HyDROCARBON RESERVES Of MEXICO. JANUARy 1, 2009

Transcription

1 2009 Hydrocarbon Reserves of Mexico January 1, 2009

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3 2009 HyDROCARBON RESERVES Of MEXICO JANUARy 1, 2009

4 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.

5 Contents Page Message from the Minister of Energy Message from the General Director of Petróleos Mexicanos v xi 1 Introduction 1 2 Basic Definitions Original Volume of Hydrocarbons in Place Petroleum Resources Original Volume of Total Hydrocarbons in Place Original Volume of Undiscovered Hydrocarbons Original Volume of Discovered Hydrocarbons Prospective Resources Contingent Resources Reserves Proved Reserves Developed Reserves Undeveloped Reserves Non-proved Reserves Probable Reserves Possible Reserves Oil Equivalent 10 3 Prospective Resources as of January 1, Mexico s Most Important Production Basins Prospective Resources and Exploratory Strategy 20 4 Estimation of Hydrocarbon Reserves as of January 1, Hydrocarbon Prices Oil Equivalent Gas Behavior at the PEP Handling and Transport Facilities Gas Behavior in Processing Complexes Remaining Total Reserves Remaining Proved Reserves Remaining Developed Proved Reserves Undeveloped Proved Reserves Probable Reserves Possible Reserves 39 5 Discoveries Aggregate Results Offshore Discoveries 46 iii

6 Contents Page 5.3 Onshore Discoveries Historical Trajectory of Discoveries 74 6 Distribution of Hydrocarbon Reserves Northeastern Offshore Region Evolution of Original Volumes in Place Evolution of Reserves Southwestern Offshore Region Evolution of Original Volumes in Place Evolution of Reserves Northern Region Evolution of Original Volumes in Place Evolution of Reserves Southern Region Evolution of Original Volumes in Place Evolution of Reserves 107 Abbreviations 115 Glossary 117 Statistical Appendix 127 Hydrocarbon Reserves as of January 1, Hydrocarbon Production 128 Distribution of Hydrocarbon Reserves as of January 1, 2009 Northeastern Offshore Region 129 Southwestern Offshore Region 130 Northern Region 131 Southern Region 132 iv

7 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, 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 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 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

8 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 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

9 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 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 MMboe as a result of discoveries was very positive because 1,041.6 MMboe were added, of which 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 MMboe of gas-condensate, as well as the Ayatsil-DL1 and Pit-DL1 wells, incorporating 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 MMboe incorporated by discoveries, 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 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

10 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 P Reserves In 2008, MMboe in 2P reserves were incorporated through discoveries, of which MMboe correspond to probable reserves. Due to revisions, delimitations and developments, MMboe of 2P reserves were de-incorporated, which means a total of 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 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 MMboe, the 3P reserve-production ratio increased from 28.0 years in 2007 to 30.0 years in As regards discoveries, there was the outstanding performance of the Ayatsil-DL1 and Pit-DL1 wells, which made it possible to incorporate MMboe of 3P heavy oil reserves, as well as the Tsimin-1 well with the inclusion of 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

11 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

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13 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

14 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 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 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, xii

15 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

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17 Hydrocarbon Reserves of Mexico Introduction 1 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, Their geographic location, extension, general geological characteristics and distribution by basin are also given. 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 Furthermore, the origin of the changes and their association with discoveries, revisions, development or production in the period is emphasized. 1

18 Introduction 2

19 Hydrocarbon Reserves of Mexico Basic Definitions 2 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. 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 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 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

20 Basic Definitions 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. 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. 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. 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. 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 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 Original Volume of Total Hydrocarbons in Place Original Volume of Undiscovered Hydrocarbons Original Volume of Discovered Hydrocarbons Non-Economic Economic Range of Uncertainty Non- Recoverable P r o s p e c t i v e R e s o u r c e s Low Estimate Central Estimate High Estimate Non- Recoverable C o n t i n g e n t R e s o u r c e s 1C 2C 3C R e s e r v e s Proved 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,

21 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 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 Original Volume of Undiscovered Hydrocarbons 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 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 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

22 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. 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 production 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 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. 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. 2.3 Reserves Original Reserve (Economic Resource) Accumulated Production Proved Original Reserves Developed Proved Reserves Undeveloped Probable Reserves Non-Proved Reserves Possible Reserves Figure 2.2 Classification of hydrocarbon reserves. 6

23 Hydrocarbon Reserves of Mexico 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

24 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 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 Undeveloped Reserves These are reserves with an expected recovery through new wells in un-drilled areas, or where a 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 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. 8

25 Hydrocarbon Reserves of Mexico 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. 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. 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 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. 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. 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

26 Basic Definitions Sweet Wet Gas isf Natural Gas Flaring Self-Consumption hesf Compressor Gas to be delivered to processing complexes tlsf Sweetening Plant plsf Cryogenic Plant Dry Gas cedglf Dry Gas Equivalent to Liquid 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 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 thousand cubic feet of dry gas per barrel of oil equivalent. This value is the result of considering 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 barrels per million cubic feet, or the opposite given by the aforementioned value. 10

27 Hydrocarbon Reserves of Mexico Prospective Resources as of January 1, 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. 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, The distribution of prospective resources is described in Figure 3.1, where the Southeastern and Gulf of Mexico Deepwater basins stand out with 88.3 percent of the country s total prospective resources. 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. 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 Crude Oil and Associated Gas Non-associated Gas W N S E Prospective Resource Bboe 1. Sabinas Burgos Tampico-Misantla Veracruz Southeastern Gulf of Mexico Deepwater Yucatan Shelf 0.3 Total Km 5 7 Figure 3.1 Distribution of Mexico s prospective resources. 11

