore Region has
21.0 percent, the Southwestern Offshore Region 11.9
percent, and the Southern Region holds 4.6 percent.
Additionally, the proved reserve is made up of 68.9 percent crude oil, 22.1 percent dry gas equivalent to liquid,
8.4 percent plant liquids, and 0.7 percent condensate.
Possible natural gas reserves, as of January 1, 2009,
amounted to 22,614.3 billion cubic feet, as can be
seen in Table 4.12. The gas to be delivered to plant
is 20,016.9 billion cubic feet, 76.9 percent of which is
located in the Northern Region. The dry gas possible
reserves total 16,916.3 billion cubic feet; 76.9 percent
of these reserves are in the Northern Region.
40
The crude oil possible reserves as of January 1, 2009,
amount to 10,149.8 million barrels, and their classification by density is shown in Table 4.13. Heavy oil
therefore oil accounts for 49.8 percent of this total,
light oil 40.0 percent, and superlight oil 10.2 percent.
The Northeastern Offshore Region has 57.3 percent
of the heavy oil possible reserves, while the Northern Region accounts for 85.0 percent of the possible
light oil reserves, and 64.9 percent of the superlight
oil reserves.
The classification of natural gas reserves by association
with crude oil in the reservoir is shown in Table 4.13.
The possible reserves of associated gas as of January
1, 2009, represented 77.3 percent of the total, while
the non-associated gas makes up the remaining 22.7
Bboe
14.2
2006
14.6
14.6
2007
2008
0.3
-0.1
-0.1
14.7
Additions
Revisions
Developments
2009
Figure 4.9 Historic behavior of Mexico’s possible oil equivalent reserves.
percent. The Northern Region accounts for 83.3 percent
of the associated gas possible reserves. The regional
distribution of non-associated gas possible reserves
shows that the Southwestern Offshore Region has 53.1
percent of the total; mostly in wet gas reservoirs. The
Northern Region holds 37.8 percent, which is largely in
wet gas reservoirs, while the Southern Region reports
8.3 percent, where the gas-condensate reservoirs
contain most of these reserves, and finally, the Northeastern Offshore Region has 0.8 percent.
The evolution of Mexico’s crude oil equivalent possible reserves over the last three years is shown in
Figure 4.9. As of January 1, 2009, there is an increase
of 116.8 million barrels of oil equivalent compared
with the previous year. This positive variation corresponds to 0.8 percent compared with 2008. Specifically, additions contributed 569.7 million barrels
of oil equivalent, while developments and revisions
reduced the reserves by 340.4 and 112.5 million barrels of oil equivalent, respectively.
41
42
5
Discoveries
The results of discovering hydrocarbon reserves
through exploratory activities are systematically im
proving. Specifically, this year Petróleos Mexicanos
reached the highest 3P reserves addition figure since
the adoption of the international guidelines jointly is
sued by the Society of Petroleum Engineers, the World
Petroleum Council, and the American Association of
Petroleum Geologists.
In 2008, the discoveries of 3P reserves totaled 1,482.1
million barrels of oil equivalent. This means a 40.7
percent increase in the addition of total reserves
through exploratory activities, when compared with
the previous year. Furthermore, another important
accomplishment in exploratory activities for the same
year is the fact that size of the discoveries by well in
creased from 43.9 million barrels of oil equivalent in
2007 to 78.0 million barrels in 2008. Undoubtedly, this
will allow reducing discovery and development costs,
and also the production ones, once the exploitation
of the associated reserves commences.
The addition of 3P reserves through discoveries in
2008 was mostly in the Northeastern Offshore Re
gion, with 54.9 percent, because of the results in
the Kambesah-1, Ayatsil-DL1 and Pit-DL1 wells. The
Southwestern Offshore Region, however, provided
30.3 percent of the total reserves, which were added
by the Tsimin-1, Tecoalli-1, Xanab-DL1 and Yaxché1DL wells. The Northern and Southern regions each
contributed 7.4 percent of the total 3P reserve.
These results illustrate the importance of maintaining
stability in the execution of exploratory activities by
means of a sustained investment rate that has tended
to improve when compared with the last few decades,
even though the desired rate of stability has not been
reached. Furthermore, most of the new reservoirs are
located very close to producing fields, which means
that these reserves will probably be developed in
less time in comparison with other smaller offshore
discoveries and consequently, they will be included
in the portfolio of projects that will add production in
the short term. Thus, the development and reclassifi
cation of probable and possible reserves into proved
category will therefore be faster.
In 2008 Petróleos Mexicanos invested a total of 24,082
million pesos in exploratory activities. The investment
was focused on drilling 65 exploratory and delinea
tion wells, the acquisition of 7,512 kilometers of 2D
seismic information and 12,163 square kilometers
of 3D seismic data, as well as the execution of geo
logical and geophysical studies for exploratory and
delineation projects.
This chapter describes the most important character
istics of the reservoirs discovered with an explana
tion of the most important geological, geophysical,
petrophysical and engineering aspects, in addition
to their reserve distribution. All of the discoveries
are also associated with the country’s respective
hydrocarbon-producing basins in order to visualize
the areas where exploratory efforts were focused in
2008. The trajectory of the discoveries is analyzed at
the end.
5.1 Aggregate Results
The booking of 3P hydrocarbons reserves was
40.7 percent higher than in 2007, which meant that
43
Discoveries
3P reserves discovered increased from 1,053.2 to
1,482.1 million barrels of oil equivalent. To this end,
exploratory localizations were drilled in onshore
and offshore areas in Mesozoic, Tertiary, and Recent
rocks. Table 5.1 summarizes the reserves discovered
at a well level in the proved reserve (1P), proved plus
probable reserve (2P), and the proved plus probable
plus possible (3P) categories.
Crude oil discoveries accounted for 73.9 percent of all
the 3P reserves added. These reserves are largely in
the Southeastern Basins and amount to 1,095.6 million
barrels of oil and 1,331.9 billion cubic feet of natural
gas, which jointly mean 1,372.9 million barrels of oil
equivalent. With the results of the Ayatsil-DL1 and
Pit-DL1 wells in the Ku-Maloob-Zaap Integral Business
Unit, and Kambesah-1 in the Cantarell Integral Busi
ness Unit, the Northeastern Offshore Region provided
a total of 789.6 million barrels of oil in 3P reserves.
In the Southwestern Offshore Region, the results of
the Tsimin-1, Tecoalli-1, Xanab-DL1, and Yaxché-1DL
wells, furnished 230.5 million barrels of oil in 3P re
Table 5.1 Composition of the hydrocarbon reserves of reservoirs discovered in 2008.
Basin
Well
Field
1P
2P
Crude Oil Natural Gas
MMbbl
Bcf
3P
MMbbl
Bcf
MMbbl
Bcf
Oil Equivalent
MMbbl
Total
244.8
592.0
681.5
1,134.8
1,095.6
1,912.8
1,482.1
Burgos
0.0
40.7
0.0
57.8
0.0
267.1
48.9
Cali
Cali-1
0.0
22.0
0.0
22.0
0.0
160.7
29.3
Dragón
Peroné-1
0.0
0.6
0.0
0.8
0.0
0.8
0.2
Grande
Grande-1
0.0
2.9
0.0
4.2
0.0
16.0
2.8
Murex
Murex-1
0.0
12.9
0.0
18.4
0.0
40.0
7.0
Ricos
Ricos-1001
0.0
2.3
0.0
12.4
0.0
49.6
9.5
244.8
440.8
681.5
798.2
1,095.6
1,331.9
1,372.9
Southeastern
Ayatsil
Ayatsil-DL1
88.6
9.2
184.2
19.2
398.7
41.5
406.7
Kambesah
Kambesah-1
16.1
18.2
24.8
28.3
24.8
28.3
30.9
Pit
Pit-DL1
64.9
8.9
278.2
38.3
366.1
50.3
375.9
Rabasa
Rabasa-101
3.7
2.2
15.9
9.8
28.3
17.3
32.6
Tecoalli
Tecoalli-1
6.1
4.3
15.4
10.8
46.2
32.4
54.0
Teotleco
Teotleco-1
Tsimin
Tsimin-1
Xanab
Yaxché
3.7
9.9
34.4
92.5
47.2
126.3
77.6
41.8
373.7
61.3
547.1
109.4
976.4
307.6
Xanab-DL1
9.7
9.1
42.1
39.4
49.8
46.6
59.5
Yaxché-1DL
10.2
5.2
25.1
12.9
25.1
12.9
28.2
Veracruz
0.0
110.6
0.0
278.9
0.0
313.8
60.3
Aral
Aral-1
0.0
2.0
0.0
4.1
0.0
8.0
1.5
Aris
Aris-1
0.0
14.6
0.0
14.6
0.0
14.6
2.8
Cauchy
Cauchy-1
0.0
86.1
0.0
206.8
0.0
223.2
42.9
Kabuki
Kabuki-1
0.0
6.9
0.0
44.3
0.0
56.3
10.8
Maderaceo
Maderaceo-1
0.0
0.9
0.0
9.1
0.0
11.7
2.2
44
serves in the Litoral de Tabasco Integral Business Unit,
and 1,068.2 billion cubic feet of natural gas, which are
equal to 449.3 million barrels of oil equivalent; the res
ervoirs discovered are light oil and gas-condensate.
Additionally, in the deep waters of the Gulf of Mexico
the Tamil-1 well discovered a resource exceeding 200
million barrels of oil equivalent that will probably be
classified as reserves when at least one other well
confirms the extension of the structure identified. In
the Southern Region, the Rabasa-101 well in the Cinco
Presidentes Integral Business Unit and the Teotleco-1
well in the Muspac Integral Business Unit, added 75.5
million barrels of oil and 143.6 billion cubic feet of
natural gas, which jointly equal 110.1 million barrels
of oil equivalent.
In reference to non-associated natural gas reserves,
all the dry and wet gas reservoirs were discov
ered in the Northern Region, which manages the
Burgos and Veracruz basins, that is, there was an
accumulated 3P reserve of 580.9 billion cubic feet
of gas, which is equal to 109.2 million barrels of oil
equivalent.
The Cali-1, Grande-1, Murex-1, Peroné-1, and Ri
cos-1001 exploratory wells, in the Burgos Basin dis
covered non-associated 3P gas reserves totaling 267.1
billion cubic feet of natural gas, which is equal to 48.9
million barrels of oil equivalent.
In the Veracruz Basin, dry gas reserves were discov
ered by the results in the Aral-1, Aris-1, Cauchy-1,
Kabuki-1, and Maderáceo-1 wells, which jointly
contributed a total of 313.8 billion cubic feet of gas,
amounting to 60.3 million barrels of oil equivalent in
3P reserves.
Table 5.2 describes the composition of the reserves
added in the 1P, 2P, and 3P categories, grouped at a
basin and regional level. Table 5.3 gives a regional
summary of the crude oil and natural gas reserves
added in the proved reserve (1P), proved plus prob
able reserve (2P), and the proved plus probable plus
possible (3P) categories, while indicating the type of
associated hydrocarbon.
The geological, geophysical, petrophysical, technical,
and dynamic aspects, of the most important reservoirs
discovered are described below; the hydrocarbon
composition and spatial distribution of the hydrocar
bon reserves in the reservoirs are also given, along
with a statistical summary.
Table 5.2 Composition of the hydrocarbon reserves of reservoirs discovered in 2008 by basin and by region.
1P
2P
3P
Basin
Crude Oil Natural Gas Crude Oil Natural Gas
Crude Oil Natural Gas Oil Equivalent
Region
MMbbl
Bcf
MMbbl
Bcf
MMbbl
Bcf
MMbbl
Total
244.8
592.0
681.5
1,134.8
1,095.6
1,912.8
1,482.1
Burgos
0.0
40.7
0.0
57.8
0.0
267.1
48.9
Northern
0.0
40.7
0.0
57.8
0.0
267.1
48.9
Southeastern
244.8
440.8
681.5
798.2
1,095.6
1,331.9
1,372.9
169.7
36.3
487.2
85.7
789.6
120.1
813.5
67.8
392.3
143.9
610.2
230.5
1,068.2
449.3
Southern
7.3
12.1
50.3
102.2
75.5
143.6
110.1
Veracruz
0.0
110.6
0.0
278.9
0.0
313.8
60.3
0.0
110.6
0.0
278.9
0.0
313.8
60.3
Northern
45
Discoveries
Table 5.3 Composition of the hydrocarbon reserves of reservoirs discovered in 2008 by hydrocarbon type.
Crude Oil
Heavy
Light
Natural Gas
Superlight
Associated
Category
Region
MMbbl
MMbbl
MMbbl
Bcf
Non-associated
G-C*
Bcf
Wet Gas
Bcf
Dry Gas
Bcf
Total
Bcf
1P
Northern
Southern
157.3
153.6
0.0
0.0
3.7
42.1
16.1
26.0
0.0
0.0
45.5
0.0
41.8
0.0
3.7
67.1
36.3
18.6
0.0
12.1
373.7
0.0
373.7
0.0
0.0
2.3
0.0
0.0
2.3
0.0
148.9
0.0
0.0
148.9
0.0
524.9
0.0
373.7
151.2
0.0
2P
Northern
Southern
478.3
462.4
0.0
0.0
15.9
107.5
24.8
82.7
0.0
0.0
95.7
0.0
61.3
0.0
34.4
251.1
85.7
63.1
0.0
102.2
547.1
0.0
547.1
0.0
0.0
12.4
0.0
0.0
12.4
0.0
324.2
0.0
0.0
324.2
0.0
883.7
0.0
547.1
336.6
0.0
3P
Northern
Southern
793.1
764.8
0.0
0.0
28.3
145.9
24.8
121.1
0.0
0.0
156.6
0.0
109.4
0.0
47.2
355.5
120.1
91.8
0.0
143.6
976.4
0.0
976.4
0.0
0.0
49.6
0.0
0.0
49.6
0.0
531.3
0.0
0.0
531.3
0.0
1,557.3
0.0
976.4
580.9
0.0
5.2 Offshore Discoveries
The exploratory activities produced favorable results
with the booking of reserves in the offshore part of
the Southeastern Basins; specifically in the Salina del
Istmo, Sonda de Campeche, and Litoral de Tabasco
sub-basins; and in the Gulf of Mexico Deepwater
Basin.
Heavy oil reserves were discovered in the Sonda de
Campeche with the drilling of the Ayatsil-DL1 and PitDL1 delineation wells that added a 3P reserve of 782.6
million barrels of oil equivalent, while the Kambesah-1
contributed with light oil reserves amounting to 30.9
million barrels of oil equivalent.
Heavy oil reserves were added in the Xanab fields
of the Litoral de Tabasco by the new reservoir in the
Upper Jurassic Kimmeridgian, and Yaxché that added
reservoirs in Tertiary sands. Miocene producing sands
were found in the Tecoalli field at the Salina del Istmo
46
sub-basin. Jointly, the above fields added 449.3 mil
lion barrels of oil equivalent.
Offshore discoveries contributed with 85.2 percent of
the total reserves, which means an accumulated 3P
reserve of 1,020.1 million barrels of oil and 1,188.3 bil
lion cubic feet of natural gas, which together is equal
to 1,262.8 million barrels of oil equivalent.
Furthermore and as mentioned before, heavy oil
resources at the Cretaceous level were found in the
Gulf of Mexico Deepwater Basin by means of well
Tamil-1, amounting to more than 200 million barrels
of oil equivalent, which will probably be reclassified
as reserves once the extent of the reservoir has been
confirmed as a result of seismic interpretation, with
the drilling of, at least, one additional well.
A description of the geological, geophysical, petro
physical and engineering aspects, of the most impor
tant reservoirs discovered in 2008 is given below.
Southeastern Basins
Stratigraphy
Tsimin-1
The geological column cut by well Tsimin-1 is formed
by Tertiary siliciclastic rocks interspersed with shales
and sandstone, with some thin stratifications of do
lomite mudstone. For the Tithonian, carbonaceous
shales are interspersed with shaly limestone, while
there is shaly dolomitic mudstone and sandy mud
stone in the Kimmeridgian. The well reached a depth
of 5,728 meters below sea level, and its chronostrati
graphic tops were established through the analysis
of planktonic foraminifer indexes found in the cutting
and core samples.
The Tsimin field is located in the territorial waters of
the Gulf of Mexico, off the coast of Frontera, Tabasco,
at 11 kilometers from shore to the north, and 87 kilo
meters northwest of Ciudad del Carmen, Campeche,
Figure 5.1.
Structural Geology
The reservoir consists of an elongated, northwestsoutheast asymmetric anticline that was formed during
the Miocene compression, affected to the north and
east by a reverse faulting system that forms the high
block of the Tsimin-1 well structure fault, Figures 5.2
and 5.3. This compressive faulting system associated
with complex saline tectonics generated seal condi
tions that favored the trapping of hydrocarbons.
Trap
The trap is structural, formed by the intrusion of a
large saline dome lying northeast-southwest. The
saline intrusion affects the highest part of the structure
in a north-south direction, Figure 5.4.
Taratunich
Le
Ixtal
N
Ixtoc
Toloc
Pol
Uech
E
S
Caan
Och
Ayín
W
Abkatún
Batab
Chuc
Kax
Kay
Wayil
Alux
Homol
B l tikú
Bolontikú
Sinán
Gulf de Mexico
Citam
Kab
Tsimin-1
Teekit
Xanab
Hayabil
May
Misón
Kix
Yum
Frontera
Yaxché
Dos Bocas
0
20 km
Figure 5.1 Map showing the location of the Tsimin-1 well.
47
Discoveries
N
W
E
S
Tsimin-1
Figure 5.2 Structural contouring for the Upper Jurassic Kimmeridgian of the Tsimin field, showing the
distribution of reserves.
Tsimin-1
500
1,000
Tsimin-1
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
Figure 5.3 Seismic cross-section passing through Tsimin-1 well, showing the top of the Upper Jurassic Kimmeridgian horizon interrupted
by the presence of a saline dome.
48
N
W
E
S
Tsimin-1
Proved Reserve
Probable Reserve
Possible Reserve
Figure 5.4 Seismic interpretation in time of the Tsimin-1 well.
Storage Rock
Seal
The reservoir’s most important storage rock dates
from the Upper Jurassic Kimmeridgian, and it is
mainly formed by mudstone and wackestone from in
terclasts. The rock is light brown, partially dolomitized,
compact, with secondary porosity in microfractures
and dissolution cavities, some of them filled with
calcite and with residual oil, and even showing some
traces of disseminated pyrite.
The seal consists of Upper Jurassic Tithonian rocks
composed of carbonaceous shales, shaly limestone,
and shaly dolomitic mudstone.
Source Rock
Because of their high organic content, the rocks of the
Upper Jurassic Tithonian are responsible for generat
ing the field’s hydrocarbons, and they were deposited
in a deep marine sedimentary environment.
Reservoir
The upper part of the reservoir is formed by carbonated
and dolomitized rocks corresponding to oolitic banks
of the Upper Jurassic Kimmeridgian, the top of the res
ervoir is at 5,215 meters below sea level and structural
closing is at 5,630 meters, in rocks corresponding to
lagoon facies. Thus, the production test developed in
the well therefore reported a flow of gas and conden
sate, with initial average daily production rates of 4,354
barrels of oil and 13.8 billion cubic feet of gas.
49
Discoveries
Reserves
The estimated original 3P volumes are 253.5 million
barrels of oil and 1,565.7 billion cubic feet of gas. 3P
reserves are 109.4 million barrels of oil and 976.4 bil
lion cubic feet of gas, which are jointly equal to 307.6
million barrels of oil equivalent. The proved and prob
able reserves are estimated at 117.7 and 54.7 million
barrels of oil equivalent, respectively.
Ayatsil-DL1
The Ayatsil field is in the territorial waters of the Gulf
of Mexico, at approximately 130 kilometers northwest
of Ciudad del Carmen, Campeche, in a water depth
of 114 meters, Figure 5.5. The field was discovered
in 2006 with the Ayatsil-1 well that penetrated 160
meters into the Upper Cretaceous Breccia reservoir
and it turned out to be a producer of 10.5 API degrees
oil with a daily flow of 4,126 barrels. Given the mag
N
W
460
500
nitude of the trap and the opportunity area offered in
terms of oil volume reclassification and increase, well
Ayatsil-DL1 was drilled and completed in 2008, and it
cut a sedimentary column of more than 600 meters in
the Lower, Middle and Upper Cretaceous; it was also
a producer of heavy oil.
Structural Geology
The structure of the Ayatsil field at the Cretaceous
level is defined as a being composed of three struc
tural highs whose main axes run in a northwesternsoutheastern direction. These three structures are
joined in the east, Figure 5.6. The structural complex
covers an area of approximately 91 square kilome
ters, and it is bounded to the east by a northeast
lateral fault and by reverse faults running northwest
to southeast and east to west. There is a dipping clos
ing to the west and it is bounded by the Comalcalco
fault. The Ayatsil-DL1 well reached the top of the
540
580
620
E
Tunich
Gulf of Mexico
S
Ayatsil-DL1
Maloob
Zazil-Ha
Lum
Bacab
Zaap
2,170
Ek
Balam
Ku
Cantarell
Kutz
Ixtoc
Chac
Takín
2,130
500 m
200 m
2,090
100 m
50 m
Cd. del Carmen
25 m
2,050
Dos Bocas
Frontera
0
10
20
30
40 km
Figure 5.5 Location of the Ayatsil-DL1 well in territorial waters of the Gulf of Mexico.
50
Loc 2DL
Loc.
Ayatsil-1
DL1
Figure 5.6 Structural contouring of the Upper Cretaceous Breccia top.
Upper Cretaceous Breccia at a depth of 4,047 meters
below sea level.
Stratigraphy
The stratigraphic column in the well consists of sedi
ments from the Upper Jurassic Tithonian to the Recent.
The Tithonian consists of shaly and bituminous mud
stone, showing a deep depositional environment with
restricted circulation. Mudstone-wackestone textured
bioclast and lithoclast carbonates predominate at the
Lower Cretaceous level, with a presence of accessory
cherts. The Middle Cretaceous is characterized by
bentonitic shaly limestones with accessory cherts
that are dolomitized and moderately fractured even
in the Ayatsil-DL1 well. Breccias associated with de
bris flows predominate along with a dolomitized and
fractured mudstone-wackestone textured limestone
with mobile heavy oil impregnation, predominate
in the Upper Cretaceous. Lithoclastic and bioclastic
dolomitized breccias with intercrystalline and vuggy
porosity are deposited at the top of the Upper Cre
taceous. The Tertiary consists of interspersed shales
with thin fine to medium grain sandstone alternations,
while the formations from Recent consist of poorly
consolidated clays and sands.
Trap
The trap is an anticline structure that includes three
elongated lobes with a noticeable east-west lie, all
of which are bounded reverse faults. Well Ayatsil-1
was drilled in the central lobe while Ayatsil-DL1 is
in the southern lobe, 3,900 meters southeast of the
former. The structure is affected by reverse faulting
on the northern and northeastern flanks, and the
51
Discoveries
structuring process is geologically associated with
the Maloob field.
to greenish-gray shales of formations from the Pa
leocene age.
Storage Rock
Reservoir
The reservoir is mostly represented by a dolomitized
sedimentary breccia formed by mudstone-wacke
stone fragments, with secondary porosity in fractures
and dissolution cavities, Figure 5.7.
According to the geochemical studies of the oil and
core samples, it was determined that the most im
portant hydrocarbon source rock in the Sonda de
Campeche dates from the Upper Jurassic Tithonian,
and it is formed by bituminous shales and shaly lime
stones, with abundant organic matter.
The water-oil contact was determined in well AyatsilDL1 at a depth of 4,228 meters below sea level in
the Upper Cretaceous Breccia formation by means
of pressure-production tests, well logs, engineering
data, and the results of core analyses. Nevertheless,
the reservoirs correspond to the Middle and Lower
Cretaceous in the highest structural position where
the fracturing and dolomitization are more intense, as
it has observed in analogous fields. Figure 5.8 shows
the oil-water contact position for the field. The well in
question was a producer of 11 API degrees oil with
a flow rate of 4,150 barrels per day, and it reached a
total depth of 4,710 meters.
Seal
Reserves
The seal rocks of the Upper Cretaceous breccias are
bentonitic, plastic and partially calcareous greenish
The original 3P volumes added as a result of well
Ayatsil -DL1 were 2,184.7 million barrels of oil and 88.4
Source Rock
Ayatsil-1
Ayatsil-DL1
Figure 5.7 Cores cut in the Cretaceous reservoir showing oil in the porous and fractured
system.
52
Loc. DL2
Ayatsil-1
Ayatsil-DL1
Recent
1,000
2,000
Pliocene
3,000
Oligocene
Eocene
4,000
Paleocene
Breccia
J. Tithonian
5,000
J. Kimmeridgian
Figure 5.8 Structural section of the Ayatsil field showing the water-oil contact.
billion cubic feet of gas. The associated 1P reserve is
estimated at 90.4 million barrels of oil equivalent, the
2P is 187.9 million barrels of oil equivalent and the 3P
reserve is 406.7 million barrels of oil equivalent.
N
W
460
500
Kambesah-1
The Kambesah field is located in the territorial waters
of the Gulf of Mexico, at approximately 92 kilometers
540
580
620
E
Tunich
Gulf of Mexico
S
Maloob
Zazil-Ha
Lum
Bacab
Zaap
Ek
Balam
Ku
Kambesah-1
2,170
Cantarell
Kutz
Ixtoc
Chac
Takín
2,130
500 m
200 m
2,090
100 m
50 m
Cd. del Carmen
25 m
2,050
Dos Bocas
Frontera
0
10
20
30
40 km
Figure 5.9 Map showing the location of the Kambesah-1 well.
53
Discoveries
northwest of Ciudad del Carmen, Campeche, west of
the Yucatán Platform, and 5.3 kilometers northeast of
the Ixtoc field, in a water depth of 55 meters, Figure
5.9. Geologically, it is located in the Pilar de Akal geo
morphological province in the Sonda de Campeche.
The Kambesah-1 exploratory well discovered a 30 API
degrees light oil reservoir similar to the Ixtoc field, in
shallow waters of the Gulf of Mexico, in Upper Cre
taceous rocks (breccia).
