Book 20091.pdf

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

3 3 4 5 5 5 5 6 6 7 8 8 8 9 9 10

3 Prospective Resources as of January 1, 2009 3.1 Mexico’s Most Important Production Basins 3.2 Prospective Resources and Exploratory Strategy

11 12 20

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

23 23 23 24 26 26 30 33 35 37 39

5 Discoveries 5.1 Aggregate Results 5.2 Offshore Discoveries

43 43 46

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Contents Page

5.3 Onshore Discoveries 5.4 Historical Trajectory of Discoveries

iv

61 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 6.2.1 Evolution of Original Volumes in Place 6.2.2 Evolution of Reserves 6.3 Northern Region 6.3.1 Evolution of Original Volumes in Place 6.3.2 Evolution of Reserves 6.4 Southern Region 6.4.1 Evolution of Original Volumes in Place 6.4.2 Evolution of Reserves

77 77 79 80 85 86 88 95 96 98 104 104 107

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

127 127 128 129 130 131 132

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 v

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. vii

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 xi

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.

xii

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

xiii

xiv

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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

Prospective Resources

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

Hydrocarbon Reserves of Mexico

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

Prospective Resources

Table 3.2 Prospective resources documented in the Burgos Basin by hydrocarbon type. Hydrocarbon Type

Exploratory Wells number

Light Oil

Prospective Resources 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.

Hydrocarbon Reserves of Mexico

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

Prospective Resources

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

Prospective Resources MMboe 52 54 408 57 571

Hydrocarbon Reserves of Mexico

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

Prospective Resources

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

Prospective Resources 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

Hydrocarbon Reserves of Mexico

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

Prospective Resources

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

Prospective Resources MMboe 289 5,143 607 1,183 7,222

Hydrocarbon Reserves of Mexico

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

Prospective Resources

22

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Estimation as of January 1, 2009

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

Hydrocarbon Reserves of Mexico

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

Estimation as of January 1, 2009

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 Northeastern Offshore 12,510.6 Southwestern Offshore 2,900.9 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 Northeastern Offshore 11,936.8 Southwestern Offshore 2,927.8 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 Northeastern Offshore 11,656.6 Southwestern Offshore 3,217.4 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

Hydrocarbon Reserves of Mexico

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 Northeastern Offshore 13,487.5 Southwestern Offshore 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 Northeastern Offshore 12,444.0 Southwestern Offshore 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 Northeastern Offshore 11,900.3 Southwestern Offshore 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 Northeastern Offshore 11,569.1 Southwestern Offshore 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

Estimation as of January 1, 2009

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.

Remaining Hydrocarbon Reserves Year Region

Crude Condensate Oil MMbbl MMbbl

Plant Liquids MMbbl

Remaining Gas Reserves

Dry Gas Total Natural Gas Gas to be Dry Gas Equivalent Delivered to Plant MMboe MMboe Bcf Bcf Bcf

2006 11,813.8 Northeastern Offshore 7,106.2 Southwestern Offshore 1,011.3 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 Northeastern Offshore 6,532.0 Southwestern Offshore 1,038.0 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 Northeastern Offshore 6,052.8 Southwestern Offshore 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 Northeastern Offshore 5,919.3 Southwestern Offshore 1,176.0 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

Hydrocarbon Reserves of Mexico

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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

Developments Production

2009

Figure 4.6 Historic behavior of Mexico’s remaining proved oil equivalent reserves.

31

Estimation as of January 1, 2009

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 States of America 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

Hydrocarbon Reserves of Mexico

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.

Remaining Hydrocarbon Reserves Plant Liquids MMbbl

Remaining Gas Reserves

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

Estimation as of January 1, 2009

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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

Hydrocarbon Reserves of Mexico

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.

Remaining Hydrocarbon Reserves Plant Liquids MMbbl

Remaining Gas Reserves

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

Estimation as of January 1, 2009

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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

Hydrocarbon Reserves of Mexico

Table 4.10 Historic distribution by fluid and region of probable reserves.

Remaining Hydrocarbon Reserves Year Region

Crude Condensate Oil MMbbl MMbbl

Plant Liquids MMbbl

Remaining Gas Reserves

Dry Gas Total Natural Gas Gas to be Dry Gas Equivalent Delivered to Plant MMboe MMboe Bcf Bcf Bcf

2006 11,644.1 Northeastern Offshore 4,112.4 Southwestern Offshore 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 Northeastern Offshore 3,444.7 Southwestern Offshore 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 Northeastern Offshore 3,085.0 Southwestern Offshore 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 Northeastern Offshore 2,844.5 Southwestern Offshore 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

Estimation as of January 1, 2009

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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

Hydrocarbon Reserves of Mexico

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.