28 Prospective Resources 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 Sabinas Basin Oil exploration in the basin was initiated by foreign companies in 1921 and later continued as a nationalized industry after 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. Geologically, the Sabinas Mesozoic Basin corresponds to an intracratonic basin formed by three paleoelements; the Tamaulipas paleopeninsula, the Coahuila paleoisland and the Sabinas Basin. 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. 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, N 102º 101º 100º W S E A Salt Dome Anticline USA 28º Inverse Fault B A C A D 27º B Monclova C 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 km 12

29 Hydrocarbon Reserves of Mexico Table 3.1 Prospective resources documented in the Sabinas Basin by hydrocarbon type. Hydrocarbon Type Exploratory Wells number Dry Gas Total Prospective Resources MMboe 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

30 Prospective Resources Table 3.2 Prospective resources documented in the Burgos Basin by hydrocarbon type. Hydrocarbon Type Exploratory Wells Prospective Resources number MMboe Light Oil Dry Gas Wet Gas 364 1,478 Total 504 2,000 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. 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. 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 Tamaulipas Arch Tamaulipas- Constituciones Ebano Pánuco Tampico Arenque 200 m W Gulf of Mexico N S E Tampico-Misantla Basin 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 0 Chicontepec Sierra Madre Oriental 100 km Faja de Oro Atoll Poza Rica SanAndrés Figure 3.4 Map of the Tampico-Misantla Basin showing the most important areas. 14

31 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 Dry Gas 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 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 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 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 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

32 Prospective Resources N 673 Km² W E S Veracruz 181 Km² Folded Thrust Belt Cocuite 3D Seismic 286 Km² 0 25 km Tezonapa 2 1 Mata Pionche Field Cocuite Field Miocene-Pliocene 5 10 Lower Miocene Paleocene-Eocene-Oligocene 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 producer of non-associated gas; with an average production of 957 million cubic feet per day in 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 Exploratory Wells Prospective Resources number MMboe Heavy Oil 6 52 Light Oil 9 54 Dry Gas Wet Gas Total

33 Hydrocarbon Reserves of Mexico percent of the potential recorded in 237 exploratory opportunities; the remaining 18 percent is still being documented, Table 3.4. The Salina del Istmo province, with an area of around 15,300 square kilometers is a pile of siliciclastic sediments intruded by salt that produces light oils, mostly from the plays that underlay, overlay or terminate against the allochthonous salt of Jurassic origin. 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 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. 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 Litoral de Tabasco province covers an area of approximately 7,400 square kilometers. The 1,500 m N W E S 1,000 m Gulf of Mexico Sonda de Campeche 200 m Litoral de Tabasco Salina del Istmo Chiapas- Tabasco- Comalcalco Macuspana Figure 3.6 Location of the Southeastern Basins. 17

34 Prospective Resources Table 3.5 Prospective resources documented in the Southeastern Basins by hydrocarbon type. Hydrocarbon Type Exploratory Wells Prospective Resources number MMboe Heavy Oil 53 1,076 Light Oil 284 3,508 Superlight Oil 209 2,648 Dry Gas Wet Gas Total 629 8,186 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. 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 18

35 Hydrocarbon Reserves of Mexico N W E S 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 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

36 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. at 300 million barrels of oil equivalent, of which 271 million barrels of oil equivalent have been documented with 16 heavy oil exploratory opportunities. 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 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 Exploratory Wells Prospective Resources number MMboe Heavy Oil Light Oil 91 5,143 Dry Gas Wet Gas 12 1,183 Total 126 7,222 20

37 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 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. 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. 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

38 Prospective Resources 22

39 Hydrocarbon Reserves of Mexico 4 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. 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 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 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 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 4.2 Oil Equivalent 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 re- 23

40 Estimation as of January 1, Crude Oil dollars per barrel Sour Wet Gas dollars per thousand cubic feet Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul 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 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 24

41 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 condensation 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) Transport liquefiables shrinkage factor (tlsf) Condensate recovery factor (crf) barrels per million cubic feet 10 0 Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Northeastern Offshore Southwestern Offshore Northern Southern Figure 4.2 Gas shrinkage and condensate recovery factors, by region, of the national petroleum system. 25

42 Estimation as of January 1, 2009 Northeastern Offshore Region reported a decrease compared with 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 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 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 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 Aren que GPCs, that receive sour gas. The La Venta, Rey nosa, 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 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 Arenque, Burgos, Cactus, Ciudad Pemex, La Venta, Ma tapionche, 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. The classification by fluid type of remaining total reserves of Mexico s oil equivalent is shown in Table 26

43 Hydrocarbon Reserves of Mexico 0.99 Impurities shrinkage factor (isf) Plant liquefiables shrinkage factor (plsf) Plant liquids recovery factor (plrf) barrels per million cubic feet Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Arenque Burgos Cactus Cd. Pemex 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 Consequently, as of January 1, 2009, crude oil particular, the Northeastern Offshore Region provides accounted for 71.0 percent of the total, dry gas 68.7 percent of the nation s total heavy oil, while the 19.7 percent, plant liquids added 8.0 percent, and Northern Region furnishes 61.6 percent of the light condensates provided 1.3 percent. In a regional oil, and 47.2 percent of the total superlight oil. context, 3P reserves are distributed as follows; 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. Bboe 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 Probable 2P Possible Figure 4.4 Integration by category of the remaining oil equivalent reserves of Mexico. 3P 27

