ESTIMATION OF THE OIL PRODUCTION POTENTIAL OF THE FIELD SINGUE, ORIENTE BASIN, ECUADOR. GUILLERMO FERNANDO GUERRA DEL HIERRO MSc

Transcription

1 ESTIMATION OF THE OIL PRODUCTION POTENTIAL OF THE FIELD SINGUE, ORIENTE BASIN, ECUADOR GUILLERMO FERNANDO GUERRA DEL HIERRO MSc School of Computing Science and Engineering University of Salford This dissertation is submitted in part fulfilment of the requirements for the MSc degree in Petroleum and Gas Engineering SUPERVISOR: MR ALLAN WELLS 2014

2 DECLARATION I, GUILLERMO FERNANDO GUERRA DEL HIERRO, declare that this dissertation is my own work. Any section, part or phrasing of more than 20 consecutive words that is copied from any other work or publication has been clearly referenced at the point of use and also fully described in the reference section of this dissertation. Signed.. ii

3 CERTIFICATION I certify that I have read this report and in my opinion it is fully adequate in scope and quality, as partial fulfilment of the degree of Master in Science in Petroleum and Gas Engineering. Signed MR. ALLAN WELLS SUPERVISOR iii

4 ABSTRACT The Oriente Basin is the most important oil reservoir in Ecuador. The field Singue is one of the oil fields that is located in the basin and is considered to be one of the marginal fields of the region that have not been developed yet. In the area of the field there is one abandoned well called Singue-1 and other dry well called Alama-1. The Oriente Basin has from deep to top the following formation rocks: Hollin, Napo, Tena, Tiyuyacu, Orteguaza, Chalcana, Arajuno and Chambira. The present study is done on the Napo sandstones of the field Singue. The objective of the project is to estimate the oil production potential of the field reservoirs based on the analysis of well logs, seismic data and background information of the basin across the region. Napo is a sandstone reservoir with high possibilities of oil production. It is subdivided in lithofacies whithin these are the sandstones: U up, U low, T up, T low and Basal T. Analysis of well logs is performed to identify the lithofacies and to calculate the petrophysical properties of each rock component. Seismic interpretation of the region is done to identify the boundaries of the reservoir. Reserves estimations are performed by the volumetric method on the net pay zones for each formation. Based on calculations performed on the net pay interval, Napo U low is the facie that has the highest potential of oil content followed by Napo T up, Napo Basal and Napo U up. In the area of the field there are two major faults and the oil trapping structure is an anticline. The final results of the oil reserves in Napo U low sandstone are 3,270,746 bbl. and reach up to 8,065,545 bbl. if all the facies are considered. iv

5 DEDICATION This work is dedicated to my family for all the support, And to the people that believe in education as a key force to improve the world. v

6 ACKNOWLEDGEMENT Thanks to God for all his blessing and to my family for their unconditional support. Especially thanks to my sponsor SENESCYT in behalf of the government of Ecuador that is promoting the scholarship program, believing in education as the main resource for the development of the country. The project is structured to complete the MSc. Petroleum and Gas Engineering program. This work was completed under the tutelage of Mr. Allan Wells, scholar at the Petroleum at Gas department of the University of Salford, would like to thank my supervisor who has delineated and supervised the development of this project. In addition, would like to thank all the staff and lecturers of the University of Salford that have contributed to enhance my knowledge during this last year of study, especially to Dr. Lateef Akanji, the coordinator of the Petroleum department and mainly Petroleum lecturer, who also has supported me with the technical assessment for this project, as well as to Mr. Abubakar Abbas, as passionate lecturer and technical advisor. Additionally, would like to thank the personnel of Dygoil Cia Ltda, Ecuadorian company who provided information for the development of the thesis. Thanks to them I discovered the world of oil and the importance of promoting domestic industry so I decided to study this program, thanks for the on-going technical support. Finally would like to thank the support and encourage of my friends, especially the ones who have meet during this year and have collaborated with their knowledge related to this project. The author recognizes that there are still some shortcomings in the development of the project. Any suggestion and criticism is welcome from various parties. The author hopes the results of this study could contribute with knowledge of the case of study for the benefit of all. vi

7 CONTENTS TABLE OF CONTENTS Declaration... ii Certification... iii Abstract... iv Dedication... v Acknowledgement... vi Contents... vii 1. Introduction Introduction Objectives General Objective Specific Objectives Outline Background Overview Of Importance Of Petroleum In Ecuador Marginal Fields Limitations Of The Project Literature Review Reservoir Exploration Geophysical Exploration Seismic Surveying Seismic Interpretation Well Logging Well Log Types A. Spontaneous Pontential (Sp) B. Resistivity Logs C. Gamma Ray (Gr) vii

8 D. Neutron Logs E. Density Logs F. Sonic Logs G. Nuclear Magnetic Resonance Logs (Nmr) H. Dip-Meter Logs Formation Evaluation Subsurface Geology Well Correlation Geological Cross Sections Subsurface Maps Coring Analysis Reserves Estimation Preliminary Volumetric Calculation Post-Discovery Reserves Calculations Software Petrel Interactive Petrophysics (Ip) Case Of Study: The Oriente Basin, Ecuador Geology Of The Oriente Basin Depositional Environment Stratigraphy Of Oriente Basin Metodology Analysis Of Data General Information Of Singue Geological Structure Of The Basin Biostratigraphy Analysis Of Singue Core Sample Analysis Of Singue Pvt Analysis Of Singue Production Of Singue Data: Well Logs Data: Seismic Surveys viii

9 4.2 Well Logging Analysis Well Log Interpretation To Identify Reservoir Rock Well Correlation Petrophysical Analysis Seismic Interpretation Well Tie Horizon Interpretation Fault Interpretation Boundary Identification Reserves Estimation Finding / Results Well Logging Interpretation Identification Of Reservoir Rock Well Correlation Petrophysical Calculations Seismic Interpretation Well Tie Horizon Interpretation Fault Interpretation Reservoir Boundary Reserves Estimation Conclusions And Recommendations Conclusions Recommendations References And Bibliography Appendix ix

10 LISTS OF FIGURES Figure 1 - Reservoir geological modelling types (Weber & Van Genus, 1990)... 9 Figure 2 - Schematic Diagram of Seismic Study. (Faytteville Shale Natural Gas) Figure 3 - Seismic Processing (CGG) Figure 4 - Seismic processed data (CGG) Figure 5 - Identification of seismic sequence boundaries (Selley R., 1998) Figure 6 - Seismic facies analysis: Reflection attributes (Bradley, 1985) Figure 7 - Seismic reflection configurations (Vali, Mitchum, & Thompson, 1977) Figure 8 - Attribute seismic interpretation (Boggs, 2001) Figure 9 - The borehole environment for well logging. (SPE, 2013) Figure 10 - Gamma ray radiation of formation rocks (Darling, 2005) Figure 11 - Reserves classification (Etherington J., 2005) Figure 12 - Regional tectonic location of Oriente-Maranon Basin (Xie Yinfu, 2010) Figure 13 - Oil structural corridors of Oriente Basin. (Modified from Baby, 2004) Figure 14 Paleogeography map of the Napo Formation, Oriente Basin Figure 15 Stratigraphy of the Oriente Basin (Dashwood M F, 1990) Figure 16 U and T sandstone of the Napo formation (J. Estupiñan R. M., 2010) Figure 17 - Hydrocarbon migration model Oriente Basin (Xie Yinfu, 2010) Figure 18 - Methodology Figure 19 - Singue Field in Google Earth, location of wells Singue-1and Alama Figure 20 - Well Singue-1 production Figure 21 - Singue-1 basic log interpretation. Lithology and well tops Figure 22 - Alama-1 basic log interpretation. Lithology and well tops Figure 23 - Well correlation of Singue-1 and Alama Figure 24 - Clay volume interpretation Figure 25 - Saturation of fluids Figure 26 - Net Pay intervals Figure 27 - Seismic interpretation Figure 28 - Well Tie Figure 29 - Horizon interpretation process Figure 30 Horizon interpretation Figure 31 - Fault interpreatation x

11 Figure 32 - Singue boundary Figure 33 - Remaining Reserves Distribution LIST OF TABLES Table 1 - Density of fluids (Myers, 2007) Table 2 Napo formations sub-layers Table 3 - UTM and Geographic coordinates, Singue. Zone: 18S. Datum: WSG Table 4 - General Information of the wells. Singue-1 and Alama Table 5 - Biostratigraphy results of Singue Table 6 - Singue 1 Core samples tests Table 7 - Volumetric information Napo U sanstone of Singue Table 8 - Separation tests results at 100 F and 14.7 psi (U sanstone, Singue-1) Table 9 - Molecular composition of gas (Napo U, Singue-1) Table 10 - Well logs summary Table 11 - Well tops from well log interpretation Table 12a - SINGUE petrophysical results of the reservoir interval Table 12b - SINGUE petrophysical results of the net pay interval Table 13a - ALAMA petrophysical results of the reservoir interval Table 13b - ALAMA petrophysical results of the net pay interval Table 14 Well tops Table 15 - STOIIP calculation results Table 16 - Reserves calculation results xi

12 1. INTRODUCTION 1.1 INTRODUCTION Singue is a small marginal oil field located in the Oriente Basin in Ecuador. Seismic surveys and geophysical analysis were done on 1988 to define the exploitation of the field. One exploratory well named Singue-1 was drilled on December 1990, at that time it was part of the national oil company Petroecuador. During the drilling operation core samples were analysed to define the rock properties of the reservoir. Additionally, analysis of the fluid properties and initial production tests were done to make decisions about the development of the field. The exploratory well Singue-1 was successful. It reached an initial production of 500 bbl/ day and was kept in production with expectations of drilling more wells on the field in order to increase the production of the national oil company at that time. During the production stage one workover was developed due to a failure on the pump and one build up well test was done to monitor the status of the wellbore. Shortly after, the priorities of the national oil company shifted to more productive areas. The well was left in production but no other wells were drilled. Singue-1 remained in production for 7 years. Afterwards the well was closed due to highly increase in water cut and the field was finally abandoned in The objective of this dissertation is to analyse the present potential of the field. Available data for this study includes geological information of the basin, seismic surveys of the area and well logs of two wells in the field. The data will be used to calculate the volume of oil in the reservoir. Historical production data will be used to define the situation at the end of production time. Finally the estimation of further hydrocarbon available for commercial use will be done. The effects of closing a well for more than 15 years were analysed in order to estimate the production potential of the field. Analysis and discussion of results will be used to make conclusions and suggest recommendations for further development of the field. 1

13 1.2 OBJECTIVES GENERAL OBJECTIVE Analyse the potential oil production of the field Singue of the Oriente Basin in Ecuador SPECIFIC OBJECTIVES Analyse the geological information of the region and the available information of the wells that are in the field. Analyse well logs to identify the lithology. Analyse well logs to calculate porosity, water saturation and net pay interval of the sandstones. Run a simulation and interpretation of the seismic lines to establish the accumulation of hydrocarbon. Calculate the original and remaining oil in place. Analyse the results of calculations and simulations to define the potential of hydrocarbon in the field in order to suggest further work on it. 1.3 OUTLINE The dissertation document in chapter one introduce an overview of the importance of oil in Ecuador and a discussion about the desire of producing marginal fields to attend the local energy demand and contribution for the country economical welfare. The second chapter brings up the literature review which includes information about reservoir characterization assessment and methods used to calculate oil in place and available oil reserves. The third chapter introduces the geological information of the Oriente Basin, in which the field of the present case of study is located. Chapter four is focused on the methodology used to meet the objectives of the dissertation. It includes an analysis of the provided data; the procedure used to perform well logging analysis and seismic interpretation in specialized software in order to assess the location and characterization of the reservoir defining some properties of the sandstones. At the end of the methodology chapter the procedure to calculate remaining reserves is explained. 2

14 The results of the study are presented on chapter five with the corresponding discussion. Finally, in chapter 6 are the conclusions and recommendations for further development in the field. References and appendixes are attached on the last pages. 1.4 BACKGROUND OVERVIEW OF IMPORTANCE OF PETROLEUM IN ECUADOR All over the world petroleum is the mainly energy source. It is used in daily live for transportation, domestic consumption and industrial applications. Therefore petroleum is a strategic key factor that influences the economy of the nations and quality of life of the people. The prices of oil are established by the global consumption and by the offer of the countries that produce this resource. OPEC is an organization in which are involved the countries with the bigger hydrocarbon reserves. The aim of this organization is to protect the member s production and therefore their economy and development against the global market in which are involved big transnational enterprises mainly based on developed countries whose are the more energy consumers as well. OPEC plays an important role to set the market price of oil. Since petroleum was discovered it was used to produce energy making live more comfortable for all their users. After the industrial revolution in 1970 the consumption increased significantly in the countries where it took place. Developed countries were the most consumers 40 years ago. Nowadays countries like China or India have become big consumers because of their high population and their current industrial development. At the end of the day the consumption is related with the population and technological level of the country. Developed countries had reached a peak of consumption that has managed to be steadily. In developing countries the consumption has been growing with expectations of increment in the future. On the other side reserves of oil around the world have been dropping through the years. For that reason the role of countries with the bigger reserves is very important. 3