The current configuration of the structure at the Cre
taceous and Tertiary levels is due to the compression
during the Chiapaneca Orogeny, which is responsible
for the formation of the large structures in the area.
The Kambesah structure is limited by a normal fault
to the west with gentle dipping that belongs to the
same alignment as Ixtoc, Figure 5.11.
Structural Geology
The geological column of the field covers sedimentary
rocks that range from the Recent to the Upper Jurassic
Oxfordian. Studies indicate that the reservoir’s rock
deposits of the Upper Cretaceous age correspond
to debris flows and piles of these flows interspersed
with thin layers of fine pelagic sediments, shaly to
dolomitic, which were deposited in medium to deep
slope environments.
The origin of the Kambesah structure is related to both
the Upper Jurassic Kimmeridgian-Tithonian saline
thrust, and to the compressive events concerning
the Laramide and Chiapaneca Orogeny, Figure 5.10.
The salt accumulations started to migrate as soon
as the weight of the overlying sediments exerted
enough pressure to trigger the flow or movement
of salt towards shallower layers, thus generating the
respective domes. This structural pattern and its dome
structures lie approximately north-south, parallel to
the paleocoast of the Upper Jurassic Kimmeridgian,
and they affect the stratigraphic column, in some
cases even up to the Early Tertiary.
Stratigraphy
Trap
It is structural and made up of an asymmetric anticline
6 kilometers long and 2 kilometers wide. The limits are
a normal fault to the west and oil-water contact against
the fault at a depth of 3,760 meters below sea level.
Callovian Salt
Triassic?-Early Jurassic
Figure 5.10 Composed seismic line showing the structures and deformed salt deposits of the Jurassic Callovian.
54
N
W
E
S
potential load values, in addition to being
mature and distributed over most of the off
shore portion of the Southeastern Basins.
Seal
The Upper Cretaceous Breccia top seal of
the reservoir consists of an interspersing
of Lower Paleocene shale that varies later
ally in thickness from 20 to 40 meters. The
lateral seal also consists of a Paleocene
shale sequence because the jump of the
western fault put the storage rock against
the shaly sequence.
7 Km2
Reservoir
10 Km2
1 Km
Figure 5.11 Structural contouring of the Upper Cretaceous Breccia top.
The reservoir is in the upper part of the
Upper Cretaceous Breccia, which is where
the best petrophysical properties of the
reservoir are located, with porosity that
varies between 4 and 12 percent. The
facies are light gray dolomitized, slightly
shaly wackestone, with traces of bioturba
tion, and shaly laminations parallel to the
stratification planes. The well was a pro
ducer of 30 API degrees oil with an initial
flow rate of 1,432 barrels per day, and 1.6
million cubic feet of gas per day.
Storage Rock
Reserves
This reservoir’s storage rock is light gray dolomitized,
slightly shaly wackestone, with traces of bioturbation
and shaly laminations parallel to the stratification
planes.
Source Rock
The source rock is Upper Jurassic Tithonian, and the
studies using rock-oil geochemical correlations have
established that this rock feeds the Kambesah reservoir,
and that it is made up largely of clay-calcareous rocks
that are rich in organic matter and have the highest
The original 3P volumes are estimated at 82.4 million
barrels of oil and 93.8 billion cubic feet of gas. The
reserves added by this discovery amount to 20.0 mil
lion barrels of oil equivalent in the 1P category, and
30.9 million barrels of oil equivalent for the 2P and
3P categories.
Tecoalli-1
The field discovered is 22 kilometers northeast of the
Amoca-1 well and 31 kilometers northwest of Dos
55
Discoveries
Taratunich
Le
Ixtal
N
Ixtoc
Abkatún
Batab
Toloc
Pol
Uech
E
S
Caan
Och
Ayín
W
Chuc
Kax
Kay
Wayil
Alux
Homol
Bolontikú
Sinán
Gulf of Mexico
Citam
Kab
Hayabil
May
Teekit
Tecoalli-1
Xanab
Misón
Kix
Yum
Frontera
Yaxché
Dos Bocas
0
20 km
Figure 5.12 Map showing the location of the Tecoalli-1 well.
Bocas, Tabasco, Figure 5.12. Geologically it is located
in the Salina del Istmo Basin.
Structural Geology
The field is formed by an anticline with closing against
normal faults to the east, northeast and southwest,
generated by block expulsion, and it has its own
structural closure downdip to the west. It is limited
to the northeast by facie changes. It is thought that
the salt evacuation in this area occurred mainly dur
ing the Pleistocene-Recent because there are signs
of syntectonic folds and wedges derived from the
Pliocene contraction.
Stratigraphy
The geological column of the field covers siliciclastic
sedimentary rocks that range from the Lower Pliocene
to the Recent-Pleistocene. The chronostratigraphic
tops were established through the analysis and iden
tification of planktonic foraminifer, indexes in the drill
cuttings and core samples.
56
Trap
The reservoir is formed by siliciclastic rocks of the
Lower Pliocene, and the discovery well was drilled
very close to the culminating part of the structure.
This reservoir has a structural and stratigraphic com
ponent that covers an area of 20.6 square kilometers,
Figure 5.13.
Storage Rock
The reservoir’s storage rock is mostly formed by
angular to subrounded quartz fine grain sandstone,
moderately classified and with oil impregnation, Fig
ure 5.14. Additionally, there are signs of monocrystal
line quartz, plagioclases, clay fragments, dispersed
organic matter, calcite and disseminated pyrite. Poros
ity is very good; mostly interangular.
Source Rock
As regards the source rock, the results of the bio
markers analyzed indicate that these hydrocarbons
GR
Rt
Tecoalli-1
W
E
Sandstone Top
2,000
Sandstone Bottom
2,500
3,000
3,500
Figure 5.13 Seismic-structural cross-section revealing the field’s structural and stratigraphic
characteristics.
0
GR_Cores
0
y
Gamma Ray
100
100
0.2
Resistivity
y
20
Reservoir Top: 3,371 m.
3,375
C-3
3,379 m.
Interval II (3,384 - 3,405 m.)
3,400
Tecoalli-1, 3,380.54 m, 4X Natural Light
C-4
Reservoir Bottom: 3,418 m.
Physical Limit
3,425
C-3
3,380 m.
Figure 5.14 Reservoir storage rock in the Tecoalli field showing hydrocarbon impregnation in core 3.
57
Discoveries
are generated in Upper Jurassic Tithonian rocks,
in a carbonated marine environment with a certain
siliciclastic influence.
rates of 3,560 barrels and 2.3 million cubic feet were
measured, at the interval 3,384-3,405 meters below
the rotary table interval.
Seal Rock
Reserves
The seal of the upper part of the reservoir is formed
by 321 meters of shale cut by the well, and by shales
that graduate to limolites with a thickness of 14 meters
in the lower part.
The estimated original 3P volumes were 220.2
million barrels of oil and 154.1 billion cubic feet of
gas; the distribution is shown in Figure 5.15. The
reserves estimated for the 1P, 2P and 3P categories
are 7.1, 18.0 and 54.0 million barrels of oil equiva
lent, respectively.
Reservoir
The drilling of this well led to the discovery of a reser
voir producing 29 API degrees light oil; the dynamic
behavior of said well adjusts to a homogenous model
with variations in the effective flow thickness and edge
effects, associated with a system of internal platform
bars. During the production test, daily oil and gas flow
Xanab-DL1
The field is in the territorial waters of the Gulf of
Mexico, within the area known as the Reforma-Akal
Tectonic Pillar, 13 kilometers northwest of the Dos
Bocas sea terminal in Tabasco. Geologically it is
N
W
E
S
Possible Reserve
Area: 16.2 Km2
Probable Reserve
Area: 2.4 Km2
Proved Reserve
Area: 2.0 Km2
Figure 5.15 Distribution and classification of reserves in the Tecoalli field.
58
Taratunich
Le
Ixtal
N
Ixtoc
Abkatún
Batab
Toloc
Pol
Uech
E
S
Caan
Och
Ayín
W
Chuc
Kax
Kay
Wayil
Alux
Homol
Bolontikú
Sinán
Gulf of Mexico
Citam
Kab
Hayabil
May
Xanab-DL1
Xanab
Teekit
Misón
Kix
Yum
Frontera
Yaxché
Dos Bocas
0
20 km
Figure 5.16 Map showing the location of the Xanab-DL1 well.
located in the western part of the Comalcalco pit,
Figure 5.16.
penetrate it because the total depth of the well was
5,980 meters, Figure 5.18.
Structural Geology
Stratigraphy
It is an asymmetric dome structure separated by a
reverse fault running east to west. Towards the central
part, in the most prominent structural height to the
north of well Xanab-1, there is a series of normal faults
in an east to west direction that are interrupted to the
east by small parallel faults. A mostly southwest to
northeast trend dominates the southeastern portion
that is perpendicular to the compressive structures.
Block DL1 is 500 meters higher than the structure
where the Xanab-1 well is located, Figure 5.17.
The geological column cut during drilling in the
formations corresponding to the Tertiary is formed
by siliciclastic rocks with some carbonated horizons
towards the base. The Cretaceous mostly consists
of mudstone and wackestone of foraminifers and
intraclasts, with thin interspersing of shale and shaly
mudstone. The Upper Jurassic Tithonian is repre
sented by shaly limestones and carbonous shale, and
the Upper Jurassic Kimmeridgian is predominantly
wackestone with ooidal packstone interspersing. The
chronostratigraphic tops were established through
the analysis of fauna types in the drill cuttings and
cores samples.
Trap
It is structural and bounded to the southeast by a
normal fault. The reservoir rock is formed by naturally
fractured carbonated rocks of the Upper Jurassic
Kimmeridgian; the top was found at 5,610 meters
below sea level, without being able to completely
Storage Rock
The reservoir storage rock that was analyzed by means
of core and drill cuttings is formed by mudstone,
59
Discoveries
Kuché-1
Xanab-DL1
Xanab-1
Yaxché-101
Yaxché-1
Figure 5.17 Structural section showing the structural characteristics of the reservoir and the
Xanab-1 and Xanab-DL1 wells.
packstone, and grainstone of ooids and intraclasts. It
has natural factures with good black oil impregnation,
shaly parts and it is partially dolomitized. The primary
porosity is microcrystalline, and the secondary porosity
has dissolution and intercrystalline fractures that show
good residual oil impregnation and are occasionally
sealed by calcite. Additionally, there are sporadic hori
zons of oil-impregnated mesocrystalline dolomites.
N
W
E
S
0
1
2
3
Figure 5.18 Structural contouring of the Upper Jurassic Kimmeridgian reservoir top.
60
4 km
Source Rock
As regards the source rock, the results of the bio
markers analyzed make it possible to determine that
the hydrocarbons were generated in Upper Jurassic
Tithonian rocks, which are responsible for the genera
tion of the reservoir’s hydrocarbons because of their
high organic matter content.
and in the Southeastern Basins of the Southern Re
gion. The 3P reserves added through discoveries
of onshore wells amount to 219.3 million barrels of
oil equivalent, while the reserves in the 1P and 2P
categories are 38.9 and 139.1 million barrels of oil
equivalent, respectively. In terms of natural gas, the
onshore discoveries total 724.5 billion cubic feet of 3P
reserves. A detailed explanation of the most important
discoveries in 2008 is given below.
Seal Rock
Burgos Basin
The seal in the upper part of the reservoir is more
than 100 meters thick, formed by shaly carbonated
rocks (mudstone) and dark gray to black shale of the
Upper Jurassic Tithonian.
Reservoir
The interval tested at a depth of 5,610
to 5,665 meters below the rotary table
was a producer of 33 API degrees oil
with a flow rate of 9,200 barrels per
day. The reservoir follows the double
porosity model, primary (interparticu
lar) and secondary (in fractures and dis
solution), associated with an open sea
sedimentary environment.
Cali-1
It is located approximately 33 kilometers southwest of
Reynosa, in the municipality of Gustavo Díaz Ordaz,
Tamaulipas, Figure 5.19. The target of the well was to
N
W
E
S
Camargo
Jazmín-1A
Valadeces-6
Integral-1
Camargo Sur-1A
Cañón
Cali-1
L
Ferreiro-1
0
The onshore discoveries have mostly
been in the Burgos, Sabinas, and Vera
cruz basins of the Northern Region,
1
2
4
6
8
10 Km
Presa Falcón
Reynosa
Matamoros
Herreras
5.3 Onshore Discoveries
Lomitas
Draker-1
Reserves
The original 3P volumes are estimated
at 382.0 million barrels of oil and 357.2
billion cubic feet of gas. The estimated
reserves for the 1P, 2P, and 3P catego
ries are 11.6, 50.4, and 59.5 million bar
rels of oil equivalent, respectively.
Misión
Reynosa
Camargo
Gulf of Mexico
Figure 5.19 Map showing the location of the Cali-1 well in the Camargo
project.
61
Discoveries
X/Y:
ters
534500
536500
538500
540500
542500
544500
N
W
2318.59
2344.71
2370.83
2396.95
2423.07
E
2894800
00
24
2894800
25
27
S
25
6
7
2 47
5
5
25
2
25
2892800
25
INTEGRALINTEGRAL-1
75
262 5
2892800
26
INTEGRAL-1
25
25
4
52
5
24
75
2
2
2890800
5
1700
23
7
2890800
75
1825
1575
1600
1625
1650
1675
1700
1725
1750
1775
1800
1825
242 5
2 32
5
1575
CALI-1
2888800
2888800
7
23
12
5
2
02
CALI-1
5
2
2
CALI-101
23
75
3
5
25
FERREIRO-1
FERREIROFERREIRO-1
2886800
1717.85
1743.97
1770.09
1796.21
1822.33
1848.44
1874.56
1900.68
1926.80
1952.92
1979.04
2005.16
2031.28
2057.40
2083.52
2109.64
2135.76
2161.88
2188.00
2214.12
2240.23
2266.35
2292.47
2318.59
2344.71
2370.83
2396.95
2423.07
2449.19
2475.31
2501.43
2527.55
2553.67
2579.79
2605.91
2632.03
2658.14
2684.26
2710.38
2736.50
2762.62
2886800
2325
2 2 75
2225
2884800
22
2884800
2
5
Cali-1CALICALI-1
ReservoirARENA
EJM4 EJM4
Map
CONFIGURACIÓ
EN PROFUNDIDAD
CONFIGURACIÓ N Structural
536500
538500
2
534500
75
25
21
540500
542500
544500
Figure 5.20 Structural and stratigraphic map of the Cali field.
find gas reserves in deltaic sandy sequences, associ
ated with a progradant complex of estuary bars and
distributary channels in the Eocene Jackson play.
sediments occurred towards the lower blocks of
fault segments.
Stratigraphy
Structural Geology
The well was completed in a structure associated
with a high block adjacent to an Eocene Jackson
growth fault and caused by the convergence of two
segments of extensional faults, with an inclination
to the east, giving rise to a ramp-like relief structure,
Figure 5.20.
Trap
The trap is structural with a stratigraphic compo
nent and it is associated with a structural high point,
with a fault closing. The accumulation of sediments
was especially towards the edges of the expansion
fault; consequently, the greatest accumulation of
62
The well was drilled to a depth of 2,411 meters below
sea level. The geological column cut is formed by
sediments that range from the Middle Eocene Jackson
formation to the Oligocene Frio No Marino formation,
which is outcropping. A production test was positive
within the Middle Jackson formation. The geological
model of these sands, which shows characteristics
that are similar in the well logs, was estuary bars as
sociated with a wave-dominated delta, Figure 5.21.
Storage Rock
The storage rock in these reservoirs is lithologically
made up of fine grain sandstone, quartz and lithic
fragments, sub-rounded and regularly sorted.
Figure 5.21 Sedimentary model of the Ejm4 sand.
Source Rock
This zone’s hydrocarbon source rock corresponds to
shale rocks belonging to the Wilcox Paleocene forma
tion, with good characteristics for the generation of
hydrocarbons because it contains a high amount of
organic matter.
of 20 percent, water saturation of 44 percent and per
meability of 5 millidarcy. The porosity values shown
in sands like these are generally good, which is also
the case of those obtained in this reservoir. The well
reported an initial flow of 23.1 million cubic feet of
gas per day during the production test.
Reserves
Seal Rock
The seal rock of the play corresponds to shaly pack
ages of considerable thickness up to 200 meters,
belonging to the Upper Jackson formation. This has
been corroborated by data from well logs and drill
cutting samples.
The original 3P volume of gas is 230.1 billion cubic
feet of gas, while the original 1P, 2P, and 3P reserve
volumes are estimated at 22.0, 22.0 and 160.7 billion
cubic feet of natural gas, respectively.
Veracruz Basin
Reservoir
Cauchy-1
The reservoirs are made up of fine grain quartz sand
stone and lithic fragments, with an average porosity
Cauchy-1 is located on the coastal plain of the Gulf
of Mexico at approximately 19.6 kilometers south
63
Discoveries
N
W
Veracruz
E
S
Miralejos
Gulf of Mexico
Cópite
Vistoso
Mata Pionche
Playuela
Alvarado
Mecayucan
Madera
Apertura
Angostura
Papán
Cocuite
Aral-1
Lizamba
Perdiz
Tierra Blanca
Aris-1
Estanzuela
Cosamaloapan
Arquimia
San Pablo
Rincón Pacheco
Nopaltepec
Mirador
Veinte
Novillero
Tres Valles
0
10
Kabuki-1
3D Norte de
Tesechoacán
1,024 Km2
Cauchy-1
20 Km.
Figure 5.22 Map showing the location of the Cauchy-1 well.
east of Cosamaloapan, Veracruz, and 10.2 kilometers
southeast of the Novillero-10 well in the municipality
of Chacaltianguis, Veracruz, Figure 5.22. Geologically,
it is located in the Veracruz Tertiary Basin and seismi
cally, it is on line 267 and trace 768, within the Norte de
Tesechoacán-3D cube. The well accomplished its target
of evaluating the sandstones deposited as channeled
facies and overflows associated with basin floor fans of
the Upper Miocene, and it was therefore a producer of
dry gas and reached a total depth of 1,950 meters.
Structural Geology
The main reservoir is associated with a combined trap.
The Cauchy-1 well cut through this reservoir’s longi
tudinal axis, which lies in a northwest to southeast
64
direction. The stratigraphic component is interpreted
as a basin floor fan in channel facies and lobes with
apparent contribution from the southwest, which
indicates that there are strong contributions of sedi
ments in the southern part that allowed the formation
of stratigraphic traps associated with the preexisting
structures, Figure 5.23.
Trap
The producing horizon PP1 in this well is associated
with a combined trap, with a strong structural compo
nent, located in a zone with high seismic amplitude.
The static model of this reservoir was obtained on the
basis of the structure’s geometry, the distribution of
seismic anomalies, and the sedimentary model that
Cauchy-1
1,200
1,400
Obj. 1: 1,730 mbsl
PT1:
P 2,590
P=
2 590 psii
Obj. 2: 1,777 mbsl
Qg= 9.205 MMcfd
7/16”
1,600
TD: 1,950 m
Figure 5.23 Seismic line illustrating the structural behavior of the reservoir.
N
W
E
S
Northern Probable Area:
4.5 Km2
Possible Area:
2 Km2
Proved Area:
3.5 Km2
Cauchy-1
Southern Probable Area:
2 Km2
0
1 Km.
Figure 5.24 Structural contouring of the main reservoir, with
the distribution of the reserve category areas.
65
Discoveries
makes up the result of the petrophysical analysis,
Figure 5.24.
Stratigraphy
A basin floor submarine fan environment was defined
for the reservoir that was formed by two principal
distributary channels, laterally and vertically amal
gamated, with box-like well log patterns, and parallel
structures observed in cores. These channels are
interwoven and extend approximately 9 kilometers
long by 3 kilometers wide in one complex.
Source Rock
The hydrocarbon source rock for this zone corre
sponds to shales belonging to Miocene formations,
with good generation characteristics because they
contain a considerable amount of organic matter.
Seal Rock
The seal rock of the play corresponds to shaly pack
ages of considerable thickness, of up to dozens of
meters, in the Upper Miocene, and associated with
basin floor facies.
Storage Rock
Reservoir
In the most important reservoir, the storage rock is
formed by medium to coarse grain, dark brown sand
stone, lithic debris, quartz and, to a lesser extent, mod
erately classified and sub-angular feldspars. Given
the composition, it is largely classified as litarenite
that graduates to sublithic arenite. Core 8, cut at the
interval 1,829-1,838 meters below the rotary table, is
representative of this reservoir, Figure 5.25. In general,
the rock sample shows intergranular primary porosity
of up to 32 percent.
Cauchy 1
Cauchy-1
The petrophysical analysis carried allowed the defi
nition of the interval at 1,792-1,849 meters below
rotary table, with a gross thickness of 57 meters,
net impregnated thickness of 30 meters, and con
sequently, a net/gross thickness ratio of 62 percent.
The average values determined were porosity of
25 percent, permeability of 425 millidarcy, water
saturation of 17 percent, and a clay volume of 13
percent. For the cores cut inside the reservoirs, the
Core 8
Interval: 1,829 - 1,838 m.
C-1
C-2
 ==27.15
27.15
 == 1,242
1242 md
md
C-3
C-4
C-5
C-6
C-7
C-8
Figure 5.25 Photograph of core 8 of the Cauchy-1 well.
66
average porosity from laboratory varies from 21 to
31 percent, while the range obtained for permeability
is 5 to 1,250 millidarcy. Interval 1,792-1,849 reported
and initial flow rate of 9.2 million cubic feet of gas
per day.
Reserves
The estimated original 3P volume of natural gas
was 372.1 billion cubic feet. The reserve added by
the Cauchy-1 well in the 1P, 2P, and 3P categories
amounts to 86.1, 206.8, and 223.2 billion cubic feet
of gas, respectively.
Southeastern Basins
Rabasa-101
The field is located in the Agua Dulce municipality,
Veracruz, at 3,950 meters southeast of the Rabasa-1
well, and 25.4 kilometers southeast of the city of Coat
zacoalcos, Veracruz, Figure, 5.26. The field belongs
to the Cinco Presidentes Integral Business Unit, and
geologically it is located within the Salina del Istmo
Basin, in the geological province of Southeastern
Tertiary Basins. The seismic information corresponds
to the Rodador 3D study. The Rabasa-101 well was
completed as an oil producer in sediments of the
Lower and Middle Miocene.
Structural Geology
The structure is a faulted anticline, truncated by salt
bodies to the northeast and southwest, with general
dipping to the west. The reservoirs in the Middle Mio
cene are affected by compressive tectonics that gave
rise to a zone of folding to the southeast and they are
affected by two faults that limit the structure in that
direction, as can be seen in Figure 5.27.
Stratigraphy
The sedimentary model corresponds to deposits of
turbidities that consist of large packages of sands
Gulf of Mexico
Rabasa-1
Rabasa-101
Figure 5.26 Map showing the location of the Rabasa-101 well.
67
Discoveries
NW
Loc. Tonalli-1
1,000
Gurumal-1 Gurumal-2 Rabasa-1
Rabasa-101
SE
Plio-Pleistocene
Lower Pliocene
1,662 m.
Upper Miocene
2,000
Salt
Middle Miocene
Lower Miocene
3,000
OBJ-1 ( 2,900 m.)
OBJ-2 ( 3,950 m.)
3,707 m.
4,000
4,000 m.
4,600 m.
5,000
5,187 m.
Figure 5.27 Seismic line illustrating the structural behavior of the reservoir.
with thin layers of shale, with shallow to medium
depth bathymetry. The distribution follows the con
tribution direction, that is, southeast to northwest.
The deposits finally form a complex system of chan
nels and fans on the basin slope and floor, where
the sandy bodies reach their greatest thickness,
Figure 5.28.
Mountains
Coast Line and
Platform Margin
Trap
It is a structural anticline lying in a southwest-northeast
direction and with closure at both ends. The structure
has a closure on the northern and southern flanks at the
level of the two reservoirs, while there is a salt closure
to the west and east. These reservoirs are compart
Coastal Plain
Conglomerates
Sandy
Turbidites Fans
Basin
Slope
Canopie and Saline Intrusion
Rabasa-101
Deep Turbiditic
Sandstones Fans
Figure 5.28 Sedimentary model established for the area of the field.
68
Reservoir 1 Top (2,565 m)
Middle Miocene
N
Gurumal-1
3750
0
400
Depth (m)
W
Reservoir 2 Top (3,198 m)
Lower Miocene
F-2
F-1
E
N
4750
4250
3250
W
E
3500
Gurumal-2
3750
S
4750
S
4000
47
4250
50
4500
4500
F-3
00
45
4750
00
4000
5000
75
0
35
Gurumal-1
5000
3000
00
50
Gurumal-2
50
47
Salt
4500
4750
Rabasa-1
4750
00
40
00
37
50
4750
30
3250
Salt
50
F-4
00
Rabasa-1
Rabasa-101
42
50
5000
50
37
4750
3000
Depth (m)
3250
3500
450
0
3750
Salt
F-4
3250
4500
3500
F-6
4000
4000
Rabasa-101
4250
F-6
50
42
4500
4750
5000
50
42
3500
3500
Salt
ESC.1:25,000
ESC.1:25,000
367 500
370 000
372 500
375 000
Figure 5.29 Structural contouring of the reservoirs’ tops.
mentalized due to the faulting in the zone; in both cases
and although the traps are combined, the stratigraphic
component defines the reservoir’s limits. Figure 5.29
shows the reservoirs’ structural contouring.
Jurassic Tithonian. The quality of the organic matter
present in the Tithonian corresponds to Type II and it
has an advanced state of maturity, as determined by
geochemical studies of the biomarkers.
Storage Rock
Seal Rock
This is made up of quartz sandstones, rock fragments,
feldspars, and micas. The grain size varies from me
dium to coarse and occasionally it is a conglomerate;
the cement is clay-calcareous, the classification is
poor to moderate, and it is poorly consolidated; it
corresponds to a system of turbidite deposits that
have been greatly influenced by saline intrusions.
The quality and characteristics of the storage rock
depend on the geomorphology and distribution of
channels and fans.