44 Estimation as of January 1, 2009 Table 4.1 Historic distribution by fluid and region of remaining total reserves. Remaining Hydrocarbon Reserves Remaining Gas Reserves Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , , ,715.6 Northeastern Offshore 13, , , , ,621.7 Southwestern Offshore 2, , , , ,770.1 Northern 12, , , , , , ,950.5 Southern 3, , , , , , , , , , , , , ,367.9 Northeastern Offshore 12, , , , ,067.5 Southwestern Offshore 2, , , , , ,048.5 Northern 12, , , , , , ,564.5 Southern 3, , , , , , , , , , , , ,858.8 Northeastern Offshore 11, , , , ,709.7 Southwestern Offshore 2, , , , , ,566.2 Northern 12, , , , , , ,193.0 Southern 3, , , , , , , , , , , , ,622.7 Northeastern Offshore 11, , , , ,619.7 Southwestern Offshore 3, , , , , ,165.8 Northern 12, , , , , , ,005.0 Southern 3, , , , , ,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

45 Hydrocarbon Reserves of Mexico Table 4.2 Classification of total reserves, or 3P, of crude oil and natural gas. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , , , , , ,171.8 Northeastern Offshore 13, , Southwestern Offshore , , , ,709.3 Northern 4, , , , , , ,328.5 Southern , , , , , , , , , , , ,642.1 Northeastern Offshore 12, , Southwestern Offshore , , , , , ,681.5 Northern 4, , , , , , ,473.5 Southern , , , , , , , , , , , ,291.6 Northeastern Offshore 11, , Southwestern Offshore , , , , , ,106.3 Northern 4, , , , , , ,952.0 Southern , , , , , , , , , , , ,664.3 Northeastern Offshore 11, , Southwestern Offshore , , , , , ,338.9 Northern 4, , , , , , ,619.4 Southern , , , ,648.2 * G-C: Gas-Condensate reservoirs added 1,482.1 million barrels of oil equivalent, thus replacing production in 2008 by percent. Developments increased reserves by million barrels of oil equivalent, while revisions reduced the reserves by 1,157.8 million barrels. Considering additions, revisions and developments, million barrels of oil equivalent in 3P reserves were replaced, which means an integrated replacement rate of 36.6 percent. Bboe Additions Revisions Developments Production 2009 Figure 4.5 Historic evolution of Mexico s total oil equivalent reserves. 29

46 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 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 Remaining Gas Reserves Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , , ,557.3 Northeastern Offshore 7, , , , ,459.9 Southwestern Offshore 1, , , , ,439.6 Northern , , , ,412.4 Southern 2, , , , , , , , , , , , ,855.8 Northeastern Offshore 6, , , , ,198.4 Southwestern Offshore 1, , , , ,872.6 Northern , , , ,331.8 Southern 2, , , , , , , , , , , , ,161.8 Northeastern Offshore 6, , , , ,891.2 Southwestern Offshore , , , ,066.4 Northern , , , ,005.7 Southern 2, , , , , , , , , , , ,702.0 Northeastern Offshore 5, , , , ,840.4 Southwestern Offshore 1, , , , ,386.0 Northern , , , ,693.3 Southern 2, , , , ,

47 Hydrocarbon Reserves of Mexico Table 4.4 Classification of proved reserves, or 1P, of crude oil and natural gas. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , , , , ,682.7 Northeastern Offshore 7, , Southwestern Offshore , Northern , , , ,534.1 Southern , , , , , , , , , , ,379.2 Northeastern Offshore 6, , Southwestern Offshore , ,057.8 Northern , , , ,540.0 Southern , , , , , , , , , , ,283.5 Northeastern Offshore 6, , Southwestern Offshore , ,402.5 Northern , , , ,244.5 Southern , , , , , , , , , , ,176.4 Northeastern Offshore 5, , Southwestern Offshore , , ,846.9 Northern , , , ,936.7 Southern , , ,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 Additions Revisions Developments Production 2009 Figure 4.6 Historic behavior of Mexico s remaining proved oil equivalent reserves. 31

48 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. Bboe 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. Developed Undeveloped Proved Figure 4.7 Classification by category of the remaining 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 Additions and developments increased proved reserves by 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 Crude Oil a Ranking Country Dry Gas MMbbl Bcf 1 Saudi Arabia 264,210 1 Russia 1,680,000 2 Canada 178,092 2 Iran 991,600 3 Iran 136,150 3 Qatar 891,945 4 Iraq 115,000 4 Saudi Arabia 257,970 5 Kuwait 101,500 5 United States of America 237,726 6 Venezuela 99,377 6 United Arab Emirates 214,400 7 United Arab Emirates 97,800 7 Nigeria 184,160 8 Russia 60,000 8 Venezuela 170,920 9 Libya 43,660 9 Algeria 159, Nigeria 36, Iraq 111, Kazakhstan 30, Indonesia 106, United States of America 21, Turkmenistan 94, China 16, Kazakhstan 85, Qatar 15, Malaysia 83, Brazil 12, Norway 81, Algeria 12, China 80, Mexico 11, Mexico 12,702 Source: Mexico, Pemex Exploración y Producción. Other countries, Oil & Gas Journal, December 22, 2008 a. Includes condensates and liquids from natural gas 32