15 Investments with the aim of discovering new energy sources and technology development to improve current production systems are done everywhere. Even if there are new energy sources such as hydroelectricity, nuclear and sustainable; fossil based resources that includes coal, petroleum and natural gas are still the most used. Petroleum is the most important resource and natural gas has a greater foresight. The aim is to ensure energy supplying to meet the growing global energy consumption. In this context, one important problem is that most of the producer countries still are in developing conditions and they do not have the technology, on the other hand consumer countries that have the technology through the time are getting out of the resource. This has made producer developing countries to export crude oil for cash. There are some countries that sell crude oil and import final products like diesel, gasoline, LPG or lubricants. Then could be understood the close relationship and dependence between producers, consumers and their economies. The last 5 years the price of oil have been as higher an ever, above 100 US dollars per barrel. This has promoted the investment on the oil industry all around the world and therefore and increasing wealthy of the countries that have the resource. Compared with the beginning of the industry the situation has improved. Nowadays, State-owned national oil companies control 90% of the world's conventional petroleum resources. As a result in some countries such as Ecuador, private companies have increasingly focused on projects located in marginal areas that are often inhabited by indigenous, tribal and minority groups; in other words they are left to work on more costly, dangerous and risky areas. (Wasserstrom, 2013). This fact is notably fairer for the country than in previous times. The amazon region of Ecuador is located in the Oriente Basin. The first oil well was discovered in Since then the country has changed to oil production as the main economic income. Two types of crude oil have been discovered in the country: the first called Oriente that has an API gravity of 26, and the second which is heavier is called Napo with an API gravity of 19. Ecuador was member of OPEC from 1973 to 1993 and then, re-joined in There are some refineries to supply the local consumption; the rest of the crude is exported representing an important weight in the gross domestic product (GDP) of the nation. 4

16 At the present, the national oil company called Petroecuador is the main operator of the production fields; however few fields are in charge of international companies under service contracts. The aim of the government is to let private companies to develop less cost effective or high risk fields. In this group are the heavy oil fields, some mature and the marginal fields. Heavy oil fields are the ones with petroleum with API gravity below 15. Mature fields are those that have been producing for more than 30 years showing a significantly drop on the production rate; those represent a challenge to develop middle and long term strategies and may be an interesting opportunity to implement new technologies to enhance the production. In addition there are the marginal fields which have low economic or operational priority, and represent less than 1% of total national production (Petroecuador, 2010). Marginal fields are very risky because of their small size and based on previous experiences, they can easily disappear if there are problems with the speed of production. Once those are put into production, oil can easily be flooded, because of the small oil column compared to the very strong formation water. Even though, the marginal fields are not priority of the national government those are important for private companies that want to invest, summing up that any increasing in production will benefit the government to maintain the current daily production quota established by the OPEC. The government of Ecuador since the year 2007 is driving a campaign to optimize the oil production in all the country with appropriate environmentally and social caution. In this program the less cost effective and risky fields have been put out to tender for development to private companies seeking investment. The analysis of one of the marginal fields named Singue that is considered one of the marginal fields of Ecuador is the purpose of this dissertation. The company, Dygoil & Gente Consortium (DGC), had been in charge of the operation of the field since Dygoil have provided the information to develop this project. In Appendix 1 is attached the authorization letter that states the use of the provided documentation for this project with strictly academic purposes of the author MARGINAL FIELDS The article two of the Ecuadorean Law of Hydrocarbons stands that "marginal fields are those of low operational or economic priority, so considered because found far from 5

17 Petroecuador infrastructure, to contain low gravity crude oil or heavy oil, or because require techniques of excessively costly recovery. These fields may not represent more than 1% of the national production and will be subject to the international conservation reserves fee." (PGE, 2013). 1.5 LIMITATIONS OF THE PROJECT In the present project the author found certain difficulties that might affect to some extend the results, among them are: From the case of study, because Singue is a non-developed field there are only two wells in the area. It is recommended to have at least three wells to make a reservoir model. Even though the model was not finished, the calculations that correspond to the first stage of oil exploration were developed successfully to get results and meet the objectives of this project. From the available data of the area, seismic lines are 2D and are not so close, for that reason some assumptions were done to get the boundary of the reservoir. Additionally, some available seismic lines that have different resolution were not taken in consideration for the interpretation. The method used in the calculation of reserves is the volumetric method. The use of Petrel and Interactive Petrophysics in short time has been a big challenge. Some lack of experience in the programs might influence in the decision of running some calculations in the programs with default parameters, nevertheless results have been satisfactory obtained. 6

18 2. LITERATURE REVIEW 2.1 RESERVOIR EXPLORATION A reservoir is a rock with the capability of hydrocarbon accumulation. The rock to act as a reservoir must have pores to contain the oil or gas and the pores must be connected to allow the movement of fluids, in other words the essential characteristics are the porosity and permeability. Most of the oil and gas reserves have been founded in sandstones and carbonates. The exploration is the first stage in order to find hydrocarbon. It consists in the geological, geophysical and petro-physical study of the earth rock layers of the possible oil reservoir. Exploration stage concludes with the drilling of an appraisal well that will demonstrate the existence of oil. Geological knowledge is used to understand the development of the hydrocarbon basin in which the reservoir rock is present. The reservoir sedimentary rock must be porous and with a structure capable of trapping the hydrocarbon. The analysis of the geological time of the region is used to define the organic depositional environment and sedimentary depositional sequence of the basin. Superficial rock samples, electric log interpretations and down-hole samples are acquired during the drilling and are used to understand the geology of the region. Geophysical studies are used to define the lithology, structure of the reservoir in order to determine the probable oil accumulation zones known as facies. After having enough information of the region, geophysical seismic prospective is done. Specialised tools generate explosive waves that are reflected and recorded by geophones; a lineal radiography of the subsurface is created in specialized technical software. Interpretation of the results must define the accurate region where hydrocarbon is stored. As was mentioned, the only way to determine the existence of oil is drilling an appraisal well. Therefore the next stage is to drill a well in the most probable analysed zone. During the drilling, more information of the reservoir is obtained by samples and logs that are interpreted to define more accurate properties of the reservoir. Petrophysical analysis of the 7

19 well logs will determine the rock properties such as porosity, permeability and fluid saturation. Pressure-volume-temperature (PVT) analysis of the fluid is done to determine the type of hydrocarbon available; properties such as API gravity, viscosity, density, bubble point are found. The results of the appraisal well will determine investment on the field. When the well is on production, analysis of the driven mechanism of the reservoir and composition of the fluid could be done. As long as more wells are drilled more information could be collected and better representation of the reservoir could be done to assess the calculation of reserves and the effective way of recovering as much petroleum as economically possible. (Weber & Van Genus, 1990) A reservoir characterization is a model of the reservoir that includes all the parameters that will define the ability of storage and production of the hydrocarbons. To characterize a reservoir two models could be created: Geological static model: Created by geologists and geophysicists to provide a static description of the reservoir before production. Reservoir dynamic model: Created by reservoir engineers to simulate the flow of fluids within the reservoir during the production lifetime. The geological model can be used to predict the distribution of porosity, permeability and fluids in the field. Based on the geometric complexity the reservoir model could be layer cake, jigsaw puzzle or labyrinthine type shown in (Figure 1). Whatever it is, it can be modelled deterministically using geology or probabilistically using statics. For any appraisal used, the objective is to produce a three dimensional grid of the field with a specific value of porosity, permeability and petroleum saturation within each cell of the grid. Once the model is created the hydrocarbon reserves could be calculated and the production method could be simulated in a computer. (Tarek H, 2004) 8

20 Figure 1 - Reservoir geological modelling types (Weber & Van Genus, 1990) The present project is focused on the geophysical and petrophysical interpretation of the seismic lines well logs in order to determine the potential of oil available in the reservoir. 2.2 GEOPHYSICAL EXPLORATION Geophysical exploration is the applied branch of geophysics that uses surface methods to measure the physical properties of the subsurface Earth, along with the anomalies in these properties, in order to detect the presence and position of minerals, hydrocarbons, geothermal reservoirs, groundwater reservoirs, and other geological structures. Geophysical exploration includes three types: the magnetic method, the gravity method and the seismic surveying. The first two are used only in pre-drilling phase, but seismic is used in both exploration and development phases. Seismic is the most important method because integrates the knowledge of geologists and geophysics with physic, mathematics and computing engineering to create a virtual model of the reservoir. The integration of seismic surveying with geophysical logs is referred as Borehole Geophysics and is used to generate a four dimensions model capable to give an efficient image of the reservoir with properties prior to the identification of hydrocarbons. In later stage it is used to the development and expansion of the field. (Darling, 2005) 9

21 2.2.1 SEISMIC SURVEYING The principle of seismic is to create reflecting waves to estimate the properties of the Earth. Seismic surveying consist in three stages: data acquisition, data processing and interpretation. As shown in figure 2, for the data acquisition is required a source of energy that generates waves that travel in the subsurface at a velocity governed by the acoustic impedance of the medium. When the travelling wave find an interface with different acoustic impedance the wave energy is reflected and some refracted. A group of receptors arranged in groups called geophones will sense the arrival time of the reflected wave. A recording truck will get all the information from the geophones. Figure 2 - Schematic Diagram of Seismic Study. (Faytteville Shale Natural Gas) Once the data is acquired, it must be processed into a suitable format for it interpretation using mathematical techniques that take in account the velocity, amplitude, frequency and time of the wave, as well as the travelled depth and introduced noise. Seismic data processing requires accuracy, reliability, speed and computing resources. 10

22 Figure 3 - Seismic Processing (CGG) For processing a technique called deconvolution is used to convert the output signal as cleaner and sharper as possible. Seismic traces from the same reflecting point are gathered together. The more of these seismic traces we can stack together into one output trace, the clearer the seismic image, because background noise is eliminated. Any missing traces are filled in by interpolation. A process called migration moves reflected energy to its true subsurface position of origin. Advanced processing techniques, such as pre-stack depth migration (PSDM), can significantly improve seismic imaging, especially in areas of complex geology. Figure 4 - Seismic processed data (CGG) Finally, processed seismic data is interpreted and integrated with other geo-scientific information to understand the geology of the reservoir and assess the likelihood of finding hydrocarbon accumulations. 11

23 2.2.2 SEISMIC INTERPRETATION The interpretation of seismic is a very important part of the petroleum exploration because it could be used to regional mapping, prospect mapping, reservoir delineation, seismic modelling, hydrocarbon detection and monitoring of production. (Selley, 1998) Seismic stratigraphic analysis is carried out in a logical series of steps: the seismic sequence, facies and attributes analysis. Seismic sequence analysis is based on the identification of stratigraphic units composed of a relatively conformable succession of genetically related strata called depositional sequence. The upper and lower boundaries of depositional sequences are unconformities or correlative conformities. Those are recognized on seismic data by identifying reflections caused by lateral terminations (Figure 5). In practice it separates out time-depositional units based on detecting unconformities or changes in seismic patterns. (Selley R., 1998) Three main types of reflection discordance are: Erosional truncation: is the termination of strata against an overlying erosional surface. Apparent truncation: is the termination of relatively low-angle seismic reflections beneath a dipping seismic surface, where that surface represents marine condensation. Lapout: is the lateral termination of a reflection at its depositional limit. o Onlap: is recognized on seismic data by the termination of low-angle reflections against a steeper seismic surface. Two types of onlap are recognized: marine onlap and coastal onlap. o Downlap: is a baselap in which an initially inclined stratum terminates downdip against an initially horizontal or inclined surface. The surface of downlap represents a marine condensed unit in most cases. o Toplap: is the termination of inclined reflections against an overlying lower angle surface, where this is believed to represent the proximal depositional limit. 12

24 Figure 5 - Identification of seismic sequence boundaries (Selley R., 1998) The steps for depositional sequence analysis are summarized below: 1. Determine the vertical and horizontal scale of the section. 2. Define if it is migrated section and if it is marine or land data. 3. Identify multiples such as water-bottom multiples, peg-leg multiples, etc. and mark them in light blue. 4. Identify and mark reflection terminations or unconformities (onlap, downlap, and truncation) with arrowheads in red. 5. Identify seismic surfaces on the basis of reflection terminations. Assign a specific colour to individual seismic surface based on its type or age. 6. Identify sequence boundaries. Sequence boundaries are commonly marked by truncation or onlap, whereas maximum-flooding surfaces are commonly marked by downlap. 7. Carry out a similar exercise on other intersected seismic lines and tie the seismic surfaces and interpretation around the data set. 8. Map sequence units on the basis of thickness, geometry, orientation, or other features to see how each sequence relates to neighbouring sequences. 9. Identify seismic facies for each sequence. 10. Interpretation of depositional environments and lithological facies. Seismic facies analysis is the description and geological interpretation within sequences of smaller reflection units that may be the seismic response between boundaries. It analyses 13

