Petroleum Policy and Management (PPM) Project. Final Report. Submitted by:

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2 Petroleum Policy and Management (PPM) Project Final Report Submitted by: Coordinating Committee for Geoscience Programmes in East and Southeast Asia (CCOP) September 2006 Bangkok, Thailand

3 Volume 1 Table of Contents Page 1. EXECUTIVE SUMMARY 1 2. INTRODUCTION 3 3. THE PETROLEUM POLICY AND MANAGEMENT (PPM) PROJECT 4 - Goals of PPM Project 4 - Objectives 4 - The Case Study Concept 5 - CCOP Organization and PPM Project Management 5 4. THE PPM PROJECT CASE STUDIES AND SUPPORTING ACTIVITIES 4.1. The Cambodia Khmer Basin Case Study 6 - Objectives 6 - Expected Results 6 - Activities 6 - Summary of the Results and Recommendations of the Cambodia Case Study 7 - Cambodian Participation in other Case Studies 9 - Computer Software and Hardware for Cambodia The Philippine Sulu Sea East Palawan Basins Case Study 11 - Objectives 11 - Expected Results 11 - Activities 11 - Summary of the Results and Recommendations of the Philippines Case Study 12 - Philippines Participation in other Case Studies The China Sichuan Basin Case Study 15 - Objectives 15 - Expected Results 15 - Activities 15 - Summary of the Results and Recommendations of the China Case Study 16 - Chinese Participation in other Case Studies The Indonesia Kutei Basin Case Study 18 - Objectives 18 - Expected Results 18 - Activities 18 - Summary of the Results and Recommendations of the Indonesia Case Study 18 - Indonesia Participation in other Case Studies 22 iii

4 5. PPM PROJECT SEMINARS PPM PROJECT WEBSITE SOFTWARE AND HARDWARE COORDINATION MEETINGS USE OF REGIONAL EXPERTS CONTRIBUTION OF THE CCOP MEMBER COUNTRIES TECHNICAL ASSISTANCE FROM THE NORWEGIAN PETROLEUM DIRECTORATE (NPD) PPM PROJECT BUDGET AND EXPENSES IMPACT OF THE PROJECT EVALUATION: General Summary ACKNOWLEDGEMENTS 39 iv

5 Volume 2 Table of Contents Page 1. Final Report of the CCOP Member Countries Hosting the PPM Project Case Studies 1.1 Cambodia Philippines China Indonesia Final Report of the CCOP Member Countries Participating in the PPM Project (not hosting a case study) 2.1 Korea Malaysia Papua New Guinea Thailand Vietnam List of Annexes (in the Final Report CDR) 1. CCOP Organization Chart 2. PPM Project Organization and Management Chart 3. 1 st Workshop of the Cambodia Case Study 4. 2 nd Workshop of the Cambodia Case Study 5. 3 rd Workshop of the Cambodia Case Study 6. 4 th Workshop of the Cambodia Case Study 7. 5 th Workshop of the Cambodia Case Study 8. 6 th Workshop of the Cambodia Case Study 9. 1 st Expert Visit of the Cambodia Case Study nd Expert Visit of the Cambodia Case Study rd Expert Visit of the Cambodia Case Study th Expert Visit of the Cambodia Case Study th Expert Visit of the Cambodia Case Study th Expert Visit of the Cambodia Case Study th Expert Visit of the Cambodia Case Study th Expert Visit of the Cambodia Case Study 17. Dissemination Seminar of the Cambodia Case Study st Workshop of the Philippines Case Study nd Workshop of the Philippines Case Study rd Workshop of the Philippines Case Study th Workshop of the Philippines Case Study th Workshop of the Philippines Case Study st Expert Visit of the Philippines Case Study nd Expert Visit of the Philippines Case Study rd Expert Visit of the Philippines Case Study th Expert Visit of the Philippines Case Study th Expert Visit of the Philippines Case Study 28. Dissemination Seminar of the Philippines Case Study v