49 Hydrocarbon Reserves of Mexico however, reduced reserves by 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 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 percent of the production of 1,451.1 million barrels of oil equivalent. In the international context, Mexico is ranked 17 th in reference to the proved reserves, including oil, condensate and plant liquids. In terms of dry gas, Mexico is in the 35 th place. Table 4.5 shows the proved reserves of crude oil and dry gas of the most important producing countries. 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 Remaining Gas Reserves Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , ,888.2 Northeastern Offshore 5, , , , ,193.8 Southwestern Offshore , Northern , , , ,074.0 Southern 2, , , , , , , , , , ,688.2 Northeastern Offshore 5, , , , ,209.6 Southwestern Offshore , , Northern , , , ,152.9 Southern 1, , , , , , , , , , ,162.9 Northeastern Offshore 4, , , , ,218.1 Southwestern Offshore , , Northern , , ,809.8 Southern 1, , , , , , , , , , ,206.1 Northeastern Offshore 4, , , , ,640.5 Southwestern Offshore , , , ,032.4 Northern , , ,573.9 Southern 1, , , , ,

50 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 Northeastern 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 Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , , , , ,755.4 Northeastern Offshore 5, , Southwestern Offshore , Northern , , ,633.6 Southern , , , , , , , , , , ,683.6 Northeastern Offshore 5, , Southwestern Offshore , Northern , , ,905.5 Southern , , , , , , , , , , ,282.4 Northeastern Offshore 4, , Southwestern Offshore Northern , , ,599.7 Southern , , , , , , , , , , ,729.6 Northeastern Offshore 4, , Southwestern Offshore , Northern , ,209.4 Southern , , ,134.2 * G-C: Gas-Condensate reservoirs 34

51 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 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 million barrels of oil equivalent; delimitations provided 74.7 million barrels, developments meant a decline of million barrels of oil equivalent, and the revisions reduced this reserve by 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 Remaining Gas Reserves Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , ,669.0 Northeastern Offshore 1, , , , ,266.1 Southwestern Offshore , Northern , , ,338.4 Southern , , , , , , , , ,167.5 Northeastern Offshore 1, , , , Southwestern Offshore , , ,065.7 Northern , , ,179.0 Southern , , , , , , , , ,998.9 Northeastern Offshore 1, , , Southwestern Offshore , , ,207.0 Northern , , ,195.9 Southern , , , , , , , , ,495.9 Northeastern Offshore 1, , Southwestern Offshore , , ,353.6 Northern , , ,119.4 Southern , , , ,

52 Estimation as of January 1, 2009 Table 4.9 Classification of undeveloped proved crude oil and natural gas reserves. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , ,927.3 Northeastern Offshore 1, , Southwestern Offshore Northern Southern , , , , ,695.6 Northeastern Offshore 1, , Southwestern Offshore Northern Southern , , , , ,001.0 Northeastern Offshore 1, , Southwestern Offshore ,131.5 Northern Southern , , , , , ,446.8 Northeastern Offshore 1, Southwestern Offshore ,460.9 Northern Southern , * 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 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

53 Hydrocarbon Reserves of Mexico Table 4.10 Historic distribution by fluid and region of probable reserves. Remaining Hydrocarbon Reserves Remaining Gas Reserves Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , , ,246.0 Northeastern Offshore 4, , , Southwestern Offshore , Northern 6, , , , , ,328.1 Southern , , , , , , , , , , ,567.9 Northeastern Offshore 3, , Southwestern Offshore , , , ,320.8 Northern 6, , , , , ,276.8 Southern , , , , , , , , , , ,452.0 Northeastern Offshore 3, , Southwestern Offshore , , , ,750.5 Northern 6, , , , , ,907.7 Southern , , , , , , , , , , ,004.4 Northeastern Offshore 2, , Southwestern Offshore , , , ,983.2 Northern 5, , , , , ,310.0 Southern , , , ,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 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

54 Estimation as of January 1, 2009 Table 4.11 Classification of probable crude oil and natural gas reserves. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , , , ,316.0 Northeastern Offshore 4, , Southwestern Offshore Northern 2, , , , ,614.3 Southern , , , , , , , , ,071.1 Northeastern Offshore 3, Southwestern Offshore ,207.6 Northern 2, , , , ,817.9 Southern , , , , , , , , ,104.5 Northeastern Offshore 3, Southwestern Offshore ,418.4 Northern 2, , , , ,755.1 Southern , , , , , , , , ,365.7 Northeastern Offshore 2, Southwestern Offshore ,772.1 Northern 2, , , ,748.4 Southern , * 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 Additions Revisions Developments 2009 Figure 4.8 Historic behavior of Mexico s probable oil equivalent reserves. 38

55 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 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 million barrels of oil equivalent, that is, 4.1 percent, compared with the previous year. The additions contributed 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 million barrels of oil equivalent, due to the reclassification of reserves to this category 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 Crude Condensate Plant Dry Gas Total Natural Gas Gas to be Dry Gas Year Oil Liquids Equivalent Delivered to Plant Region MMbbl MMbbl MMbbl MMboe MMboe Bcf Bcf Bcf , , , , , , ,912.3 Northeastern Offshore 2, , Southwestern Offshore 1, , , , ,506.3 Northern 5, , , , , ,210.0 Southern , , , , , , , , ,944.2 Northeastern Offshore 2, , Southwestern Offshore 1, , , , ,855.1 Northern 5, , , , , ,955.9 Southern , , , , , , ,245.0 Northeastern Offshore 2, , Southwestern Offshore 1, , , , ,749.2 Northern 5, , , , , ,279.6 Southern , , , , , , , ,916.3 Northeastern Offshore 2, , Southwestern Offshore 1, , , , ,796.6 Northern 5, , , , , ,001.8 Southern