The seal rock for this zone consists of Lower Mio
cene shales that are interspersed in this sequence.
Furthermore, the presence of an upper seal formed
by anhydrite to the northeast of the reservoir is
considered.
Source Rock
In this basin, the hydrocarbon source rock corre
sponds to clay-calcareous sediments of the Upper
Reservoir
The reservoirs are formed by quartz sandstone, rock
fragments, feldspar and micas. The petrophysical
characteristics show that the resistivity is generally
low, in a range of 2 to 4 ohms-meter with some varia
tions of 20 ohms-meter. The porosity ranges from 19
to 28 percent and the water saturation is 19 to 50 per
cent. The well completed at the Lower Miocene level
69
Discoveries
had an initial daily production of 1,867 barrels of 27
API degrees of oil, and 1.2 million cubic feet of gas.
Reserves
The 3P original oil volume is 123.0 million barrels, while
the 1P, 2P and 3P original reserves are 3.7, 15.9, and
28.3 million barrels of crude oil, respectively, which
when associated gas is added total 4.2, 18.3, and 32.6
million barrels of oil equivalent, respectively.
Teotleco-1
The well is in the coastal zone of the Gulf of Mexico,
geologically; it belongs to the Chiapas-Tabasco Meso
zoic area. It is located 18 kilometers to the southeast of
Cárdenas, Tabasco, Figure 5.30. The target was to add
hydrocarbon reserves in Upper, Middle and Lower Cre
taceous rocks, and in the Upper Jurassic Kimmeridgian
producer formations in the area. The well was complet
ed as a producer of light oil in Middle Cretaceous rocks,
and it reached a developed depth of 5,810 meters.
Structural Geology
The structure that makes up the reservoir corresponds
to an anticline in a west to east direction. The anticline
has a dipping closure of the southern and eastern lay
ers, where a reverse fault separates it from the Cactus
field, while to the northeast it is limited by a reverse
fault and normal fault to the northwest, Figure 5.31.
Trap
It is structural and it corresponds to a block adjacent to
the Cactus field, from which it is separated by a com
bined reverse fault with the presence of saline intrusions
in the area. The trap is split internally into two blocks
as a result of a normal fault in a southwest to northeast
direction, with a drop to the north, Figure 5.32.
Stratigraphy
The geological column drilled consists of rocks corre
sponding to ages ranging from the Middle Cretaceous
N
W
E
S
Frontera
Coatzacoalcos
Cárdenas
Villahermosa
Níspero
Teotleco-1
Cactus
Río Nuevo
0
Figure 5.30 Map showing the location of the Teotleco-1 well.
70
10
20
30
40
50 km
N
W
E
S
Teotleco-1
Figure 5.31 Structural contouring of the Middle Cretaceous top.
NW
Teotleco-1
SE
2,000
2,500
Salt
3,000
Eocene
Paleocene
Salt
3,500
Upper Cretaceous
5,290 m
Middle Cretaceous
5,810 md
5,587 tvd
Lower Cretaceous
Upper Jurassic Tithonian
4,000
Upper Jurassic Kimmeridgian
N
Sal
Teotleco-1
Amacoite-1B
Figure 5.32 Seismic cross-section showing well Teotleco-1 and the characteristics of the reservoir.
71
Discoveries
of gas. The proved reserves amount to 3.7 million bar
rels of crude oil and 9.9 billion cubic feet of gas, while
the 2P reserves total 34.4 million barrels of crude oil,
and 92.5 billion cubic feet of gas. The total reserves
are 47.2 million barrels of oil and 126.3 billion cubic
feet of gas, which jointly means 77.6 million barrels
of oil equivalent.
to the Pliocene-Pleistocene. The presence of a body
of salt at the Tertiary level meant that the well had
to be drilled directionally, and a normal sedimentary
sequence was found.
Storage Rock
The storage rock consists of carbonated rocks of
the Middle Cretaceous that are also producers in the
Cactus field and which are largely made up of dark
gray fractured dolomites.
Gulf of Mexico Deepwater Basin
Tamil-1
The well is in the territorial waters of the Gulf of
Mexico, off the coasts of Campeche and Tabasco, at
Source Rock
In the area of this reservoir, the hydro
carbon source rock corresponds to
clay-calcareous sediments of the Upper
Jurassic Tithonian age, according to geo
chemical studies made in this basin.
N
W
S
Nab
Seal Rock
The seal is formed by marlstone of the
Upper Cretaceous and calcareous shale
of the Tertiary, mostly those of the Mio
cene, which are interspersed inside this
sequence.
Tamil-1
Maloob
Tamil-DL1
Kastelán-1
Ku
Kach-1
Cantarell
Alak-1
Abkatún
Ayín
Reservoir
The reservoir consists of fractured do
lomites of the Middle Cretaceous. The
average porosity is 5.0 percent and the
average water saturation is around 8.0
percent. The initial average production
was 3,559 barrels per day of 42 API de
grees of volatile oil, and 9.9 million cubic
feet of gas per day.
146 Km.
Sinán
May
Frontera
Cd. del Carmen
Reserves
The original 3P volume is 195.6 million
barrels of oil and 524.3 billion cubic feet
72
E
Figure 5.33 Map showing the location of the Tamil-1 well.
approximately 146 kilometers northwest of Ciudad
del Carmen, Campeche, 131.8 kilometers northeast
of Dos Bocas, Tabasco, and 14.6 kilometers northwest
of the Kach-1 well, which was a producer in Lower
and Middle Cretaceous rocks, Figure 5.33. Geologi
cally, it is located in the northwestern portion of the
Comalcalco pit. Although this discovery did not add
reserves in 2008, it will be possible to book them
once the other wells corroborate the extension of
the structure derived from the seismic and geological
interpretation.
Structural Geology
The structure is a lengthy anticline in a northwest to
southeast direction that is limited all around by clos
ing against reverse faulting. There is a compressive
tectonic and salt combination in the area. The seismic
nature of the information indicates that the structural
highs contain salt in their core, but without affecting
the horizons interpreted corresponding to Mesozoic
targets.
The reservoir is formed by naturally fractured Creta
ceous carbonated rocks; the top of the reservoir is
at 2,747 meters and the bottom is at 3,040 meters,
which coincides with the top of the Upper Jurassic
Tithonian, while the structural close is at 4,050 meters.
The reservoir continuity inferred from the seismic cor
relation makes it possible to consider it an attractive
opportunity to delimit the reservoir to the southeast
of the structure. Figure 5.34 shows the continuity of
the horizons interpreted.
Stratigraphy
The geological column cut by well Tamil-1 covers
rocks from the Recent-Pleistocene (terrigenous) to
the Upper Jurassic Oxfordian (carbonates). The well
reached a depth of 3,598 meters below sea level and
its chronostratigraphic tops were established through
the analysis of planktonic foraminifer indexes in the
drill cuttings and core samples.
Storage Rock
The storage rock of the reservoir seen in the core
and drill cuttings samples mostly consists of naturally
fractured mudstone-wackestone foraminifers and
with good heavy oil impregnation, which is partly
shaly-bituminous and partially dolomitized, with mi
crocrystalline and secondary porosity in fractures,
Tamil-1
Tamil-DL1
N
SE
1,000
1,500
2,000
N
2,500
3,000
Tamil-1
Reservoir Top: 2,747 m (Middle Cretaceous)
3,500
4,000
Reservoir Bottom: 3,040 m (Upper Jurassic Tithonian)
Tamil-DL1
Kach-1
4,500
Figure 5.34 Seismic-structural cross-section showing the characteristics of the reservoir.
73
Discoveries
due to dissolution and intercrystalline. The fractures
are generally at angles exceeding 60 degrees and
with good oil impregnation and they are occasionally
sealed with calcite and/or silica; there are also bands
of cherts and layers of bituminous shale.
Resources
Based on the models and information available, the
resources are estimated at more than 200 million
barrels of oil equivalent.
5.4 Historical Trajectory of Discoveries
Table 5.4 shows the volumes of 1P, 2P, and 3P reserves
discovered in the period from 2005 to 2008 by basin,
for oil, natural gas, and oil equivalent. Said reserves
correspond to the volumes discovered in each year
and they are reported as of January 1 of the following
year. According to the information presented, there
is a continuous annual increase in the total reserves
added, with a maximum value of 1,482.1 million bar
rels of oil equivalent reached in 2008. This means an
increase of 40.7 percent in total reserves discovered
when compared with 2007. Additionally, the most
important additions were in the Southeastern Basins
where the figure for 2008 amounted to 1,372.9 million
barrels of oil equivalent in 3P reserves, that is, 92.6
percent of the national total.
It is important to stress that these accomplishments
are the result of the sustained investment in explora
tion involving amounts exceeding the figures for the
last decade. Given the complexity and magnitude of
the work involved, such as the acquisition of 2D and
Table 5.4 Volumes of reserves discovered in the period from 2005-2008.
1P
2P
3P
Year
Crude Oil Natural Gas Total
Crude Oil Natural Gas Total Crude Oil Natural Gas Total
Basin
MMbbl
Bcf
MMboe
MMbbl
Bcf
MMboe MMbbl
Bcf
MMboe
2005
Burgos
Southeastern
Tampico-Misantla
Veracruz
2006
Burgos
Gulf of Mexico Deepwater
Southeastern
Veracruz
2007
Burgos
Gulf of Mexico Deepwater
Southeastern
Veracruz
2008
Burgos
Southeastern
Veracruz
74
52.6
440.9
136.8
151.4
646.4
276.6
730.7
1,140.0
950.2
0.0
42.7
7.9
0.0
128.0
24.0
0.0
396.4
76.3
45.3
21.8
50.5
142.8
98.7
166.0
718.1
290.6
778.1
7.3
43.2
14.4
8.6
78.2
20.9
12.6
108.2
29.6
0.0
333.3
64.1
0.0
341.6
65.7
0.0
344.7
66.3
66.2
548.4
182.9
158.1
1,180.6
412.1
340.5
2,999.1
966.1
0.0
62.3
11.9
0.0
133.7
25.6
0.0
351.8
67.3
0.0
308.5
63.6
0.0
672.9
138.8
0.0
1,722.0
349.3
62.9
129.9
95.2
154.4
311.6
232.3
302.8
779.4
487.6
3.3
47.7
12.2
3.7
62.4
15.4
37.7
145.9
62.0
129.1
244.3
182.8
467.5
944.8
675.4
708.3
1,604.0
1,053.2
0.0
49.4
9.6
0.0
80.4
15.7
0.0
168.4
32.6
0.0
0.0
0.0
0.0
242.6
47.6
0.0
708.8
138.9
128.8
160.6
166.4
466.7
556.2
598.9
706.1
650.6
865.2
0.3
34.3
6.8
0.8
65.6
13.2
2.2
76.2
16.5
244.8
592.0
363.8
681.5
1,134.8
912.4
1,095.6
1,912.8
1,482.1
0.0
40.7
7.4
0.0
57.8
10.5
0.0
267.1
48.9
244.8
440.8
335.2
681.5
798.2
848.3
1,095.6
1,331.9
1,372.9
0.0
110.6
21.3
0.0
278.9
53.6
0.0
313.8
60.3
3D seismic information, geological, geochemical
and paleontological modeling studies, seismic pro
cessing, seismic interpretation, and the drilling and
completion of wells, the exploratory process cycle
covers several years and therefore requires a stable
budget allocation in the medium and long term.
According to the fluid type contained in the reser
voirs, the 3P oil reserves discovered in the South
eastern Basins amounted to 1,095.6 million barrels;
this volume is 55.2 percent higher than the figure
reported in 2007. In particular, the discoveries of
light and superlight oil in the Southeastern Basins
contributed 27.6 percent. Furthermore, said discov
eries will make it possible to improve the quality of
heavy oils added in the northern part of the basin,
which will thus improve the quality of Mexican crude
oil exports. The remaining 72.4 percent corresponding
to heavy oils was furnished by the Ku-Maloob-Zaap
reservoirs in the Northeastern Offshore Region and
Cinco Presidentes in the Southern Region.
The 3P natural gas reserve discovered, as of Janu
ary 1, 2009, amounts to 1,912.8 billion cubic feet of
gas, which means an increase of 19.3 percent when
compared to 2007. The most important contribution
can be attributed to the discoveries made in the Li
toral de Tabasco Integral Business Unit, particularly
the addition of the Tsimin field that provided 976.4
billion cubic feet of gas. The Burgos and Veracruz
basins, moreover, provided 580.9 billion cubic feet
of gas. This will obviously help maintain and improve
the natural gas supply for production. Furthermore,
gas associated with the oil reservoirs discovered
contributed 18.6 percent of the natural gas added in
the period. Figure 5.35 shows the evolution of the
reserves discovered from 2005 to 2008. As can be
MMboe
950.2
966.1
1,053.2
1,482.1
3P
912.4
2P
363.8
1P
675.4
276.6
412.1
136.8
182.9
182.8
2005
2006
2007
2008
Figure 5.35 Replacement rate trajectory for the 1P, 2P,
and 3P reserves of oil equivalent.
observed, the volumes discovered have improved
gradually.
The evolution of exploratory additions in the Burgos
Basin, which despite being a mature basin is still add
ing dry gas reserves, and thus showing the remaining
associated potential, reported an increase of 58.6
percent over 2008 as regards the previous year, with
the addition of 267.1 billion cubic feet of natural gas,
that is, 48.9 million barrels of oil equivalent.
The increase as against 2007 in the Veracruz Basin was
312.1 percent, which means the addition of 313.8 bil
lion cubic feet of dry gas reserves, that is, an amount
equal to 60.3 million barrels of oil equivalent.
The reserves added in the Southeastern Basins
in 2008 amounted to 1,372.9 million barrels of oil
equivalent, which means an increase of 58.7 percent
compared with the previous year. In terms of oil and
gas, the reserves totaled 1,095.6 barrels and 1,331.9
billion cubic feet, that is, an increase of 55.2 and 104.7
percent, respectively, compared to 2007.
75
Discoveries
76
6
Distribution of Hydrocarbon
Reserves
This basic purpose of this chapter is to describe
the evolution of original volumes and hydrocarbon
reserves in their different categories; proved, probable and possible, that stem from all the activities
carried out during 2008, such as the development of
fields, analyses of the pressure-production behavior
in said fields, reinterpretation of geological models
and exploratory activities, among others.
As regards the variations of original hydrocarbon
reserves through additions, this element is formed
by discoveries and field delineations that are the result of drilling exploratory and delineation wells, and
therefore, the variations mentioned may be positive
or negative. The second element is obtained from
drilling development wells, thus generating increases
and decreases in hydrocarbon reserves. Finally, the
analysis of pressure-production behavior in fields or
the updating of the geological-geophysical models leads
to increases or decreases in revisions that could influence the values of the hydrocarbon reserves reported.
The above estimations were made in accordance with
the guidelines issued by the Securities and Exchange
Commission (SEC) of the United States for proved
reserves, while the definitions adopted by the Society
of Petroleum Engineers (SPE), the American Association of Petroleum Geologists (AAPG), and the World
Petroleum Council (WPC) were used to evaluate the
probable and possible reserves.
Added to the above, there is the distribution of reserves at an integral business unit level. In this regard,
it is important to mention that a new organizational
scheme was set up in Pemex Exploración y Producción in 2008 when two new integral business units
Table 6.1 Previous and current organizational scheme at
Pemex Exploración y Producción.
Region
2003
Cantarell
Ku-Maloob-Zaap
Abkatún-Pol-Chuc
Litoral de Tabasco
Northern
Burgos
Cantarell
Ku-Maloob-Zaap
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Veracruz
Burgos
Aceite Terciario del Golfo
Poza Rica-Altamira
Veracruz
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Poza Rica-Altamira
Southern
2008
were incorporated, which in addition to complying
with the task of producing current reserves, they are
also entrusted with the mission of extending fields
discovered through the reserves additions and the
delineation of fields, in order to efficiently ensure the
capture of economic value. Table 6.1 compares the
organization of previous business units in effect since
2003 with the new distribution established last year.
6.1 Northeastern Offshore Region
This region is in the southeast of Mexico and it includes part of the continental shelf and the Gulf of
Mexico slope. It covers an area of approximately
166,000 square kilometers and is located in national territorial waters, off the coasts of the states
of Campeche, Yucatán and Quintana Roo. Figure 6.1
shows the geographic location of this region.
77
Distribution of Hydrocarbon Reserves
N
W
E
S
Baja California Norte
Sonora
Chihuahua
Coahuila
Baja California Sur
Sinaloa
Tamaulipas
Zacatecas
Northeastern
Offshore
Region
San Luis Potosí
Aguascalientes
Nayarit
Pacific Ocean
Gulf of Mexico
Nuevo León
Durango
Guanajuato
Veracruz
Querétaro
Hidalgo
México
D.F. Tlaxcala
Michoacán
Morelos
Puebla
Yucatán
Jalisco
Colima
Quintana Roo
Tabasco
Guerrero
Campeche
Belize
Oaxaca
Chiapas
Guatemala
0
100
200
300
400
500 Km
Honduras
El Salvador
Figure 6.1 The Northeastern Offshore Region is located in national territorial waters, off the coasts of
Campeche, Yucatán and Quintana Roo.
The Northeastern Offshore Region currently has two
integral business units: Cantarell and Ku-MaloobZaap, which administer 25 fields. Figure 6.2 shows
the geographic location of the integral business units.
Eleven of the fields have remaining reserves but are
not in production, Kambesah and Után in the Cantarell
Integral Business Unit, and Ayatsil, Baksha, Kayab,
Nab, Numán, Pit, Pohp, Tson, and Zazil-Ha in the KuMaloob-Zaap Integral Business Unit. 14 fields are in
production, of which 9 are located in the Cantarell
Integral Business Unit, and five are in the Ku-MaloobZaap Integral Business Unit.
In 2008, the region’s oil production was 638.9 million
barrels of crude oil, and the natural gas output was
695.9 billion cubic feet of gas. These volumes account
for 62.5 and 27.5 percent of the national total oil and
natural gas production, respectively.
78
In 2008, the Northeastern Offshore Region reported an
average daily production of 1.7 million barrels of oil,
and 1,901.3 million cubic feet of natural gas. Furthermore, the Ku-Maloob-Zaap project is gradually increasing its production as a result of the development of the
Maloob and Zaap fields. As in previous years, the Akal
field in the Cantarell complex is still the most important
in the country. In 2008, Akal reported an average daily
production of 0.927 million barrels of oil and 1,576.8
million cubic feet of natural gas, all of which was the
result of the activities aimed at maintaining the recovery factor of the Cantarell project, which especially
included well drilling, workovers and well completion
activities and the continuation of reservoir pressure
maintenance projects through nitrogen injection. Just
as in 2008, and based on the above, it is forecast that
the Northeastern Offshore Region will continue to be
the most important oil producer nationwide.
N
W
460
500
540
580
620
E
S
Gulf of Mexico
Tunich
Ku-Maloob-Zaap
Integral Business Unit
Zazil-Ha
Maloob
Zaap
Ek
Balam
Pok-1
Ku
Cantarell
Kutz
Ixtoc
2170
Lum
Bacab
Chac
Cantarell Integral
Business Unit
Takín-101
Takín
2130
200 m
2090
100 m
50 m
Cd. del Carmen
25 m
Dos Bocas
2050
Frontera
0
10
20
30
40 km
Figure 6.2 Geographic location of the integral business units of the Northeastern Offshore Region.
Business Unit reported 17,395.5 million barrels of oil,
which represents 32.0 percent of the regional volume
and this evidences an increase compared with the pre-
Table 6.2 shows the evolution of the original oil and
natural gas volumes of the Northeastern OffTable 6.2 Historical evolution over the last three years of the original
shore Region in all the different categories
volumes in the Northeastern Offshore Region.
over the last three years. Consequently, the
proved original volume of oil, as of January
Year
Category
Crude Oil
Natural Gas
MMbbl
Bcf
1, 2009, is 54,356.6 million barrels, which is
equal to 36.1 percent of the national volume
2007
Total
63,792.2
26,190.5
for such category and this means an increase
Proved 53,417.6
24,172.3
as a result of the exploratory activity, as well
Probable
1,106.7
255.0
as the delineation and development of the
Possible
9,268.0
1,763.2
fields in the region. At a regional level, the
2008
Total
64,920.2
26,410.4
Cantarell Integral Business Unit holds most
Proved 54,029.8
24,321.0
Probable
2,851.8
684.0
of this volume with 36,961.1 million barrels
Possible
8,038.7
1,405.3
of oil, that is, 68.0 percent of the region’s
total, which means a slight decrease com 2009
Total
66,087.6
26,033.0
Proved 54,356.6
23,981.4
pared with the previous year as a result of
Probable
5,616.1
897.3
the development and revision of fields in the
Possible
6,114.9
1,154.3
business unit. The Ku-Maloob-Zaap Integral
79
vious year that is essentially due to the addition of new
reservoir volumes. The probable original volume of oil
amounted to 5,616.1 million barrels, which represents
6.7 percent of the national total and, in turn, it is an
increase when compared with the previous year. The
highest probable original volume of oil corresponds
to the Ku-Maloob-Zaap Integral Business Unit with
5,322.9 million barrels, that is, 94.8 percent of the
region’s total, as a result of the exploration, delineation, development and revision activities. Additionally,
the Cantarell Integral Business Unit reported 293.2
million barrels of oil, which represents 5.2 percent of
the region’s total, and an increase over the previous
year that can largely be attributed to the addition of the
Kambesah field. The possible original oil volume was
6,114.9 million barrels, which represents 9.7 percent
of the country’s total volume. The possible original
volume decreased when compared with 2008 due to
field revision and development. The Ku-Maloob-Zaap
Integral Business Unit holds 5,607.9 million barrels in
its fields and the Cantarell Integral Business Unit has
507.0 million barrels.
Business Unit contains 73.3 percent of the original
volume, that is, 17,583.9 billion cubic feet and this
implies a reduction compared with last year, mostly
due to revision, while the Ku-Maloob-Zaap Integral
Business Unit has 6,397.6 billion cubic feet of gas,
which is equal to 26.7 percent of the region’s total
and this points to a slight increase in this business
unit. The probable original volume amounted to 897.3
billion cubic feet of natural gas, which represents an
increase when compared with the previous year. Of
this, 93.5 percent is in the Ku-Maloob-Zaap Integral
Business Unit and 6.5 percent is in the Cantarell Integral Business Unit. The possible original natural gas
volume decreased when compared with the previous
year, which was the result of field revision and development. As of January 1, 2009, the regional figure
was 1,154.3 billion cubic feet of gas, of which 83.1
percent is in the Ku-Maloob-Zaap Integral Business
Unit, while the Cantarell Integral Business Unit holds
the remaining 16.9 percent.
In reference to the proved original volumes of natural
gas, the Northeastern Offshore Region has 23,981.4
billion cubic feet, which is 13.3 percent of the national
total. This value means a decrease over the amount
reported last year, which was mainly due to delineation, development and revision. The Cantarell Integral
MMbbl
Figures 6.3 and 6.4 show the variations in crude oil and
natural gas reserves over the last three years. As of
January 1, 2009, the total reserves of the Northeastern
Offshore Region amounted to 11,656.6 million barrels
of crude oil and 4,892.9 billion cubic feet of natural gas.
Bcf
12,510.6
Possible
2,533.9
Probable
3,444.7
Proved
11,936.8
11,656.6
2,799.0
2,892.8
3,085.0
2,844.5
6,532.0
6,052.8
5,919.3
2007
2008
2009
5,716.7
Possible
814.9
Probable
863.0
Proved
Figure 6.3 Historical evolution of the remaining
crude oil reserves in the Northeastern Offshore
Region over the last three years.
80
4,038.8
2007
5,382.7
962.4
784.7
4,892.9
896.1
631.1
3,635.6
3,365.8
2008
2009
Figure 6.4 Historical evolution of the remaining natural gas reserves in the Northeastern
Offshore Region over the last three years.
Table 6.3 Composition of 2P reserves by business unit of the Northeastern Offshore Region.
Crude Oil
Business Unit
Heavy
MMbbl
Light
MMbbl
Total
Cantarell
Ku-Maloob-Zaap
8,676.2
4,087.0
4,589.2
87.6
87.6
0.0
Natural Gas
Superlight
MMbbl
0.0
0.0
0.0
Associated Non-associated
Bcf
Bcf
3,981.1
2,260.7
1,720.4
15.7
15.7
0.0
The results obtained in 2008 did not cause substantial
variations in the oil type classification in the region’s
proved reserves; heavy and light oil accounted for
99.1 and 0.9 percent, respectively. As regards natural
gas, 99.6 percent is associated gas and 0.4 percent is
non-associated gas.
The 2P reserves amounted to 8,763.8 million barrels
of crude oil, and 3,996.8 billion cubic feet of natural
gas. Tables 6.3 and 6.4 show the composition of the
2P and 3P reserves, respectively, at an integral business unit level in terms of heavy, light and superlight
crude oil, as well as associated and non-associated
gas. It should be noted that the non-associated gas
values include the reserves of gas-condensate, dry
gas and wet gas reservoirs.
The probable oil reserve, as of January 1, 2009, is
estimated at 2,844.5 million barrels of oil, that is, 27.4
percent of the national total, while the probable gas
reserve, which is 631.1 billion cubic feet, equals 3.1
percent of the country’s total.
The region’s proved reserve as of January 1, 2009
amounts to 5,919.3 million barrels of crude oil, that
is, 56.9 percent of the country’s proved reserves. The
proved natural gas reserve totals 3,365.8 billion cubic
feet, and it accounts for 19.1 percent of the national
reserve.
The possible oil reserve as of January 1, 2009 amounts
to 2,892.8 million barrels of oil, which corresponds to
28.5 percent of the national total. In reference to the
possible natural gas reserve, the figure is 896.1 billion cubic feet of gas, or 4.0 percent of the country’s
total.
The developed proved reserve was 4,837.5 million
barrels of crude oil and 2,892.0 billion cubic feet of
natural gas. These figures represent 81.7 and 85.9
percent of the region’s total proved reserve, respectively. The undeveloped proved reserves total 1,081.8
million barrels of crude oil and 473.7 billion cubic feet
of natural gas. These amounts correspond to 18.3 and
14.1 percent of the region’s total proved reserve.