Remaining Hydrocarbon Reserves

Remaining Gas 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore 2,892.8 Southwestern Offshore 1,056.0 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

Estimation as of January 1, 2009

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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

Hydrocarbon Reserves of Mexico

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

Estimation as of January 1, 2009

42

Hydrocarbon Reserves of Mexico

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

Crude Oil Natural Gas MMbbl Bcf

Crude Oil Natural Gas 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

Hydrocarbon Reserves of Mexico

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



Northeastern Offshore

169.7

36.3

487.2

85.7

789.6

120.1

813.5



Southwestern Offshore

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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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 Northeastern Offshore Southwestern Offshore 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

* G-C: Gas-Condensate reservoirs

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.

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Northeastern Offshore Cantarell Ku-Maloob-Zaap Southwestern Offshore 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

United States of America

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.

Hydrocarbon Reserves of Mexico

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.

6.1.1 Evolution of Original Volumes in Place

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

Distribution of Hydrocarbon Reserves

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.

6.1.2 Evolution of Reserves 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.

Hydrocarbon Reserves of Mexico

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

Associated Non-associated Bcf Bcf 4,835.1 2,782.6 2,052.5

57.8 57.8 0.0

81

Distribution of Hydrocarbon Reserves

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,

Hydrocarbon Reserves of Mexico

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 1, 2009, distributed by business unit in the Northeastern Offshore Region.

83

Distribution of Hydrocarbon Reserves

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 1, 2009, distributed by business unit in the Northeastern Offshore Region.

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

Developments Production

Figure 6.8 Elements of change in the total reserve of the Northeastern Offshore Region.

84

2009

Crude Oil

Hydrocarbon Reserves of Mexico

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

Distribution of Hydrocarbon Reserves

N W

United States of America

E S

Baja California Norte

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.

6.2.1 Evolution of Original Volumes in Place 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

Hydrocarbon Reserves of Mexico

N W

460

500

540

580

620

E

Gulf of Mexico

S

2170

Holok-Temoa Integral Business Unit Manik Taratunich Ixtal

301

101 201

Abkatún

Toloc

2130

Batab Och

Ayín

Pol

Kax

Chuc

Uech

Litoral de Tabasco Integral Business Unit 200 m

Citam

Sinán 1A

Bolontiku

Kab

Kay

Misón

Hayabil-1 Yum 2-B

May

50 m

Abkatún-Pol-Chuc Integral Business Unit

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

Distribution of Hydrocarbon Reserves

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 Offshore Region over the last three years.

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.

6.2.2 Evolution of Reserves 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 Offshore Region over the last three years.

Hydrocarbon Reserves of Mexico

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

Associated Non-associated 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.

Crude Oil and Natural Gas 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

Associated Non-associated 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

Distribution of Hydrocarbon Reserves

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.

Hydrocarbon Reserves of Mexico

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

Distribution of Hydrocarbon Reserves

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.

Hydrocarbon Reserves of Mexico

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

Developments Production

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

Distribution of Hydrocarbon Reserves

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.

Reserves by Fluid Type

Reserve-Production Ratio 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

Hydrocarbon Reserves of Mexico

N W

United States of America

E S

Baja California Norte

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

Distribution of Hydrocarbon Reserves

N W

United States of America

E S

Baja California Norte

Sonora Chihuahua Coahuila

Burgos Integral Business Unit Baja California Sur

Sinaloa

Nuevo León

Durango

Gulf of Mexico

Tamaulipas

Zacatecas

San Luis Potosí Aguascalientes Nayarit Altamira-Poza

Rica Integral Business Unit

Pacific Ocean

Jalisco Colima

Guanajuato

Aceite Terciario del Golfo Integral Business Unit

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

Table 6.12 Historical evolution over the last three years of the original 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

Hydrocarbon Reserves of Mexico

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. Crude Oil and Natural Gas 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

Distribution of Hydrocarbon Reserves

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.

6.3.2 Evolution of Reserves 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 over the last three years.

Hydrocarbon Reserves of Mexico

Table 6.13 Composition of 2P reserves by business unit of the Northern Region.