56 Estimation as of January 1, 2009 Table 4.13 Classification of possible crude oil and natural gas reserves. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Year G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf , , , , , , , ,173.2 Northeastern Offshore 2, Southwestern Offshore , ,291.9 Northern 1, , , , ,180.2 Southern , , , , , , , ,191.8 Northeastern Offshore 2, Southwestern Offshore , ,416.1 Northern 1, , , , ,115.6 Southern , , , , , , ,903.6 Northeastern Offshore 2, Southwestern Offshore , ,285.4 Northern 1, , , , ,952.5 Southern , , , , , , , ,122.2 Northeastern Offshore 2, Southwestern Offshore , ,719.9 Northern 1, , , , ,934.3 Southern * G-C: Gas-Condensate reservoirs tribution by region and by fluid type is shown in Table 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 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. 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 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 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

57 Hydrocarbon Reserves of Mexico Bboe 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 million barrels of oil equivalent compared with the previous year. This positive variation corresponds to 0.8 percent compared with Specifically, additions contributed million barrels of oil equivalent, while developments and revisions reduced the reserves by and million barrels of oil equivalent, respectively. 41

58 Estimation as of January 1,

59 Hydrocarbon Reserves of Mexico Discoveries 5 The results of discovering hydrocarbon reserves through exploratory activities are systematically improving. Specifically, this year Petróleos Mexicanos reached the highest 3P reserves addition figure since the adoption of the international guidelines jointly issued 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 increased from 43.9 million barrels of oil equivalent in 2007 to 78.0 million barrels in 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 Region, with 54.9 percent, because of the results in the Kambesah-1, Ayatsil-DL1 and Pit-DL1 wells. The South western Offshore Region, however, provided 30.3 percent of the total reserves, which were added by the Tsimin-1, Tecoalli-1, Xanab-DL1 and Yaxché- 1DL wells. The Northern and Southern regions each con tributed 7.4 percent of the total 3P reserve. 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 reclassification 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 delineation 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 geological and geophysical studies for exploratory and delineation projects. This chapter describes the most important characteristics of the reservoirs discovered with an explanation 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 The trajectory of the discoveries is analyzed at the end. 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, 5.1 Aggregate Results The booking of 3P hydrocarbons reserves was 40.7 percent higher than in 2007, which meant that 43

60 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 Business Unit, the Northeastern Offshore Region provided a total of 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 million barrels of oil in 3P re Table 5.1 Composition of the hydrocarbon reserves of reservoirs discovered in P 2P 3P Basin Well Crude Oil Natural Gas Crude Oil Natural Gas Crude Oil Natural Gas Oil Equivalent Field MMbbl Bcf MMbbl Bcf MMbbl Bcf MMbbl Total , , , ,482.1 Burgos Cali Cali Dragón Peroné Grande Grande Murex Murex Ricos Ricos Southeastern , , ,372.9 Ayatsil Ayatsil-DL Kambesah Kambesah Pit Pit-DL Rabasa Rabasa Tecoalli Tecoalli Teotleco Teotleco Tsimin Tsimin Xanab Xanab-DL Yaxché Yaxché-1DL Veracruz Aral Aral Aris Aris Cauchy Cauchy Kabuki Kabuki Maderaceo Maderaceo

61 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 million barrels of oil equivalent; the reservoirs 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 billion cubic feet of natural gas, which jointly equal million barrels of oil equivalent. In reference to non-associated natural gas reserves, all the dry and wet gas reservoirs were discovered in the Northern Region, which manages the Burgos and Veracruz basins, that is, there was an accumulated 3P reserve of billion cubic feet of gas, which is equal to million barrels of oil equivalent. The Cali-1, Grande-1, Murex-1, Peroné-1, and Ricos-1001 exploratory wells, in the Burgos Basin discovered non-associated 3P gas reserves totaling 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 discovered by the results in the Aral-1, Aris-1, Cauchy-1, Kabuki-1, and Maderáceo-1 wells, which jointly contributed a total of 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 probable 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 hydrocarbon 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 , , , ,482.1 Burgos Northern Southeastern , , ,372.9 Northeastern Offshore Southwestern Offshore , Southern Veracruz Northern

62 Discoveries Table 5.3 Composition of the hydrocarbon reserves of reservoirs discovered in 2008 by hydrocarbon type. Crude Oil Natural Gas Heavy Light Superlight Associated Non-associated Category G-C* Wet Gas Dry Gas Total Region MMbbl MMbbl MMbbl Bcf Bcf Bcf Bcf Bcf 1P Northeastern Offshore Southwestern Offshore Northern Southern P Northeastern Offshore Southwestern Offshore Northern Southern P ,557.3 Northeastern Offshore Southwestern Offshore Northern Southern * 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. sub-basin. Jointly, the above fields added million 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 billion cubic feet of natural gas, which together is equal to 1,262.8 million barrels of oil equivalent. Heavy oil reserves were discovered in the Sonda de Campeche with the drilling of the Ayatsil-DL1 and Pit- DL1 delineation wells that added a 3P reserve of 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 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, petrophysical and engineering aspects, of the most important reservoirs discovered in 2008 is given below. 46