25 the configuration, continuity, amplitude, phase, frequency and interval velocity. These parameters indicate the lithology and sedimentary environment of the facies. (Figure 6) Figure 6 - Seismic facies analysis: Reflection attributes (Bradley, 1985) Parallelism of reflections to cross bedding or to physical surfaces that separates older from younger sediments are defined as reflection configurations, and are helpful to identify stratification patterns, depositional processes, erosion and paleo-topography. Some reflection patterns are (Figure 7): Parallel and subparallel Divergent Prograding: Sigmoid, oblique, complex sigmoid-oblique, shingled or hummocky. Chaotic Reflection free 14

26 Figure 7 - Seismic reflection configurations (Vali, Mitchum, & Thompson, 1977) Attribute seismic analysis is done once the objective aspects of delineating seismic sequences and facies have been completed, the final objective is to integrate the facies in terms of litho-facies and depositional environments to create a 3D model. It is done 15

27 examining the lateral variation of individual reflection events to locate where stratigraphic changes occur and identify their nature; the primary tool for this is synthetic seismograms and seismic logs. Figure 8 - Attribute seismic interpretation (Boggs, 2001) 2.3 WELL LOGGING Logs are run after drilling into the open hole or completed well to measure petrophysical properties of the formations and to assess in the geophysical analysis of the reservoir. The well logs measure many parameters of the rock such as formation resistivity, sonic velocity, density and radioactivity of the elements. Interpretation of the results is used to determine the lithology, porosity of the formation, type of fluid and saturation. Logs could be interpreted manually but, nowadays specialized computer programs process the logs to give accurate and faster results WELL LOG TYPES Below are described some of the types of logs commonly used in the petroleum exploration industry. a. Spontaneous Pontential (SP) SP is a log that measures the natural difference in electrical potential between an electrode in the borehole and a fixed reference electrode on the surface. It can be used in open holes filled with conductive mud. The SP response is dependent on the difference in salinity 16

28 between drilling mud and the formation water. SP is used to identify permeable zones, therefore the lithology of the well; and also could be used to calculate the formation water resistance. Porous sandstones with high permeability tend to generate more electricity than impermeable shales. Thus, SP logs are often used to differentiate sandstones from shales. (SPE, 2013) b. Resistivity logs Resistivity logs determine the type of fluid that is present in reservoir rocks by measuring how effective are these rocks to conducting electricity. Because fresh water and oil are poor conductors of electricity they have high resistivity. By contrast, most formation waters are salty enough that they conduct electricity with ease. Thus, formation waters generally have low resistivity. The resistivity (R) of a substance is the electrical resistance measured between opposite faces of a unit cube of the substance at a specified temperature: Where, R = resistivity in ohm-m, r = resistance in ohm, A = area in m 2, L = length in m. Conductivity (σ) is the reciprocal of resistivity and is expressed in millisiemens per meter [ms/m]: Formation resistivity is measured by passing a known current through the formation and measuring the electrical potential or by inducing a current distribution in the formation and measuring its magnitude. It is usually in the range of [ohm-m]; higher resistivity values are uncommon in most permeable formations but are observed in low porosity formations such as evaporites. The resistivity of the borehole is commonly much less than the formations of interest that generally consists of rock layers with widely varying resistivity. (Figure 9) 17

29 Figure 9 - The borehole environment for well logging. (SPE, 2013) The main objectives of resistivity logs are the determination of Rt and Rxo and, for the newer imaging devices, the mapping of resistivity profiles into and around the borehole. There are many different types of resistivity logs, which differ in how far into the rocks they measure the resistivity (San Joaquin Valley Geology): The deep laterolog device (LLd) The deep induction device (ILd) The shallow laterolog (LLs) The medium induction (ILm) The microresistivity device The spherically focused log (SFL) c. Gamma Ray (GR) GR logs measure radioactivity to determine the types of rocks in the well. Natural occurring radioactive materials (NORM) include the elements uranium, thorium, potassium, radium and radon. Logging tools have been developed to read the gamma rays emitted by these elements and interpret lithology from the information collected. It is particularly used to distinguish sands from shales. 18

30 (Russell, 1944) In figure 10, the distributions of radiation levels observed by Russell are plotted for numerous rock types. Evaporites (NaCl salt, anhydrites) and coals typically have low levels. In other rocks, the general trend toward higher radioactivity with increased shale content is apparent. At the high radioactivity extreme are organic-rich shales and potash (KCl). Figure 10 - Gamma ray radiation of formation rocks (Darling, 2005) d. Neutron logs Neutron logs or compensated neutron logs (CNL) determine porosity by assuming that the reservoir pore spaces are filled with either water or oil; and then measure the amount of hydrogen atoms (neutrons) in the pores. If the lithology is known, the neutron log can be used to calculate porosity. Generally, the neutron and density logs are run together. The level of radiation reaching the detector is inversely related to the hydrogen content as shown below: High Porosity = High hydrogen content = Low GR Low Porosity = Low hydrogen content = High GR Gas has a very marked effect on both density and neutron logs. If it is assumed that the formation fluid is water and the invasion zone is shallow, then gas will result in a lower 19

31 bulk density and lower apparent neutron porosity. In limestone and dolomites, the lithology of a gas zone may show up as sandstone. The gas contact can sometimes be easily identifiable in carbonates from the raw logs, as they are frequently plotted on a limestone scale. The gas will cause the density log to be abnormally low, at the same time the neutron porosity will read too low. (Myers, 2007) e. Density logs Density logs or formation density compensated logs (FDC), determine porosity by measuring the density of the rock. It belongs to the group of active nuclear tools, which contains a radioactive source and two detectors. Tools rely on gamma-gamma scattering or on photoelectric (PE) absorption. The bulk density (ρ b ), from the density log is the sum of the density of the fluid (ρ f ) times it relative volume ( ) plus the density of the matrix (ρ ma ) times it relative volume (1 ), or: There is some variation in grain density. Dolomites can vary from 2.83 to Generally, the density tool will read mostly the flushed zone. Recommended density filtrate values are 1.0, 1.1 and 0.90 gm/cc for freshwater, saturated salt water, and oil based muds, respectively. A list of reference densities for common materials is shown in table 1. Table 1 - Density of fluids (Myers, 2007) f. Sonic logs Sonic logs or borehole compensated (BHC) logs are used to determination of porosity, identification of gas intervals and cement evaluation. In general, those measure how fast 20

32 sound waves travel through rocks in the well. Sound waves travel faster through high density shales than through low density sandstones. g. Nuclear magnetic resonance logs (NMR) NMR logs measure the magnetic response of fluids present in the pore spaces of the reservoir rock and are used to determine porosity and permeability, as well as the types of fluids present in the pore spaces. h. Dip-meter logs Dip-meter logs determine the orientations of sandstone and shale beds in the well, as well as the orientations of faults and fractures. Modern dip meters could make a detailed image of the rocks on all sides of the well hole. Borehole scanners do this with sonic waves, FMS (formation micro scanner) and FMI (formation micro-imager) logs do this by measuring the resistivity. These type of 3D logs are known as image logs since they provide a 360 image of the borehole that can show bedding features, faults and fractures, and even sedimentary structures FORMATION EVALUATION The formation evaluation is the complete process of analysing well logs to get the petrophysical characteristics of the formation. Required parameters for volume calculations are: Volume of shale, porosity, water saturation and thickness of the reservoir. The shale volume estimation (V sh ) is calculated using values of the gamma ray (GR), spontaneous potential (SP), neutron (PHIN) and density (PHID) porosity logs. V shg = GR GR clean GR shale GR clean V shs = SP SP clean SP shale SP clean V shhx = PHIN PHID PHIN shale PHID shale 21

33 GR, SP, PHIN and PHID are the picked log values, while clean and shale indicates values picked in the clean and shale base lines, respectively. Porosity from logs is considered total porosity (PHIt), which includes the bound water in the shale; to obtain effective porosity (PHIe) it must be corrected for shale volume. When both the neutron and density porosity curves are available, as in this case, the best method for correcting porosity is the complex lithology Density/Neutron crossplot. First, porosity is corrected for shale volume by PHI xc = PHID (V sh PHI shale ), where x will be n for neutron or d for density porosity. Effective porosity is then calculated as: PHI e = PHI nc PHI dc 2 To calculate water saturation, most methods require a water resistivity (Rw) value. In this case, an obvious clean water zone is present in two of the wells in the area and the water resistivity was calculated from the porosity and resistivity in this zone, using the Ro method, given by the following equation: temperature = PHI wtr m Ro a is the water resistivity at formation temperature, PHI wtr and Ro are the total porosity and deep resistivity values in the water zone, a is the tortuosity factor and m is the cementation exponent. 2.4 SUBSURFACE GEOLOGY Successful petroleum exploration involves the integration of geophysical seismic surveys and wire line logs with geological data and concepts. When information of more than one well is available, stratigraphic correlations could be done and summed up to the logs are used to determine the facies and depositional environment of the reservoir. Vertical cross sections are created to understand the geological data from small scale sections up to regional sections WELL CORRELATION The first stage for create a cross section is based on well correlation. When a well is drilled and logged, a correlation of the geological data gathered from well cuttings with well logs 22

34 is generated. Firstly, the formation tops are picked at a specific depth by the geologist, palaeontologist and geophysicist. Then correlation of the tops is correlated with adjacent wells based on the geophysical logs. The gamma, sonic and resistivity curves all the most used. Some useful marks are coal beds and limestone, which are thin but show exaggerate kicks on resistivity and porosity logs. Examination of the appropriate seismic data is necessary because sometimes significant intervals may be missing caused by depositional thinning, erosion or faulting. Repetition of sections caused by reverse faulting in sections subjected to compressional tectonics also may be noted GEOLOGICAL CROSS SECTIONS After the formation tops have been picked and the wells correlated, a cross section may be created with datum which could be sea level, fluid contact or a particular geological horizon. The procedure is simple for vertical wells, but more complex for deviated or horizontal ones in which the true vertical depth may be used. Cross sections of fields are based on well control. Seismic and well data is used for regional studies. A development of a single cross section is a series of drawings using a sequence of different data horizons that nowadays also is done by specific computer programs SUBSURFACE MAPS Many types of geological maps are used for oil exploration. As much information is available the accuracy of the interpretation will increase. Some of these geological maps are: The structure contour maps indicate the morphology of the basin and the traps based on seismic data and well logs. These maps are useful for reserves calculation. Isopach maps record the thickness of formations based on seismic and well logs. Isochore maps is a particular type of isopach that indicates the thickness of the interval between the oil-water contact and the cap rock of the trap. 23

35 The net pay map contours the ratio of gross pay to net pay within the reservoir. Sand-shale ratio maps indicate the source of sandstones and therefore possible reservoir areas. Paleogeographic maps are based on seismic and well logs of a section in which the depositional environment has been interpreted. Those are used to predict the quality of source rock and reservoirs. The combination of the maps is used to delineate plays and prospects where hydrocarbon could be found CORING ANALYSIS During the exploration phase, coring samples are analysed in order to get more information of the reservoir and calibrate the petrophysical model with data not obtained by the well logs. The information obtained from basic coring analysis is: Homogeneity of the reservoir Type of cementation and distribution of porosity and permeability Types of minerals in the reservoir Presence of fractures and their orientation Dip features that may influence logging tools response. 2.5 RESERVES ESTIMATION Oil reserves are the amount of technically and economically recoverable oil. Reserves may be calculated for a well, reservoir, field, or a nation. Estimation of reserves can be done before a field have been drilled with approximate data that may give an indication of the economic viability of the projects. As the field is being developed and produced, accurate reserves could be known. Several methods are used to estimate reserves depending on the availability of data. 24

36 The reserves defined by the Society of Petroleum Engineers (SPE), the American Petroleum Institute (API) and the American Association of Petroleum Geologists (AAPG) can be probed, probable, possible or remaining (Figure 11). Figure 11 - Reserves classification (Etherington J., 2005) Proved Reserves Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. Proved Reserves = Oil initially in place (STOIIP) x Recovery Factor Probable Reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. Possible Reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Remaining Reserves Remaining reserves are the proved reserves minus the produced ones; those are the remaining recoverable reserves. Remaining Reserves = Proved reserves - Production 25

37 The volumetric method is the most common methodology used for estimation of reserves. The precision of porosity, water saturation and volume of the reservoir will determine the hydrocarbon calculated volume PRELIMINARY VOLUMETRIC CALCULATION A rough estimation of reserves can be calculated assuming that the trap is full of fluid using the following equation: Recoverable oil reserves (bbl) = V b x RF Where, V b = Bulk Volume F = Recoverable oil (bbl/acre-ft) The bulk volume is calculated from the area and closure estimated from seismic data with the following equation: Where, V b = Volume h = Contour interval V b = h a a 1 + a a n 1 + a n 2 a o = area enclosed by oil-water contact a 1 = area enclosed by first contour a n = area enclosed by nth contour The recoverable oil is difficult to assess unless local information is available from adjacent fields. It may be calculated with an estimate of the average porosity of the reservoir. Since only a certain amount of hydrocarbon could be recovered of the total oil in place and is called recovery factor. It will be affected by the type of rock, the reservoir production driven mechanism and the fluid properties. The recovery factor used for oil is about 10-20% for carbonate reservoirs and 30% for sandstones. 26