6 29. 1 st Workshop of the China Case Study nd Workshop of the China Case Study rd Workshop of the China Case Study th Workshop of the China Case Study st Expert Visit of the China Case Study nd Expert Visit of the China Case Study rd Expert Visit of the China Case Study th Expert Visit of the China Case Study 37. Dissemination Seminar of the China Case Study st Workshop of the Indonesia Case Study nd Workshop of the Indonesia Case Study rd Workshop of the Indonesia Case Study th Workshop of the Indonesia Case Study st Expert Visit of the Indonesia Case Study nd Expert Visit of the Indonesia Case Study 44. Dissemination Seminar of the Indonesia Case Study st PPM Project Seminar nd PPM Project Seminar rd PPM Project Seminar th PPM Project Seminar th PPM Project Seminar 50. Report on the status of the GeoX licenses in the CCOP Member Countries 51. Cambodia- Resource Assessment results 52. Summary of PPM Project Budget and Expenses vi

7 ABBREVIATIONS AND ACRONYMS ASEAN ASCOPE BPMIGAS CCOP CCOP TS CGS CNPA DMF DMO DOE DSA EPRI ESCAP PNG KIGAM KNOC LEMIGAS MEMR MLR MOPE NOK NORAD NPCC PETRAD PPM PETRONAS PSC PTT PTTEP PNOC SINOPEC SPB UTP TAMU Association of Southeast Asian Nations ASEAN Council on Petroleum Executive Agency for Upstream Oil & Gas Business Activities, Indonesia Coordinating Committee for Geoscience Programmes in East and Southeast Asia CCOP Technical Secretariat China Geological Survey Cambodia National Petroleum Authority Department of Mineral Fuels, Thailand Domestic Market Obligation Department of Energy, Philippines Daily Subsistence Allowance Exploration & Production Research Institute, SINOPEC Economic and Social Committee for Asia and Pacific (UN) Papua New Guinea Korea Institute of Geoscience & Mineral Resources Korea National Oil Corporation Research and Development Center for Oil and Gas Technology, Indonesia Ministry of Energy and Mineral Resources, Indonesia Ministry of Land and Resources, China Ministry of Petroleum and Energy, Norway Norwegian Kroner Norwegian Agency for Development Cooperation National Project Coordination Committee International Programme for Petroleum Management and Administration Petroleum Policy and Management Petroliam Nasional Berhad Production Sharing Contract Petroleum Authority of Thailand (now a public company) PTT Exploration and Production Public Company Limited Philippine National Oil Company China Petroleum & Chemical Corporation Southwest Petroleum Branch, SINOPEC Universiti Teknologi PETRONAS, Malaysia Texas A & M University vii

8 1. EXECUTIVE SUMMARY The Coordinating Committee for Geoscience Programmes in East and Southeast Asia (CCOP) in cooperation with the Norwegian Petroleum Directorate with support from the Norwegian Agency for Development Cooperation (NORAD) launched the 4-year Petroleum Policy and Management (PPM) Project on July The responsibility for support to the Project was transferred to the Royal Norwegian Embassy, Bangkok in 2004 with the re-organization at the Norwegian Ministry of Foreign Affairs. The PPM Project has been based on a series of case studies. The intention was to utilize the lessons learned from the previous NORADfunded projects in a hands-own setting using country data from diverse settings. The overall goal is to develop human resources and to promote public sector institutional capacitybuilding in the petroleum management of the CCOP Member Countries. This was done through the implementation of four case studies supported by workshops, seminars and expert visits, addressing issues on resource assessment, economic modeling, legal and fiscal systems, and exploration and licensing strategies. The studies were carried out in Cambodia and Philippines (frontier basin), China (semi-mature basin), and Indonesia (mature basin). With a budget of NOK Million (~USD Million), the PPM Project has implemented a total of 19 workshops, 19 expert visits, 5 seminars, and 4 dissemination seminars. The total number of participation is 1,127 from the 10 CCOP Member Countries; about 25% of the participants are women. Majority is geoscientists, engineers, and economists, and about 20% with management level position (ranging from Division Chiefs to Vice President). The Project has capitalized on the expertise available in the CCOP region that resulted in significant savings for the project and, at the same time further enhanced the friendship and cooperation among Member Countries. The Project has also availed the expertise of Norway particularly in the areas of petroleum resource management and development, and was made possible through the strong support provided by the Norwegian Petroleum Directorate, the technical advisor to the Project. PETRAD, a Norwegian Foundation, and a CCOP Cooperating Organization, has also helped in identifying experts that were invited as resource persons through its international network. The recommendations of the PPM Mid-term review were implemented and benefited the Project. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 1