Crude Oil

Business Unit

Heavy MMbbl

Light MMbbl

Total Aceite Terciario del Golfo 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

Associated Non-associated 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 Aceite Terciario del Golfo 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

Associated Non-associated 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

Distribution of Hydrocarbon Reserves

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. Crude Oil and Natural Gas 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

Hydrocarbon Reserves of Mexico

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 Aceite Terciario del Golfo 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 Aceite Terciario del Golfo 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 Aceite Terciario del Golfo 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

Distribution of Hydrocarbon Reserves

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 business unit in the Northern Region. 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

Reserve-Production Ratio 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 business unit in the Northern Region.

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

Hydrocarbon Reserves of Mexico

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

Developments Production

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. Reserves by Fluid Type 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

Distribution of Hydrocarbon Reserves

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

United States of America

E S

Baja California Norte

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

Hydrocarbon Reserves of Mexico

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 Table 6.17 Historical evolution over the last three years of the original 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

Distribution of Hydrocarbon Reserves

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. Crude Oil and Natural Gas 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

Hydrocarbon Reserves of Mexico

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

6.4.2 Evolution of Reserves 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 over the last three years.

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

Distribution of Hydrocarbon Reserves

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. Crude Oil and Natural Gas

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

Hydrocarbon Reserves of Mexico

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

Distribution of Hydrocarbon Reserves

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

Developments Production

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

Hydrocarbon Reserves of Mexico

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

Distribution of Hydrocarbon Reserves

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. Reserve-Production Ratio 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. Reserves by Fluid Type 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

Hydrocarbon Reserves of Mexico

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

Distribution of Hydrocarbon Reserves

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

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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

Hydrocarbon Reserves of Mexico

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.

Hydrocarbon Reserves of Mexico

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 Northeastern Offshore Southwestern Offshore 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

Remaining Hydrocarbon Reserves 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

Remaining Gas Reserves 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 Northeastern Offshore Southwestern Offshore Northern Southern

Northeastern Offshore Southwestern Offshore Northern Southern

150,565.8 54,356.6 17,691.1 41,592.2 36,926.0

Proved Northeastern Offshore Southwestern Offshore Northern Southern

2P

298,308.2 66,087.6 25,273.4 166,240.5 40,706.7

Total (3P) Northeastern Offshore Southwestern Offshore Northern Southern

MMbbl

Original Volume in Place Oil Gas

Pemex Exploración y Producción Hydrocarbon Reserves as of January 1, 2009

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

Aceite Terciario del Golfo

Litoral de Tabasco

Southern

Norte

173.4

Southwestern Offshore 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

Northeastern Offshore

Pemex Exploración y Producción 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

Remaining Hydrocarbon Reserves Crude Oil Condensate 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

Remaining Gas Reserves 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.

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

Original Volume in Place Oil Gas

Pemex Exploración y Producción, Northeastern Offshore Region Hydrocarbon Reserves as of January 1, 2009

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

Remaining Hydrocarbon Reserves Crude Oil Condensate 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

Remaining Gas Reserves 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.

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

Original Volume in Place Oil Gas

Pemex Exploración y Producción, Southwestern Offshore Region Hydrocarbon Reserves as of January 1, 2009

131

51,752.8 50,967.5 3.7 773.8 7.9

Possible Aceite Terciario del Golfo 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

Remaining Hydrocarbon Reserves Crude Oil Condensate 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

Remaining Gas Reserves 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.

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 Aceite Terciario del Golfo Burgos Poza Rica-Altamira Veracruz

Aceite Terciario del Golfo Burgos Poza Rica-Altamira Veracruz

41,592.2 13,114.5 130.0 27,569.2 778.6

Proved Aceite Terciario del Golfo Burgos Poza Rica-Altamira Veracruz

2P

166,240.5 136,783.6 142.3 28,492.8 821.9

Total (3P) Aceite Terciario del Golfo Burgos Poza Rica-Altamira Veracruz

MMbbl

Original Volume in Place Oil Gas

Pemex Exploración y Producción, Northern Region Hydrocarbon Reserves as of January 1, 2009

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

Remaining Hydrocarbon Reserves Crude Oil Condensate 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

Remaining Gas Reserves 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.

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

Original Volume in Place Oil Gas

Pemex Exploración y Producción, Southern Region Hydrocarbon Reserves as of January 1, 2009