38 2.5.2 POST-DISCOVERY RESERVES CALCULATIONS Original oil in place (OOIP) or Oil initially in place (OIIP) is the total volume of hydrocarbon content of an oil reservoir before beginning of the production and is calculated with the following equation for stock tank barrel units: STOIIP (STB) = 7758 A th Φ (1 Sw) Bo Eq. 1 Where, V = Volume of the reservoir (A x h) A = Area of the reservoir (acres) th = Thickness of pay zone (ft)from logs 7758 = Conversion factor from acre-feet to barrels Φ = Average rock porosity (decimal) from logs Sw = Average water saturation (decimal) from logs Bo = Formation volume factor for oil at initial conditions When oil is produced, the high reservoir temperature and pressure decreases to surface conditions and gas bubbles out of the oil. As the gas bubbles out of the oil, the volume of the oil decreases. Stabilized oil under surface conditions (60 o F, 14.7 psi) is called stock tank oil; it could be expressed as stock tank barrel (STB). Since the reserves are the volume that can be recoverable, when a well is drilled accurate reservoir data become available and an efficient calculation of reserves could be done with the appropriate recovery factor: Recorvable oil (bbl) = STOIIP RF.Eq. 2 Where, STOOIP = Initial oil in place (STB) RF = Estimated recovery factor 27

39 Oil formation volume factor (Bo) converts a stock tank barrel of oil to its volume at reservoir pressure and temperature. It depends on oil composition, but it is approximated by calculating the gas-oil ratio (GOR) and oil density (API gravity). It usually varies from 1.0 for heavy crudes with low GOR up to 1.7 for volatile oils and high GOR. Where, GOR (in the reservoir) = Q g Q o = μ ok g μ g K o Q = Flow rate at reservoir pressure and temperature g = gas o = oil µ = Viscosity at reservoir pressure and temperature K = Effective permeability An accurate measurement of Bo and GOR are done in laboratory with fluid samples. This procedure is referred as pressure-volume-temperature (PVT) analysis. Petro-physical analysis based on the well logs is used to assess the properties of the reservoir rock. In addition, during the drilling of each well some rock core samples of the reservoir are analysed in the laboratory to assess the initial information of porosity, permeability, water saturation and other necessary reservoir properties acquired with the logs. As the field is produced several changes take place in the reservoir such as pressure drops and decreases in flow rates. The GOR also changes depending on the production driven mechanism. The changes are analysed with a material balance equation (MBE) that is based on the law of mass conservation. MBE relates volumes of fluid in the reservoir at initial pressure with produced and remaining volumes at any stage of the production life. Dynamic modelling of the reservoir is based on the material balance and more complex relations. 28

40 2.6 SOFTWARE PETREL Hydrocarbon exploration integrates geophysical exploration, well logging and geology concepts. Technological development makes exploration work more efficient and less time consuming due to specialized computing tools developed for this purpose. Several software packages for geologic modelling of reservoirs can display, edit, digitise and automatically calculate the parameters required by engineers, geologists and surveyors for exploration phase as well as any other stage of hydrocarbon production. (Schlumberger, 2014) Petrel is a Schlumberger owned Windows PC software application intended to aggregate oil reservoir data from multiple sources. It allows the user: to interpret seismic data, perform well correlation, build reservoir models suitable for simulation, submit and visualize simulation results, calculate volumes, produce maps and design development strategies to maximize reservoir exploitation. It integrates in a single application the "seismic-to-simulation" workflow. A probabilistic analysis of the volumetric equations described previously is done with the required distributions of uncertainty for each parameter which, apart from the gross rock volume, reflect the average value of that parameter over the area or volume for which oil in place is being calculated. It takes in consideration not the hole reservoir but to be more precise, the average net pay over the area of the reservoir, the average porosity over the bulk volume, and the average oil saturation over the net pore volume. These computations are often dealt with through the application of 3D geological models. Since the equation requires the use of averages for reservoir properties as input, it is the uncertainty in the reservoir average that must be the basis for a probabilistic analysis. (Murtha J., 2009) Reservoir simulators in Petrel are classified according the type of fluid: Gas reservoir simulator: Single phase or two phase reservoirs. Black oil reservoir simulator: Gas, oil and water present in the reservoir. Compositional reservoir simulator: Condensate and volatile oil reservoirs. After the type of model has been selected, the reservoir is divided into blocks; each block is assigned with the rock properties (porosity and permeability), geometrical data (cell 29

41 dimensions and thickness) and the well data (phase saturation, relative permeability, capillary pressure, PVT). If field data exist therefore an accurate performance predictions can be done, if data is not available simulators may compare qualitatively the results of different ways of operating the reservoir. Accuracy of results could be done by history matching techniques. The following steps are required to build a 3D geological model of a petroleum reservoir: 1) Data Import 2) Input Data Editing 3) Well Correlation 4) Fault Modeling 5) Pillar Gridding 6) Vertical Layering 7) Geometrical Property Modeling 8) Upscaling in the Vertical Direction-Well Logs Upscaling 9) Facies Modeling 10) Petrophysical Modeling 11) Defining Fluid Contacts 12) Volume calculations INTERACTIVE PETROPHYSICS (IP) (Senergy Software Ltd., 2011) IP is a fast, flexible and robust software package that is used by petrophysicists, geologists and reservoir engineers to perform well logging analysis offering control and flexibility through a friendly and intuitive interface. IP offers some interpretation modules such as: Basic log analysis, Mineral solver, Monte Carlo simulation, Saturation Height modelling, Statistical prediction modules, Rock physics interpretation, Pore pressure prediction, Formation test, Date-Time well, Real-Time data and Image log analysis. The Basic log Analysis module is used to make a quick and basic log analysis. The functionality has been deliberately simplified to perform a type of analysis that could be easily duplicated using a calculator. 30

42 Clay volume is calculated from a Gamma Ray or entered as an input curve. Porosity is either from the Density or Sonic tool or the Neutron / Density crossplot. Water saturations are calculated using either the basic Archie equation, Indonesian equation or the Simandoux equation. No hydrocarbon or bad-hole corrections are made. No flushed zone (Sxo) calculations are made. The analysis can be divided into zones and a plot can be used to modify interactively interpretation parameters. The Clay Volume interpretation module is used to interactively calculate clay volume curves from multiple clay indicators. The Porosity and Water Saturation interpretation module is used to interactively calculate porosity (PHI), water saturation (Sw), flushed zone water saturation (Sxo), matrix density (RHOMA), hydrocarbon density (RHOHY) and wet and dry clay volumes (VWCL & DCL). The Cut-offs and Summation module allows you to interactively define Net Reservoir and Net Pay cut-off criteria and zones, and to calculate the average petrophysical properties of porosity, clay volume and water saturation for each zone within a petrophysical interpretation. 31

43 3. CASE OF STUDY: THE ORIENTE BASIN, ECUADOR 3.1 GEOLOGY OF THE ORIENTE BASIN The Oriente Basin is located between the Andes Mountains and the Gondwana Shield in the Amazon region of Ecuador (Figure 12). The basin has a north-south direction, topologically and geographically contiguous to the Putumayo Basin of Colombia and the Maranon Basin of Peru. (Granja, 1976) The basin covers an area of 100,000 km 2 and is where most of the oil fields of Ecuador have been discovered. The geodynamics of the central and northern Andes is directly linked to the subduction of the oceanic Nazca plate beneath the South American continent. In front of the coast of Ecuador, the structure of the Nazca plate is characterized by the presence of the Carnegie Ridge. (Baby P, 2004) Figure 12 - Regional tectonic location of Oriente-Maranon Basin (Xie Yinfu, 2010) The Oriente Basin represents a back-arc sedimentary sequence where the Paleozoic and Mesozoic sediments were deposited, overlaying the Triassic-Jurassic basement. The basin is a result of Late Cretaceous transpression force that produced immersion of the Cordillera Real and therefore originated the back-arc basin. Compressional events occurred in the Early Cretaceous causing the tectonic inversion of the Triassic-Jurassic sequences 32

44 throughout the basin. The deformation and structure of the traps and oil fields are the result of the inversion of old faults linked to rift systems of the Triassic-Jurassic age. These faults now reversed and steeply dipping, are mainly oriented NS or NNE-SSW. (Baby P, 2004) The faults delineate three structural oil corridors with own characteristics (Figure 13): Subandino System (Weast Play) Sacha-Shushufindi System (Central Play) Capirón-Tiputini System (East Play) Figure 13 - Oil structural corridors of Oriente Basin. (Modified from Baby, 2004) The corridor Sacha-Shushufindi, shown in blue in figure 13, is a back arc basin controlled by deep faults associated with a rift system developed during the Triassic-Jurassic. The Sacha-Shushufindi play covers the most important fields of the country: Sacha, Shushufindi and Libertador. At the north are the fields with light and medium oil, while at the centre and south the oil turns from medium to heavy. Even if it is a mature play, prospective is high because the traps are old; therefore any mapped structure has a good probability of having oil. 33

45 The Capiron-Tiputini play, shown in green in figure 13, has normal listric faults horizontally interconnected. The Capiron-Tiputini play is where the ITT and Pañacocha fields are located. This structure has medium and heavy oil. The Subandino play, shown in green in figure 13, has three important structures: The Napo lifting in NNE-SSO direction, limited to the east and west by transpressive faults, the Pastaza depression where the faults are more dispersed; and the Cutucu mountains where the structures changes direction from N-S to NNW-SSE emerging the Triassic-Jurasic Santiago and Chapiza formations. In the Subandino play is located the Bermejo field where heavy and extra heavy oils are present DEPOSITIONAL ENVIRONMENT The Early Cretaceous volcanic activity was followed by the marine sedimentation in the Late Cretaceous. Continental sedimentation followed the Cretaceous depositions; Cenozoic sediments took place along the axis of the back arc basin. Cenozoic and Mesozoic sediments are preserved in the Ecuadorean fields. (Baldock, 1982) Figure 15 shows the depositional environment along the region corresponding to the oil corridors previously described. Figure 14 Paleogeography map of the Napo Formation, Oriente Basin (J. Estupiñan R. M., 2010) 34

46 Figure 15 Stratigraphy of the Oriente Basin (Dashwood M F, 1990) 35

47 3.1.1 STRATIGRAPHY OF ORIENTE BASIN Well logging and seismic reflection have corroborated geological studies to get the stratigraphy of the basin. The following main formations have been determined across the Oriente Basin from bottom to surface: Hollin, Napo, Tena, Tiyuyacu, Orteguaza, Chalcana, Arajuno and Chambira. In some areas the presence of a specific formation is more evident than in others. Figure 14 shows the stratigraphy of the basin related to the geological occurrence time. There are several sets of potential source rocks in the Oriente Basin, among which the Cretaceous Napo formation of the Mesozoic Era is the most important in the north of the basin based on geochemical analysis of crude oil and source rock extraction; while in the south of the basin oil comes from the Triassic-Jurassic Santiago formation. The sandstone Cretaceous Napo formation is where most of the hydrocarbon has been found in the fields of the country. In turn, Napo formation is composed of some layers listed on table 2. Table 2 Napo formations sub-layers Napo Formations Napo Upper M1 M2 A U upper U lower Napo medium B T upper T lower Basal T Napo lower Rock type Lutite Limestone Limestone Limestone Sandstone Sandstone Lutite Limestone Sandstone Sandstone Sandstone Lutite 36

48 Within the Napo sedimentary rock formation there are two important reservoir units called U and T sandstones. Those are composed of cyclic sequences of limestones, shales and sandstones deposited on a low-energy shallow-marine platform controlled by sea level changes. (White, 1995) The depositional stage for the Napo T sandstone interval corresponds to sea level fall during the Cretaceous Albian Age that created a major boundary and an erosive drainage network after filled by incised valley sandstones during an early transgressive sea-level rise. The depositional stage of the Napo U sandstone interval corresponds to a later sea level fall during the Cretaceous Cenomanian Age, resulted in another erosional sequence boundary. Although similar in terms of environment of deposition, the sandstone members are different in composition and maturity. Napo formation is the main producing reservoir of the basin. It is composed of many formation units described on Table 2. The braided river-delta sandstone called Hollin is other important formation of the basin. This reservoir consists of thick-bed to massive white quartz sandstones, widely spread. It mainly serves as a lateral migration pathway for hydrocarbons. Fields of this reservoir are mainly distributed in the central and western parts of the Oriente Basin. (Marocco R, 1995) The fluvial river sandstone Tena formation composed of massive quartz sandstones is above the Napo formation, but is not well developed in the whole Oriente Basin. Along the country the structure of the Napo reservoir varies from one point to another. In figure 16 is summarized the stratigraphy sequence and geological occurrence time of the entire Napo reservoir rock layers or also called litho-facies. 37

49 Figure 16 U and T sandstone of the Napo formation (J. Estupiñan R. M., 2010) PETROLEUM SYSTEMS Traps in Oriente Basin are mainly structural anticline type (Valasek D, 1996). The Pacific plate continued to push into the South America plate since Late Cretaceous. The strong extrusion stress was released in the western part of the basin, which formed fold traps. The residue extrusion stress was transferred to the east. 38