9 As reported by the National Coordinators, listed below are some of the impacts of the PPM Project. Improved understanding of the petroleum potential and policies of the CCOP Member Countries, especially the case study countries Information and Knowledge learned are disseminated through reporting and conduct of in-house seminars in the participant s respective organization Adoption of some concepts learned in basin assessment and exploration investment promotions The Project provided a good forum of building closer relationship and cooperation PPM is easily implemented based on the already established network. This network also functions outside the project Easier facilitation and coordination of new projects in the CCOP TS This final report of the PPM Project is divided into 2 volumes. Volume 1 is the report on the activities that were conducted to support the case studies and other administrative accomplishments. Volume 2 of the report was written by the case study participants and provides details on the results and recommendations of the case studies by the case study hosts as well as the report from the other Member Countries not hosting the case studies. This volume also highlights how information and knowledge learned from Project were given value and used to enhance their capacities. The PPM Project homepage provides complete information of the Project and all its activities. 2 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

10 2. INTRODUCTION The CCOP is an intergovernmental organisation consisting of 11 Member Countries, namely: Cambodia, China, Indonesia, Japan, Malaysia, Papua New Guinea, Philippines, Republic of Korea, Singapore, Thailand and Vietnam. 14 Cooperating Countries, including Norway, support the activities of CCOP. The CCOP mission is to facilitate and coordinate the implementation of applied geosciences programmes in East and Southeast Asia in order to contribute to economic development and an improved quality of life within the region. To this end, CCOP promotes capacity building, technology transfer, exchange of information and institutional linkages for sustainable resource development, management of geoinformation, geo-hazard mitigation and protection of the environment. Cooperation, Collaboration & Coordination: The Elements for Continued Success The CCOP activities are strongly supported by many Cooperating Countries and Cooperating Organizations through funding support and technical cooperation. For the activities in the Energy Programme, the Royal Government of Norway continued to be the major supporter of CCOP s petroleum projects. The Norwegian Agency for Development Cooperation (NORAD) Evaluation Mission in 2000 with its review of the PPM Project proposal submitted by CCOP to NORAD concluded that there is a need to sustain the transfer of technology and knowledge gained from previous NORAD-funded projects. This can be accomplished by utilizing the established network and competence in the CCOP region. Several government organizations of CCOP Member Countries also needed further technical assistance to facilitate and put to practical use the technology and knowledge from the previously completed NORAD-supported projects: Working Group on Resource Assessment (WGRA), Oil and Gas Resource Management (OGRM), Resource Evaluation and Planning (REP), Phase 1 and 2, The first two projects focused on the transfer of resource assessment methodologies, know-how, technology, and to a lesser extent, management of petroleum resources in a national perspective. The activities were centered upon regional mapping of petroleum resources and plays in basins, mostly in offshore areas, which are shared among CCOP Member Countries. Utilizations of national data in joint regional compilations of maps and petroleum plays have demonstrated the vast potential in regional geo-scientific cooperation and have also enhanced cooperation, trust, and the friendship among the Member Countries. These projects have in no small way contributed to the extensive development of the oil and gas resources in the CCOP Member Countries. This very cooperative environment has been further developed during the REP Project. The REP Project focused on full-cycle economic analysis of petroleum prospects, which forms the basis for most exploration decisions. Two important outputs from the REP Project were the general guidelines for petroleum resource Volume 1: Final Report of CCOP Petroleum Policy and Management Project 3