Crude Oil and Natural Gas
The proved oil reserve as of January 1, 2009 increased
by 505.4 million barrels compared with the previous
year. This increase is mostly the result of reclassifying
Table 6.4 Composition of 3P reserves by business unit of the Northeastern Offshore Region.
Business Unit
Crude Oil
Heavy
MMbbl
Light
MMbbl
Total
11,569.1
Cantarell
5,570.3
Ku-Maloob-Zaap 5,998.7
87.6
87.6
0.0
Natural Gas
Superlight
MMbbl
0.0
0.0
0.0
Bcf
Bcf
4,835.1
2,782.6
2,052.5
57.8
57.8
0.0
81
probable reserves to proved caused by the drilling of
development wells in the Maloob and Zaap fields and
the continuation of pressure maintenance through
nitrogen injection in the Ku field, the delineation of
the Ayatsil field, and the discovery of the Pit field that
jointly total 759.1 million barrels of oil. Additionally, the
decrease of 412.6 million barrels of oil was the result of
the revision of the pressure-production behavior in the
Akal, Sihil and Bacab fields. The Cantarell Integral Business Unit holds 50.0 percent of the region’s proved oil
reserve, just like the Ku-Maloob-Zaap Integral Business
Unit. In field terms, the highest proportion of proved
oil reserve is to be found in the Akal field.
Regionally, the remaining proved natural gas reserve
reported a net increase of 426.1 billion cubic feet compared with the previous year. The variation may be
attributed to the revision of the pressure-production
behavior in the Akal and Ixtoc fields, the reclassification of probable reserves to proved category due to
development drilling in the Zaap field, the delineation
of the Ayatsil field and the addition of the Kambesah
and Pit fields. All of the above therefore made it possible to add 418.3 billion cubic feet of natural gas.
Nevertheless, this increase was slightly affected by the
decline of 11.4 billion cubic feet of gas in the Bacab,
Lum and Sihil fields. It should be noted that the Akal
and Ku fields provide 69.4 percent of the regional
reserve. At a business unit level, Cantarell provides
59.2 percent, and Ku-Maloob-Zaap has 40.8 percent
of the region’s proved natural gas reserves.
The probable oil reserve estimated as of January 1,
2009 shows a decrease of 240.5 million barrels of oil,
that is, 7.8 percent less when compared with the previous year. In particular, there were decreases of 718.3
million barrels of oil in Ku, Maloob and Zaap fields
caused by the reclassification of probable reserves to
proved. These decreases were offset by an increase of
329.6 million barrels of oil in the Ayatsil and Pit fields
as a result of the delineation of the fields, as in the
case of the Ayatsil-DL1 well that found much deeper
water-oil contact than previously considered, in addi82
tion to the exploratory activities that also contributed
to the above increase. It should be noted that 57.2
percent of the region’s probable oil reserve is in the
Ku-Maloob-Zaap Integral Business Unit.
The region’s probable natural gas reserve reported
a decrease of 153.7 billion cubic feet as of January
1, 2009, when compared with January 1, 2008. This
was mostly due to the reclassification of reserves in
the Maloob and Zaap fields. These decreases were
softened by the increases in the Ayatsil, Ixtoc, Kambesah and Pit fields that jointly added 79.8 billion cubic
feet of natural gas. At a business unit level, 55.0 percent of the probable gas reserves are concentrated
in the Ku-Maloob-Zaap Integral Business Unit, with
the remaining 45.0 percent in the Cantarell Integral
Business Unit.
The possible oil reserve as of January 1, 2009 reported
an increase of 93.8 million barrels compared with the
previous year. The delineation of the Ayatsil field, the
development and revision of the Balam field, and
the addition of the Pit field, increased reserves by
408.4 million barrels of oil. Additionally, the decrease
of 165.4 million barrels of oil was the result of the
variation of the pressure-production behavior in the
Akal, Ek, and Maloob fields. The region’s possible oil
reserves are distributed as follows; 51.3 percent in the
Cantarell Integral Business Unit, and 48.7 percent in
the Ku-Maloob-Zaap Integral Business Unit.
As of January 1, 2009, the possible natural gas reserve
declined by 66.4 billion cubic feet when compared
with January 1, 2008, as a result of the revision of the
pressure-production behavior and development in
the Akal, Ek and Maloob fields, that jointly reported a
decrease of 92.5 billion cubic feet of gas. In contrast,
the increase in reserves amounting to 42.5 billion
cubic feet of natural gas in the Ayatsil and Pit fields
due to delineation and addition activities lessened
the above-mentioned decline in reserves. Table 6.5
shows the natural gas reserves by integral business
unit estimated as of January 1, 2009 in the proved,
Table 6.5 Distribution of remaining gas reserves by business unit of the Northeastern Offshore Region as of January 1, 2009.
Category
Business Unit
Natural Gas
Gas to be
Delivered to Plant
Bcf
Bcf
Proved
Total
Cantarell
Ku-Maloob-Zaap
Probable
Total
Cantarell
Ku-Maloob-Zaap
Possible
Total
Cantarell
Ku-Maloob-Zaap
Dry Gas
Bcf
3,365.8
1,992.2
1,373.5
2,337.7
1,561.8
775.9
1,840.4
1,230.5
609.9
631.1
284.2
346.9
394.2
225.7
168.5
310.3
177.9
132.4
896.1
563.9
332.2
585.1
451.9
133.2
468.9
364.2
104.7
Oil Equivalent
integral business unit level, Cantarell accounts for
52.2 percent, and Ku-Maloob-Zaap has 47.8 percent.
Figure 6.5 shows the distribution of proved reserves
by business unit.
The proved oil equivalent reserve in the Northeastern
Offshore Region as of January 1, 2009 totaled 6,712.3
million barrels. Field exploration, delineation and
development activities, plus field behavior revisions
in 2008, indicate an increase of 377.2 million barrels
of oil equivalent. This variation is mostly associated
with the Ayatsil, Maloob, Pit, and Zaap fields. At an
The probable oil equivalent reserve as of January 1,
2009 was 2,977.1 million barrels, which means 20.5
percent of the country’s reserves. Compared with
January 1, 2008, there was a reduction of 313.1 million
barrels of oil equivalent caused by the reclassification
of probable reserves to proved and possible in the
Ku, Maloob, and Zaap fields. Figure 6.6 shows the
probable and possible categories, as well as the gas
to be delivered to plant and dry gas.
MMboe
MMboe
3,210.7
6,712.3
2,977.1
Cantarell
Total
1,686.8
3,501.6
Cantarell
1,290.3
Ku-MaloobZaap
Total
Figure 6.5 Proved reserves as of January
1, 2009, distributed by business unit in the
Northeastern Offshore Region.
Ku-MaloobZaap
Figure 6.6 Probable reserves as of January
83
MMboe
1,459.3
production behavior in the case of the former, and
field development in the case of the two last cases.
Figure 6.7 shows the participation of each business
unit in the region’s possible oil equivalent reserves.
It can therefore be seen that 52.9 percent of the total
is in the Cantarell Integral Business Unit.
3,096.5
1,637.2
Cantarell
Ku-MaloobZaap
Total
Figure 6.7 Possible reserves as of January
distribution of probable reserves by business unit;
Ku-Maloob-Zaap accounts for the highest amount
with 56.7 percent of the region’s total.
The possible oil equivalent reserve, as of January 1,
2009, amounted to 3,096.5 million barrels, which is
21.0 percent of the national total. When comparing
this reserve with the figure reported the previous year,
there is a positive variation of 53.6 million barrels of
oil equivalent, which is largely the result of delineation
in the Ayatsil field and the exploratory addition of the
Pit field. As regards the decreases, the Akal, Ek, and
Maloob fields, jointly account for 209.3 million barrels
of oil equivalent due to the revision of the pressure-
Figure 6.8 shows the elements of change in the total
or 3P reserve of the Northeastern Offshore Region. As
can be seen, as of January 1 2009, the total regional
reserves amounted to 12,785.9 million barrels of
oil equivalent, which is 29.4 percent of the national
total. There was an increase of 0.9 percent in the
region’s 3P reserve, that is, 117.7 million barrels of
oil equivalent, compared with the figure reported in
the previous year.
Reserve-Production Ratio
The Northeastern Offshore Region produced 689.5
million barrels of oil equivalent during 2008; consequently, the proved reserve-production ratio is 9.7
years. Considering the proved plus probable (2P)
reserve, the reserve-production ratio is 14.1 years and
18.5 years for the proved plus probable plus possible
(3P) reserve.
In particular, the proved reserve-production ratio of
the Cantarell Integral Business Unit is 8.4 years and the
MMboe
15,193.5
696.4
421.1
14,086.0
509.6
589.8
350.2
635.4
795.3
-713.9
36.3
13,357.7
-689.5
521.0
283.5
616.4
12,785.9
11,936.8
11,656.6
503.7
256.6
368.9
Dry Gas
Equivalent
Plant Liquids
Condensate
13,566.4
12,510.6
2006
2007
2008
Additions
Revisions
Figure 6.8 Elements of change in the total reserve of the Northeastern Offshore Region.
84
2009
Crude Oil
Table 6.6 Historical evolution of reserves by fluid type in the Northeastern Offshore Region.
Year
Category
Crude Oil
Condensate
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Equivalent
MMboe
Total
MMboe
2007
Total
Proved
Probable
Possible
2008
Total
Proved
Probable
Possible
12,510.6
6,532.0
3,444.7
2,533.9
635.4
443.2
103.1
89.1
350.2
254.3
53.5
42.4
589.8
422.7
88.8
78.3
14,086.0
7,652.2
3,690.1
2,743.7
11,936.8
6,052.8
3,085.0
2,799.0
616.4
407.5
98.6
110.3
283.5
200.7
37.9
44.8
521.0
363.6
68.6
88.7
13,357.7
7,024.6
3,290.2
3,042.9
2009
Total
Proved
Probable
Possible
11,656.6
5,919.3
2,844.5
2,892.8
368.9
256.1
42.1
70.7
256.6
183.0
30.9
42.8
503.7
353.9
59.7
90.2
12,785.9
6,712.3
2,977.1
3,096.5
figure for Ku-Maloob-Zaap is 11.7 years, considering
production volumes of 415.1 and 274.4 million barrels
of oil equivalent, respectively. The production of 1.0
million barrels per day makes the Cantarell Integral
Business Unit the leading oil producer nationwide.
The Ku-Maloob-Zaap Integral Business Unit, however,
showed a proved plus probable (2P) reserve-production ratio of 17.8 years, and a reserve-production
ratio of 23.2 years for the proved plus probable plus
possible (3P) reserve. Reservoir development and
pressure maintenance activities through nitrogen
injection are focused on maintaining production at
approximately 800 thousand barrels of oil per day
during the coming years.
Reserves by Fluid Type
Table 6.6 shows the evolution of reserves over the last
three years in the Northeastern Offshore Region by fluid
type, in the proved, probable and possible categories.
The proved reserve is therefore 6,712.3 million barrels
of oil equivalent, of which 88.2 percent is crude oil, 3.8
percent is condensate, 2.7 percent is plant liquids, and
5.3 percent is dry gas equivalent to liquid.
The probable reserve amounts to 2,977.1 million barrels
of oil equivalent. Of this amount, 95.5 percent is crude
oil, 1.4 percent is condensate, 1.0 percent is plant liquids, and 2.0 percent is dry gas equivalent to liquid.
The 3,096.5 million barrels of oil equivalent in the possible reserve are constituted as follows: 93.4 percent is
crude oil, 2.3 percent is condensate, 1.4 percent is plant
liquids and 2.9 percent is dry gas equivalent to liquid.
6.2 Southwestern Offshore Region
In recent years, the Southwestern Offshore Region
has been characterized by discoveries of significant
volumes of hydrocarbon reserves, and therefore it
helps in the drive to meet reserve replacement rates
at a regional and national level. The region is in territorial waters that include the continental shelf and slope
of the Gulf of Mexico. It covers an area of 352,390
square kilometers. To the south, it is bounded by the
states of Veracruz, Tabasco and Campeche, to the
east it borders on the Northeastern Offshore Region,
and to the north and west; it is limited by the national
territorial waters, as is shown in Figure 6.9.
85
N
W
E
S
Sonora
Chihuahua
Gulf of Mexico
Coahuila
Baja California Sur
Sinaloa
Nuevo León
Durango
Zacatecas
San Luis Potosí
Aguascalientes
Nayarit
Pacific Ocean
Southwestern
Offshore
Region
Tamaulipas
Guanajuato
Veracruz
Querétaro
Hidalgo
México
D.F. Tlaxcala
Michoacán
Morelos
Puebla
Yucatán
Jalisco
Colima
Quintana Roo
Tabasco
Guerrero
Campeche
Belize
Oaxaca
Chiapas
Guatemala
0
100
200
300
400
500 Km
Honduras
El Salvador
Figure 6.9 The Southwestern Offshore Region is in the continental shelf and slope waters of
the Gulf of Mexico.
As of January 1, 2009, the organization structure consisted of the Abkatún-Pol-Chuc, Litoral de Tabasco, and
Holok-Temoa integral business units. The latter is a recent creation and it was basically established to develop
and administer the fields located in isobaths exceeding
500 meters. Additionally, the Southwestern Offshore
Region has an exploration business unit whose name
was changed from the Regional Exploration Business
Unit to the Plataforma Continental Sur Exploration Business Unit. Figure 6.10 shows the geographic location.
The region currently administers 66 fields, 17 of which
produce light and superlight oil and associated gas,
that is, there is a sizeable number of fields still to be
developed. It should be noted that two new fields
have been included in the register of fields, and they
illustrate the positive results of the exploratory work
being done in the region, and they also evidence an
opportunity area to maintain and increase hydrocarbon production at a regional and national level.
86
In 2008, the daily oil and natural gas production in the
region averaged a volume of 500.3 thousand barrels
and 1,022.9 million cubic feet, that is, over the year
there was an accumulation of 183.1 million barrels of
oil and 374.4 billion cubic feet of natural gas, which
means a contribution of 17.9 and 14.8 percent of the
national oil and gas production, respectively.
Last year’s exploratory activity was successful in that
two new fields, Tsimin and Tecoalli, were discovered;
in addition more reservoirs were added in the existing
fields, that is, at a Jurassic level in Xanab and the contribution of new Tertiary sands in the Yaxché field.
The proved original volume of oil in the Southwestern
Offshore Region as of January 1, 2009 was 17,691.1
million barrels, which is equal to 11.7 percent of the
N
W
460
500
540
580
620
E
Gulf of Mexico
S
2170
Holok-Temoa
Manik
Taratunich
Ixtal
301
101
201
Abkatún
Toloc
2130
Batab
Och
Ayín
Pol
Kax
Chuc
Uech
Litoral de Tabasco
200 m
Citam
Sinán
1A
Bolontiku
Kab
Kay
Misón
Hayabil-1
Yum
2-B
May
50 m
Abkatún-Pol-Chuc
101A
101
100 m
25 m
Ki
Alux
Caan
2090
Kix
401
301
Cd. del Carmen
Yaxché
Dos Bocas
2050
Frontera
0
10
20
30
40 km
Figure 6.10 Geographic location of the integral business units that make up the Southwestern Offshore Region.
barrels, that is, 63.2 percent of the region’s total, as a
national total volume for such category, and implies an
result of the exploratory addition of new reservoirs,
increase of 6.4 percent when compared with last year.
and development and revision activities. In contrast,
The Abkatún-Pol-Chuc Integral Business Unit holds
the Abkatún-Pol-Chuc Integral Business Unit holds
most of the region’s volume with 14,158.1 million barrels of oil, that is, 80.0 percent of the total.
Table 6.7 Historical evolution over the last three years of the original
The Litoral de Tabasco Integral Business Unit,
volumes in the Southwestern Offshore Region.
however, has 3,533.0 million barrels of oil,
that is, 20.0 percent of the regional volume,
Year
Category
Crude Oil
Natural Gas
MMbbl
Bcf
which means an increase when compared
with the previous year, due to new reservoirs,
2007
Total
22,799.4
28,763.0
developments and revisions. Furthermore,
Proved 16,275.3
18,659.7
the newly-created Holok-Temoa Integral Busi Probable
2,763.2
3,320.8
ness Unit administers the Lakach, Lalail, and
Possible
3,761.0
6,782.4
Noxal fields that only contain non-associated
2008
Total
24,163.4
31,161.6
gas reservoirs. The probable and possible
Proved 16,625.7
19,652.2
Probable
3,328.2
4,621.8
original oil volumes total 3,396.3 and 4,186.0
Possible
4,209.6
6,887.6
million barrels, which is equal to 4.0 and 6.6
percent of the national volumes, respectively.
2009
Total
25,273.4
33,394.2
Proved 17,691.1
21,615.9
The highest probable original volume of
Probable
3,396.3
5,439.7
oil corresponds to the Litoral de Tabasco
Possible
4,186.0
6,338.6
Integral Business Unit with 2,147.2 million
87
36.8 percent of the probable original volume, which
means 1,249.1 million barrels of oil, and which is less
than last year essentially because of the reclassification
of probable reserves to proved due to field development. Of the 4,186.0 million barrels in the possible
original volume of crude oil, 3,034.0 million barrels are
located in the fields of the Litoral de Tabasco Integral
Business Unit and 1,152.0 million barrels correspond
to the Abkatún-Pol-Chuc Integral Business Unit. When
compared with those reported as of January 1, 2008,
these figures show an increase in the case of the Litoral
de Tabasco Integral Business Unit, that was largely due
to the addition of new reservoirs through exploratory
activities, and a decrease in the case of Abkatún-PolChuc caused by field delineation activities.
In reference to the original volumes of natural gas,
as of January 1, 2009, the Southwestern Offshore
Region has 21,615.9 billion cubic feet in the proved
category, which is 11.9 percent of the national total.
This is an increase over what was reported as January
1, 2008. The Abkatún-Pol-Chuc Integral Business Unit
contains 66.9 percent of the regional volume, that is,
14,459.1 billion cubic feet, which is an increment due
to new developments and revisions. There are 6,728.4
billion cubic feet distributed in the Litoral de Tabasco
Integral Business Unit, and it makes up 31.1 percent
of the region’s total. The remaining 2.0 percent is in
the Holok-Temoa Integral Business Unit, specifically
in the Lakach field. The probable original volumes
total 5,439.7 billion cubic feet of natural gas, that is,
there is an increase over the previous year mostly
caused by new reservoirs and reclassification as a
result of developments. 62.4 percent of the probable
original volume corresponds to the Litoral de Tabasco
Integral Business Unit, 20.8 percent is in the AbkatúnPol-Chuc Integral Business Unit, and 16.7 percent in
Holok-Temoa. The possible volumes total 6,338.6
billion cubic feet of gas, which means a decrease
when compared with last year that was caused by
delineations. The Litoral de Tabasco Integral Business
Unit accounts for 59.9 percent of the region’s possible
original volume, while the Holok-Temoa fields hold
88
MMbbl
2,900.9
2,927.8
Possible
1,118.8
1,020.9
Probable
744.2
911.9
1,038.0
994.9
2007
2008
3,217.4
1,056.0
Proved
985.5
1,176.0
2009
Figure 6.11 Historical evolution of the remaining crude oil reserves in the Southwestern
34.1 percent and the Abkatún-Pol-Chuc fields provide
the remaining 6.1 percent. It is important to mention
that there were significant discoveries in 2008 as a
result of exploratory activities carried out particularly
in the Litoral de Tabasco Integral Business Unit that
led to increases in the original volumes. Table 6.7
shows the behavior of the original oil and natural gas
volumes in their different categories reported as of
January 1, 2007 to 2009.
The proved oil reserve in the Southwestern Offshore
Region as of January 1, 2009 was 1,176.0 million barBcf
9,571.8
7,961.9
Possible
3,611.9
8,269.3
3,433.0
3,267.6
2,675.9
2,214.3
Probable
1,706.4
Proved
2,643.7
2,787.4
2007
2008
3,462.9
2009
Figure 6.12 Historical evolution of the remaining natural gas reserves in the Southwestern
Table 6.8 Composition of 2P reserves by business unit of the Southwestern Offshore Region.
Business Unit
Total
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Crude Oil
Heavy
MMbbl
Light
MMbbl
337.2
128.7
0.0
208.6
1,375.3
737.2
0.0
638.1
Natural Gas
Superlight
MMbbl
449.0
41.4
0.0
407.5
Bcf
Bcf
2,519.8
1,428.7
0.0
1,091.1
3,619.0
251.4
915.5
2,452.0
The region’s proved oil reserve consists of 1,176.0
million barrels that are made up, in terms of density,
by 120.9 million barrels of heavy oil or 10.3 percent
of the reserve, 808.2 million barrels of light oil or
68.7 percent, and the remaining 246.9 million barrels
are superlight, which means the latter provides 21.0
percent of the region’s proved total. In reference to
the proved natural gas reserve, the figure is 3,462.9
billion cubic feet, of which 46.7 percent or 1,616.0 billion cubic feet correspond to associated gas, and the
remaining 53.3 percent is non-associated gas, that is,
1,846.9 billion cubic feet. Tables 6.8 and 6.9 illustrate
the composition of the 2P and 3P oil and natural gas
reserves. It should be noted that the non-associated
gas values reported include the reserves of gascondensate, dry gas, and wet gas reservoirs.
rels, which is 11.3 percent of the country’s proved
reserves. In reference to the proved reserve of natural gas, the figure was 3,462.9 billion cubic feet, that
is, 19.6 percent of the total proved reserve of gas
nationwide.
The probable and possible oil reserves inventory totaled 985.5 and 1,056.0 million barrels, representing
9.5 and 10.4 percent, respectively, of the national oil
reserves in these categories. Consequently, the 2P
and 3P reserves amounted to 2,161.5 and 3,217.4
million barrels of oil, respectively. F0or natural gas,
the probable and possible reserves are 2,675.9 and
3,433.0 billion cubic feet, which is equal to 13.3 and
15.2 percent of the national total in such categories.
The 2P and 3P reserves therefore amounted to 6,138.8
and 9,571.8 billion cubic feet of natural gas. Figures
6.11 and 6.12 show the variations in the oil and natural
gas reserves over the last three years. In reference to
the developed and undeveloped proved reserves of
the region, the figures show 673.7 and 502.3 million
barrels of crude oil, while the amount for natural gas is
1,604.6 and 1,858.2 billion cubic feet, respectively.
The proved oil reserve as of January 1, 2009 in the
Southwestern Offshore Region is 1,176.0 million barrels, of which 563.4 million barrels or 47.9 percent is
in the Abkatún-Pol-Chuc Integral Business Unit, while
Table 6.9 Composition of 3P reserves by business unit of the Southwestern Offshore Region.
Business Unit
Total
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Crude Oil
Heavy
MMbbl
Light
MMbbl
739.9
251.1
0.0
488.8
1,793.1
785.3
0.0
1,007.8
Natural Gas
Superlight
MMbbl
684.4
47.0
0.0
637.4
Bcf
Bcf
3,232.9
1,498.6
0.0
1,734.3
6,338.9
286.2
2,430.3
3,622.4
89
612.6 million barrels or 52.1 percent corresponds
to the Litoral de Tabasco Integral Business Unit. As
mentioned before, to date the Holok-Temoa Integral
Business Unit only manages natural gas fields.
In regional terms, the proved oil reserve reported a
net increase of 364.1 million barrels when compared
with January 1, 2008. Additionally, there was a net
rise of 323.6 million barrels of oil in the developed
proved reserve. Furthermore, the undeveloped
reserve increased by 40.5 million barrels of oil as
against the previous year. At an integral business unit
level, Abkatún-Pol-Chuc reported an increase of 185.3
million barrels, which corresponds to a developed
proved reserve volume of 199.6 million barrels, while
the undeveloped proved reserve decreased by 14.3
million barrels. The increase in the developed proved
reserve was essentially due to the revision of the
pressure-production behavior and the reclassification
of reserves in Ixtal, Chuc, Caan, Homol, and Manik
fields that jointly added 183.7 million barrels of oil. The
decrease reported in the undeveloped proved reserve
was largely due to the reclassification of undeveloped
reserves to developed as a result of drilling two wells
in the Ixtal field.
As of January 1, 2009, the Litoral de Tabasco Integral
Business Unit showed an increase of 178.9 million
barrels of crude oil in the proved reserve. This figure
is the result of increases in the developed proved
reserve of 124.0 million barrels and 54.8 million barrels in the undeveloped proved reserve. The fields
that reported the most important positive variations
in the developed proved reserve are Bolontikú, Sinán,
May and Yaxché, with 74.8, 16.9, 14.4, and 13.2 million
barrels of oil, respectively, caused by development
in Bolontikú and May, revisions and development in
Sinán, and delineation activities in the latter field.
The Tsimin, Xanab and Tecoalli fields in the Litoral de
Tabasco Integral Business Unit reported increases in
the undeveloped proved oil reserve of 41.8, 9.7 and
6.1 million barrels through exploratory addition.
90
The proved natural gas reserves as of January 1,
2009 amounted to 3,462.9 billion cubic feet, of which
35.9 percent of the reserve, or 1,243.1 billion cubic
feet, are in the Abkatún-Pol-Chuc Integral Business
Unit, while the Litoral de Tabasco holds 1,911.2 billion cubic feet or 55.2 percent, and the remaining 8.9
percent, that is, a volume of 308.6 billion cubic feet,
is in Holok-Temoa.
The region’s proved natural gas reserve reported a net
increase of 1,049.8 billion cubic feet compared with
January 1, 2008. This variation consists of an increase
in developed proved reserves of 751.5 billion cubic
feet of natural gas and 298.3 billion cubic feet for the
undeveloped reserve. The Abkatún-Pol-Chuc Integral
Business Unit reported an increase in the proved
reserve of 359.4 billion cubic feet of natural gas. This
situation is explained by the positive variation of 402.6
billion cubic feet of gas in the developed proved reserve especially in the Ixtal, Caan, Chuc, Homol, Manik,
and Taratunich fields, with 184.5, 133.2, 52.8 20.3, 9.7,
and 9.3 billion cubic feet of gas, respectively, due to
the behavior and the reclassification of reserves.