50 In the central part of the basin, the extrusion is weak; which resulted in the formation of anticlines. In the east, the extrusion stress from the west was blocked by the Gondwana shield which reversed the former normal fault and formed some thrust anticlines. In addition, some lithological traps and stratigraphic traps may develop in the central and eastern parts of the basin. The traps are distributed like belt along NW-SE direction. The hydrocarbon in the Oriente Basin has long distance and step-up migration features (Figure 17). The Lower Cretaceous Hollin sandstone with high porosity and permeability provides a lateral migration channel for large scale hydrocarbon migration for distances around 100 km. (Pindell J L, 1995) In addition, the successive faults provide a vertical channel for step up hydrocarbon migration, through which the hydrocarbon could migrate to the shallow reservoirs. Figure 17 - Hydrocarbon migration model Oriente Basin (Xie Yinfu, 2010) HISTORY OF ORIENTE BASIN EXPLORATION IN ECUADOR Oil exploration in the Oriente Basin of Ecuador is divided in four stages summarized in the book Petroleum in Ecuador (Petroecuador, 2010). At the initial exploratory stage ( ), although commercial accumulations of oil were not discovered, the status of sedimentary basin and the oil potential was established 39

51 based on the presence of surface springs and few exploratory works. After initial analysis the sediment thickness, potential existence of a source rock and sandstones with highly potential of reservoir rock were discovered. The structure derived from the Andean evolution was defined. The end of this first exploration effort was concluded by discovering oil in one well at the Basal Tena reservoir. The second stage ( ), the Oriente was confirmed as an oil basin with the discovery of the biggest fields: Lago Agrio, Shushufindi, Sacha and Auca. These fields incorporated the greatest oil reserves of the country. Third stage ( ), was when exploratory activity was developed. State-owned and international oil companies discovery the field Libertador, which is the fourth bigger in the basin. The fourth stage (after 1983), is when exploratory maturity is achieved. This stage was characterized by a decrease in the rate of exploration success, by decreasing the size of the exploration prospects and by an increase in the density of the discovered crude (Rivadeneira M, 2004). In this stage the discovery of the small marginal fields among which Singue was discovered. The drilling of the well Singue-1 was done in 1990 and confirmed the existence of the field as an independent oil reservoir. The Oriente Basin in Ecuador had been explored for more than 50 years, now it is seem to be into the maturity stage. Seismic coverture of almost all the geography had been obtained, an important number of exploratory wells and geological studies allow an important knowledge of the reservoir such as the tectonic structure, stratigraphic architecture and oil producing systems is available to assess the study of new fields in the region. (Petroecuador, 2010) 40

52 4. METODOLOGY To estimate the production potential of the field Singue and meet the objectives of this dissertation the methodology used by the author is described in this chapter. The first step is the analysis of the data available to understand the current status of the field. The field has one well named Singue-1 that was producing oil from 1991 to Another exploratory well named Alama-1 that was drilled on 1984 but was water saturated. The information available is listed: o General information of the field. o Geological information of the basin. o Core samples results and bio-stratigraphic report of the well Singue-1. o PVT analysis results of the fluid and production history of the well Singue-1. o Raw 2D seismic surveys of the area. o Raw well logs of Singue-1 and Alama-1. The second step is the evaluation of the formation based on the well logging interpretation of the available logs of Singue-1 in the software Interactive Petrophysics (IP). With this information is possible to define the possible reservoirs in the field and define the properties of them. The input parameters required for the program are the.las files of each well. The interpretation procedure for the interpretation in IP is detailed later on this chapter. The third step is the seismic interpretation in Petrel to then integrate the results with the log interpretation results and the available information described on section 4.1 to find the boundaries of the reservoir. The process will give a better idea of the field potential. The input parameters for Petrel are the seismic surveys.sgy files and the.las well logs files. The procedure for the integration of logs and seismic data, as well as the interpretation methodology is detailed later on this chapter. Finally, the step four is the calculation of the remaining oil reserves in the field based on previous stages results. 41

53 Figure 18 - Methodology The flow chart of the methodology used in the project is on figure 18. The blue boxes are the available information, the green boxes are the available input data for processing, and then is the sequential sequence getting to the main process stages that are in yellow boxes. The process will be done by the program Petrel and by manual calculations if applicable. In chapter 5 are the results and discussions of each of the described stages. Integration of processed information with initial data will be complemented to get final results to conclude about the oil potential of the field. 42

54 4.1 ANALYSIS OF DATA GENERAL INFORMATION OF SINGUE The oilfield Singue is located in the Province of Sucumbíos at the northeast of Ecuadorean Amazon Region in South America. The field is close to two important producer fields: at the north of the Cuyabeno-Sansahuari field and at the northeast of the Libertador field. UTM and geographic coordinates of the field are shown in Table 1. (SHC, 2011) Table 3 - UTM and Geographic coordinates, Singue. Zone: 18S. Datum: WSG84 (Conversion units) UTM COORDINATES GEOGRAPHIC COORDINATES POINT X (E) Y (N) LATITUDE (N) LONGITUDE (E) A o o B o o C o o D o o The block Singue has an approximate area of 34.5 Km 2 equivalents to acres. The block has a rectangular north orientated shape. On the field there are two wells: Singue-1 and Alama-1. Figure 19 - Singue Field in Google Earth, location of wells Singue-1and Alama-1. Singue-1 is a vertical well with a depth of 8,035 feet that is located in the west side of the field as it is shown in figure 19. It was drilled in 1990 with successful initially oil production of 500 bbl/day. 43

55 Alama-1 is a vertical well with a depth of 8054 feet. It is the closest well to Singue-1 and was drilled in 1984 for appraisal development of the region. The well was dry of oil, namely water saturated. The information of this well is helpful to understand the geology of the region. The summary of general information of the wells is on table 4. Table 4 - General Information of the wells. Singue-1 and Alama-1. SINGUE -1 ALAMA -1 Well location (Geographical Long: ' 59.45" E Long: ' 35.85" E Coord): Lat: 00 09' 27.46" N Lat: 00 09' 55.04" N Well location in UTM Zone X (east): X (east): (18S): Y (north): Y (north): Altitude of the terrain: 806 ft. 898 ft.. Depth of the well: 8035 ft ft. Geological position of the well: Centre of the anticline Top of anticline Production tests: Produced Napo U lower Water saturated Status of the well: Abandoned 1997 Dry GEOLOGICAL STRUCTURE OF THE BASIN The field is located in the Oriente Basin of Ecuador, which was result of transpressive effort of the Late Cretacius that generated the emergence of the Cordillera Real and the formation of the back arc basin and Ecuadorean Andes. Singue Field is located to the end of Capirón system more NNW-Tiputini system orientated, which corresponds to an extended inverted basin, currently structured by listric faults that are connected on a horizontal level off overall. Additional information of the Oriente Basin can be found in chapter 3. The operator company at the time defined the geological structure of the field as an anticline NS direction that was discovered with the well Singue-1. The length of the structure is of approximately 1.2 Km and the width is approximately 0.9 Km. resulting an anticline area of approximately 1 Km 2. (Petroproduccion, 1990) 44

56 BIOSTRATIGRAPHY ANALYSIS OF SINGUE-1 The biostratigraphy analysis is the study of the micro-paleontological elements present in rock samples taken during the drilling. The results give an idea of the sedimentary deposit environment of each sample. Then it is assigned to a geological time of occurrence that has specific characteristics in each rock layer. And then is possible to identify to which formation the core belongs. The biostratigraphy analysis of Singue-1 was done with 37 reservoir samples taken from the depth of 4566 to 7900 ft. Table 5 shows the results of the analysis. (Petroproduccion, 1991) Table 5 - Biostratigraphy results of Singue-1 Depth interval (ft) Sedimentary Formation that Depositional Geologic Time (Age) represent Environment Shallow marine Oligocene Orteguaza Shallow marine Palaeogene Tiyuyacu Transitional Upper cretasic Tena Continental marine Santonian Napo Continental marine Turonian medium Santonian Napo Continental marine Turonian medium Napo CORE SAMPLE ANALYSIS OF SINGUE-1 Three core samples of 30 ft. were analysed in laboratory to determine the percentage of uranium, potasium and thorium presented in the formation based on the gamma radiation of these elements in each sample. This study enforces the identification of the sedimentary rock and depositional environments that represent. The results of the core sample analysis of Singue-1 are shown in Table 6. (Petroproduccion, 1991) Table 6 - Singue 1 Core samples tests Core sample interval (ft) Uranium (U) Potasium (K) Thorium (Th) Depositional environment Formation that represent ppm 2.6 % 12 ppm Marine and continental Napo U upper ppm 2.6 % 12 ppm Marine Napo U lower ppm 2.6 % 12 ppm Marine and continental Napo T 45

57 PVT ANALYSIS OF SINGUE-1 Pressure-volume-temperature (PVT) laboratory analysis was made with two samples of the fluid of the Napo U sandstone formation ( ft) of the well Singue-1. (Petroproduccion, 1994) Bubble point was calculated at ambient temperature. Then the sample was taken to a high pressure cell at the bottom hole temperature of 206 o F. At this temperature the sample reached the bubble point at a pressure of 550 psi and released 162 ft 3 of gas per residual oil barrel at 14.7 psi and 60 o F. The volumetric factor is barrels of saturated oil per barrel of residual oil at 60 o F. The residual oil at 60 o F has a API gravity of 24.4 and at 206 o F it has a density of gr/cc. Viscosity of the fluid was determined at bottom hole temperature of 206 o F, obtaining values of 3.20 cp at saturation pressure and 4.08 cp at atmospheric pressure. Additionally, some gas parameters were calculated at bubble point such as compressibility (Z), gas volumetric factor (Bg) and solubility (RS). Complete results are shown in table 7. Table 7 - Volumetric information Napo U sanstone of Singue-1 General Information Formation Napo U sandstone Interval ft Sample height (Ho) 16 ft Water saturation (Sw) 0.3% Bottom hole temperature 206 o F PVT results Saturation pressure at 206 o F 550 psi Thermic expansion of Volume at 206 o F and 5000 psi Saturated oil Volume at 82 o F and 5000 psi Saturated oil Gas-Oil ratio (GOR) 162 (550psi, 206 F) Volumetric factor (Bo) Density (lbs/bbl) Specific volume Viscosity 3.20 cp Residual oil API gravity at 60 o F 24.4 Density at 206 o F (gr/cc) Viscosity at 206 o F

58 The chromatography of the gas was done to determine gas composition and API gravity of the Stock tank. Table 8 and 9 show the results. (Petroproduccion, 1994) Table 8 - Separation tests results at 100 F and 14.7 psi (U sanstone, Singue-1) P (psi) GOR Bo API Gravity Specific Gravity (60 F) (SG) BTU Table 9 - Molecular composition of gas (Napo U, Singue-1) Component % Mol N2 (Nitrogen) 1.45 C1 (Methane) CO2 (Carbon dioxide) C2 (Ethane) 7.40 C3 (Propane) C4 (Iso-Butane) 4.46 nc4 (Butane) 9.66 ic5 (Iso-Pentane) 2.93 C5 (Pentane) 3.27 C6 (Exane) 1.06 C7 (Heptane) 1.57 Formation water analysis indicates that the tendency of this well is incrusting PRODUCTION OF SINGUE-1 Singue-1 was producing by the Napo U lower formation during 1991 and Initially it was with a production of 500 bbl./day, but then the production decreased below 200 bbls per day as is shown in figure 19. The water content was steadily increasing with the time. The well was closed because of the high water cut in The total cumulative production during the time the well was opened is bbl. of oil. 47

59 Singue 1 - Production OIL (BPPD) GAS WATER (BWPD) / / / / / / /1998 Figure 20 - Well Singue-1 production DATA: WELL LOGS Well logs have been used in exploration and development of well as part of drilling practice, to provide more information and greater accuracy of reserve estimation (Connolly, 1965). Well logs are used to identify the depth and thickness of productive zones, to distinguish the oil-water-gas contact, and to estimate reserves (Asquith, 2004). Well logging was performed during the drilling of the wells Alama-1 and Singue-1. The raw data available are the.las files. LAS stands for Log ASCII Standard, which is a fileformat common in the oil and gas industry to store wellbore log information. The.las files available contain the well logs listed on table 10. Analysis of some of this logs to get the lithology of the reservoir as well as some petrophysical properties such as porosity, water saturation, pay interval that will be used to volume calculations are described on next sections. 48