63 Hydrocarbon Reserves of Mexico Southeastern Basins Stratigraphy Tsimin-1 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 kilometers 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 conditions that favored the trapping of hydrocarbons. The geological column cut by well Tsimin-1 is formed by Tertiary siliciclastic rocks interspersed with shales and sandstone, with some thin stratifications of dolomite mudstone. For the Tithonian, carbonaceous shales are interspersed with shaly limestone, while there is shaly dolomitic mudstone and sandy mudstone in the Kimmeridgian. The well reached a depth of 5,728 meters below sea level, and its chronostratigraphic tops were established through the analysis of planktonic foraminifer indexes found in the cutting and core samples. 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. Le Ixtal Taratunich Batab Ixtoc Abkatún W N S E Ayín Alux Och Uech Toloc Pol Chuc Kax Wayil Homol Kay Caan Gulf de Mexico Citam Bolontikú Sinán Kab Hayabil Misón Kix Tsimin-1 May Yum Teekit Frontera Xanab Yaxché Dos Bocas 0 20 km Figure 5.1 Map showing the location of the Tsimin-1 well. 47

64 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 ,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

65 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 interclasts. 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. Source Rock Because of their high organic content, the rocks of the Upper Jurassic Tithonian are responsible for generating the field s hydrocarbons, and they were deposited in a deep marine sedimentary environment. The seal consists of Upper Jurassic Tithonian rocks composed of carbonaceous shales, shaly limestone, and shaly dolomitic mudstone. 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 reservoir 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 condensate, with initial average daily production rates of 4,354 barrels of oil and 13.8 billion cubic feet of gas. 49

66 Discoveries Reserves The estimated original 3P volumes are million barrels of oil and 1,565.7 billion cubic feet of gas. 3P reserves are million barrels of oil and billion cubic feet of gas, which are jointly equal to million barrels of oil equivalent. The proved and probable reserves are estimated at 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 magnitude 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 structural 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 kilometers, 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 closing to the west and it is bounded by the Comalcalco fault. The Ayatsil-DL1 well reached the top of the N W S E Gulf of Mexico Ayatsil-DL1 Tunich Zazil-Ha Maloob Bacab Lum 2,170 Zaap Ek Balam Ku Kutz Ixtoc Cantarell Chac Takín 2, m 200 m 2, m 50 m Cd. del Carmen 25 m Dos Bocas Frontera km 2,050 Figure 5.5 Location of the Ayatsil-DL1 well in territorial waters of the Gulf of Mexico. 50

67 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

68 Discoveries structuring process is geologically associated with the Maloob field. to greenish-gray shales of formations from the Paleocene age. Storage Rock Reservoir The reservoir is mostly represented by a dolomitized sedimentary breccia formed by mudstone-wackestone fragments, with secondary porosity in fractures and dissolution cavities, Figure 5.7. Source Rock According to the geochemical studies of the oil and core samples, it was determined that the most important hydrocarbon source rock in the Sonda de Campeche dates from the Upper Jurassic Tithonian, and it is formed by bituminous shales and shaly limestones, with abundant organic matter. The water-oil contact was determined in well Ayatsil- DL1 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 Ayatsil-1 Ayatsil-DL1 Figure 5.7 Cores cut in the Cretaceous reservoir showing oil in the porous and fractured system. 52

69 Hydrocarbon Reserves of Mexico Loc. DL2 Ayatsil-1 Ayatsil-DL1 Recent 1,000 2,000 Pliocene 3,000 4,000 Eocene Breccia Oligocene Paleocene 5,000 J. Kimmeridgian J. Tithonian 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 million barrels of oil equivalent and the 3P reserve is million barrels of oil equivalent. Kambesah-1 The Kambesah field is located in the territorial waters of the Gulf of Mexico, at approximately 92 kilometers N W E Gulf of Mexico Tunich S Zazil-Ha Maloob Bacab Lum 2,170 Zaap Ku Kambesah-1 Kutz Ixtoc Cantarell Ek Balam Chac Takín 2, m 200 m 2, m 50 m Cd. del Carmen 25 m 2,050 Dos Bocas Frontera km Figure 5.9 Map showing the location of the Kambesah-1 well. 53

70 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 geomorphological 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 Cretaceous rocks (breccia). The current configuration of the structure at the Cretaceous 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 Stratigraphy Structural Geology 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 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. 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. 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

71 Hydrocarbon Reserves of Mexico W N S E potential load values, in addition to being mature and distributed over most of the offshore portion of the Southeastern Basins. Seal 7 Km 2 The Upper Cretaceous Breccia top seal of the reservoir consists of an interspersing of Lower Paleocene shale that varies laterally 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. Reservoir 1 Km Storage Rock 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 10 Km 2 Figure 5.11 Structural contouring of the Upper Cretaceous Breccia top. 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 Reserves 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 bioturbation, and shaly laminations parallel to the stratification planes. The well was a producer 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. 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 million 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

72 Discoveries Le Ixtal Taratunich Batab Ixtoc Abkatún W N S E Ayín Alux Och Uech Toloc Pol Chuc Kax Wayil Homol Kay Caan Gulf of Mexico Citam Bolontikú Sinán Kab Hayabil Misón Kix May Yum Tecoalli-1 Xanab Yaxché Teekit Frontera Dos Bocas 0 20 km Figure 5.12 Map showing the location of the Tecoalli-1 well. Bocas, Tabasco, Figure 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 during 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 identification of planktonic foraminifer, indexes in the drill cuttings and core samples. 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 component that covers an area of 20.6 square kilometers, Figure Storage Rock The reservoir s storage rock is mostly formed by angular to subrounded quartz fine grain sandstone, moderately classified and with oil impregnation, Figure Additionally, there are signs of monocrystalline quartz, plagioclases, clay fragments, dispersed organic matter, calcite and disseminated pyrite. Porosity is very good; mostly interangular. Source Rock As regards the source rock, the results of the biomarkers analyzed indicate that these hydrocarbons 56