The Litoral de Tabasco Integral Business Unit reported
an increase of 690.5 billion cubic feet of natural gas in
proved reserves, where the positive variation of 348.9
billion cubic feet is explained by the developed proved
reserves. There was also an increase of 341.6 billion
cubic feet of natural gas in the undeveloped proved
reserves. In particular, the increases reported in the
developed proved reserves category are basically
due to development activities in the May field that
meant 190.4 billion cubic feet of natural gas, Bolontikú
marked up an increase of 139.4 billion cubic feet, and
Sinán added 10.8 billion cubic feet of gas. As regards
the undeveloped proved reserve of natural gas, the
increase was essentially due to exploratory activities
in the Tsimin, Xanab, and Tecoalli fields that jointly
contributed a volume of 387.1 billion cubic feet of
natural gas. Additionally, there was a reduction of
44.1 billion cubic feet of gas in the May field caused
by development in the field.
The region’s probable oil reserve as of January 1,
2009 rose by 73.6 million barrels of crude oil when
compared with the previous year. In particular, the
Abkatún-Pol-Chuc Integral Business Unit reported a
decrease of 92.4 million barrels of oil, which combined
with the increase in the Litoral de Tabasco Integral
Business Unit of 166.0 million barrels of crude oil,
explain the above-mentioned positive variation. Basically, the exploratory activity permitted the addition of
reserves totaling more than 61 million barrels of oil in
the Xanab field, at the Jurassic level, and the Tsimin
and Tecoalli fields. There was also an increase of 35.8
million barrels of oil in the Sinán field because of development and revision. The May and Bolontikú fields,
however, reported increases of 34.0 and 32.5 million
barrels of oil due to their development. Therefore,
the probable oil reserve amounted to 985.5 million
barrels as of January 1, 2009.
The probable natural gas reserve increased by 461.6
billion cubic feet of gas compared with the figure reported as of January 1 last year. This variation includes
the decline reported in the Abkatún-Pol-Chuc Integral
Business Unit of 77.6 billion cubic feet of natural gas,
and the increase of 539.2 billion cubic feet of gas in the
Litoral de Tabasco. The most important reduction, that
is, more than 100 billion cubic feet of gas, was in Ixtal,
which comes under the Abkatún-Pol-Chuc Integral Business Unit, as a result of reclassifying probable reserves
to proved caused by field development. In contrast,
the Homol field in the same business unit reported an
increase of 43.2 billion cubic feet of natural gas, due
to development. Furthermore, exploratory discoveries
in the Litoral de Tabasco Integral Business Unit added
210.2 billion cubic feet of gas. The development and
revision of the May, Bolontikú and Sinán fields led to
increases of 180.7, 65.6 and 80.2 billion cubic feet of
natural gas, which made up a positive variation in the
Litoral de Tabasco Integral Business Unit.
As of January 1, 2009, the region’s possible reserves
of oil and natural gas totaled 1,056.0 million barrels
and 3,433.0 billion cubic feet, respectively. The possible oil reserve in the Southwestern Offshore Region
showed a positive variation of 35.1 million barrels
compared with the figure estimated as of January 1,
2008. In this category, the Abkatún-Pol-Chuc Integral
Business Unit reported a decrease of 36.0 million
Table 6.10 Distribution of remaining gas reserves by business unit of the Southwestern
Offshore Region as of January 1, 2009.
Category
Business Unit
Natural Gas
Gas to be
Delivered to Plant
Bcf
Bcf
Dry Gas
Proved
Total
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Probable
Total
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Possible
Total
Abkatún-Pol-Chuc
Holok-Temoa
Litoral de Tabasco
Bcf
3,462.9
1,243.1
308.6
1,911.2
2,973.0
1,003.0
308.6
1,661.4
2,386.0
782.7
272.1
1,331.2
2,675.9
437.1
606.9
1,631.9
2,388.4
344.9
606.9
1,436.6
1,983.2
267.7
535.2
1,180.3
3,433.0
104.6
1,514.8
1,813.6
3,204.7
77.0
1,514.8
1,612.8
2,796.6
59.8
1,385.4
1,351.4
91
barrels, which is mostly attributable to the delineation
of the Homol field that removed 35.5 million barrels
of oil. Nevertheless, there was a rise of 71.1 million
barrels of oil in this category in the Litoral de Tabasco
Integral Business Unit. The variation was basically
due to discoveries in the Tsimin, Tecoalli and Xanab
(Jurassic) fields that provided 48.1, 30.8 and 7.7 million barrels of oil, respectively.
As regards the region’s possible natural gas reserve,
there was a positive variation of 165.4 billion cubic
feet when compared with the previous year. Specifically, there was a decline of 266.4 billion cubic feet of
gas in the Abkatún-Pol-Chuc Integral Business Unit,
largely caused by the delineation of Homol that led
to a reduction of 264.6 billion cubic feet of natural
gas. Nevertheless, the Litoral de Tabasco Integral
Business Unit reported a net increase of 432.0 billion
cubic feet in the possible natural gas reserve, with the
noteworthy exploratory success that added a volume
of 458.0 billion cubic feet of gas in the Tsimin, Tecoalli,
and Xanab fields of the Litoral de Tabasco Integral
Business Unit, amounting to 429.3, 21.6, and 7.2 billion cubic feet of natural gas, respectively. Table 6.10
shows the natural gas reserves by business unit in the
different categories, including gas to be delivered to
plant and dry gas.
Oil Equivalent
As of January 1, 2009, there was a proved reserve of
1,893.9 million barrels of oil equivalent in the Southwestern Offshore Region. This volume represents
13.2 percent of the national total. Compared with
the previous year’s reserve, there is a net positive
variation of 524.1 million barrels in the reserve. According to Figure 6.13, the Abkatún-Pol-Chuc Integral
Business Unit holds 43.3 percent of the region’s total,
which means reserves of 819.3 million barrels of oil
equivalent, and a net increase of 245.0 million barrels
of oil equivalent when compared with the previous
year. These increases are basically due to revisions
in the Ixtal, Chuc, Caan, Homol, and Manik fields of
92
MMboe
819.3
70.4
1,893.9
HolokTemoa
Total
1,004.3
Litoral de
Tabasco
AbkatúnPol-Chuc
Figure 6.13 Proved reserves as of January 1, 2009, distributed by business unit in the Southwestern Offshore
Region.
98.6, 57.4, 43.3, 18.5, and 14.9 million barrels of oil
equivalent, respectively.
The Litoral de Tabasco Integral Business Unit holds
53.0 percent of the region’s total proved reserves, that
is, 1,004.3 million barrels of oil equivalent, while the
remaining 3.7 percent is in the Holok-Temoa Integral
Business Unit. In the first business unit, the increases
totaled 279.0 million barrels of oil equivalent, which are
primarily explained by additions in the Tsimin, Xanab
(Jurassic), Yaxché (Tertiary), and Tecoalli fields that
contributed 117.7, 11.6, 11.4, and 7.1 million barrels
of oil equivalent, respectively. Additionally, there were
increases of 85.5 million barrels of oil equivalent in
Bolontikú and Sinán because of field development.
MMboe
433.2
130.1
1,536.9
HolokTemoa
Total
973.5
Litoral de
Tabasco
AbkatúnPol-Chuc
Figure 6.14 Probable reserves as of January 1, 2009,
distributed by business unit in the Southwestern Offshore Region.
The region’s probable reserve amounted to 1,536.9
million barrels of oil equivalent as of January 1, 2009.
This volume represents 10.6 percent of the country’s
total reserves in this category. Figure 6.14 shows the
distribution of these reserves at a business unit level.
Compared with the figure for January 1, 2008, the
region’s current volume shows an increase of 132.2
million barrels of oil equivalent. In particular, the
fields of the Abkatún-Pol-Chuc Integral Business Unit
reported decreases totaling 116.2 million barrels of oil
equivalent, which was mainly caused by the reclassification of reserves in Ixtal of 104.2 million barrels
of oil equivalent.
MMboe
The positive variation of 248.9 million barrels of oil
equivalent in the Litoral de Tabasco Integral Business
Unit is primarily explained by the discoveries made
in the Tsimin, Xanab (Jurassic), Yaxché (Tertiary), and
Tecoalli fields that contributed 54.7, 38.8, 16.7, and
10.9 million barrels of oil equivalent, which means a
total of 121.1 million barrels. There were increases
by development in the May and Bolontikú fields of
50.7 and 44.0 million barrels. The increase in Sinán
as a result of development and revision amounted
to 48.6 million barrels of oil equivalent. It should also
be mentioned that there were reductions in the probable oil equivalent reserve; nevertheless, they were
not significant to counteract the above-mentioned
successful results.
The region’s possible oil equivalent reserve as of
January 1, 2009 amounted to 1,758.5 million barrels,
as it is shown in Figure 6.15. This volume means
11.9 percent of the national total. Thus, there was an
increase of 33.4 million barrels when compared with
the previous year. At an integral business unit level,
Abkatún-Pol-Chuc showed a decrease of 95.2 million
barrels, most which was due to the delineation of the
Homol field, where the volume fell by 92.8 million barrels of oil equivalent. The Litoral de Tabasco Integral
Business Unit reported a rise of 129.6 million barrels
of oil equivalent. The exploratory activity culminated
in the discovery of the Tsimin, Tecoalli, and Xanab (Jurassic) fields, with 135.3, 36.0 and 9.1 million barrels.
There were also development and revision decreases
196.3
1,758.5
AbkatúnPol-Chuc
Total
314.5
1,247.8
Litoral de
Tabasco
HolokTemoa
Figure 6.15 Possible reserves as of January 1, 2009,
distributed by business unit in the Southwestern Offshore Region.
MMboe
387.5
4,647.0
4,043.5
104.5
197.7
-260.2
1,377.8
1,163.0
1,262.5
407.6
175.4
422.3
147.3
2,773.1
2,900.9
2,927.8
2006
2007
2008
724.9
360.2
185.2
5,189.4
4,759.9
509.7
84.5
3,217.4
Additions
Revisions
Dry Gas
Equivalent
Plant Liquids
Condensate
Crude Oil
2009
Figure 6.16 Elements of change in the total reserve of the Southwestern Offshore Region.
93
in Sinán totaling 60.9 million barrels of oil equivalent,
nevertheless, they did not affect the favorable addition
results reported above.
tively. When using the 3P or total reserves, the figure
is 9.3 years for the Abkatún-Pol-Chuc Integral Business
Unit and 30.8 years for the Litoral de Tabasco.
Figure 6.16 shows the balance of the region’s 3P oil
equivalent reserves as of January 1, 2009, as compared with 2006 to 2008.
The proved reserve-production ratio of the Southwestern Offshore Region is 7.3 years considering a
constant production flow of 260.2 million barrels of
oil equivalent. The proved plus probable ratio is 13.2
years, while the ratio for the 3P reserve is 19.9 years.
In particular, the Abkatún-Pol-Chuc Integral Business
Unit showed the lowest value in this ratio, 5.3 years
for the proved reserve, while the Litoral de Tabasco
Integral Business Unit reported 9.6 years. The HolokTemoa Integral Business Unit is expected to add production in 2012 with the Lakach integral project.
When the 2P oil equivalent reserves are considered,
the ratios are 8.1 and 18.9 years for Abkatún-Pol-Chuc
and Litoral de Tabasco integral business units, respec-
Hydrocarbon reserves in terms of fluid type are
shown in Table 6.11 as of January 1 in 2007 to 2009,
for the respective associated categories. The remaining proved reserve at the closing of 2008 consisted
of 1,893.9 million barrels of oil equivalent, that is,
62.1 percent crude oil, 2.0 percent condensate, 11.7
percent plant liquids, and 24.2 percent is dry gas
equivalent to liquid.
The probable reserve volume of 1,536.9 million barrels
of oil equivalent is made up as follows: 64.1 percent
is crude oil, 1.5 percent is condensate, 9.5 percent is
plant liquids, and 24.8 percent is dry gas equivalent
to liquid.
The possible reserve amounting to 1,758.5 million
barrels of oil equivalent consists of 60.0 percent crude
oil, 1.3 percent condensate, 8.1 percent plant liquids,
and 30.6 percent dry gas equivalent to liquid.
Table 6.11 Historical evolution of reserves by fluid type in the Southwestern Offshore Region.
Year
Category
Crude Oil
Condensate
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Equivalent
MMboe
Total
MMboe
2007
Total
Proved
Probable
Possible
2008
Total
Proved
Probable
Possible
2,900.9
1,038.0
744.2
1,118.8
175.4
68.1
36.8
70.5
407.6
161.1
81.0
165.6
1,163.0
360.0
254.0
549.0
4,647.0
1,627.2
1,116.0
1,903.8
2,927.8
994.9
911.9
1,020.9
147.3
61.2
40.9
45.2
422.3
176.7
115.3
130.4
1,262.5
397.3
336.6
528.6
4,759.9
1,630.1
1,404.7
1,725.1
2009
Total
Proved
Probable
Possible
3,217.4
1,176.0
985.5
1,056.0
84.5
38.0
23.7
22.8
509.7
221.2
146.3
142.1
1,377.8
458.8
381.3
537.7
5,189.4
1,893.9
1,536.9
1,758.5
94
N
W
E
S
Sonora
Chihuahua
Coahuila
Baja California Sur
Sinaloa
Nuevo León
Durango
Northern Region Tamaulipas
Gulf of Mexico
Zacatecas
San Luis Potosí
Aguascalientes
Nayarit
Pacific Ocean
Guanajuato
Veracruz
Querétaro
Hidalgo
México
D.F. Tlaxcala
Michoacán
Morelos
Puebla
Yucatán
Jalisco
Colima
Quintana Roo
Tabasco
Campeche
Guerrero
Belize
Oaxaca
Chiapas
Guatemala
0
100
200
300
400
500 Km
Honduras
El Salvador
Figure 6.17 The Northern Region consists of a continental and an offshore section.
6.3 Northern Region
The region covers an area of approximately 1.8 million
square kilometers that consists of both onshore and
offshore portions. It is in the north of Mexico, bordering on the United States of America to the north, Río
Tesechoacán to the south, the 500 meter isobath of
the Gulf of Mexico to the east and the Pacific Ocean
to the west, Figure 6.17. As can be seen in Figure
6.18, the region is administratively divided into four
integral business units, the recently created Aceite
Terciario del Golfo, Burgos, Poza Rica-Altamira, and
Veracruz, whose activities are focused on developing and optimizing the exploitation of existing fields,
while the Regional Exploration Business Unit handles
the activities aimed at adding reserves and assessing
the potential.
As of January 1, 2009, the region was still the leading
producer of natural gas and it was also where most of
the field development activity was being carried out.
Once again, the Northern Region is the most important
in terms of Mexico’s probable and possible oil and
natural gas reserves.
In 2008, the region’s annual oil production was 31.9
million barrels, while the natural gas output amounted
to 931.1 billion cubic feet. These figures represent 3.1
and 36.8 percent of the national oil and gas production, respectively.
In terms of national natural gas production in 2008,
the Northern Region was ranked first with an average
daily output of 2,543.9 million cubic feet. This is based
on drilling activities, especially in the Burgos Integral
Business Unit, where 201 wells were drilled.
Moreover, the exploratory activities in 2008 included
discoveries that led to the addition of non-associated
gas reserves in the Burgos and Veracruz integral
business units. In the case of the former, well Cali-1
stands out with the addition of dry gas reserves, while
95
N
W
E
S
Sonora
Chihuahua
Coahuila
Burgos
Baja California Sur
Sinaloa
Nuevo León
Durango
Gulf of Mexico
Tamaulipas
Zacatecas
San Luis Potosí
Aguascalientes
Nayarit Altamira-Poza
Rica
Pacific Ocean
Jalisco
Colima
Guanajuato
Querétaro
Hidalgo
México
Michoacán
D.F.Tlaxcala
Morelos Puebla Veracruz
Veracruz Integral Business Unit
Quintana Roo
Campeche
Tabasco
Guerrero
Oaxaca
Yucatán
Belize
Chiapas
Guatemala
0 100 200 300 400 500 Km
Honduras
El Salvador
Figure 6.18 Geographic location of the integral business units that constitute the
Northern Region.
in the Veracruz Integral Business Unit, the drilling of
well Cauchy-1 paved the way to the largest dry gas
discovery in 2008, thus adding the greatest volume
of dry gas reserves nationwide.
6.3.1 Evolution of Original Volumes in
Place
Table 6.12 shows the evolution of original
volumes of crude oil and natural gas in the
Northern Region over the last three years.
As of January 1, 2009, the volume of proved
oil was therefore 41,592.2 million barrels,
while natural gas totaled 66,663.6 billion cubic feet. The above volumes represent 27.6
and 36.8 percent of the national total for oil
and natural gas. Regionally, 66.3 percent of
the proved original oil volume is in the fields
of the Poza Rica-Altamira Integral Business
Unit, while 31.5 percent corresponds to the
Aceite Terciario del Golfo Integral Business
96
Unit, and the remaining 2.2 percent is in the Burgos
and Veracruz integral business units. 60.1 percent
of the proved original natural gas volume is in the
fields of the Poza Rica-Altamira Integral Business Unit,
25.0 percent corresponds to the fields in the Burgos
volumes in the Northern Region.
Year
Category
Crude Oil
MMbbl
Natural Gas
Bcf
2007
Total
Proved Probable
Possible
166,046.7
40,180.5
77,890.0
47,976.2
122,167.7
64,776.4
33,622.8
23,768.5
2008
Total
Proved Probable
Possible
165,934.0
41,176.5
76,576.8
48,180.7
123,418.8
66,792.6
33,279.3
23,346.9
2009
Total
Proved Probable
Possible
166,240.5
41,592.2
72,895.5
51,752.8
123,900.7
66,663.6
32,576.6
24,660.4
Integral Business Unit, 8.2 percent is in the Veracruz
Integral Business Unit and 6.7 percent is in the Aceite
Terciario del Golfo Integral Business Unit.
The probable original oil and gas volumes amount
to 72,895.5 million barrels and 32,576.6 billion cubic
feet, which are equal to 86.4 and 75.4 percent of the
national totals, respectively. In regional terms, the
Aceite Terciario del Golfo Integral Business Unit holds
almost the entire probable volume of oil and 89.8 percent of the probable original volume of natural gas, the
Burgos Integral Business Unit, however, accounts for
7.1 percent. The remaining 3.1 percent is in the Poza
Rica-Altamira and Veracruz integral business units.
As regards the possible original volumes of oil and
natural gas in the Northern Region as of January
1, 2009, the values are 51,752.8 million barrels and
24,660.4 billion cubic feet. The above volumes account for 81.7 and 73.3 percent of the national total,
respectively. Regionally, the Aceite Terciario del Golfo
Integral Business Unit has almost all the possible
crude oil volume, that is, 98.5 percent. This business
unit has 83.2 percent of the natural gas volume and the
Burgos Integral Business Unit possesses 11.8 percent.
The Veracruz and Poza Rica-Altamira integral business
units account for the remaining 5.0 percent.
The region’s proved original volume of associated
gas as of January 1, 2009, was 45,306.1 billion cubic
feet, while the volume for non-associated gas totaled
21,357.5 billion cubic feet. Specifically, in the case of
the former, 44,322.6 billion cubic feet are connected
with oil reservoirs, and 983.5 billion cubic feet correspond to free associated gas reservoirs. 12,441.1
billion cubic feet of the non-associated gas volume
are in wet gas reservoirs, 8,596.9 billion cubic feet are
in dry gas accumulations, and 319.6 billion cubic feet
are gas-condensate reservoirs.
In reference to the probable original volume of natural
gas, 29,413.7 billion cubic feet are associated gas and
3,162.9 billion cubic feet are non-associated gas. Spe-
cifically, in the case of associated gas, 29,362.7 billion
cubic feet are in oil reservoirs, and 51.0 billion cubic
feet correspond to free associated gas reservoirs. In
terms of the volume of non-associated gas, 2,045.0
billion cubic feet are in wet gas reservoirs, 1,077.0 billion cubic feet are in dry gas reservoirs, and 41.0 billion
cubic feet are in gas-condensate reservoirs.
Finally, the possible original volume of natural gas
reserves, as of January 1, 2009, consisted of 21,484.5
billion cubic feet of associated gas and 3,175.9 billion
cubic feet of non-associated gas. 99.8 percent of the
associated gas is located in oil reservoirs, while 61.2
percent of the non-associated gas is to be found in
wet gas reservoirs, 38.0 percent in dry gas reservoir,
and the remaining 0.9 percent is in gas-condensate
reservoirs.
As of January 1, 2009 the Northern Region reported
an increase in the proved original oil volume of 415.7
million barrels when compared with the previous year
due to the reclassification of reserves to proved in
the Poza Rica-Altamira and Aceite Terciario del Golfo
integral business units. Specifically, the Poza Rica field
in the former and the Coapechaca and Presidente
Alemán fields in the latter stand out among said reclassification activities.
The region reported a decrease of 129.0 billion cubic
feet in terms of the proved original volume of natural
gas, when compared with the previous year. This
decline was mostly in the Papán and Perdiz fields of
the Veracruz Integral Business Unit and Arcos field of
the Burgos Integral Business Unit.
The probable original volumes of oil and natural gas
in the region revealed a decline of 3,681.3 million barrels and 702.7 billion cubic feet when compared with
January 1, 2008. This mostly took place in the Aceite
Terciario del Golfo Integral Business Unit as a result
of reclassifying probable volumes to possible.
97
There was an increase in the possible original volumes
of oil and natural gas in the Northern Region as of
January 1, 2009 totaling 3,572.0 million barrels and
1,313.5 billion cubic feet. This increase is essentially
attributed to the Aceite Terciario del Golfo Integral
Business Unit due to the reclassification of probable
volumes to possible category.
The proved oil reserve of the Northern Region as of
January 1, 2009 was 828.7 million barrels, of which
407.8 million barrels correspond to the developed
proved reserve and 420.9 million barrels to the undeveloped proved reserve. Additionally, the probable
and possible oil reserves are 5,845.0 and 5,729.2
million barrels, respectively. The 2P and 3P reserves
therefore add up to 6,673.7 and 12,402.9 million barrels. The proved natural gas reserve is 4,218.7 billion
cubic feet, of which 2,890.5 billion cubic feet correspond to the developed proved reserve and 1,328.2
billion cubic feet are undeveloped proved reserve.
Furthermore, 1,282.0 billion cubic feet of the proved
natural gas reserve are associated gas and 2,936.7
billion cubic feet are non-associated gas. The probable
and possible natural gas reserves total 14,901.3 and
17,383.0 billion cubic feet, respectively. The 2P and 3P
reserves therefore amount to 19,120.0 and 36,503.1
billion cubic feet of natural gas, respectively.
MMbbl
12,769.4
12,546.0
12,402.9
Possible
5,780.8
5,648.7
5,729.2
Probable
6,099.7
6,056.7
5,845.0
Proved
888.9
2007
840.7
2008
828.7
2009
Figure 6.19 Historical evolution of the remaining crude oil reserves in the Northern Region
over the last three years.
38.0 percent, and the Veracruz Integral Business Unit
with 1.5 percent. The region’s proved natural gas reserve represents 23.9 percent of the national total, of
which 45.8 percent is in the Burgos Integral Business
Unit in the first place, followed by the Veracruz, Aceite
Terciario del Golfo and Poza Rica-Altamira integral
business units, with 20.7, 19.5 and 13.9 percent,
respectively.
The developed proved oil and natural gas reserves as
of January 1, 2009, account for 5.3 and 25.2 percent,
in terms of national totals. In a regional context, the
Aceite Terciario del Golfo and Poza Rica-Altamira integral business units have almost all the developed
proved oil reserve, that is, 97.5 percent, with the reBcf
Figures 6.19 and 6.20 show the historical evolution
over the last 3 years of the proved, probable and
possible oil and natural gas reserves, while the
composition of the 2P and 3P reserves by fluid type
and at a business unit level are shown in Tables 6.13
and 6.14.
As of January 1, 2009, 8.0 percent of Mexico’s proved
oil reserve was in the Northern Region. In regional
terms, 60.5 percent of said reserve was in the Aceite
Terciario del Golfo Integral Business Unit, followed
by the Poza Rica-Altamira Integral Business Unit with
98
38,910.0
37,546.1
36,503.1
Possible
18,179.4
17,441.5
Probable
15,874.2
15,624.9
14,901.3
Proved
4,856.4
4,479.7
4,218.7
2007
2008
2009
17,383.0
Figure 6.20 Historical evolution of the remaining natural gas reserves in the Northern Region
Table 6.13 Composition of 2P reserves by business unit of the Northern Region.
Crude Oil
Business Unit
Heavy
MMbbl
Light
MMbbl
Total
Burgos
Poza Rica-Altamira
Veracruz
2,575.1
2,321.3
0.0
235.7
18.1
3,283.7
2,874.4
0.0
409.2
0.0
mainder in the Veracruz Integral Business Unit. The
greatest proportion of the developed proved natural
gas reserve is in the Burgos Integral Business Unit,
with 46.2 percent, followed in second place by the
Veracruz Integral Business Unit with 26.5 percent.
The Poza Rica-Altamira and Aceite Terciario del Golfo
integral business units provide 16.1 and 11.2 percent,
respectively.
The undeveloped proved oil and natural gas reserves
represent 15.2 and 21.4 percent of the national total,
respectively. Regionally speaking, the Aceite Terciario
del Golfo Integral Business Unit has 79.0 percent of
the undeveloped proved oil reserve, followed by the
Poza Rica-Altamira Integral Business Unit with 20.4
percent. As regards the natural gas reserve, 45.0
percent of the undeveloped proved reserve is in the
Burgos Integral Business Unit, trailed by the Aceite
Terciario del Golfo Integral Business Unit with 37.8
percent, and the Poza Rica-Altamira Integral Business
Unit with 9.2 percent.