60 Table 10 - Well logs summary Log Indication Name Unit Depth Depth DEPTH ft Caliper Lithology CALI in Spontaneus potential Lithology SP mv Gamma ray Lithology GR GR API Sonic Porosity Lithology DT (Δt) µs/ft Shear sonic Porosity DT2 µs/ft Lithology Bulk Density Porosity RHOB g/cc Neutron Porosity Porosity NPHI V/V (%) Laterlog-Deep Resistivity Resistivity LLD Ohm Laterlog-Shallow Resistivity Resistivity LLS Ohm Lateralog 3 Band Resistivity Resistivity LL3 Ohm Induction Deep Resistivity Resistivity ILD Ohm Micro Spherical Focused Log Micro-Resistivity MSFL Ohm Photoelectric Absorption PEF B/e DATA: SEISMIC SURVEYS 2D seismic surveys were done in the area of the field Singue in the year The raw data available are the seismic files along approximately 150 km that cover an area of 170 km 2 in seismic format.sgy. The file format is one of several standards developed by the Society of Exploration Geophysicists to store single-line seismic reflection digital data on magnetic tapes. The available 2D seismic lines recorded by Petroproduccion (1990) are listed: 1) CP ) CP ) CP ) CP 347 2) CP ) CP E 14) CP 327E 20) CP 346 3) CP ) CP ) CP ) CP 119 4) CP E 10) CP ) CP ) CP ) CP ) CP ) CP 149 6) PE ) CP ) CP

61 Recording Equipment: Geophones and a portable register MDS-16, recording format SEG-B. The field parameters used were 40m in between points, shoots each 80m, depth 15 to 20 m with 2 pound of explosive. The receptor had 120 channels located in between channels 60 and 61 the farthest channel was at 2400 m of the origin. 9 geophones were used per channel. The line CP E has a coverture of 2.4% and the shots were done each 40 m. (Petroproduccion, 1990) Initial interpretations determined that Singue structure had high possibilities of being a reservoir. The exploratory well Singue-1was drilled in the line CP E at the shooting point 295. Re-process of the lines to assess in the remaining oil reserves will be described in next sections. 4.2 WELL LOGGING ANALYSIS The aim is to process and interpret the well logs of the well Singue-1 and Alama-1 to determine the stratigraphy and petro-physical characteristics of the sandstones. The study has been carried through qualitative and quantitative analysis by the programs Interactive Petrophysics (IP). The analysis includes determination of permeable rock zones and within each formation calculation of formation pay thickness, porosity and fluid saturation. Other parameters such as shale volume of each formation must be determined for this purpose. The methodology for each stage in the program IP is described below: WELL LOG INTERPRETATION TO IDENTIFY RESERVOIR ROCK a) Create a project in IP and create the wells Singue-1 and Alama-1, define general specifications such as well head position and import the well logs.las files into each well. 50

62 b) Make a quality check of the logs, to be sure the data is in the corresponding units and ranges. c) Run the Basic Log Interpretation process and plot the results in the range of interest for each well. d) Interpret GR, SP, RHOB, NPHI, CALIPER and RESISTIVITY logs to identify the lithology of the well and permeable formations. e) Pick the well tops of each identified permeable formation. f) Compare results with expected stratigraphy of the region presented on chapter 3 and with the bio-stratigraphic and core sample report presented on chapter WELL CORRELATION a) Using IP analyse well logs to identify the well tops of each formation picked in the area of interest that is between 7200 and 8100 ft. b) Use the well correlation process to correlate the logs for the available wells to identify if there are changes in the stratigraphy in the two available wells. c) Plot the well correlation obtained PETROPHYSICAL ANALYSIS Interactive Petrophysics have special modules to perform well log interpretation. The methodology includes: calculation of clay volume, porosity, water saturation and Net Pay thickness of each formation. The results are required for the volumetric calculation of oil in place. The well log interpretation is based on the Interactive Petrophysics Help document procedure (Senergy Software Ltd., 2011). The used modules are: Basic Interpretation module, Shale volume module, Porosity and water saturation module, Cutoff and Summation module. The basic module is a faster way of processing the data. The other three modules use more complex algorithms and are run together to get more accurate results. Both ways were developed in this project. Methodology of each module used for the interpretation of the logs of Singue-1 contained in the.las file is described below. 51

63 Basic Log Interpretation a) In the IP project open the Basic Log Analysis module. b) Define Density, Sonic or Neutron/density logs as input for Porosity calculations. c) Define GR as input for Clay Volume Calculations. d) Define the resistivity curve as input for Water Saturation calculation. e) Define the rock zones previously found. f) Select the clay volume calculation method and define GR clean (minimum value in clean non shaley intervals) and GR clay (maximum value in shale intervals) values. In this case is used GR method, Gr clean and Gr are selected interactively from the curves. g) Clay Volume (Vcl) is calculated and plotted using the equation: Vcl = Gr log Gr clean Gr clay Gr clean h) Select the porosity calculation model from Density, Sonic or Neutron/Density. In this case will be used the Density model. Set the parameters: Rho matrix = 2.65 for sandstones, Rho fluid = 1 g/cc for fresh water, Rho clay is the density reading of the log in the shale interval in this case is Vcl is the caly volume calculated. i) Porosity (Phi) is calculated and plotted using the equation: Phi = Rho matrix Rho b Vcl (Rho matrix Rho clay ) (Rho matrix Rho fluid ) j) Select the model used for water saturation calculation from Archie, Simand or Indonesian models. In clean rock select Archie, in shaley sands the Simandoux or Indonesian equations will make corrections for shale in the rock and give better results. In this case is used Archie method with the parameters: Rw formation temperature = 0.1 ohm, Archie factor a=1, m=2 and n=2. Those parameters also could be picked from porosity/resistivity curves. Rt is the value from the log. k) Water saturation is calculated and plotted using the Archie s equation: a Rw SwU = ( Phi m Rt )1/n l) Analyse the result curves: porosity (PHI), water saturation (Sw), bulk volume water (BVW), clay volume (VCL), apparent water resistivity (Rwapp). 52

64 Clay Volume Interpretation a) In the IP project open the Clay Volume interpretation process. Input as single clay indicators the gamma ray (GR), resistivity (ILD) and as double clay indicators the density/neutron (RHOB/NPHI) logs imported from the.las file of the well. Define the caliper log as bad hole indicator. b) Run the simulation to get minimum clay volume (VCL) and average clay volume (VCLAV) and the corresponding plots. c) Define the zones and select the method used for each clay indicator: The Gamma Ray clay indicator (VclGr) is set to the linear as in the basic interpretation module. The resistivity is set as linear. Z = Gr clean Rt R clean Rt R clean R clay The sonic density work on the principle of defining a clean line and a clay point. The clay volume is calculated as the distance the input data falls between the clay point and the clean line. d) Analyse the input curves, change limits of maximum and minimum parameters for each method if it is required. e) Interpret and discuss the obtained results for VCL and VCLAV in each formation. Porosity and Water Saturation Interpretation a) Porosity and water saturation is done under the interpretation menu, porosity and water saturation analysis. b) Link the module to the clay results. c) Define the porosity model and saturation equation. In this case is used the Density model for porosity and the Archie equation for water saturation. If the density porosity model is selected, then porosity is calculated as follows: 53

65 Where the values are picked from the input curves, ρ ma = Matrix density ρ b = Input bulk density log ρ cl = Wet clay density ρ fl =Filtrate density, calculated in 2 or entered as a parameter ρ HyAp = Apparent hydrocarbon density, calculated in.4, entered as a parameter Vcl = Wet clay volume Sxo = Flushed zone water saturation Archie water saturation equation is defined by: Where, a = 1, n = 2, m =2. d) IP assumes that any neutron curve entered is in Limestone matrix units. If this is not the case, then the curve should be converted to Limestone porosity units. e) Generate the temperature curve. Temperature is 206 F from PVT data. f) Run the simulation to get the plots of porosity and water saturation for each zone. Results include: porosity (PHI), water saturation (Sw), flushed zone water saturation (Sxo), matrix density (RHOMA), hydrocarbon density (RHOHY) and wet and dry clay volumes (VWCL & VDCL). g) Modify the input parameters if necessary interactively from the plots, refer to me Interactive petrophysics help manual. h) Analyse results for each formation. Cutoffs and Summation The Cut-offs and Summation module allows you to interactively define Net Reservoir and Net Pay cut-off criteria and zones, and to calculate the average petrophysical properties of porosity, clay volume and water saturation for each zone. a) Open Cut-offs and Summation under interpretation menu in IP. b) Define the input curves: Clay Volume (VCL), Porosity (PHI) and Water saturation (Sw), obtained in previous sections.. 54

66 c) Select the averaging method for each input curve. Available methods in selecting the averaging method for creating a continuous attribute are: - Arithmetic (Typically used for attributes such as porosity, saturation and net/gross because these are additive variables. The arithmetic mean is only correct for horizontal permeability that is constant within each layer). - Harmonic (Gives the effective vertical permeability if the reservoir is layered with constant permeability in each layer. The harmonic mean works well with log normal distributions. Used for permeability because it is sensitive to lower values. Only positive values may be used with this method). - Geometric (Normally a good estimate for permeability if it has no spatial correlation and is log normally distributed. The geometric mean is sensitive to lower values, which will have a greater influence on results. Only positive values may be used with this method). In this case was used the arithmetic method with following equations: Average porosity: Average water saturation: Average Clay volume: Extra curve arithmethic average: 55

67 Where, i = ith input value, hi = height input interval, n = number of samples. d) The default Cut-offs values are used to initialize the calculations e) Run the simulation to get the Reservoir and Pay plots. f) Check the Cutoff parameters: Zone Depths, Reservoir Cutoffs, Pay Cutoffs, Additional Cutoffs,. Change any parameter in the parameters screen if is necessary. g) Analyse results and plots that include Reservoir Results, Pay Results and Additional Results curves with parameters which include Gross Interval, Net interval, Net/Gross ratio, Average porosity and Average water saturation in the reservoir and in the Net Pay intervals. 4.3 SEISMIC INTERPRETATION The aim is to process the seismic raw data available in Petrel to get the boundaries of the reservoir. Integration of the well logs with the picked well tops with the seismic data in time is the initial stage. Then a model for the interpretation of horizons and faults has to be done to get the boundaries and area of the reservoir. a) Create a Petrel project with the coordinate reference system of the data (CRS) that is located in the UTM zone 18S. b) Create a well folder with the wells Singue-1 and Alama-1, define well head position, well path and import the well logs.las files with the available logs for each well. c) Open the well section window with each well and display the logs. Identify the well tops based on the obtained data of the previous section. d) Import the 2D seismic lines available WELL TIE Well tie process relates well logs with seismic surveys. The procedure is done following the Petrel 2010 Manual (Schlumberger, 2011). a) Under well tie process in Petrel use the sonic log to create the sonic despiked log. b) Do the sonic calibration to transform the well tops data from depth to TWT (two way time data) to relate logs with seismic data by the wavelet extraction process. 56

68 c) Create the synthetic seismogram. d) Display well tops table with depth and time HORIZON INTERPRETATION After having the synthetic seismogram and well tops in time horizon interpretation could be done. Each horizon corresponds to a well top, namely the top of a facie. a) Under seismic interpretation process of Petrel open the seismic data and well tops (TWT), each well top correspond to a seismic horizon in time domain. b) In the interpretation window open one by one the seismic lines and start horizon interpretation for the 5 formations: Napo U up, U low, T up, T low and Basal T. Use manual and 2D auto-tracking tool of Horizon interpretation. c) A folder with the horizons is created, and the horizons could be displayed in the 2D or 3D window FAULT INTERPRETATION a) Under seismic interpretation process, activates fault interpretation tool. b) In the interpretation window open one by one the seismic lines and start fault interpretation, use manual lines to identify faults. c) Follow the identified faults in all the seismic sections. d) A folder with the faults will be created BOUNDARY IDENTIFICATION a) From the interpreted horizons create a surface under make/edit surfaces process. b) Input interpreted horizon. c) Select the algorithm used. In this case the default convergent interpolation is used. d) Define the geometry of the field. e) Execute the process. Surfaces for each horizon are being created. f) Create a velocity model based on the manual (Schlumberger, 2011), use the created surfaces and the well tops as input data. It will be used to do domain conversion (time-depth) of any required data. g) Convert the surfaces, horizons and faults to depth domain. 57

69 h) Under the operations tab of each surface variogram maps for each surface could be created to visualize time/depth relations or properties of each surface. i) Using the surfaces and faults define the boundary of the reservoir. j) Use area to volumetric calculations. 4.2 RESERVES ESTIMATION a) Calculate the STOOIP for each formation The volumetric method used for initially oil in place calculation (STOIIP) is based on equation 1 mentioned in chapter 2. Where, STOIIP (STB) = 7758 V b Φ (1 Sw) Bo Vb = Area x thickness of the net pay A = Area (acres) from seismic interpretation th = Thicknes of net pay (ft) from well log interpretation Φ = Average rock porosity (decimal) from well log interpretation Sw = Average water saturation (decimal) from well log interpretation Bo = Formation volume factor from PVT data b) Calculate the initial reserves for each formation. The initial reserves are calculated using the equation 2 mentioned in chapter 2: Recorvable oil (bbl) = STOIIP RF Where, RF = Recovery factor (approximate 25% for sandstones) c) Calculate remaining reserves for each formation. The remaining reserves are calculated using the equation: Remanent reserves (bbls) = Recorvable oil Production Where, Production is the historical production of Singue-1 d) Add all the results to find the remaining oil in the field. e) Discuss the results 58