73 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 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, 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

74 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. Reservoir The estimated original 3P volumes were million barrels of oil and billion cubic feet of gas; the distribution is shown in Figure The reserves estimated for the 1P, 2P and 3P categories are 7.1, 18.0 and 54.0 million barrels of oil equivalent, respectively. The drilling of this well led to the discovery of a reservoir 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 Km 2 Probable Reserve Area: 2.4 Km 2 Proved Reserve Area: 2.0 Km 2 Figure 5.15 Distribution and classification of reserves in the Tecoalli field. 58

75 Hydrocarbon Reserves of Mexico Le Ixtal Taratunich Batab Ixtoc Abkatún W N S E Ayín Alux Och Uech Toloc Pol Chuc Kax Wayil Homol Kay Caan Gulf of Mexico Citam Bolontikú Sinán Kab Hayabil Misón Kix May Yum Xanab-DL1 Teekit Frontera Xanab 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 penetrate it because the total depth of the well was 5,980 meters, Figure 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 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 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 represented 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. Storage Rock The reservoir storage rock that was analyzed by means of core and drill cuttings is formed by mudstone, 59

76 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 horizons of oil-impregnated mesocrystalline dolomites. N W E S km Figure 5.18 Structural contouring of the Upper Jurassic Kimmeridgian reservoir top. 60

77 Hydrocarbon Reserves of Mexico Source Rock As regards the source rock, the results of the biomarkers analyzed make it possible to determine that the hydrocarbons were generated in Upper Jurassic Tithonian rocks, which are responsible for the generation of the reservoir s hydrocarbons because of their high organic matter content. Seal Rock 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 and in the Southeastern Basins of the Southern Region. The 3P reserves added through discoveries of onshore wells amount to million barrels of oil equivalent, while the reserves in the 1P and 2P categories are 38.9 and million barrels of oil equivalent, respectively. In terms of natural gas, the onshore discoveries total billion cubic feet of 3P reserves. A detailed explanation of the most important discoveries in 2008 is given below. Burgos Basin Cali-1 It is located approximately 33 kilometers southwest of Rey nosa, in the municipality of Gustavo Díaz Ordaz, Ta mau lipas, Figure The target of the well was to 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 (interparticular) and secondary (in fractures and dissolution), associated with an open sea sedimentary environment. W N S E Camargo Camargo Sur-1A Cali-1 Jazmín-1A Valadeces-6 Integral-1 L Ferreiro-1 Misión Cañón Lomitas Reserves Draker Km The original 3P volumes are estimated at million barrels of oil and billion cubic feet of gas. The estimated reserves for the 1P, 2P, and 3P categories are 11.6, 50.4, and 59.5 million bar Presa Falcón rels of oil equivalent, respectively. Reynosa Matamoros Herreras Reynosa 5.3 Onshore Discoveries Camargo Gulf of Mexico The onshore discoveries have mostly been in the Burgos, Sabinas, and Veracruz basins of the Northern Region, Figure 5.19 Map showing the location of the Cali-1 well in the Camargo project. 61

78 Discoveries X/Y: ters N W E S INTEGRALINTEGRAL INTEGRAL CALI CALI CALI FERREIRO-1 FERREIROFERREIRO Cali-1CALICALI-1 ReservoirARENA EJM4 EJM4 Map CONFIGURACIÓ EN PROFUNDIDAD CONFIGURACIÓ N Structural 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 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 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.

79 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 formation, with good characteristics for the generation of hydrocarbons because it contains a high amount of organic matter. Seal Rock The seal rock of the play corresponds to shaly packages 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. of 20 percent, water saturation of 44 percent and permeability 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 The original 3P volume of gas is billion cubic feet of gas, while the original 1P, 2P, and 3P reserve volumes are estimated at 22.0, 22.0 and billion cubic feet of natural gas, respectively. Veracruz Basin Reservoir Cauchy-1 The reservoirs are made up of fine grain quartz sandstone 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

80 Discoveries N W E Veracruz S Miralejos Cópite Mata Pionche Mecayucan Madera Vistoso Playuela Alvarado Gulf of Mexico Angostura Papán Apertura Cocuite Aral-1 Perdiz Lizamba Kabuki-1 Tierra Blanca Km. Estanzuela Arquimia San Pablo Rincón Pacheco Mirador Nopaltepec Veinte Novillero Tres Valles Cosamaloapan 3D Norte de Tesechoacán 1,024 Km 2 Cauchy-1 Aris-1 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 Geologically, it is located in the Veracruz Tertiary Basin and seismically, 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 longitudinal axis, which lies in a northwest to southeast 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 sediments in the southern part that allowed the formation of stratigraphic traps associated with the preexisting structures, Figure Trap The producing horizon PP1 in this well is associated with a combined trap, with a strong structural component, 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 64

81 Hydrocarbon Reserves of Mexico Cauchy-1 1,200 1,400 Obj. 1: 1,730 mbsl Obj. 2: 1,777 mbsl PT1: P= 2,590 psi Qg= 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 Km 2 Possible Area: 2 Km 2 Proved Area: 3.5 Km 2 Cauchy-1 Southern Probable Area: 2 Km Km. Figure 5.24 Structural contouring of the main reservoir, with the distribution of the reserve category areas. 65