11 classification and risk assessment of petroleum prospects. Established standards in resource classification and prospect evaluations are very useful in planning petroleum activities at government level. The guidelines were published as CCOP Technical Reports and are easily downloadable from the CCOP website. 3. THE PETROLEUM POLICY AND MANAGEMENT (PPM) PROJECT Towards the concluding phase of the REP Project, the CCOP Technical Secretariat submitted the PPM Project Proposal to NORAD. In 2000, NORAD commissioned an appraisal team to review the PPM Project Proposal and CCOP. The conclusion of the appraisal team fittingly describes the PPM Project Several of the concerned organizations in the CCOP Member Countries need further technical assistance to facilitate that the technology and knowledge being transferred through the previous NORAD financed projects, is turned into practical use. To have case studies as the primary component of the PPM seems to be the best option to meet the objective of securing sustainability of the assistance. Goals of PPM Project The goal of the project is to enable government organisations responsible for petroleum resource management in the CCOP Member Countries to: establish a sustainable and efficient national petroleum management and policy, envisage the mechanism and importance in revising and improving their petroleum management and policy arrangements due to changes in political, economic and market conditions, and enhance their capacity and capability in petroleum resource management based upon a realistic assessment of their own petroleum potentials utilizing national data. Objectives The objectives of the CCOP Petroleum Policy and Management Project (PPM) are to transform gained knowledge from previous petroleum projects into efficient petroleum resource management models in the public domain of the CCOP Member Countries with respect to: Exploration strategies and licensing procedures Models and arrangements of regulations and framework conditions for the petroleum industry, and their consequences on the exploration and development activities Balancing between the government take and the industry profit, in order to maximise the economic potential derived from the petroleum resources Enhancing the expertise in petroleum resource management of Member Countries Optimal development of the petroleum resources with good environmental consideration and good management practice 4 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

12 This will be done through implementation of case studies supported by workshops, seminars and expert visits. The case studies cover frontier, semi-mature and mature basins and address questions related to gas development, marginal field problems, and exploration strategies. The Case Study Concept The case study is being introduced to give selected Member Countries practical experience in integrating resource assessments, resource management and petroleum policy, partly guided by foreign experts. The primary activity in the project will consist of four case studies. The main elements of the external support to these case studies will be: Workshops for the case study members in the host countries Seminars covering subjects that will support the case studies Dissemination seminars primarily targeted at the national stakeholders The activities that were closely linked to each case study are the following: 1. Member Countries participation 2. Workshops 3. Expert visits 4. Seminars 5. Dissemination of results 6. Project coordination 7. Software 8. Final report CCOP Organization and PPM Project Management The CCOP Technical Secretariat is responsible for the overall management of the Project. The Project Coordinator is tasked to conduct planning, budget preparation and implementation of the Project. The Project Coordinator reports to the Director of CCOP Technical Secretariat. During the first two years, the Project Coordinator is Mr. Gunnar Søiland of the Norwegian Petroleum Directorate (NPD). After one year into the Project s implementation, the Regional Project Coordinator Mr Simplicio P. Caluyong (DOE, Philippines) was hired and he has undertaken full Project coordination when Mr Søiland s term was completed. An overlapping period of approximately 1.5 years was made to ensure a smooth transfer of responsibility and continuity in Project coordination. NPD provided technical assistance to the Project and each CCOP Member Country that participated in the Project assigned their National Coordinator as contact person and to follow up the project implementation in each member country. A National Project Coordination Committee, NPCC, chaired by the Permanent Representative and including the PPM Project Coordinator as a member, was set up in each host country for the case study. Annex 1: Chart of CCOP Organization Annex 2: Chart of PPM Project Management Volume 1: Final Report of CCOP Petroleum Policy and Management Project 5