Natural Gas
Superlight
MMbbl
814.9
812.5
0.0
2.4
0.0
Bcf
Bcf
14,435.0
13,693.8
3.8
702.3
35.1
4,685.1
0.0
3,062.6
589.6
1,032.8
As of January 1, 2009, the region’s probable oil and
natural gas reserves represented 56.3 and 74.1 percent
of the national total, respectively. In regional terms, 94.2
percent of the oil reserve is associated with the Aceite
Terciario del Golfo Integral Business Unit because this
business unit holds all the reserves of the Paleocanal
de Chicontepec. This business unit also represents 86.4
percent of the probable natural gas reserves, followed
by the Burgos Integral Business Unit with 7.6 percent,
then the Poza Rica-Altamira and Veracruz integral business units with 4.7 and 1.3 percent, respectively.
As of January 1, 2009, the possible oil and natural
gas reserves in the Northern Region represented 56.4
and 76.9 percent of the national total, respectively.
As in the case of the probable category, in regional
terms the Aceite Terciario del Golfo Integral Business
Unit reports the highest possible oil and natural gas
reserves, with 96.8 and 87.0 percent, once again,
because this business unit holds all the reserves of
the Paleocanal de Chicontepec.
Table 6.14 Composition of 3P reserves by business unit of the Northern Region.
Crude Oil
Natural Gas
Business Unit
Heavy
MMbbl
Light
MMbbl
Superlight
MMbbl
Total
Burgos
Poza Rica-Altamira
Veracruz
4,177.0
3,880.1
0.0
268.4
28.5
6,740.3
6,192.7
0.0
547.7
0.0
1,485.5
1,481.2
0.0
4.3
0.0
Bcf
Bcf
29,883.7
28,822.7
3.8
937.5
119.7
6,619.4
0.0
4,783.1
729.3
1,107.0
99
The addition of proved, probable and possible reserves, also known as 3P, of oil and natural gas in the
Northern Region were 12,402.9 million barrels and
36,503.1 billion cubic feet, respectively. Nationally,
the above figures mean 40.1 and 60.5 percent, respectively. Furthermore, in regional terms the Aceite
Terciario del Golfo Integral Business Unit makes up
most of the 3P oil reserve with 93.2 percent, that is,
11,554.0 million barrels. As regards natural gas, once
again the above-mentioned business unit was ranked
first with 79.0 percent, followed by the Burgos Integral
Business Unit with 13.1 percent and then the Poza
Rica-Altamira and Veracruz integral business units
with 4.6 and 3.4 percent, respectively.
Based on the field development activities carried on
in 2008, which meant the completion of 485 wells, the
oil and natural gas reserves in the Northern Region,
reported variations in the different categories, as can
be seen below.
As of January 1, 2009, the proved oil reserve volume
showed a net decrease of 12.0 million barrels when
compared with the previous year that can largely be
attributed to the production extracted in 2008, that is,
31.9 million barrels of oil. If the effect of the production
extracted is not considered, there is an increase in the
remaining proved reserve of 19.9 million barrels. This
situation is mostly due to field development activities,
especially in Corralillo, Agua Fría, and Coapechaca of
the Aceite Terciario del Golfo Integral Business Unit,
Aguacate and Poza Rica of the Poza Rica-Altamira
Integral Business Unit, and Perdiz of the Veracruz
Integral Business Unit. It should be noted that the reactivation of mature fields in the region has paid off;
the tangible examples of this are the Temapache field
and recently in the Aguacate field, which form part of
the Poza Rica-Altamira Integral Business Unit.
There was a net decrease of 261.0 billion cubic feet in
the proved natural gas reserve, which was essentially
100
due to the production of 931.1 billion cubic feet of gas
in 2008. However, if the production effect is removed,
the remaining reserves increase by 670.1 billion cubic
feet of natural gas. Specifically, 22.6 percent of this
increase can be attributed to exploratory additions
totaling 151.2 billion cubic feet of natural gas, where
the Cali-1 well in the Burgos Basin and Cauchy-1 in
the Veracruz Basin stand out with the discovery of
22.0 and 86.1 billion cubic feet of gas, respectively.
Furthermore, the fields being exploited that reported
increases in the undeveloped proved natural gas reserve are Culebra, Nejo, Velero, Fundador, Cuervito,
and Forastero, of the Burgos Integral Business Unit,
with 49.7, 36.1, 32.0, 31.9, 34.3, and 28.5 billion cubic
feet of gas, respectively. There were also increases
in the Coapechaca, Corralillo, and Agua Fría fields, of
the Aceite Terciario del Golfo Integral Business Unit,
with 18.1, 13.1, and 11.6 billion cubic feet of gas, respectively. Additionally, there were increases in the
Playuela, Lizamba, and Papán fields, of the Veracruz
Integral Business Unit, with 16.4, 13.2, and 11.6 billion
cubic feet of gas, respectively.
The probable oil and natural gas reserves of the Northern Region, as of January 1, 2009, totaled 5,845.0
million barrels and 14,901.3 billion cubic feet, respectively. A comparison of the above figures with those
available as of January 1 the previous year reveals a
net decline of 211.7 million barrels of oil and 723.6 billion cubic feet of natural gas, respectively. The above
decreases are essentially due to the reclassification
of probable reserves to possible, and because of the
revision of oil and natural gas reserves in the Paleocanal de Chicontepec fields of the Aceite Terciario del
Golfo Integral Business Unit.
The possible oil and natural gas reserve volumes as of
January 1, 2009 are 5,729.2 million barrels and 17,383.0
billion cubic feet, respectively. The above values show
that when compared with the previous year, there is
a positive variation of 80.5 million barrels in the case
of oil and a decrease of 58.5 billion cubic feet in the
case of natural gas. The rise in possible oil reserves is
Table 6.15 Distribution of remaining gas reserves by business unit of the Northern Region as of
January 1, 2009.
Category
Business Unit
Natural Gas
Gas to be
Delivered to Plant
Bcf
Bcf
Dry Gas
Bcf
Proved
Total
Burgos
Poza Rica-Altamira
Veracruz
4,218.7
824.6
1,933.4
587.7
873.0
3,922.4
727.2
1,878.1
451.7
865.4
3,693.3
603.0
1,825.6
403.6
861.1
Probable
Total
Burgos
Poza Rica-Altamira
Veracruz
14,901.3
12,869.1
1,133.0
704.3
194.9
13,302.2
11,403.8
1,105.5
600.3
192.6
11,310.0
9,482.4
1,075.5
560.5
191.5
Possible
Total
Burgos
Poza Rica-Altamira
Veracruz
17,383.0
15,129.0
1,720.4
374.8
158.8
15,389.9
13,274.5
1,668.9
293.7
152.9
13,001.8
10,970.5
1,626.2
261.6
143.5
mainly due to the reclassification of probable reserves
to possible in the fields of the Paleocanal de Chicontepec. The decrease reported in possible natural gas
reserves was caused by the behavior of the reservoirs,
principally in the Tajín, Patlache, Mareógrafo, Dandi,
Casta and Kosni fields with 111.4, 36.2, 28.1, 23.1, 14.1
and 10.2 billion cubic feet of gas, respectively. These
decreases were partially offset however by exploratory
additions that totaled 244.3 billion cubic feet of gas.
Finally, Table 6.15 shows the distribution
MMboe
of the remaining gas reserves, as of January 1, 2009, by business unit.
in this category as against the remaining reserves of
the previous year, as a result of exploratory additions,
field development activities, and revisions of the
pressure-production behavior in reservoirs.
The probable reserve expressed in oil equivalent
showed a net decrease of 371.5 million barrels, which
is primarily due to the reclassification of probable reserves to possible in the Paleocanal de Chicontepec
180.5
1,652.4
Veracruz
Total
391.2
Oil Equivalent
412.4
The proved reserve of the Northern
Region, as of January 1, 2009 totaled
1,652.4 million barrels of oil equivalent,
which is 11.5 percent of the proved
national reserve. Figure 6.21 shows the
distribution of the reserve by integral
business unit. There was a net increase
of 144.5 million barrels of oil equivalent
668.2
Aceite Terciario
del Golfo
Poza RicaAltamira
Burgos
Figure 6.21 Proved reserves as of January 1, 2009, distributed by
business unit in the Northern Region.
101
MMboe
The total or 3P reserve as of January 1,
2009 was 19,724.8 million barrels of oil
42.5
8,862.6
230.3
455.9
8,134.0
equivalent, which is 45.3 percent of the
national total. Specifically, the highest regional percentage, that is, 88.2 percent, is
in the fields belonging to the Aceite Terciario del Golfo Integral Business Unit. When
comparing the 3P oil equivalent reserve
in question with the figure reported last
year, there is a net decline of 210.6 million
Aceite Terciario Poza RicaBurgos
Veracruz
Total
barrels, which is mostly due to the 213.6
del Golfo
Altamira
million barrels of oil equivalent produced
Figure 6.22 Probable reserves as of January 1, 2009, distributed by
in production in 2008. Figure 6.24 shows
the above and gives the composition of
the
3P
reserves
in the Northern Region.
fields. Consequently, the reserve as of January 1, 2009
amounted to 8,862.6 million barrels of oil equivalent,
which is 61.1 percent of the national total. Figure 6.22
shows the distribution of probable reserves for all of
the region’s integral business units.
The possible oil equivalent reserve as of January 1,
2009 totaled 9,209.9 million barrels, which is 62.5
percent of the total national possible reserve. Figure
6.23 shows the distribution of possible reserves at
an integral business unit level. The reserves this year
increased by 16.4 million barrels of oil equivalent
when compared with the previous year, which is
essentially attributable to the exploratory additions
made in 2008.
MMboe
8,590.5
Aceite Terciario
del Golfo
341.5
Burgos
235.6
Poza RicaAltamira
42.2
Veracruz
As of January 1, 2009, the ratio of the proved reserveproduction for oil equivalent was 7.7 years. The above
estimate is the coefficient arising from dividing the
1P reserve by the production in 2008 of 213.6 million
barrels of oil equivalent. The 2P reserve, that is, the
proved plus probable oil equivalent reserves, has a
reserve-production ratio of 49.2 years, and the ratio
for the 3P reserve, that is, proved plus probable plus
possible reserves of oil equivalent, the figure is 92.4
years. The differences between the figure estimated
for 1P reserves and the estimates for 2P and 3P reserves are clearly because of the fact that
the latter two have been affected by the
probable and possible reserve volumes in
9,209.9
the fields of the Paleocanal de Chicontepec belonging to the Aceite Terciario del
Golfo Integral Business Unit, which are
also in fact the highest volumes in these
categories nationwide.
Total
Figure 6.23 Possible reserves as of January 1, 2009, distributed by
102
The reserve-production ratio for the
proved oil reserve is 26.0 years, while
the period for the 2P and 3P reserves
are 209.4 and 389.1 years, respectively.
It should be mentioned that the above
MMboe
51.5
20,539.1
20,397.0
20,149.0
5,950.9
5,876.7
5,613.0
1,659.4
39.4
1,711.4
109.2
-347.8
28.0
-213.6
19,724.8
1,970.5
19.4
5,384.6
Dry Gas
Equivalent
1,918.2
Plant Liquids
19.1
12,877.3
12,769.4
12,546.0
2006
2007
2008
Condensate
12,402.9
Additions
Revisions
Crude Oil
2009
Figure 6.24 Elements of change in the total reserve of the Northern Region.
results consider an annual production of 31.9 million
barrels of oil. In the case of natural gas, the reserveproduction ratio for the 1P, 2P and 3P reserve is 4.5,
20.5 and 39.2 years, respectively. These figures are
obtained by using an annual natural gas production
of 931.1 billion cubic feet of natural gas.
Table 6.16 shows the evolution over the last three
years of the oil equivalent reserves broken down
by fluid type for the Northern Region. Based on the
above, it can be seen that for 2009, 50.2 percent of
the proved reserve volume consists of crude oil, 43.0
percent is dry gas equivalent to liquid, 6.4 percent
is plant liquids, and 0.5 percent is condensate. The
figures for the probable oil equivalent reserves are
made up as follows: 66.0 percent is oil, 24.5 percent
is dry gas equivalent to liquid, 9.5 percent is plant
liquids and 0.1 percent corresponds to condensate.
Finally, the possible oil equivalent reserve is made up
as follows: 62.2 percent is oil, 27.1 percent is dry gas
equivalent to liquid, 10.6 percent is plant liquids and
0.1 percent corresponds to condensate.
Table 6.16 Historical evolution of reserves by fluid type in the Northern Region.
Year
Category
Crude Oil
Condensate
MMbbl
MMbbl
Plant
Liquids
MMbbl
Dry Gas
Equivalent
MMboe
Total
MMboe
2007
Total
Proved
Probable
Possible
2008
Total
Proved
Probable
Possible
12,769.4
888.9
6,099.7
5,780.8
39.4
18.2
9.5
11.7
1,711.4
106.4
751.9
853.1
5,876.7
832.9
2,360.5
2,683.3
20,397.0
1,846.4
9,221.6
9,328.9
12,546.0
840.7
6,056.7
5,648.7
19.4
8.2
5.0
6.3
1,970.5
102.4
883.0
985.1
5,613.0
770.2
2,289.5
2,553.3
20,149.0
1,721.5
9,234.1
9,193.4
2009
Total
Proved
Probable
Possible
12,402.9
828.7
5,845.0
5,729.2
19.1
8.0
4.6
6.5
1,918.2
105.5
838.4
974.3
5,384.6
710.1
2,174.6
2,499.9
19,724.8
1,652.4
8,862.6
9,209.9
103
The Cinco Presidentes Integral Business Unit has the
highest number of fields, 43, which represents 27.6
percent of the regional total.
6.4 Southern Region
The Southern Region covers an area of approximately
390,000 square kilometers and it is in the southern
part of Mexico. To the north it borders on the Gulf
of Mexico, to the northwest it adjoins the Northern
Region at parallel 18 and Río Tesechoacán. The eastern part is limited by the Caribbean Sea, Belize and
Guatemala and to the south by the Pacific Ocean.
The region encompasses 8 states in Mexico: Guerrero, Oaxaca, Veracruz, Tabasco, Campeche, Chiapas,
Yucatán, and Quintana Roo, as can be seen in Figure
6.25. It currently consists of a Regional Exploration
Business Unit and five integral business units: BellotaJujo, Cinco Presidentes, Macuspana, Muspac, and
Samaria-Luna, Figure 6.26. In 2008 the region administered 156 fields with remaining reserves; two more
than in the previous year. The additional fields, Rabasa
and Teotleco, are the result of exploratory activity.
In 2008, the regional production of hydrocarbons was
167.9 million barrels of crude oil and 530.9 billion
cubic feet of natural gas, which means 16.4 and 21.0
percent of the total national oil and gas production,
respectively. In reference to the production in terms
of oil equivalent, last year the Southern Region provided 287.8 million barrels, that is, 19.8 percent of
the national total, which as in previous years, puts
the region in second place.
6.4.1. Evolution of Original Volumes in Place
The region’s proved original volume of oil as of January 1, 2009 is 36,926.0 million barrels, which is 24.5
N
W
E
S
Sonora
Chihuahua
Coahuila
Baja California Sur
Sinaloa
Nuevo León
Durango
San Luis Potosí
Aguascalientes
Nayarit
Pacific Ocean
Gulf of Mexico
Tamaulipas
Zacatecas
Guanajuato
Veracruz
Querétaro
Hidalgo
México
D.F. Tlaxcala
Michoacán
Morelos
Puebla
Yucatán
Jalisco
Colima
Guerrero
Quintana Roo
Tabasco
Southern Region
Oaxaca
Campeche
Belize
Chiapas
Guatemala
0
100
200
300
400
500 Km
Honduras
El Salvador
Figure 6.25 Geographical coverage of the Southern Region. It includes the states of Guerrero, Oaxaca,
Veracruz, Tabasco, Campeche, Chiapas, Yucatán and Quintana Roo.
104
N
W
E
S
Campeche
Frontera
BellotaJujo
Coatzacoalcos
SamariaLuna
Villahermosa
Macuspana
Tabasco
Cinco Presidentes
Palenque
Veracruz
Muspac
Ocosingo
Chiapas
0
Oaxaca
10
20
30
40
50 Km
Figure 6.26 Geographical location of the integral business units of the Southern Region.
percent of the national proved original volume. Table
6.17 shows the evolution of the original oil volume
over the last 3 years. The original volumes of oil in
the probable and possible categories are 2,508.4 and
1,272.4 million barrels, respectively, which account
for 3.0 and 2.0 percent of the country’s total. Regionally speaking, the Samaria-Luna Integral Business
Unit produces the highest percentage of the proved
original volume of oil, that is, 33.6 percent. In terms
of probable original volumes of oil, the Bellota-Jujo
Integral Business Unit provides the largest
proportion, with 37.5 percent of the region’s
volumes in the Southern Region.
total. The Samaria-Luna Integral Business
Unit provides 64.1 percent of the regional
Year
Category
Crude Oil
Natural Gas
MMbbl
Bcf
total of possible original oil volume.
2007
Total
Proved Probable
Possible
38,686.4
36,358.3
1,406.2
921.9
70,440.7
66,706.6
2,711.8
1,022.3
2008
Total
Proved Probable
Possible
40,149.8
36,863.3
2,156.9
1,129.6
72,254.5
67,159.8
3,684.7
1,410.0
2009
Total
Proved Probable
Possible
40,706.7
36,926.0
2,508.4
1,272.4
74,457.5
68,675.6
4,276.9
1,505.0
The Southern Region contributes 38.0 percent of the country’s total proved original
volume of natural gas, which means a
volume of 68,675.6 billion cubic feet. The
original volumes of natural gas in the probable and possible categories are 4,276.9 and
1,505.0 billion cubic feet, respectively, which
means 9.9 and 4.5 percent of the national
total in said categories. Regionally, the Muspac Integral Business Unit holds the highest
proved original volume of natural gas, with
105
23,384.5 billion cubic feet, that is, 34.1 percent of the
total. With a total of 1,310.0 billion cubic feet, the Bellota-Jujo Integral Business Unit is the most important
provider of the region’s probable original gas volume,
with 30.6 percent. Finally, the highest percentage of the
possible original volume of natural gas is concentrated
in the Samaria-Luna Integral Business Unit, with 33.0
percent of the total.
As of January 2009, the Southern Region reported
an increase of 1.4 percent in the total or 3P original
volume of oil in comparison with the previous year,
which means, 40,706.7 million barrels. This increase
was mostly the result of a rise in the probable category
thanks to the development of the Sunuapa field and
the discovery of the Teotleco field.
The total or 3P original natural gas volume was
74,457.5 billion cubic feet, which means an increase
of 3.0 percent when compared with the previous year
that was mostly in the probable category, primarily
because of the addition of the new Teotleco field.
The proved original volume of oil as of January 1, 2009
was 36,926.0 million barrels, that is, 0.2 percent higher
than the figure for the previous year. This positive
variation originated in the Muspac and Samaria-Luna
integral business units where the Sunuapa, Caparroso-Pijije-Escuintle and Sen fields raised volumes by
124.0, 91.0 and 59.1 million barrels of oil, respectively.
The respective geological models were updated in
the first two fields as a result of drilling development
wells. The increase in the Sen field was also due to
the result of drilling 4 wells in 2008, and the new 3D
Chopo seismic interpretation.
The proved original volume of natural gas as of January 1, 2009, was 68,675.6 billion cubic feet, which
means an increase of 2.3 percent when compared
with the previous year. This increase can largely be
attributed to the Tizón field with 286.8 billion cubic
106
feet of natural gas that occurred as a result of field
development. Furthermore, the Costero field also
reported a sizeable rise of 240.0 billion cubic feet of
gas caused by the new seismic reinterpretation and
field development activities.
The probable original volume of crude oil increased by
16.3 percent compared to the previous year to a total
of 2,508.4 million barrels as of January 1, 2009. The
most important increase, 168.6 million barrels, was
in the Sunuapa field and it was due to the updating of
the geological model of the East block, as a result of
drilling the Sunuapa-302 and 304 wells. Noteworthy
increases were also reported in the Muspac and Cinco
Presidentes integral business units that were essentially the result of additions made by the discoveries of
the Teotleco and Rabasa fields, which provided 127.0
and 53.0 million barrels of oil, respectively.
The probable original natural gas volume was 4,276.9
billion cubic feet as of January 1, 2009, which means
an increase of 16.1 percent as against the previous
year. This rise was mostly due to exploratory additions
as a result of the discoveries in the Teotleco and Rabasa fields, estimated at 340.3 and 35.0 billion cubic
feet of gas, respectively.
The original volume of oil in the possible category
was 1,272.4 million barrels, that is, 12.6 percent
higher than the figure for the previous year. As in
the previous cases, this increase is essentially due to
the exploratory addition of the Rabasa and Teotleco
fields, which contributed 54.0 and 52.7 million barrels
of oil, respectively.
The possible original natural gas volume as of January 1, 2009 is 1,505.0 billion cubic feet, which means
a rise of 6.7 percent when compared with the year
2008. This positive variation was primarily because
of Sen and Paché fields, with the addition of 157.5
and 142.8 billion cubic feet of gas, respectively. Furthermore, the discovery of the Teotleco field added
141.2 billion cubic feet of gas. The increase in the Sen
field is due to the updating of the 3D Chopo seismic
reinterpretation, and also to the result of the static
characterization study in the Paché field.
MMbbl
3,727.9
3,801.0
3,652.9
Possible
393.9
422.4
Probable
745.3
765.8
2,588.7
2,612.8
2,480.2
2007
2008
2009
471.8
700.8
The Southern Region’s total or 3P reserves as of January 1, 2009 are 3,652.9 million barrels of oil and 9,406.5
billion cubic feet of natural gas, which accounts for
11.8 and 15.6 percent, respectively, of the national
total reserves. Figures 6.27 and 6.28 show the historic
evolution of oil and natural gas reserves over the last
three years in the region.
The region’s 2P or proved plus probable reserves, as
of January 1, 2009, totaled 3,181.1 million barrels of
oil and 8,504.3 billion cubic feet of natural gas, which
is 15.3 and 22.5 percent, respectively, of the country’s
total. Tables 6.18 and 6.19 show the distribution of the
2P and 3P reserves at a business unit level, classified
as heavy, light and superlight oil; the gas is given as
associated and non-associated gas.
The region’s proved oil reserve reported as of January
1, 2009, was 2,480.2 million barrels, that is, 23.8 percent of the country’s total proved reserve. Regionally,
the oil reserve in this category is mostly in the SamariaLuna Integral Business Unit, with 49.2 percent, or in
other words 1,220.5 million barrels of oil. The region’s
proved natural gas reserve amounts to 2,650.0 billion
cubic feet, with is equal to 37.4 percent of the national
total, where the Samaria-Luna Integral Business Unit
is the most important, with a contribution of 40.1 percent of the regional total, followed by the Bellota-Jujo
Integral Business Unit with 32.6 percent.
The developed proved oil and natural gas reserve as
of January 1, 2009 were 1,719.4 million barrels and
4,062.8 billion cubic feet, which account for 22.5 and
35.5 percent of the national total, respectively. The
undeveloped proved reserves, however, were 760.9
million barrels of crude oil and 2,539.3 billion cubic
Proved
Figure 6.27 Historical evolution of the remaining crude oil reserves in the Southern Region
feet of natural gas, that is, the equivalent of 27.5 and
41.0 percent of the national total.
The region’s proved oil reserves are made up as follows: 1,910.2 million barrels of light oil or 77.0 percent,
followed by superlight reserves and finally by heavy
oil reserves with 520.5 and 49.5 million barrels, respectively, that are equal to 21.0 and 2.0 percent. The
most important light oil fields are Jujo-Tecominoacán,
Samaria, and Iride, with 1,401.2 million barrels of oil,
which is 73.4 percent of the regional total.
In reference to the Southern Region’s proved natural
gas reserve, this volume is made up of 5,222.8 billion
cubic feet of associated gas, which is 79.1 percent of
Bcf
10,456.6
Possible
996.0
Probable
2,042.2
Proved
10,160.4
1,048.2
1,938.2
7,418.4
7,174.0
2007
2008
9,406.5
902.2
1,902.2
6,602.1
2009
Figure 6.28 Historical evolution of the remaining natural gas reserves in the Southern Region over the last three years.
107
Table 6.18 Composition of 2P reserves by business unit of the Southern Region.
Business Unit
Total
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Crude Oil
Heavy
MMbbl
Light
MMbbl
194.8
27.4
17.5
0.0
15.2
134.7
2,137.2
791.0
249.0
15.4
49.9
1,031.9
the regional total, while the non-associated gas constitutes the remaining 20.9 percent or 1,379.3 billion
cubic feet. The associated gas fields that provided the
most reserves are Jujo-Tecominoacán, Iride, Samaria,
Cunduacán, and Oxiacaque, which jointly provide
3,488.3 billion cubic feet of gas, while the most significant non-associated gas contribution came from
the Chiapas-Copanó, Giraldas, Costero, Narváez and
Muspac fields, with 879.8 billion cubic feet of gas.
Natural Gas
Superlight
MMbbl
849.0
254.0
16.5
66.7
142.7
369.1
Associated
Bcf
Non-associated
Bcf
6,282.0
2,322.5
369.5
7.7
521.8
3,060.5
2,222.3
122.6
20.3
1,096.0
810.4
173.0
The region’s possible reserves totaled 471.8 million
barrels of oil, that is, 4.6 percent of the national total,
while in the case of gas, the possible reserve was
902.2 billion cubic feet, or 4.0 percent of the country’s
reserves. 64.8 percent of the possible oil reserves, that
is 305.6 million barrels, are in the Magallanes-TucánPajonal, Iride, Carrizo, Sitio Grande, Sen, Samaria and
Sunuapa fields.
The region’s probable oil reserve amount is estimated
at 700.8 million barrels, which is 6.8 percent of the
national total, while the natural gas reserve is 1,902.2
billion cubic feet, that is, 9.5 percent of the national
total. The most important probable oil reserves are in
the Samaria-Luna and Bellota-Jujo integral business
units, particularly in the Samaria and Cunduacán fields
with 210.4 million barrels of oil, and Tajón and Tepeyil
with 50.5 million barrels.
Compared with the previous year, the Southern
Region’s proved oil reserves as of January 1, 2009
increased by 1.3 percent to 2,480.2 million barrels.