70 5. FINDING / RESULTS 5.1 WELL LOGGING INTERPRETATION IDENTIFICATION OF RESERVOIR ROCK Analysis of the GR, SP, caliper, density, porosity and resistivity logs were done in the range of 7200 and 8100 ft of depth to identify the lithology of the field. The basic log analysis tool in IP was used to generate a plot of displaying the well logs. Interpretation was done for each log in order to pick the well tops that indicate the changes in rock stratigraphy. Therefore, the height between two consecutive tops corresponds to a specific rock layer or lithofacie that represent a reservoir formation rock. This section is focused on the identification of sandstones. In figures 21 and 22 are plotted the interpretation results of the basic log analysis for the wells Singue-1 and Alama-1, there are defined the picked sandstones. In the figure, track 1 indicates the depth of the well; track 2 corresponds to the identified formations; in track 3 are the main lithology indicators which are the GR and SP logs; track 4 contains the porosity, density and sonic logs that are used to calculate the petrophysical properties; track 5 contains the resistivity log that will give an indication of the fluid content in each layer; lastly, tracks 6 and 7 present the results that IP generate for fluid content and lithology. The GR is the mainly lithology indicator because measures natural radiation of the rock. Low values indicate the existence of sandstones, carbonates and anhydrites while high values indicate shales (Baker, 1999). SP log if it is available also could be used as lithology indicator. The identified formations have characteristics of sandstones that have the GR and SP curve with low values. The tops are noticed in the inflection points of these curves to the left side meanwhile non permeable rocks have GR and SP displaced to the right. Five sandstones were determined for both wells which is consistence with the lithology of the Oriente Basin presented on chapter 3. The sandstones belong to the Napo formation. In the figures is evident the existence of Napo U around 7700 ft. and Napo T around 7900 ft. for the well Singue-1, while for Alama-1 are slightly deeply. 59

71 Napo U is divided in two layers: U up and U low. For the first one the GR and SP logs are not so steady, which means could be composed by other non-permeable rock elements. The Napo U low has the most steady sandstone GR response for both wells. Below Napo U low is evident the existence of a non-permeable rock that could be shale or a low porosity limestone. Then is the Napo T formation that is divided in other three sub-layers: T up, T low and T Basal. Napo T up shows steady sandstones responses to the GR. In the border with the Napo T low the signal has drops, meaning the sandstone is mixed with non-permeable rocks, decreasing the possibility of Napo T low to be a good permeable rock. In Napo T Basal the signal is steady again. Figure 21 - Singue-1 basic log interpretation. Lithology and well tops 60

72 Figure 22 - Alama-1 basic log interpretation. Lithology and well tops. The sonic and caliper logs show a steady line in the sandstone region, that is a good indicator of permeable rock. The density and neutron porosity log are together in the sandstones regions which is another good indicator of liquid fluid content. The analysis of the resistivity curves gives an indication of the presence of oil or water. In the upper side of the Singue-1 in the Napo U low, the response to the right with high resistivity values indicates the existence of oil. In the rest of the curves the log is not so 61

73 pronounced, it indicates the presence of water. In the well Alama-1 the resistivity response is low, which indicates major presence of water along the facie. The two tracks at the end show the automatic response of the software to porosity and lithology analysis. In track 6 is shown the porosity curve and fluid content, red is for oil and blue is for water. This information contributes to define that in Singue-1 the selected sandstones have hydrocarbons. This does not occur in Alama-1, where responses give highly indication of water content. This demonstrates the information that the well was oil dry when it was drilled. The final track shows the distribution of rock and porosity. In Singue-1 is evident the sandstone that is yellow in all the identified formations. Napo U low is the one with constant porosity mean value around 24%. This formation is the most probable to have hydrocarbon. Napo U up, T up and Basal are the formations that are likely to have petroleum but in less amount. Napo U up is the sandstone that shows very low probability of having hydrocarbon. In general for these first results the formation Napo is composed of sandstones but mixed with other non-permeable rocks that change their properties and thus the probability of having hydrocarbon content. The results obtained are summarized in table 11 and correspond to the lithofacies of the Napo formation: Napo U up, Napo U low, Napo T up, Napo T low and Napo Basal T. Table 11 - Well tops from well log interpretation SINGUE -1 ALAMA-1 Formation top Rock type Top (ft) Bottom (ft) Top (ft) Bottom (ft) Napo U up Sandstone Napo U low Sandstone Napo T up Sandstone Napo T low Sandstone Napo Basal T Sandstone Each formation top was assigned to a sandstone formation based on the regional stratigraphy of the Oriente Basin described in Chapter 3. Tying this information with the biostratigraphy and core samples data, could be concluded that the facies belong to the 62

74 Napo formation, which has continental- marine sedimentary environment belonging to the geological age Santorian Turonian WELL CORRELATION Well correlation between the two wells has to be done to identify relation of the discovered formations. Correlation results are on figure 23. Figure 23 - Well correlation of Singue-1 and Alama-1. The correlation shows that GR responses have a relation in both wells that are located at 2518m of distance. The picked well tops are deeper in the well Alama-1 than in Singue-1. If is considered that Alama-1 was a dry well, could be possible that even if they are closer to each other they might not be in the same structure, even if the GR response have the same sequence in both wells. 63

75 After identified the five possible productive sandstones the next step is the calculation of the petro-physical properties of each formation to get more information of each lithofacie PETROPHYSICAL CALCULATIONS The calculation of porosity, water saturation and reservoir pay interval must be done prior to the volumetric calculations of oil in place. The developed analysis was done on IP. Below are presented the results of the analysis of the well Singue-1 for the clay volume, water saturation, porosity, cutoffs and summation modules. Clay volume Because shales are more radioactive than sands or carbonates, Gamma Ray logs can be used to calculate the volume of shale in selected formations. The neutron log measures the amount of hydrogen in a formation and the density log measures the electron density of a formation. (Baker, 1999). Clay volume was calculated based on GR, resistivity and neutron/density logs. The results are shown in the last track of the figure 24. The average shale volume is the blue line. It is an average of GR, resistivity and neutron/density resopnses to shale volume. And how can be seen the curve is similar to the GR response. In the analysed interval, U low has small shale values, confirming to be a good sandstone. After it the formation Basal T is also showing similar responses. The other three formations has responses with irregular variations, meaning that the formations are not extrictly sandstones. The clay volume calculation is only an estimate. Very few formations are pure, many are composed of shale, clays and siltstone. 64

76 Figure 24 - Clay volume interpretation 65

77 Figure 25 - Saturation of fluids 66

78 Water Saturation In figure 25 are shown the results of the porosity and water saturation modules. In Track 7 are plotted the curve of the saturation of water in sky blue colour. In all the intervals is notable the prescence of water. Napo U lower is the one that has lower resopnse, it is sligthly to the rigth with average of 20% of water. All the other formations have fluctuations and peaks. Aditionally from this module is possible to see the fluid composition of the analysed formations. This well has no gas just oil (green) and water (sky blue). Again Napo U low is the interval that shows more oil content. At the end track of the figure 25 is plotted the porosity curve and lithology composition responses that include sandstone, silk, clay, salt and carbon. In Napo U formation the predominant is the sandstone, then it has a bit of silt and almost no clay. Whereas Napo T formations are silt mixed with sandstone in almost the same percentage. From the porosity responses Napo T up is the one with very low porosity, meaning low probability of having hydrocarbon. The results are based on the Neutron-Density curve overlay, with the sonic log as a cross-check, the most useful combination for lithology determination. (Baker, 1999). Reservoir and Pay zone The pay zone is the region that have economically recoverable hydrocarbons based on the porosity and fluid saturation characteristics of the reservoir. IP give results for the reservoir and the pay intervals. Figure 26 shows the porosity (PHIE), water saturation (SWu) and clay volume (VCL) results plotted in the last three tracks. At the borders of each track in green lines are the reservoir gross intervals corrisponding to each propertie and in red lines the pay intervals. A summary of the results for the reservoir and pay zone net intervals of the well Singue-1 and Alama-1 are shown on tables 12 and

79 Figure 26 - Net Pay intervals 68

80 Table 12a - SINGUE petrophysical results of the reservoir interval Table 13b - SINGUE petrophysical results of the net pay interval Table 14a - ALAMA petrophysical results of the reservoir interval Table 15b - ALAMA petrophysical results of the net pay interval 69

81 Singue-1 Net Pay interval of the Napo U low formation is the one with higher average porosity results (21%) and less water saturation (14%), therefore this information support previous results, concluding this formation is the better to produce oil in the field. On the other hand, Napo T up is the one with less porosity (16%) and high water saturation (39%), meaning cannot be a potential productive formation. The other facies have values that are going to be computed to have an idea of the potential, but are not as explicit as Napo U low. Napo T low has porosity of 15% and Sw of 26%, that means could be the second important formation followed by Napo U up that has porosity of 17% and Sw of 35%. Napo Basal has porosity of 17% and Sw of 39%. The results of the well Alama-1 on the pay interval show that the thickness is less than in Singue-1 for all facies. Additionally all the intervals have high water saturation with values above 33%. Porosity results in this well are not so different to Singue-1 results. With this information could be concluded that the lithology could be the same for both wells, but Alama-1 might be in a different structure that is water saturated even for the Napo U low facie compared to Singue-1 that shows good probabilities of oil in the Napo low lithofacie. Since Singue-1 is the well that has historical production data and that Alama was dry well, values of the Net Pay interval of Singue-1 are going to be used for the reserves estimation (Table 12b). 5.2 SEISMIC INTERPRETATION Next step was the seismic interpretation of the seismic data in Petrel. To define the area of possible hydrocarbon accumulation 20 seismic lines distributed along 150 km that cover an area of 170 km 2 were used to define the boundaries of the reservoir. Figure 27 show the distribution of the seismic lines in 2D and 3D views. The first step was the well tie process. 70

82 Figure 27 - Seismic interpretation WELL TIE With the picked well tops and after the well correlation the purpose is to locate the information in the seismic sections, for those reason the well tie process to generate a synthetic seismogram was done using the tops and the sonic logs. Synthetic seismograms are used to identify the well tops in time scale and then relate it with the seismic surveys. Then any changes from time-depth relationship can be made and seismic horizons can be correlated with the stratigraphic boundaries identified in the well logs. (Schlumberger, 2011). The input for the process is the sonic/density log and the seismic line where is located the well. Sonic logs give a very detailed picture of the variation in velocity along the borehole; however they must be integrated to give a depth time relationship. (Schlumberger, 2011) Figure 28 shows the well tie process results. From the left side to the right the tracks of the figure are described. The first two are the time and depth scales. Then is the sonic/density log that was input to the process. The next track is used for the GR as a reference of lithology. Well tops are defined by red lines. 71

83 On the right side of the figure are the seismic lines on both sides of the synthetic. Blue and red colours show the reflection waves polarity of both seismic surveys and synthetic. It is easy to follow colours at the moment of the interpretation. As it is shown in figure 28, the synthetic wave responses are very accurate and match with the seismic data. However, the resolution is decreasing in deeper intervals. Figure 28 - Well Tie Table 16 Well tops 72

84 The well tie process was done manual based on the display plots, following the reflection waves. As result of the process the well tops now have a value in time that was automatically generated. Table 14 shows the well tops originally in depth (Z) now with the equivalent time value (TWT) HORIZON INTERPRETATION Seismic sections show the response of the earth to seismic waves. When there are changes in rock character in bed boundaries, wiggles occur. There is a coincidence of wiggle types at about the same travel times. The areas of agreement are known as seismic horizons. Petrel put colour to the lines of wave agreement to make interpretation easier for the geologist or geophysicist. Mapping started in the location of the well tops. The first trace belonged to the Top Napo U up formation that is a well-defined reflection line that was used as reference for the work to identify deeper reflectors. Then the other lithofacies were mapped matching the seismic lines with the well tops. The interpretation was done originally in the line CP-326E. After several reflector horizons were traced across the first section then it was done along the vertical intersection lines CP-119 and CP-128. Then with the marks projected as reference interpretation, next sections were interpreted to match the interpreted horizons throughout the area of coverage. On figure 29 is explained the horizon interpretation process. On the left window is the overview of the area and the available 2D seismic sections. In the middle window is the 3D view of the area. At the right is the interpretation window. With yellow colour is defined the current line that has been interpreted. With different colours are defined the picked horizons. The X marks show the horizon cross sections picked with the same colour in other seismic surveys. The interpreted horizons are in the range of 1600 to 1700 TWT (two way time). Definition of the lines is decreased on the deeper horizons which made difficult the interpretation in all the area. 73

85 Figure 29 - Horizon interpretation process Figure 30 Horizon interpretation 74

86 It was concluded the existence of a slightly anticline in the area of the well Singue-1 along the direction north south. The interpreted section has east-west direction and shows structural closure at different levels, which means there might be a hydrocarbon trap capable of petroleum storage. Figure 30 show one of the interpretation windows FAULT INTERPRETATION Fault interpretation was made creating a line starting line CP-326E on the area where the horizons presented discontinuity. Manually lines were traced in the area of the horizon discontinuity. Two main faults were found on the first 2D line, and then they were projected to the other 2D sections of the area. At the west side of the structure there is a fault, apparently is on the west border of the structure. At the east side is another fault that do not is in contact with the structure and that separates the wells Alama-1 and Singue-1. The faults were found in the region close to the area of the well Singue -1. Those faults are consistent in the shallow regions, but in the lines that are deeper those faults are not clear defined. Could be concluded that the faults are north south orientated. Figure 31 - Fault interpreatation 75