13 4. THE PPM PROJECT CASE STUDIES AND SUPPORTING ACTIVITIES 4.1 The Cambodia - Khmer Basin Case Study The study area is the Khmer Basin offshore Cambodia, proposed by the Cambodian National Petroleum Authority (CNPA). The area has been explored for 30 years. So far 11 exploration wells have been drilled and four gas discoveries have been made. Among these, the Kusrovie Natural Gas discovery is considered for development. No petroleum has been produced from this basin to date. The Khmer Basin is relatively small, situated adjacent to the petroliferous Pattani Basin and Malay Basin. The seismic coverage of the basin is approximately 20,000 km 2-D and km 3-D. The Khmer Basin is thus described as a frontier to semi-mature basin. Objectives The objective of this study is to assist the Exploration & Production Division of the Cambodian National Petroleum Authority and the other participating nations in developing an overview of the resources in this frontier offshore basin and identifying the critical elements of a gas field development. The study will also consider appropriate petroleum policies for an optimal exploitation of the resources and value creation for the society of this, and other similar frontier areas. Expected Results The results of this project should include an improved understanding and ability of the Exploration & Production Division of the Cambodian National Petroleum Authority and the other participating nations to evaluate the potential of this and similar basins. The study will include a resource assessment of the Khmer Basin, an overview of the development options of the natural gas discovery, and a discussion of petroleum policy measures to support further exploration and exploitation. Activities During the 4-year conduct of the Cambodia case study, the Project organized 6 workshops and 8 expert visits to support the case study. The workshops were organized to address the challenges of the case study team and open to the participation of technical personnel and management representatives from the Member Countries of CCOP. Experts were also called upon to help the team hosting the case study on their specific issues and needs through round-table discussions and technical training courses. The workshops conducted under the Cambodia case study covered the following topics: 1. General overview of the geology, petroleum resource assessment, and GeoX training 6 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

14 2. Petroleum resource assessment: Experiences from Analogue Basins (Thailand s Pattani basin and Malaysia s Malay basin) 3. Resource assessment, economic analysis, and field development options 4. Petroleum Prospect analysis and economic full-cycle analysis 5. Natural Gas contracts and Markets 6. Attracting Investments for Petroleum Exploration and Licensing Strategy To address the needs of the CNPA, the Project spent more time on resource assessment education of the CNPA staff through workshops and the training courses conducted during expert visits. Many CNPA staff was also sponsored by the Project to participate in some expert visits conducted in other case study countries for further training. They also participated in an on-the-job training on resource assessment in the Philippines Department of Energy, for further education on the concept and workflow of resource assessment as well as familiarize the usage of the tools used in the assessment (such as GeoX and GeoCAD software). The topics covered in the expert visits are the following: 1. Basic computer maintenance training 2. Training course on petroleum geology and data interpretation 3. GeoCAD mapping software training and digitizing 4. Follow up Training on the usage of GeoCAD/rat digitizer and GeoX software 5. Training course on Basic Petroleum economics 6. Training course on Petroleum Prospect and Play Risking 7. Lecture and exercises: Field Development Solutions and Experiences in the Gulf of Thailand (GOT) 8. Lecture and exercises: Plan of Development- the Indonesia experience Together with Norwegian experts, some of the resource persons in the abovementioned activities are from the CCOP Member Countries, who openly shared their experiences to the CNPA staff. Use of data and support of the CNPA management were the major challenges in the implementation of the Cambodia case study. The PPM Project management only learned when the Project was already implemented that there is a big organization problem in CNPA that is outside the control of the Project. The Project Coordinators have, in many ways, tried to get the full support of the management during NPCC meetings and other meetings at the CNPA, particularly on the issue of accessing and using National data for the case study. But unfortunately permissions were not granted. The case study was completed using few and vintage exploration data, and with the help of some useful information from Thailand s Pattani basin provided by the Thai participants in the case study and the experiences shared by the other participating CCOP Countries and resource persons. Summary of the Results and Recommendations of the Cambodia Case Study The case study has produced a report that contains a database of the geological and reservoir parameters used in the resource assessment activities. These were obtained from available company reports in the Khmer basin as well as information provided by the participants from CCOP Member Countries. The report has also Volume 1: Final Report of CCOP Petroleum Policy and Management Project 7