82 Discoveries makes up the result of the petrophysical analysis, Figure Stratigraphy A basin floor submarine fan environment was defined for the reservoir that was formed by two principal distributary channels, laterally and vertically amalgamated, 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. Storage Rock In the most important reservoir, the storage rock is formed by medium to coarse grain, dark brown sandstone, lithic debris, quartz and, to a lesser extent, moderately 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 In general, the rock sample shows intergranular primary porosity of up to 32 percent. Source Rock The hydrocarbon source rock for this zone corresponds 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 packages of considerable thickness, of up to dozens of meters, in the Upper Miocene, and associated with basin floor facies. Reservoir The petrophysical analysis carried allowed the definition 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 consequently, 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 Cauchy-1 Core 8 Interval: 1,829-1,838 m. C-1 C-2 = = 1, 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

83 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 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. The estimated original 3P volume of natural gas was 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 billion cubic feet of gas, respectively. Southeastern Basins Rabasa-101 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 Miocene 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 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 Coatzacoalcos, Veracruz, Figure, The field belongs 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

84 Discoveries NW Loc. Tonalli-1 Gurumal-1 Gurumal-2 Rabasa-1 Rabasa-101 SE 1,000 Plio-Pleistocene Lower Pliocene 2,000 Upper Miocene 1,662 m. Middle Miocene Salt 3,000 Lower Miocene OBJ-1 ( 2,900 m.) 4,000 4,000 m. 3,707 m. OBJ-2 ( 3,950 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 contribution direction, that is, southeast to northwest. The deposits finally form a complex system of channels and fans on the basin slope and floor, where the sandy bodies reach their greatest thickness, Figure 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 Coast Line and Platform Margin Mountains 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

85 Hydrocarbon Reserves of Mexico Reservoir 1 Top (2,565 m) Middle Miocene N Gurumal Depth (m) W Reservoir 2 Top (3,198 m) Lower Miocene F-2 F-1 E N W E 3500 Gurumal S 4750 S F Gurumal Gurumal Salt Rabasa Salt 50 F-4 00 Rabasa-1 Rabasa Depth (m) Salt F F Rabasa F Salt ESC.1:25,000 ESC.1:25, 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

86 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 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. 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 layers, 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 Trap Teotleco-1 The well is in the coastal zone of the Gulf of Mexico, geologically; it belongs to the Chiapas-Tabasco Mesozoic area. It is located 18 kilometers to the southeast of Cárdenas, Tabasco, Figure The target was to add hydrocarbon reserves in Upper, Middle and Lower Cretaceous rocks, and in the Upper Jurassic Kimmeridgian producer formations in the area. The well was completed as a producer of light oil in Middle Cretaceous rocks, and it reached a developed depth of 5,810 meters. It is structural and it corresponds to a block adjacent to the Cactus field, from which it is separated by a combined 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 Stratigraphy The geological column drilled consists of rocks corresponding to ages ranging from the Middle Cretaceous N W E S Frontera Coatzacoalcos Cárdenas Teotleco-1 Villahermosa Níspero Cactus Río Nuevo km Figure 5.30 Map showing the location of the Teotleco-1 well. 70

87 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 3,500 4,000 Salt Paleocene Upper Cretaceous Middle Cretaceous Lower Cretaceous Upper Jurassic Tithonian Upper Jurassic Kimmeridgian 5,810 md 5,587 tvd 5,290 m N Sal Teotleco-1 Amacoite-1B Figure 5.32 Seismic cross-section showing well Teotleco-1 and the characteristics of the reservoir. 71

88 Discoveries 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. of gas. The proved reserves amount to 3.7 million barrels 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 billion cubic feet of gas, which jointly means 77.6 million barrels of oil equivalent. Gulf of Mexico Deepwater Basin Tamil-1 Source Rock In the area of this reservoir, the hydrocarbon source rock corresponds to clay-calcareous sediments of the Upper Jurassic Tithonian age, according to geochemical studies made in this basin. The well is in the territorial waters of the Gulf of Mexico, off the coasts of Campeche and Tabasco, at N W E S Nab Seal Rock Tamil-1 The seal is formed by marlstone of the Upper Cretaceous and calcareous shale of the Tertiary, mostly those of the Miocene, which are interspersed inside this Tamil-DL1 Kastelán-1 Kach-1 Alak-1 Abkatún Maloob Ku Cantarell sequence. Ayín Reservoir The reservoir consists of fractured do Sinán 146 Km. lomites of the Middle Cretaceous. The average porosity is 5.0 percent and the May average water saturation is around 8.0 Frontera Cd. del Carmen percent. The initial average production was 3,559 barrels per day of 42 API degrees of volatile oil, and 9.9 million cubic feet of gas per day. Reserves The original 3P volume is million barrels of oil and billion cubic feet Figure 5.33 Map showing the location of the Tamil-1 well. 72

89 Hydrocarbon Reserves of Mexico approximately 146 kilometers northwest of Ciudad del Carmen, Campeche, 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 Geologically, 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 closing 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 Cretaceous 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 correlation 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 microcrystalline and secondary porosity in fractures, N Tamil-1 Tamil-DL1 SE 1,000 1,500 2,000 2,500 3,000 3,500 Reservoir Top: 2,747 m (Middle Cretaceous) Tamil-1 N 4,000 4,500 Reservoir Bottom: 3,040 m (Upper Jurassic Tithonian) Tamil-DL1 Kach-1 Figure 5.34 Seismic-structural cross-section showing the characteristics of the reservoir. 73