87 Figure 31 show interpretation window for the fault interpretation. In blue is defined the fault at the east side of the field. In green is the fault that is at the west side of the field. In between the two faults is the well Singue-1 in yellow. The well Alama-1 is on green clearly out the area of Singue-1. These results ascertain that the two wells are not in the same structure RESERVOIR BOUNDARY To find the boundary of the reservoir the interpreted horizons and faults were required. After processing the information in Petrel was possible to create surfaces of each horizon with interpolation algorithms. Then, it was possible to create maps of each surface in which the structure contour of each formation could be identified. Figure 32 - Singue boundary 76

88 The surface map of the formation Napo U low was created with the interpreted faults and horizons as inputs, the generated map is shown in figure 32. As it was defined in previous sections Napo U low is the formation that has the best chance of having oil. In the map is possible to define the boundary of the reservoir. Manually a line was traced on the area of the structure surrounding the Singue-1 to calculate the dimensions of it. The structure has an extension of 1270m length and 800m width. It was assumed a rectangular shape of the reservoir, which gives a boundary area result of Km 2. Other surface maps for the other facies were generated but without showing the structure as clear as in the map for the Napo U low. Due to the lack of time of availability of the software and because Napo U low was on previous results the preferred formation in the field, it was assumed the same boundary area of Km 2 for all the calculations. The author recognizes results might increase the percentage of error in the other formations. Refer to appendix section to see the maps of the Napo U, Napo T and Napo Basal horizons. 5.3 RESERVES ESTIMATION Reserves calculations were done based on the found results in previous sections. It was clearly defined that the most important formation of the field is the Napo U low. Nevertheless reserves calculations were performed for the other formations assuming the same reservoir boundary area and same formation volume factor. The results of calculations for STOIIP for the sandstones formations of the field are detailed below: Table 17 - STOIIP calculation results FORMATION Area (km2) A (acre) h (ft) Av Phi (%) Av Sw (%) Bo STOIIP Napo U up % 35% ,247,564 Napo U low % 14% ,990,983 Napo T up % 39% ,588,354 Napo T low % 26% ,758 Napo Basal % 39% ,611,521 77

89 Napo U low is the formation with highest STOIIP. It was the formation that the well Singue-1 was producing in the past and is the one with higher potential. For the reserves calculations was assumed a recovery factor of 25%, value that is common in sandstone oil/water reservoirs of the area. Calculation results for initial and remaining reserves in the field are detailed below: Table 18 - Reserves calculation results FORMATION STOIIP RF INITIAL PRODUCTION REMAINIG RESERVES (bbl) (bbl) RESERVES (bbl) Napo U up 6,247, ,561, ,561,891 Napo U low 14,990, ,747, ,270,746 Napo T up 7,588, ,897, ,897,089 Napo T low 731, , ,940 Napo Basal 4,611, ,152, ,152,880 TOTAL 8,065,545 Reserves Estimation 24% 2% 14% 19% 41% Napo U up Napo U low Napo T up Napo T low Napo Basal Figure 33 - Remaining Reserves Distribution 78

90 As is shown on figure 33 and from the obtained results it is concluded that the field has one important formation that is Napo U low with a recoverable reserve volume of 3.2 MMbls, which represent the 41% of the total amount of recoverable calculated oil. There are two other formation with high potential of having petroleum, those are: Napo T up, Napo U up and Napo Basal T with the 24%, 19% and 14% of oil reserves as is shown in figure 33. The total reserves for the main 4 formations reach around 7.8 MM of barrels. The volume calculated corresponds to a marginal field in Ecuador, which represent a field with less the 1% of production of the nation. The next step is to continue with the modelling of the reservoir to have the water oil contact and property maps of each formation. If it is possible to get data of one extra well in the area, a 3D model could be created to assess in the decisions about the field. The economical evaluation of the project to develop more wells or to put in production the ones that are there, with the option of new formations must be done in order to evaluate the opportunity of investment. 79

91 6. CONCLUSIONS AND RECOMMENDATIONS 6.1 CONCLUSIONS Exploration is one of the most important stages in the oil industry. Seismic interpretation and well logging analysis could be used together to calculate the reserves. Specialized software like the used in this project: Interactive Petrophysics and Petrel, help to get faster and accurate results. As long as more information of more wells become available an accurate results could be achieved. At beginning stages or when not too many data is available for a field it is a challenge for petroleum engineers to assess in this kind of projects. Experience and collaboration with professionals of areas such as Geology, Geophysics, Petrophysics and Reservoir Engineering is recommended. The field Singue belongs to the Oriente Basin and has a main oil productive formation which is Napo. The sandstones facies of Napo with high oil potential production are the Napo U low, Napo U up, Napo T up and Napo Basal. Napo U low is the one with highest petroleum potential. Oil remaining reserves in Napo U low reach a volume of 3.2 MMbbls. The reserves taking into account the other three important formations reach 7.8 MMbbls. The interpreted section has east-west direction and shows structural closure at different levels giving the possibility of being hydrocarbon traps. The structure is demonstrated as an anticlinal extended in direction north-south. Two faults divide the wells Singue-1 and Alama-1. The development of marginal fields such as the one of the present case of study is becoming necessary in countries as Ecuador that is an oil producer developing country. Even if the amount of oil is not bigger compared with other fields, it is an attractive opportunity of business for any petroleum company. In addition because of the world energy demand is increasing, thus the consumption of oil is increasing and the reserves decreasing and the need of development of new technologies and small fields is important to satisfy that demand. 80

92 6.2 RECOMMENDATIONS The next step is the creation of a 3D model, but information of more wells will be required to make a complete characterization, either new wells or wells in the near region. With that information will be possible the creation of a grid and to assign petro physical properties of each formation with more accuracy. The model could be used to perform volume calculations and to generate attribute maps that are helpful to visualize and make decisions about the field. The static model also could be exported to other software and used to simulate possible scenarios of production. The summary of the recommendations for the present case of study are: Make an economic analysis to re-open the well Singue-1 taking into account present market expenses and oil prices. Make an economic analysis of the costs of drilling new wells in the field. Make a geological study of any other location for a new exploratory well. Drill one more exploratory well to get more information of the field. With the new data will be possible create a dynamic model able to simulate production options for the production of the field and decisions of investment will be easy. 81

93 7. REFERENCES AND BIBLIOGRAPHY Asquith, G. a. (2004). Basic well log analysis. American Association of Petroleum Geologists, 244. Baby P, R. M. (2004). La Cuenca oriente: geología y petróleo. Quito:, Andean studies French Institute, Institut de Recherche pour le Développement, Petroecuador. Bacon, M. M. (2003). 3-D Seismic Interpretation. Cambridge University Press. Cambridge. Baldock. (1982). Geología del Ecuador. Explanation of Ecuadorean geological map bulletin Scale 1: , 66. Boggs, A. (2001). Principles of sedimentary stratigraphy. Bradley. (1985). In K. D., Tectonic Growth of a collisional continental margin: Crustal evolution of Southern Alaska (p. 72). Geological Society of America. CGG. (n.d.). CGG Passion for geoscience. Retrieved 04 03, 2014, from Connolly, E. (1965). Production logging, a resume and current status of the use of logs in production, Correlation of different maturity parameters in the Ahmed Abad- Mehsana block of the Cambay Basin. SPWLA Symposium: Organic Geochemistry. Dallas.. Conversion units. (n.d.). Retrieved from Darling, T. (2005). Well logging and formation evaluation. Boston: Elsevier. Dashwood M F, A. I. (1990). Aspects of the petroleum geology of the Oriente Basin,. Ecuador Geologic Society Special Publications, Etherington J., P. T. (2005). Comparison of Selected Reserve, Resource Classifications and Associated Definitions. SPE Oil and Gas Reserves Committee (OGRC). 82

94 Faytteville Shale Natural Gas. (n.d.). Searching for natural gas. Retrieved 04 03, 2014, from Granja, J. C. (1976). El Petróleo misceláneas. Quito: Universitaria Editorial.. J. Estupiñan, R. M. (2010). Reservoir sandstones of the cretaceous Napo formation U and T members in the Oriente basin, Ecuador: links between diagenesis and sequence stratigraphy. Journal of Petroleum Geology Vol. 33. J. Estupiñan, R. M. (n.d.). Reservoir sandstones of the cretaceous napo formation u and t members in the oriente basin, ecuador: links between diagenesis and sequence stratigraphy. Journal of Petroleum Geology V. 33, Ltd., S. S. (2011). Interactive Petrophysics 4.0 Help document. M., J. (2008). Hydrocarbon Exploration and Production. Amsterdam: Elsevier. Marocco R, L. A. (1995). Intermontane Late Paleogene-Neogene Basins of the Andes of Ecuador and Peru, sedimentologic and tectonic characteristics. In S. S. In: Tankard A, Petroleum basins of South America. Murtha J., R. J. (2009). Uncertainty and the Volumetric Equation.. JPT. Myers, G. (2007). Nuclear Logging, Reservoir Engineering and Petrophysics Volume V(A). In Petroleum Engineering Handbook (pp. V-267 to V-287). Edward Holstein, Editor. Petroecuador. (2010). El petroleo en el Ecuador. Petroproduccion. (1990). Geophysic prospect of Singue. Petroproduccion. (1991). Biostratigraphic and Paleologic report of the well Singue-1. Ordonez M., Zambrano I., Jimenez N. Petroproduccion. (1991). Core sample analysis. Petroproduccion. (1994). PVT Analysis, Singue-1, Lower U sandstone.. PGE, N. D. (2013). Hydrocarbons Law, Ecuador. 83

95 Pindell J L, T. K. (1995). Mesozoic-Cenozoic Andean paleogeography and regional controls on hydrocarbon systems. In S. S. Tankard A, Petroleum basins of South America (pp ). Tulsa. Rivadeneira M, B. P. (2004). La cuenca oriente: Geologia y petroleo. Quito: Andean studies French Institute - Petroecuador. Russell, W. (1944). The total gamma ray activity of sedimentary rocks as indicated by Geiger counter determinations. Geophysics 9 (2), pp San Joaquin Valley Geology. (n.d.). Well logs. Retrieved 04 05, 2014, from Schlumberger. (2010). Petrel 2010: Seismic visualization and interpretation.. Schlumberger. (2011). Petrel Help manual. Schlumberger. (2014). Petrel E&P Software plataform. Retrieved 04 01, 2014, from Schlumberger Software: Selley, C. (1998). Elements of Petroleum Geology. San Diego, California: Academic Press. Selley, R. (1998). Elements of Petroleum Geology.. Academic Press. Second Edition. Senergy. (2014). Interactive Petrophysics webpage. Retrieved 04 28, 2014, from Senergy World: Senergy Software Ltd. (2011). Interactive Petrophysics 4.0 Help document (2011). SHC. (2011). Decima ronda petrolera. Retrieved 02 11, 2014, from Secretary of Hydrocarbons Ecuador: SPE. (2013, 07 19). Petrowiki. Retrieved 04 07, 2014, from Resistivity and SP logging: Tarek H. (2004). Advanced reservoir engineering. Oxford: Gulf Professional. 84

96 Valasek D, A. A. (1996). Cretaceous sequence stratigraphy of the Maranon-Oriente- Putumayo Basins, northeastern Peru, eastern Ecuador, and Southeastern Colombia.. AAPG Bulletin, 80(8): Vali, P., Mitchum, R., & Thompson, S. (1977). Seismic stratigraphy and global changes of sea level. Wasserstrom, R. R. (2013). Corporate responsability and Oil in Ecuador and Nigeria. Anthropologists, Weber, K., & Van Genus, L. (1990). Framework for constructiong clastic reservoir simulation models. Journal of Petroleum Technology. White, H. S. (1995). Reservoir characteristics of Hollín and Napo Formations, western Oriente basin, Ecuador. In Petroleum basin of South America. (pp. AAPG Memoir, 62, ). Xie Yinfu, J. S. (2010). Petroleum geology and exploration potential of Oriente-Maranon Basin (Vol. 37 (1)). PETROL. EXPLOR. DEVELOP. 85

97 APPENDIX 86

98 Appendix 1: Information Autorizathion Letter 87

99 Top Napo U E E E E E E Singue Alama E E E E E E Map Country Block License Model name Horizon name Scale 1:40000 Contour inc 2.5 User name stp782 Date 05/27/2014 Signature m 1:40000 Symbol legend Oil Undefined Elevation time [ms]

100 Top Napo T E E E E E E Singue Alama E E E E E E Map Country Block License Model name Horizon name Scale 1:32000 Contour inc 1 User name stp782 Date 05/27/2014 Signature m 1:32000 Symbol legend Oil Undefined Elevation time [ms]

101 1.0016E E E E E E E Singue-1 Top Napo Basal Alama E E E E E E E+7 Map Country Block License Model name Horizon name Scale 1:40000 Contour inc 2 User name stp782 Date 05/27/2014 Signature m 1:40000 Elevation time [ms]