15 mentioned the resource assessment methodologies, assessment results, resource management strategies and recommendations. The parameters used in the volumetric calculation of the total petroleum resources in the Khmer basin are shown in the table below. Parameter Distr. Type Min. Mode Max. Remark Area of closure Str Beta Based on digitizing (Km2) Geom. Factor Ln2Lohi Trap Geom. Multiplier (decimal) NTG (decimal) Str Beta Based on well data Porosity (decimal) Str Beta Based on well data Trap fill (decimal) Const 1 Estimated Sh (decimal) Str Beta Based on regional data No. Prospects Str Beta From digitizing Rec. rate gas (decimal) Str Beta Based on regional data The total gas resource in the Khmer basin is reflected in the table below. Areas PPM Un-risked Mean (BCF) Angkor Apsara Da Koah Pring Koah Pring Koah Tang Koah Tang Northeast Koah Tang southwest Poulo Wai Poulo Wai North Total Woodside Un-risked Mean (BCF) The above results are compared to the studies conducted by Woodside in the Khmer basin. The main difference was in the calculation of the area and this is due to the uncertainties on determining the boundaries of the prospects/leads that resulted in generally larger area (& volume) calculations. The report also recommended, among others, For the CNPA management to allow the technical staff to access the latest data and information from the exploration activities in the basin and use this data to update the resource assessment of Cambodia 8 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

16 To develop and implement policies that will require oil exploration companies in Cambodia to share their knowledge and expertise to help improve the capacities of the CNPA staff Despite the challenges at CNPA, the Project has met the objectives of developing an overview of the resources in the Khmer basin but falls short of identifying the critical elements of a gas field development. The most important achievement of the Project in Cambodia is the improvement of the capacities of the CNPA technical staff in resource assessment, their confidence in interacting with other geoscientists, and ability to make a good presentation and report. HE Mr. Ho Vichit, Vice Chairman of CNPA, in his closing speech during the Dissemination Seminar, summed up the achievement of the PPM Project in Cambodia as follows I also highly appreciate the great achievements realized in the framework of the study as it is witnessed today by the presentations of the results of the study by the CNPA team. Through this study, our officials have gained valuable knowledge that will be very useful for the future development of our petroleum sector as well as for the development of our economy. Our officials have also been provided the unique opportunity to learn from the experiences of their friends from other countries. The complete report of the Cambodia Case Study Team is found in Volume 2 of this report. The following annexes provide details of the activities under the Cambodia Case Study: Annex 3-8: Workshops Annex 9-16: Expert Visits Annex 17: Dissemination Seminar Cambodia Participation in other Case Studies Technical staffs from CNPA have also participated in the workshops, seminars, and in some expert visits in the other PPM case studies Philippines, China and Indonesia. The Project also supported a special on-the-job training (OJT) on petroleum resource assessment, with emphasis on prospect and play risking using the GeoX software, of 3 CNPA staffs at the Philippine Department of Energy. Pictures from the OJT of Cambodia and PNG staff at the DOE, Philippines Volume 1: Final Report of CCOP Petroleum Policy and Management Project 9

17 Computer Software and Hardware for Cambodia The Project also provided a special budget for the purchase of computer hardware and software and internet connection for the Cambodia case study. The budget includes the maintenance of these facilities and usage training that are necessary so that the Cambodia team would be able to successfully deliver their work commitments to the Project with quality and on time. These specific supports amount to approximately USD Volume 1: Final Report of CCOP Petroleum Policy and Management Project