This positive variation was mostly in the Sen, Costero, Sunuapa, Caparroso-Pijije-Escuintle, Guaricho
and Mora fields, which jointly reclassified 101.6 million barrels of oil as proved reserve. The increase in
these fields was due to the updating of the respective
Table 6.19 Composition of 3P reserves by business unit of the Southern Region.
Business Unit
Total
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
108
Crude Oil
Heavy
MMbbl
Light
MMbbl
350.1
29.6
29.9
0.0
15.7
274.9
2,327.1
798.5
336.0
15.5
144.2
1,032.9
Natural Gas
Superlight
MMbbl
975.6
267.5
24.5
81.7
183.3
418.6
Associated
Bcf
Non-associated
Bcf
6,758.4
2,361.4
477.3
7.8
728.8
3,183.0
2,648.2
131.5
51.2
1,291.6
946.6
227.3
geological models as a result of drilling development
wells in 2008.
The Southern Region’s proved natural gas reserves,
compared with the previous year, declined by 41.0
billion cubic feet and reached a value of 6,602.1 billion cubic feet as of January 1, 2009. The decrease is
largely explained by the production of 530.9 billion
cubic feet of natural gas and the reduction in the Samaria and Chiapas-Copanó fields of 172.8 billion cubic
feet of gas. As regards the increases in this category
of reserve, the Costero field reported a value of 160.6
billion cubic feet of natural gas that is attributable to
the new geological model based on the successful
completion of the Costero-12, 31, and 2, wells.
The region’s probable oil reserves as of January 1, 2009
totaled 700.8 million barrels, which means a decrease
of 64.9 million barrels compared with the reserve as of
January 1. 2008. This decline in reserves was mostly
due to the reductions reported in the Tajón, Paché, Iride,
Palangre and Yagual fields totaling 160.8 million barrels
of oil. In the Tajón field, the decrease was caused by
a revision of the pressure-production behavior in the
Tajón-101 well, and the adverse results obtained by
drilling the Tajón-105 and 121 wells. In the case of the
Paché, Palangre and Yagual fields, the reason is the
removal of blocks in these fields and in Iride, it was
caused by a revision of the field’s pressure-production
behavior. There some were increases, but they were not
able to compensate for the reductions. For example,
the discoveries in the Teotleco and Rabasa fields added
30.8 and 12.2 million barrels of oil, respectively.
The region’s probable natural gas reserve reported a
decline of 36.0 billion cubic feet compared with January 1, 2008. Consequently, as of January 1, 2009, the
reserve was 1,902.2 billion cubic feet of natural gas.
The reduction in reserves was basically due to the
revision of the Paché field.
Table 6.20 Distribution of remaining gas reserves by business unit of the Southern Region as of
January 1, 2009.
Category
Business Unit
Natural Gas
Bcf
Proved
Total
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Probable
Total
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Possible
Total
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Gas to be
Delivered to Plant
Bcf
Dry Gas
Bcf
6,602.1
2,155.4
271.6
609.3
915.9
2,650.0
6,242.2
1,942.4
219.6
596.5
881.2
2,602.5
4,782.2
1,461.8
180.7
520.7
662.5
1,956.4
1,902.2
289.7
118.2
494.4
416.3
583.5
1,805.7
257.1
100.9
489.1
385.4
573.3
1,400.9
193.5
83.0
398.6
294.9
431.0
902.2
47.8
138.7
195.7
343.2
176.8
837.2
42.3
90.5
193.9
336.4
174.1
649.0
33.5
74.5
150.9
259.2
130.9
109
MMboe
6,641.4
1,610.0
1,038.7
116.6
6,246.3
6,216.1
1,479.4
1,420.9
84.7
-200.6
50.1
-287.8
5,862.5
1,313.6
898.4
948.1
95.8
91.0
89.2
3,876.1
3,727.9
3,801.0
2006
2007
2008
806.8
Revisions
Plant Liquids
Condensate
3,652.9
Additions
Dry Gas
Equivalent
Crude Oil
2009
Figure 6.29 Elements of change in the total reserve of the Southern Region.
The region’s possible oil reserves as of January 1,
2009 increased by 49.4 million barrels, when compared with the figure reported as of January 1, 2008,
to the figure of 471.8 million barrels. This increase
mostly took place in Sen, Paché, Teotleco, Rabasa
and Sunuapa fields, with 16.9, 13.5, 12.7, 12.4 and
10.3 million barrels, respectively. The development
of the Sen field and the characterization study of the
Paché field led to an increase in this category of reserve, which is also the case of the discoveries in the
Teotleco and Rabasa fields as a result of exploratory
activity. The possible natural gas reserves, however,
declined by 146.0 billion cubic feet when compared
with the previous year, which meant a remaining reserve value of 902.2 billion cubic feet as of January 1,
2009. The most important negative variation was in
the Costero field, due to the revision of the geological model based on drilling development wells. Table
6.20 shows the distribution of natural gas, gas to be
delivered to plant and dry gas reserves in the proved,
probable and possible categories.
Oil Equivalent
The volume of 3P reserve in terms of oil equivalent,
that is, proved plus probable plus possible reserves
as of January 1, 2009 totaled 5,862.5 million barrels,
which is 13.5 percent of the total national reserve.
When compared with the previous year, this value
means a reduction of 1.1 percent considering the
MMboe
1,439.7
316.1
247.0
169.0
4,049.1
Macuspana
Total
1,877.3
SamariaLuna
BellotaJujo
Muspac
Cinco
Presidentes
Figure 6.30 Proved reserves as of January 1, 2009, distributed by business unit in the Southern Region.
110
MMboe
117.8
1,140.3
Cinco
Presidentes
Total
153.9
201.9
208.4
458.4
SamariaLuna
BellotaJujo
Muspac
Macuspana
Figure 6.31 Probable reserves as of January 1, 2009, distributed by business unit in the Southern Region.
production obtained in 2008. The 3P reserve mostly
lies in the fields of the Samaria-Luna and Bellota-Jujo
integral business units, which hold 72.5 percent of the
total. Figure 6.29 shows the variation in 3P reserves
over 2008, compared with 2006 and 2007.
The Southern Region’s proved reserve, as of January 1, 2009 in terms of oil equivalent amounted to
4,049.1 million barrels, which is 28.3 percent of the
proved national reserve, Figure 6.30. When compared with last year, the reserve decreased by 4.2
million barrels of oil equivalent; said negative variation was mostly the result of revising the pressureproduction behavior in the Jujo-Tecominoacán and
Samaria fields.
The region’s probable oil equivalent reserve, as of
January 1, 2009, amounted to 1,140.3 million barrels,
or 7.9 percent of the country’s probable reserves,
Figure 6.31. This means a decrease of 75.0 million
barrels of oil equivalent in this category, compared
to the volume of remaining reserves in the previous
year. The situation was mainly caused by unfavorable
well drilling activities in 2008 in the Tajón field.
As of January 1, 2009, the possible reserve amounted
to 673.0 million barrels of oil equivalent, which is 4.6
percent of the country’s possible reserves, Figure
6.32. Compared with the previous year, the region’s
possible reserve showed an increase of 13.3 million
barrels of oil equivalent. This positive variation was
MMboe
130.6
60.5
33.4
673.0
BellotaJujo
Total
215.7
232.8
SamariaLuna
Muspac
Cinco
Presidentes
Macuspana
Figure 6.32 Possible reserves as of January 1, 2009, distributed by business unit in the Southern Region.
111
mostly in the Sen, Paché, Teotleco and Rabasa fields,
which jointly added 82.0 million barrels. Nevertheless, this increase was counteracted by the Costero
and Tizón fields, whose reserves fell by 40.0 and 30.6
million barrels of oil equivalent, respectively.
The proved oil reserve-production ratio of the Southern Region is 14.8 years if an annual production of
167.9 million barrels of oil is used. If the ratio is calculated for the 2P reserve, the figure is 18.9 years, and
21.8 years in the case of 3P reserves. The SamariaLuna Integral Business Unit has the highest proved
oil reserve-production ratio in the region, with 18.1
years, followed by the Bellota-Jujo Integral Business
Unit with a ratio of 14.6 years.
The proved natural gas reserve-production ratio is
12.4 years when using an annual production of 530.9
billion cubic feet, while values of 16.0 and 17.7 years,
respectively, are obtained for the 2P and 3P reserve
categories. The Bellota-Jujo Integral Business Unit
has the highest proved reserve-production ratio in
the region, with 23.5 years.
The region’s proved reserve-production ratio, in terms
of oil equivalent, is 14.1 years, considering a production of 287.8 million barrels of oil equivalent in 2008.
The ratio for the 2P reserve is 18.0 years and 20.4
years for the 3P reserve. The Bellota-Jujo and SamariaLuna integral business units show the highest proved
reserve-production ratio in the region, with 16.9 and
16.2 years, respectively.
The Southern Region’s proved reserve is made up of
61.3 percent crude oil, 1.9 percent condensate, 14.2
percent plant liquids, and 22.7 percent dry gas equivalent to liquid. According to the above, the existence of
a large number of non-associated gas, oil and associated gas reservoirs with high gas-oil ratios is evident.
Furthermore, it can be seen that the gas produced by
these reservoirs has a high amount of liquids that are
recovered in the processing complexes.
The probable reserve totals 1,140.3 million barrels of
oil equivalent, of which 61.5 percent is crude oil, 1.0
percent is condensate, 13.9 percent is plant liquids,
and 23.6 percent is dry gas equivalent to liquid.
Table 6.21 Historical evolution of reserves by fluid type in the Southern Region.
Year
Category
Crude Oil
Condensate
MMbbl
MMbbl
2007
Total
Proved
Probable
Possible
2008
Total
Proved
Probable
Possible
2009
Total
Proved
Probable
Possible
112
Plant
Liquids
MMbbl
Dry Gas
Equivalent
MMboe
Total
MMboe
3,727.9
2,588.7
745.3
393.9
91.0
78.9
9.5
2.6
948.1
671.6
184.6
91.9
1,479.4
1,049.2
290.3
139.9
6,246.3
4,388.4
1,229.7
628.2
3,801.0
2,612.8
765.8
422.4
95.8
82.8
11.0
2.0
898.4
645.9
162.3
90.2
1,420.9
999.5
276.2
145.1
6,216.1
4,341.1
1,215.3
659.8
3,652.9
2,480.2
700.8
471.8
89.2
76.3
11.1
1.8
806.8
573.1
159.0
74.7
1,313.6
919.5
269.4
124.8
5,862.5
4,049.1
1,140.3
673.0
Finally, the possible reserve amounts to 673.0 million
barrels of oil equivalent, which is made up as follows:
70.1 percent is crude oil, 0.3 percent is condensate,
11.1 percent is plant liquids, and 18.5 percent is dry
gas equivalent to liquid. Table 6.21 shows the distribution of the Southern Region’s hydrocarbon reserves
by fluid type over the last three years in the proved,
probable and possible categories.
113
114
Abbreviations
Item
1P
2D
2P
3D
3P
AAPG
API
Bbbl
bbl
bbld
Bboe
Bcf
boe
BTU
cedglf
cf
crf
DST
gr/cm3
hesf
isf
kg/cm2
Mbbl
Mboe
Mcf
MMbbl
MMboe
MMcf
MMcfd
PEP
plrf
plsf
PVT
SEC
SPE
Tcf
tlsf
WPC
proved reserves
two-dimensional
proved plus probable reserves
three-dimensional
proved plus probable plus possible reserves
American Association of Petroleum Geologists
American Petroleum Institute
billions of barrels
barrels
barrels per day
billions of barrels of oil equivalent
billions of cubic feet
barrels of oil equivalent
British Thermal Unit
calorific equivalence of dry gas to liquid factor
cubic feet
condensate recovery factor
drill stem test
grams per cubic centimeter
handling efficiency shrinkage factor
impurities shrinkage factor
kilograms per square centimeter
thousands of barrels
thousands of barrels of oil equivalent
thousands of cubic feet
millions of barrels
millions of barrels of oil equivalent
millions of cubic feet
millions of cubic feet per day
Pemex Exploración y Producción
plant liquids recovery factor
plant liquefiables shrinkage factor
pressure-volume-temperature
Securities and Exchange Commission
Society of Petroleum Engineers
trillions of cubic feet
transport liquefiables shrinkage factor
World Petroleum Council
115
116
Glossary
1P reserve: Proved reserve.
2P reserves: Total of proved plus probable reserves.
3P reserves: Total of proved reserves plus probable
reserves plus possible reserves.
Abandonment pressure: This is a direct function of
the economic premises and it corresponds to the
static bottom pressure at which the revenues obtained
from the sales of the hydrocarbons produced are
equal to the well’s operation costs.
Absolute permeability: Ability of a rock to conduct
a fluid when only one fluid is present in the pores of
the rock.
Accumulation: Natural occurrence of an individual oil
body in the reservoir.
Additions: The reserve provided by the exploratory
activity. It consists of the discoveries and delineations
in a field during the study period.
Analogous reservoir: Portion of a geological trap
hydraulically intercommunicated with reservoir conditions, drive mechanisms, and rock and fluids properties, that are similar to those of another structure of
interest, but are typically found in a more advanced
development stage, and thus provide support for its
interpretation based on limited data, as well as the
estimation of its recovery factor.
Anticline: Structural configuration of a package of
folding rocks and in which the rocks are tilted in different directions from the crest.
API specific gravity: The measure of the density of the
liquid petroleum products that is derived from the relative specific gravity, according to the following equation: API specific gravity = (141.5 / relative density) 131.5. API density is expressed in degrees; the relative
specific gravity 1.0 is equal to 10 API degrees .
Artificial production system: Any of the techniques
used to extract petroleum from the producing formation to the surface when the reservoir pressure is
insufficient to raise the oil naturally to the surface.
Associated gas: Natural gas that is in contact with
and/or dissolved in the crude oil of the reservoir. It
may be classified as gas cap (free gas) or gas in solution (dissolved gas).
Associated gas in solution or dissolved: Natural gas
dissolved in the crude oil of the reservoir, under the
prevailing pressure and temperature conditions.
Basement: Foot or base of a sedimentary sequence
composed of igneous or metamorphic rocks.
Basin: Receptacle in which a sedimentary column is
deposited that shares a common tectonic history at
various stratigraphy levels.
Bitumen: Portion of petroleum that exists in the reservoirs in a semi-solid or solid phase. In its natural
state, it generally contains sulfur, metals and other
non-hydrocarbon compounds. Natural bitumen has a
viscosity of more than 10,000 centipoises, measured
at the original temperature of the reservoir, at atmospheric pressure and gas-free. It frequently requires
treatment before being refined.
117
Glossary
Calorific equivalence of dry gas to liquid factor
(cedglf): The factor used to relate dry gas to its liquid
equivalent. It is obtained from the molar composition of the reservoir gas, considering the unit heat
value of each component and the heat value of the
equivalence liquid.
Capillary pressure: A force per area unit resulting
from the surface forces to the interface between two
fluids.
Cold production: The use of operating and specialized
exploitation techniques in order to rapidly produce
heavy oils without using thermal recovery methods.
Complex: A series of fields sharing common surface
facilities.
Compressor: A device installed in the gas pipeline
to raise the pressure and guarantee the fluid flow
through the pipeline.
Condensate: Liquids of natural gas primarily constituted by pentanes and heavier hydrocarbon
components.
Condensate recovery factor (crf): It is the factor used
to obtain liquid fractions recovered from natural gas
in the surface distribution and transportation facilities.
It is obtained from the gas and condensate handling
statistics of the last annual period in the area corresponding to the field being studied.
Contingent resource: The amounts of hydrocarbons
estimated at a given date, and which are potentially recoverable from known accumulations, but are not considered commercially recoverable under the economic
evaluation conditions corresponding to such date.
Conventional limit: The reservoir limit established
according to the degree of knowledge of, or research
into the geological, geophysical or engineering data
available.
118
Core: A cylindrical rock sample taken from a formation when drilling in order to determine its permeability, porosity, hydrocarbon saturation and other
productivity-associated properties.
Cracking: Heat and pressure procedures that transform the hydrocarbons with a high molecular weight
and boiling point to hydrocarbons with a lower molecular weight and boiling point.
Cryogenic plant: Processing plant capable of producing liquid natural gas products, including ethane, at
very low operating temperatures.
Cryogenics: The study, production and use of low
temperatures.
Deep waters: Offshore zones where the water depth
is 500 meters or more.
Delineation: Exploration activity that increases or decreases reserves by means of drilling delineation wells.
Developed proved area: Plant projection of the extension drained by the wells of a producing reservoir.
Developed proved reserves: Reserves that are expected to be recovered in existing wells, including
reserves behind pipe, that may be recovered with the
current infrastructure through additional work and with
moderate investment costs. Reserves associated with
secondary and/or enhanced recovery processes will
be considered as developed when the infrastructure
required for the process has been installed or when
the costs required for such are lower. This category
includes reserves in completed intervals which have
been opened at the time when the estimation is made,
but that have not started flowing due to market conditions, connection problems or mechanical problems,
and whose rehabilitation cost is relatively low.
Development: Activity that increases or decreases
reserves by means of drilling exploitation wells.
Development well: A well drilled in a proved area in
order to produce hydrocarbons.
Dewpoint pressure: Pressure at which the first drop
of liquid is formed, when it goes from the vapor phase
to the two-phase region.
Discovered resource: Volume of hydrocarbons tested
through wells drilled.
Discovery: Incorporation of reserves attributable to
drilling exploratory wells that test hydrocarbon-pro
ducing formations.
Dissolved gas-oil ratio: Ratio of the volume of
gas dissolved in oil compared to the volume of oil
containing gas. The ratio may be original (Rsi) or
instantaneous (Rs).
Dome: Geological structure with a semi-spherical
shape or relief.
Drainage radius: Distance from which fluids flow to
the well, that is, the distance reached by the influence
of disturbances caused by pressure drops.
Drill Stem Test: A procedure that uses a drilling
string in order to determine the productive capacity,
pressure, permeability or reservoir extension, or a
combination of the above, isolating the zone of interest with temporary packers.
Dry gas: Natural gas containing negligible amounts of
hydrocarbons heavier than methane. Dry gas is also
obtained from the processing complexes.
Dry gas equivalent to liquid (DGEL): Volume of crude
oil that because of its heat rate is equivalent to the
volume of dry gas.
Economic limit: The point at which the revenues
obtained from the sale of hydrocarbons match the
costs incurred in its exploitation.
Economic reserves: Accumulated production that is
obtained from a production forecast in which economic criteria are applied.
Effective permeability: A relative measure of the
conductivity of a porous medium for a fluid when the
medium is saturated with more than one fluid. This
implies that the effective permeability is a property
associated with each reservoir flow, for example, gas,
oil and water. A fundamental principle is that the total
of the effective permeability is less than or equal to
the absolute permeability.
Effective porosity: A fraction that is obtained by dividing the total volume of communicated pores and
the total rock volume.
Enhanced recovery: The recovery of oil by injecting
materials that are not normally present in the reservoir and which modify the dynamic behavior of the
resident fluids. Enhanced recovery is not limited to
any particular stage in the life of a reservoir (primary,
secondary or tertiary).
Evaporites: Sedimentary formations consisting
primarily of salt, anhydrite or gypsum, as a result of
evaporation in coastal waters.
Exploratory well: A well that is drilled without detailed
knowledge of the underlying rock structure in order
to find hydrocarbons whose exploitation is economically profitable.
Extraheavy oil: Crude oil with relatively high fractions
of heavy components, high specific gravity (low API
density) and high viscosity at reservoir conditions. The
production of this kind of oil generally implies difficulties in extraction and high costs. Thermal recovery
methods are the most common form of commercially
exploiting this kind of oil.
Fault: Fractured surface of geological strata along
which there has been differential movement.
119
Glossary
Field: An area consisting of one or more reservoirs,
all of which are grouped or related under the same
structural geological aspects and/or stratigraphic conditions. There may be two or more reservoirs in the
field separated vertically by a layer of impermeable
rock or laterally by geological barriers or by both.
Fluid contact: The surface or interface of a reservoir
that separates two regions characterized by predominant differences in fluid saturation. Because of
capillary and other phenomena, the change in fluid
saturation is not necessarily abrupt, and the surface
does not have to be horizontal.
Fluid saturation: Portion of the pore space occupied
by a specific fluid; oil, gas and water may exist.
Formation resistance factor (F): Ratio between the
resistance of rock saturated 100 percent with brine
divided by the resistance of the saturating water.
Formation volume factor (B): The factor that relates
the volume unit of the fluid in the reservoir with the
surface volume. There are volume factors for oil,
gas, in both phases, and for water. A sample may be
directly measured, calculated or obtained through
empirical correlations.
Free associated gas: Natural gas that overlies and is
in contact with the crude oil of the reservoir. It may
be gas cap.
Gas compressibility ratio (Z): The ratio between an
actual gas volume and an ideal gas volume. This is
an adimensional amount that usually varies between
0.7 and 1.2.
Geological province: A region of large dimensions
characterized by similar geological and development
histories.
Graben: Dip or depression formed by tectonic processes, limited by normal type faults.
Gravitational segregation: Reservoir driving mechanism in which the fluids tend to separate according
to their specific gravities. For example, since oil is
heavier than water it tends to move towards the lower
part of the reservoir in a water injection project.
Handling efficiency shrinkage factor (hesf): This is a
fraction of natural gas that is derived from considering
self-consumption and the lack of capacity to handle
such. It is obtained from the gas handling statistics
of the final period in the area corresponding to the
field being studied.
Heat value: The amount of heat released per unit
of mass, or per unit of volume, when a substance
is completely burned. The heat power of solid and
liquid fuels is expressed in calories per gram or in
BTU per pound. For gases, this parameter is generally
expressed in kilocalories per cubic meter or in BTU
per cubic foot.
Heavy oil: The specific gravity is less than or equal
to 27 API degrees.
Horst: Bock of the earth’s crust rising between two
faults; the opposite of a graben.
Hot production: The optimum production of heavy
oils through use of enhanced thermal recovery
methods.
Gas lift: Artificial production system that is used to raise
the well fluid by injecting gas down the well through
tubing, or through the tubing-casing annulus.
Hydrocarbon index: An amount of hydrocarbons
contained in a reservoir per unit area.
Gas-oil ratio (GOR): Ratio of reservoir gas production
to oil production, measured at atmospheric pressure.
Hydrocarbon reserves: Volume of hydrocarbons measured at atmospheric conditions that will be produced
120
economically by using any of the existing production
methods at the date of evaluation.
Hydrocarbons: Chemical compounds fully constituted
by hydrogen and carbon.
Impurities and plant liquefiables shrinkage factor
(iplsf): It is the fraction obtained by considering the
non-hydrocarbon gas impurities (sulfur, carbon dioxide, nitrogen compounds, etc.) contained in the sour
gas, in addition to shrinkage caused by the generation
of plant liquids in gas processing complex.
Impurities shrinkage factor (isf): It is the fraction
that results from considering the non-hydrocarbon
gas impurities (sulfur, carbon dioxide, nitrogen compounds, etc.) contained in the sour gas. It is obtained
from the operation statistics of the last annual period
of the gas processing complex (GPC) that processes
the production of the field analyzed.
Kerogen: Insoluble organic matter spread throughout
the sedimentary rocks that produces hydrocarbon
when subjected to a distillation process.
Light oil: The specific gravity of the oil is more than 27
API degrees, but less than or equal to 38 degrees.
Limolite: Fine grain sedimentary rock that is transported by water. The granulometrics ranges from
fine sand to clay.
Metamorphic: Group of rocks resulting from the transformation that commonly takes place at great depths
due to pressure and temperature. The original rocks
may be sedimentary, igneous or metamorphic.
Natural gas: Mixture of hydrocarbons existing in
reservoirs in the gaseous phase or in solution in the
oil, which remains in the gaseous phase under atmospheric conditions. It may contain some impurities
or non-hydrocarbon substances (hydrogen sulfide,
nitrogen or carbon dioxide).
Net thickness (hn): The thickness resulting from
subtracting the portions that have no possibilities of
producing hydrocarbon from the total thickness.
Non-associated gas: The natural gas found in reservoirs that do not contain crude oil at the original
pressure and temperature conditions.
Non-proved reserves: Volumes of hydrocarbons and
associated substances, evaluated at atmospheric
conditions, resulting from the extrapolation of the
characteristics and parameters of the reservoir
beyond the limits of reasonable certainty, or from
assuming oil and gas forecasts with technical and
economic scenarios other than those in operation or
with a project in view.
Normal fault: The result of the downward displacement of one of the blocks from the horizontal. The
angle is generally between 25 and 60 degrees and it is
recognized by the absence of part of the stratigraphic
column.
Oil: Portion of petroleum that exists in the liquid phase
in reservoirs and remains as such under original pressure and temperature conditions. Small amounts of
non-hydrocarbon substances may be included. It has
a viscosity of less than or equal to 10,000 centipoises
at the original temperature of the reservoir, at atmospheric pressure and gas-free (stabilized). Oil is commonly classified in terms of its specific gravity and it
is expressed in API degrees.
Oil equivalent (OE): Total of crude oil, condensate,
plant liquids and dry gas equivalent to liquid.
Original gas volume in place: Amount of gas that is
estimated to exist initially in the reservoir and that is
confined by geologic and fluid boundaries, which may
be expressed at reservoir or atmospheric conditions.
Original oil volume in place: Amount of petroleum
that is estimated to exist initially in the reservoir and
121
Glossary
that is confined by geologic and fluid boundaries,
which may be expressed at reservoir or atmospheric
conditions.
Original pressure: Pressure prevailing in a reservoir
that has never been exploited. It is the pressure measured by a discovery well in a producing structure.
Original reserve: Volume of hydrocarbons at atmospheric conditions that are expected to be recovered
economically by using the exploitation methods and
systems applicable at a specific date. It is a fraction
of the discovered and economic reserve that may be
obtained at the end of the reservoir exploitation.
Permeability: Rock property for permitting a fluid
pass. It is a factor that indicates whether a reservoir
has producing characteristics or not.