18 4.2 The Philippine Sulu Sea East Palawan Basins Case Study The Sulu Sea East Palawan basin or Sulu Sea Region (SSR) was nominated by the Philippines, through the DOE, for the case study under the Frontier Basin category. SSR is located near the southwestern margin of the Sulu Sea, and is the fully offshore portion of the North Sabah basins. The international boundary between the Philippines and Malaysia passes through the case study area. Objectives To address the geological uncertainties of the Sulu Sea region To evaluate the appropriate incentives to attract companies to explore in the region An evaluation of the potential impacts on the Philippine society Expected Results The results of this project should include an improved understanding and ability of the DOE and the other participating nations to evaluate the potential of this and similar basins. It should include a resource assessment of the Sulu Sea Basin, a view of possible development options, and a discussion of petroleum policy measures. Activities During the 4-year conduct of the PPM Project, 5 workshops and 6 expert visits were organized to support the Philippines case study. Upon the request of the Philippines PPM Team, the schedules of these support activities were adjusted to also support the current activities in the Department of Energy (DOE), in particular the 1 st Philippine Contracting Round (PCR1). The members of the PPM Team in the DOE are also the main team members of PCR1. The topics of the workshops are as follow: 1. General overview of the case study basin, upstream petroleum activities in the Philippines, and resource assessment activities by the DOE 2. Petroleum Prospect and Play analysis 3. Petroleum exploration economics and economic modelling 4. Development and Production Solutions 5. Exploration Strategies and Attracting Investments for Exploration in the Frontier Basin The expert visits covered the following topics: 1. Petroleum Economy and full cycle economic evaluation 2. Applications of Organic Geochemistry to Source Rock Appraisal and Hydrocarbon Characteristics 3. Sequence Stratigraphic Analysis using Seismic 4. Natural Gas Management- the Role of the Government 5. Petroleum reservoir management the Role of the Government Volume 1: Final Report of CCOP Petroleum Policy and Management Project 11

19 Summary of the Results and Recommendations of the Philippines Case Study The objectives of the Philippines case study have been met. The PPM Philippines Team has produced a report that discussed the resource assessment methodologies used and the results, economic analysis, marketing options analysis, licensing and fiscal regimes and recommendations. The results of the resource assessment in the case study area, Sulu Sea and East Palawan basins are shown in the tables below. Resource Class OIL GAS Prospects/ Million bbl Billion cf Sulu Sea Leads (Mean) (Mean) Total resources Discovered Resources 0 0 Undiscovered Resources Hypothetical (Mapped) Resources Speculative (Unmapped) Resources East Palawan Total resources Discovered Resources 0 0 Undiscovered Resources Hypothetical (Mapped) Resources Speculative (Unmapped) Resources Volume 1: Final Report of CCOP Petroleum Policy and Management Project

20 The results of the economic analysis on the prospects and leads in the case study area are shown in the table below. Sulu Sea Basin East Palawan Basin Parameters SS6 Prospect SS2 Prospect SS6 & SS2 Prospects EP1 Prospect Resources 1,733 BCF 1,310 BCF 3,043 BCF 1,719 BCF Production Period 21 years 21 years 21 years 21 years 12% $1,234 MM $731 MM $2,050 MM $1,218 MM IRR 26% 20% 27% 26% Payback 5 years 7 years 5 years 5 years TGT $7,837 MM $5,962 MM $12,523 MM $7,776 MM Listed below is the summary of the recommendations of the Philippines Team: 1. Change in Fiscal System Make amendments to the fiscal system specifically to P.D. 87 by decrease in the minimum area of application and an increase in the percentage of Filipino Participation Incentive Allowance (FPIA) to attract more local companies to participate in the exploration activities. 2. Exploration Risk - Exercise a thorough and comprehensive study of a frontier basin to maximize the value of petroleum reserves. 3. Access to Data - The DOE shall give exploration companies liberal access to the data especially for frontier areas although limitation shall be exercised for classified information. 4. Digital Data - Convert, if possible, all of the existing petroleum related data in digital format for easy access and use by exploration companies. 5. Progressive Incentives - Make modifications to the signature bonus by classifying the basins according to their prospectivity and decrease the percentage of relinquishment of the Service Contract area so that the exploration companies can make a complete evaluation of their respective areas especially in the frontier basins. 6. Contracting Round - The contracting round shall be carried out at least every two years. The interval for each contracting round is necessary to give way for the thorough evaluation of which area to offer and for the preparation of the necessary materials for promotion. A post-bid round evaluation is necessary to maximize the experiences encountered and to learn from mistakes done so as to better prepare and conduct the succeeding contracting round. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 13