Petroleum: Mixture of hydrocarbons composed of
combinations of carbon and hydrogen atoms found
in the porous spaces of rocks. Crude oil may contain
other elements of a non-metal origin, such as sulfur,
oxygen and nitrogen, in addition to trace metals
as minor constituents. The compounds that form
petroleum may be a gaseous, liquid or solid state,
depending on their nature and the existing pressure
and temperature conditions.
Phase: Part of the system that differs in its intensive
properties from the other part of the system. Hydrocarbon systems generally have two phases: gaseous
and liquid.
Physical limit: The limit of the reservoir defined by
any geological structures (faults, unconformities,
change of facies, crests and bases of formations, etc.),
caused by contact between fluids or by the reduction
to critical limits of porosity and permeability, or the
combined effect of these parameters.
Pilot project: Project that is being executed in a small
representative sector of a reservoir where tests per122
formed are similar to those that will be implemented
throughout the reservoir. The purpose is to gather
information and/or obtain results that could be used
to generalize an exploitation strategy in the oil field.
Plant liquefiables shrinkage factor (plsf): The fraction
arising from considering the liquefiables obtained in
the processing complexes. It is obtained from the
operation statistics of the last annual period of the gas
processing complex that processes the production of
the field analyzed.
Plant liquids: Natural gas liquids recovered in gas
processing complexes, mainly consisting of ethane,
propane and butane.
Plant liquids recovery factor (plrf): The factor used
to obtain the liquid portions recovered in the natural
gas processing complex. It is obtained from the operation statistics of the last annual period of the gas
processing complex that processes the production
of the field analyzed.
Play: Group of fields and/or prospects in a given
regions that are controlled by the same general geological characteristics (storage rock, seal, source rock
and trap type).
Porosity: Ratio between the pore volume existing in
a rock and the total rock volume. It is a measure of
rock’s storage capacity.
Possible reserves: Volume of hydrocarbons where the
analysis of geological and engineering data suggests
that they are less likely to be commercially recoverable than probable reserves.
Primary recovery: Extraction of petroleum by only using the natural energy available in the reservoirs to displace fluids through the reservoir rock to the wells.
Probable reserves: Non-proved reserves where the
analysis of geological and engineering data suggests
that they are more likely to be commercially recoverable than not.
is the difference between the original reserve and the
cumulative hydrocarbon production at a given date.
Prospective resource: It is the volume of hydrocarbons estimated at a given date of accumulations
not yet discovered, but which have been inferred,
and which are estimated as potentially recoverable through the application of future development
projects.
Reserve replacement rate: It indicates the amount
of hydrocarbons replaced or incorporated by new
discoveries compared with what has been produced
in a given period. It is the coefficient that arises from
dividing the new discoveries by production during
the period of analysis and it is generally referred to in
annual terms and is expressed as a percentage.
Proved area: Plant projection of the known part of the
reservoir corresponding to the proved volume.
Proved reserves: Volume of hydrocarbons or associated substances evaluated at atmospheric conditions,
which by analysis of geological and engineering data,
may be estimated with reasonable certainty to be
commercially recoverable from a given date forward,
from known reservoirs and under current economic
conditions, operating methods and government regulations. Such volume consists of the developed proved
reserve and the undeveloped proved reserve.
Recovery factor (rf): The ratio between the original
volume of oil or gas, at atmospheric conditions, and
the original reserves of the reservoir.
Regression: Geological term used to define the elevation of one part of the continent over sea level, as a
result of the ascent of the continent or the lowering
of the sea level.
Relative permeability: The capacity of a fluid, such
as water, gas or oil, to flow through a rock when it is
saturated with two or more fluids. The value of the
permeability of a saturated rock with two or more
fluids is different to the permeability value of the same
rock saturated with just one fluid.
Remaining reserves: Volume of hydrocarbons measured at atmospheric conditions that are still to be
commercially recoverable from a reservoir at a given
date, using the applicable exploitation techniques. It
Reserve-production ratio: The result of dividing the
remaining reserve at a given date by the production
in a period. This indicator assumes constant production, hydrocarbon prices and extraction costs, without
variation over time, in addition to the non-existence
of new discoveries in the future.
Reservoir: Portion of the geological trap containing
hydrocarbons that acts as a hydraulically interconnected system, and where the hydrocarbons are
found at an elevated temperature and pressure occupying the porous spaces.
Resource: Total volume of hydrocarbons existing in subsurface rocks. Also known as original in-situ volume.
Reverse fault: The result of compression forces where
one of the blocks is displaced upwards from the horizontal. The angle ranges from 0 to 90 degrees and it
is recognized by the repetition of the stratigraphic
column.
Revision: The reserve resulting from comparing the
previous year’s evaluation with the new one in which
new geological, geophysical, operation and reservoir
performance information is considered, in addition to
variations in hydrocarbon prices and extraction costs.
It does not include well drilling.
Saturation pressure: Pressure at which the first gas
bubble is formed, when it goes from the liquid phase
to the two-phase region.
123
Glossary
Secondary recovery: Techniques used for the additional extraction of petroleum after primary recovery.
This includes gas or water injection, partly to maintain
reservoir pressure.
Sweetening plant: Industrial plant used to treat gaseous mixtures and light petroleum fractions in order to
eliminate undesirable or corrosive sulfur compounds
to improve their color, odor and stability.
Seismic section: Seismic profile that uses the reflection of seismic waves to determine the geological
subsurface.
Technical reserves: Accumulative production derived
from a production forecast in which economic criteria
are not applied.
Spacing: Optimum distance between hydrocarbon
producing wells in a field or reservoir.
Total thickness (h): Thickness from the top of the
formation of interest down to a vertical boundary
determined by a water level or by a change of
formation.
Specific gravity: An intensive property of the matter that is related to the mass of a substance and its
volume through the coefficient between these two
quantities. It is expressed in grams per cubic centimeter or in pounds per gallon.
Standard conditions: The reference amounts for
pressure and temperature. In the English system, it
is 14.73 pounds per square inch for the pressure and
60 degrees Fahrenheit for temperature.
Stimulation: Process of acidifying or fracturing carried out to expand existing ducts or to create new
ones in the source rock formation.
Stratigraphy: Part of geology that studies the origin,
composition, distribution and succession of rock
strata.
Structural nose: A term used in structural geology
to define a geometric form protruding from a main
body.
Sucker rod pumping system: A method of artificial
lift in which a subsurface pump located at or near
the bottom of the well and connected to a string
of sucker rods is used to lift the well fluid to the
surface.
Superlight oil: The specific gravity is more than 38
API degrees.
124
Transgression: Geological term used to define the
immersion of one part of the continent under sea
level, as a result of a descent of the continent or an
elevation of the sea level.
Transport liquefiables shrinkage factor (tlsf): The
fraction obtained by considering the liquefiables obtained in transportation to the processing complexes.
It is obtained from the gas handling statistics of the
last annual period in the area corresponding to the
field being studied.
Trap: Geometry that permits the concentration of
hydrocarbons.
Undeveloped proved area: Plant projection of the
extension drained by the future producing wells of a
producing reservoir and located within the undeveloped proved reserve.
Undeveloped proved reserves: Volume of hydrocarbons that is expected to be recovered through wells
without current facilities for production or transportation and future wells. This category may include the
estimated reserve of enhanced recovery projects,
with pilot testing, or with the recovery mechanism
proposed in operation that has been predicted with
a high degree of certainty in reservoirs that benefit
from this kind of exploitation.
Undiscovered resource: Volume of hydrocarbons
with uncertainty, but whose existence is inferred
in geological basins through favorable factors
resulting from the geological, geophysical and
geochemical interpretation. They are known as prospective resources when considered commercially
recoverable.
Well abandonment: The final activity in the operation
of a well when it is permanently closed under safety
and environment preservation conditions.
Well logs: The information concerning subsurface
formations obtained by means of electric, acoustic
and radioactive tools inserted in the wells. The log also
includes information about drilling and the analysis of
mud and cuts, cores and formation tests.
Wet gas: Mixture of hydrocarbons obtained from processing natural gas from which non-hydrocarbon impu
rities or compounds have been eliminated, and whose
content of components that are heavier than methane
is such that it can be commercially processed.
125
Glossary
126
127
63,326.0
6,114.9
4,186.0
51,752.8
1,272.4
Possible
Northern
Southern
33,658.3
1,154.3
6,338.6
24,660.4
1,505.0
224,127.0
24,878.7
27,055.6
99,240.3
72,952.5
43,190.4
897.3
5,439.7
32,576.6
4,276.9
180,936.6
23,981.4
21,615.9
66,663.6
68,675.6
257,785.3
26,033.0
33,394.2
123,900.7
74,457.5
Bcf
14,737.9
3,096.5
1,758.5
9,209.9
673.0
28,824.6
9,689.4
3,430.8
10,515.0
5,189.4
14,516.9
2,977.1
1,536.9
8,862.6
1,140.3
14,307.7
6,712.3
1,893.9
1,652.4
4,049.1
43,562.6
12,785.9
5,189.4
19,724.8
5,862.5
MMboe
Oil Equivalent
10,149.8
2,892.8
1,056.0
5,729.2
471.8
20,780.0
8,763.8
2,161.5
6,673.7
3,181.1
10,375.8
2,844.5
985.5
5,845.0
700.8
10,404.2
5,919.3
1,176.0
828.7
2,480.2
30,929.8
11,656.6
3,217.4
12,402.9
3,652.9
101.7
70.7
22.8
6.5
1.8
460.0
298.2
61.7
12.7
87.4
81.6
42.1
23.7
4.6
11.1
378.4
256.1
38.0
8.0
76.3
561.7
368.9
84.5
19.1
89.2
1,233.8
42.8
142.1
974.3
74.7
2,257.4
213.9
367.6
943.9
732.1
1,174.6
30.9
146.3
838.4
159.0
1,082.9
183.0
221.2
105.5
573.1
3,491.3
256.6
509.7
1,918.2
806.8
Crude Oil Condensate
Plant
Liquids *
MMbbl
MMbbl
MMbbl
3,252.6
90.2
537.7
2,499.9
124.8
5,327.2
413.5
840.1
2,884.7
1,188.9
2,884.9
59.7
381.3
2,174.6
269.4
2,442.3
353.9
458.8
710.1
919.5
8,579.7
503.7
1,377.8
5,384.6
1,313.6
Dry Gas **
Equivalent
MMboe
22,614.3
896.1
3,433.0
17,383.0
902.2
37,760.0
3,996.8
6,138.8
19,120.0
8,504.3
20,110.5
631.1
2,675.9
14,901.3
1,902.2
17,649.5
3,365.8
3,462.9
4,218.7
6,602.1
60,374.3
4,892.9
9,571.8
36,503.1
9,406.5
Bcf
16,916.3
468.9
2,796.6
13,001.8
649.0
27,706.4
2,150.8
4,369.2
15,003.3
6,183.1
15,004.4
310.3
1,983.2
11,310.0
1,400.9
12,702.0
1,840.4
2,386.0
3,693.3
4,782.2
44,622.7
2,619.7
7,165.8
28,005.0
6,832.1
Bcf
Natural Gas
Dry Gas
* Gas liquids from processing plants.
** The liquid obtained supposes a heat value equivalent to the Maya crude oil and an average mixture of the dry gas obtained at Cactus, Ciudad Pemex and Nuevo Pemex GPC.
Note: All the units are expressed at atmospheric conditions and assume 15.6° C and 14.7 lb of pressure per square inch.
234,982.2
59,972.7
21,087.4
114,487.7
39,434.3
84,416.3
5,616.1
3,396.3
72,895.5
2,508.4
Probable
Northern
Southern
Northern
Southern
150,565.8
54,356.6
17,691.1
41,592.2
36,926.0
Proved
Northern
Southern
2P
298,308.2
66,087.6
25,273.4
166,240.5
40,706.7
Total (3P)
Northern
Southern
MMbbl
Original Volume in Place
Oil
Gas
Statistical Appendix
128
121.2
Abkatún-Pol-Chuc
Veracruz
70.3
Samaria-Luna
168.9
134.5
70.4
20.7
99.1
493.5
264.0
53.7
485.5
9.8
813.1
125.4
0.0
187.1
312.5
73.9
262.0
68.1
12.3
3.8
16.3
69.4
169.8
0.7
23.1
0.0
8.0
31.7
70.7
0.0
114.0
184.6
192.4
546.2
738.7
1,124.8
MMbbl
Crude Oil
2007
188.9
113.5
81.4
22.4
87.5
493.8
336.4
71.9
515.3
9.3
932.9
163.6
0.0
198.6
362.3
77.5
344.9
422.4
2,211.3
Bcf
Natural Gas
Note: All the units are expressed at atmospheric conditions and assume 15.6 °C and 14.7 lb of pressure per square inch.
12.2
Muspac
2.4
14.4
Cinco Presidentes
Macuspana
80.0
Bellota-Jujo
179.3
0.5
22.0
0.0
Burgos
Poza Rica-Altamira
8.3
30.8
52.2
Litoral de Tabasco
Southern
Norte
173.4
0.0
147.4
Ku-Maloob-Zaap
Holok-Temoa
657.3
Cantarell
1,955.0
1,188.3
335.9
Bcf
MMbbl
804.7
Natural Gas
Crude Oil
2006
Hydrocarbon Production
67.6
13.2
5.8
17.3
64.0
167.9
0.8
20.5
0.0
10.7
31.9
70.3
0.0
112.8
183.1
258.4
380.5
638.9
1,021.7
MMbbl
Crude Oil
2008
209.5
109.6
95.3
24.7
91.7
530.9
350.1
55.9
506.1
18.9
931.1
166.1
0.0
208.3
374.4
99.8
596.0
695.9
2,532.2
Bcf
Natural Gas
3,283.5
1,686.1
28.8
1,737.4
2,920.8
9,656.6
75.8
5,399.4
33.3
160.1
5,668.7
435.2
0.0
5,217.8
5,653.0
2,659.3
13,259.6
15,919.0
36,897.3
MMbbl
Crude Oil
5,732.8
9,267.7
5,651.2
2,117.9
4,439.6
27,209.2
2,348.9
7,392.3
10,453.8
269.8
20,464.8
978.6
0.0
5,721.2
6,699.8
1,336.5
5,946.7
7,283.2
61,657.0
Bcf
Natural Gas
Cumulative Production as of
January 1, 2009
129
22,718.4
Ku-Maloob-Zaap
5,607.9
507.0
959.6
194.8
1,154.3
7,236.8
17,641.9
24,878.7
839.3
58.0
897.3
6,397.6
17,583.9
23,981.4
8,196.4
17,836.6
26,033.0
Bcf
1,459.3
1,637.2
3,096.5
4,897.5
4,791.9
9,689.4
1,686.8
1,290.3
2,977.1
3,210.7
3,501.6
6,712.3
6,356.8
6,429.1
12,785.9
MMboe
Oil Equivalent
1,409.5
1,483.3
2,892.8
4,589.2
4,174.6
8,763.8
1,628.2
1,216.3
2,844.5
2,961.0
2,958.2
5,919.3
5,998.7
5,657.9
11,656.6
19.1
51.6
70.7
91.2
207.0
298.2
19.9
22.2
42.1
71.3
184.8
256.1
110.3
258.6
368.9
10.5
32.3
42.8
74.4
139.5
213.9
13.3
17.6
30.9
61.1
121.9
183.0
84.9
171.8
256.6
Plant
Liquids *
MMbbl
MMbbl
MMbbl
20.1
70.0
90.2
142.7
270.8
413.5
25.5
34.2
59.7
117.3
236.6
353.9
162.9
340.8
503.7
Dry Gas **
Equivalent
MMboe
332.2
563.9
896.1
1,720.4
2,276.5
3,996.8
346.9
284.2
631.1
1,373.5
1,992.2
3,365.8
2,052.5
2,840.4
4,892.9
Bcf
104.7
364.2
468.9
742.4
1,408.4
2,150.8
132.4
177.9
310.3
609.9
1,230.5
1,840.4
847.1
1,772.6
2,619.7
Bcf
Natural Gas
Dry Gas
Ku-Maloob-Zaap
Cantarell
6,114.9
37,254.3
59,972.7
5,322.9
293.2
Cantarell
Possible
2P
Ku-Maloob-Zaap
Cantarell
5,616.1
17,395.5
Ku-Maloob-Zaap
Probable
36,961.1
Cantarell
54,356.6
28,326.3
Ku-Maloob-Zaap
Proved
37,761.3
66,087.6
Cantarell
Total (3P)
MMbbl
Oil
Gas
Pemex Exploración y Producción, Northeastern Offshore Region
130
Litoral de Tabasco
Holok-Temoa
Abkatún-Pol-Chuc
3,034.0
0.0
1,152.0
4,186.0
5,680.2
0.0
15,407.2
21,087.4
2,147.2
0.0
1,249.1
3,396.3
3,533.0
0.0
14,158.1
17,691.1
8,714.2
0.0
16,559.2
25,273.4
3,793.7
2,158.8
386.2
6,338.6
10,124.5
1,338.9
15,592.2
27,055.6
3,396.1
910.4
1,133.1
5,439.7
6,728.4
428.5
14,459.1
21,615.9
13,918.2
3,497.7
15,978.3
33,394.2
Bcf
1,247.8
314.5
196.3
1,758.5
1,977.8
200.5
1,252.5
3,430.8
973.5
130.1
433.2
1,536.9
1,004.3
70.4
819.3
1,893.9
3,225.6
514.9
1,448.8
5,189.4
MMboe
Oil Equivalent
879.8
0.0
176.2
1,056.0
1,254.2
0.0
907.3
2,161.5
641.6
0.0
343.9
985.5
612.6
0.0
563.4
1,176.0
2,134.0
0.0
1,083.4
3,217.4
8.6
12.0
2.1
22.8
19.1
11.2
31.4
61.7
8.1
6.8
8.9
23.7
11.0
4.4
22.6
38.0
27.7
23.2
33.6
84.5
99.6
36.1
6.5
142.1
221.7
34.0
111.8
367.6
96.9
20.4
29.0
146.3
124.8
13.6
82.8
221.2
321.2
70.1
118.3
509.7
Plant
Liquids *
MMbbl
MMbbl
MMbbl
259.8
266.4
11.5
537.7
482.9
155.2
202.0
840.1
226.9
102.9
51.5
381.3
256.0
52.3
150.5
458.8
742.7
421.6
213.5
1,377.8
Dry Gas **
Equivalent
MMboe
1,813.6
1,514.8
104.6
3,433.0
3,543.1
915.5
1,680.2
6,138.8
1,631.9
606.9
437.1
2,675.9
1,911.2
308.6
1,243.1
3,462.9
5,356.7
2,430.3
1,784.8
9,571.8
Bcf
1,351.4
1,385.4
59.8
2,796.6
2,511.5
807.3
1,050.4
4,369.2
1,180.3
535.2
267.7
1,983.2
1,331.2
272.1
782.7
2,386.0
3,862.9
2,192.7
1,110.2
7,165.8
Bcf
Natural Gas
Dry Gas
Litoral de Tabasco
Holok-Temoa
Abkatún-Pol-Chuc
Possible
2P
Litoral de Tabasco
Holok-Temoa
Abkatún-Pol-Chuc
Probable
Litoral de Tabasco
Holok-Temoa
Abkatún-Pol-Chuc
Proved
Litoral de Tabasco
Holok-Temoa
Abkatún-Pol-Chuc
Total (3P)
MMbbl
Oil
Gas
Pemex Exploración y Producción, Southwestern Offshore Region
131
51,752.8
50,967.5
3.7
773.8
7.9
Possible
Burgos
Poza Rica-Altamira
Veracruz
24,660.4
20,505.7
2,906.7
1,134.3
113.7
99,240.3
33,716.3
18,988.9
41,037.9
5,497.2
32,576.6
29,248.5
2,314.2
976.9
37.0
66,663.6
4,467.8
16,674.7
40,061.0
5,460.2
123,900.7
54,222.0
21,895.6
42,172.2
5,610.9
Bcf
9,209.9
8,590.5
341.5
235.6
42.2
10,515.0
8,802.2
621.5
868.3
223.0
8,862.6
8,134.0
230.3
455.9
42.5
1,652.4
668.2
391.2
412.4
180.5
19,724.8
17,392.7
963.0
1,103.9
265.3
MMboe
Oil Equivalent
5,729.2
5,545.8
0.0
173.0
10.4
6,673.7
6,008.2
0.0
647.4
18.1
5,845.0
5,507.2
0.0
332.7
5.1
828.7
501.0
0.0
314.7
13.0
12,402.9
11,554.0
0.0
820.4
28.5
6.5
0.0
5.7
0.0
0.8
12.7
0.0
12.2
0.0
0.5
4.6
0.0
4.5
0.0
0.1
8.0
0.0
7.6
0.0
0.4
19.1
0.0
17.9
0.0
1.3
974.3
935.4
23.1
12.3
3.5
943.9
854.8
51.5
35.5
2.0
838.4
803.6
19.0
15.4
0.4
105.5
51.2
32.6
20.1
1.6
1,918.2
1,790.2
74.6
47.8
5.5
Plant
Liquids *
MMbbl
MMbbl
MMbbl
2,499.9
2,109.3
312.7
50.3
27.6
2,884.7
1,939.2
557.8
185.4
202.4
2,174.6
1,823.2
206.8
107.8
36.8
710.1
115.9
351.0
77.6
165.6
5,384.6
4,048.5
870.5
235.7
230.0
Dry Gas **
Equivalent
MMboe
17,383.0
15,129.0
1,720.4
374.8
158.8
19,120.0
13,693.8
3,066.4
1,292.0
1,067.9
14,901.3
12,869.1
1,133.0
704.3
194.9
4,218.7
824.6
1,933.4
587.7
873.0
36,503.1
28,822.7
4,786.8
1,666.8
1,226.7
Bcf
13,001.8
10,970.5
1,626.2
261.6
143.5
15,003.3
10,085.4
2,901.2
964.1
1,052.6
11,310.0
9,482.4
1,075.5
560.5
191.5
3,693.3
603.0
1,825.6
403.6
861.1
28,005.0
21,055.8
4,527.4
1,225.7
1,196.1
Bcf
Natural Gas
Dry Gas
114,487.7
85,816.1
138.6
27,719.0
814.0
72,895.5
72,701.6
8.6
149.8
35.5
Probable
Burgos
Poza Rica-Altamira
Veracruz
Burgos
Poza Rica-Altamira
Veracruz
41,592.2
13,114.5
130.0
27,569.2
778.6
Proved
Burgos
Poza Rica-Altamira
Veracruz
2P
166,240.5
136,783.6
142.3
28,492.8
821.9
Total (3P)
Burgos
Poza Rica-Altamira
Veracruz
MMbbl
Oil
Gas
Pemex Exploración y Producción, Northern Region
132
1,272.4
86.5
182.5
31.6
155.8
816.0
Possible
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
1,505.0
170.9
233.2
305.6
298.7
496.5
72,952.5
15,321.6
6,588.1
8,742.0
24,598.1
17,702.6
4,276.9
1,310.0
314.3
882.0
1,213.7
557.0
68,675.6
14,011.7
6,273.9
7,860.0
23,384.5
17,145.6
74,457.5
15,492.5
6,821.3
9,047.7
24,896.9
18,199.1
Bcf
673.0
33.4
130.6
60.5
215.7
232.8
5,189.4
1,648.1
364.8
322.9
518.0
2,335.7
1,140.3
208.4
117.8
153.9
201.9
458.4
4,049.1
1,439.7
247.0
169.0
316.1
1,877.3
5,862.5
1,681.5
495.4
383.4
733.7
2,568.5
MMboe
Oil Equivalent
471.8
23.1
107.5
15.1
135.4
190.6
3,181.1
1,072.5
282.9
82.1
207.8
1,535.7
700.8
141.8
92.0
42.7
109.1
315.2
2,480.2
930.7
190.9
39.4
98.7
1,220.5
3,652.9
1,095.6
390.4
97.2
343.3
1,726.4
1.8
0.6
0.0
0.0
1.0
0.2
87.4
45.0
0.0
0.6
6.5
35.3
11.1
4.6
0.0
0.1
1.4
5.1
76.3
40.4
0.0
0.6
5.1
30.2
89.2
45.6
0.0
0.6
7.5
35.6
74.7
3.3
8.8
16.4
29.5
16.8
732.1
212.3
31.1
63.5
119.6
305.6
159.0
24.8
9.8
34.5
34.7
55.2
573.1
187.5
21.3
29.0
84.9
250.5
806.8
215.6
39.9
79.9
149.1
322.4
Plant
Liquids *
MMbbl
MMbbl
MMbbl
124.8
6.4
14.3
29.0
49.8
25.2
1,188.9
318.3
50.7
176.7
184.1
459.0
269.4
37.2
16.0
76.6
56.7
82.9
919.5
281.1
34.8
100.1
127.4
376.2
1,313.6
324.7
65.0
205.8
233.9
484.2
Dry Gas **
Equivalent
MMboe
902.2
47.8
138.7
195.7
343.2
176.8
8,504.3
2,445.2
389.8
1,103.7
1,332.2
3,233.5
1,902.2
289.7
118.2
494.4
416.3
583.5
6,602.1
2,155.4
271.6
609.3
915.9
2,650.0
9,406.5
2,492.9
528.5
1,299.4
1,675.4
3,410.4
Bcf
649.0
33.5
74.5
150.9
259.2
130.9
6,183.1
1,655.3
263.8
919.2
957.4
2,387.4
1,400.9
193.5
83.0
398.6
294.9
431.0
4,782.2
1,461.8
180.7
520.7
662.5
1,956.4
6,832.1
1,688.8
338.3
1,070.2
1,216.6
2,518.3
Bcf
Natural Gas
Dry Gas
39,434.3
11,767.8
6,951.8
403.5
7,254.7
13,056.5
2,508.4
939.7
230.4
147.5
529.4
661.4
Probable
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
36,926.0
10,828.1
6,721.5
256.0
6,725.3
12,395.1
Proved
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
2P
40,706.7
11,854.3
7,134.3
435.1
7,410.5
13,872.5
Total (3P)
Bellota-Jujo
Cinco Presidentes
Macuspana
Muspac
Samaria-Luna
MMbbl
Oil
Gas
Pemex Exploración y Producción, Southern Region

HyDROCARBON RESERVES Of MEXICO

Transcription

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