21 7. Promotion - Prepare and disseminate the necessary promotional materials such as brochures, posters, exhibits, and equivalent digital information on CDs and official website whereby all of the needed geological and/or technical background and administrative guidelines in a frontier basin are reflected before the announcement of a contracting round. The complete report of the Philippines case study results can be found at the Volume 2 of this report. The following annexes provide details of the activities under the Philippines Case Study: Annex 18-22: Workshops Annex 23-27: Expert Visits Annex 28: Dissemination Seminar Philippines Participation in other Case Studies DOE technical staffs have also given their share of support to the Project by sharing their expertise, particularly in petroleum resource assessment to other CCOP Member Countries - as resource persons during expert visits to Cambodia and workshop in China. DOE representatives (from the technical staff and management) have also participated in the workshops and some expert visits conducted in other PPM case studies countries - China, Cambodia and Indonesia. In addition, the Philippine coordinators have attended the annual seminar conducted in Thailand. 14 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

22 4.3 The China Sichuan Basin Case Study The Western depression, the Sichuan Basin, is a semi-mature basin that covers an area of about km 2. A total of 5 plays are identified within the basin, three of which are proven.14 gas discoveries are found in fractured sandstones of Triassic and Jurassic age. A total of 50 drillable prospects are outlined. Total discovered resources are 220 billion m 3. 4 gas fields are developed and the production is 3.3 x 10 6 m 3 / day. The producing gas is transported to Chengdu city and its surrounding area. A 550 km network of gas pipeline has been built in this area. Objectives The objective of the case study is to conduct a total resource assessment and economic analysis of the 5 plays in the Triassic and Jurassic reservoirs. Principles and procedures of geological risk analysis of fractured reservoirs should be established. The effect of various framework conditions and their impact on profitability of fields and prospects should be evaluated. Strategies for further development of this semimature basin with existing gas production, regarding use, sale and infrastructure, should be developed. Expected Results Reports on the resource assessment and research results on petroleum resource profitability will be prepared and economic analysis of prospects, discoveries and fields in the five plays of the study area made exploration and development strategies of natural gas will also be formulated. Activities During the 4-year conduct of the China case study, the Project organized 4 workshops and 4 expert visits to support the case study. The workshops covered the following topics: 1. General overview of the geology, petroleum activities and resource assessment activities of SINOPEC in the case study basin 2. Petroleum resource assessment and economic analysis 3. Onshore gas development solutions and policies for investment opportunities 4. Exploration and Development Strategies for low permeability gas reservoirs and the role of the Government in achieving the strategies While the expert visits were focused on the topics listed below: 1. Low permeability gas reservoir development in the USA 2. Basin geology: Gas-centered gas system 3. Modelling of exploration projects by use of GeoX version Technology Exchange: Solutions to the development and production challenges in the low permeability (tight) gas reservoirs Volume 1: Final Report of CCOP Petroleum Policy and Management Project 15

23 The China case study of the PPM Project is hosted by SINOPEC, one of the National oil companies of China. The supporting activities are very much focused on the technical aspects of improving exploration practices and production of the case study area. SINOPEC has also financially supported the PPM Project by sponsoring the daily subsistence allowance of 4 participants from the CCOP Countries during Workshops 1-3. They sent additional experts to participate in other case studies activities on their own costs. SINOPEC also shouldered the computer rentals, and purchase of office supplies needed in the workshops and expert visits. The expenses related to field trips and transportation transfers airport-hotel-airport were also sponsored by SINOPEC. Summary of the Results and Recommendations of the China Case Study The China PPM Team has produced a report of the China case study that highlights the following: (1) Exploration risk Develop the internal guideline and procedures of risk analysis for the major Chinese petroleum basin to estimate the probability of making a discovery in play and prospect. (2) Resource assessment and economic analysis A total of 4 major plays and 9 key prospects in the middle part of the Western Sichuan depression were selected for resource assessment and economic analysis. Its results indicate that the total natural gas resources in place is estimated to be 5, m 3 and undiscovered gas resource in place is 3, m 3, with the 35% of discovery maturity, and that the most significant play in terms of undiscovered resource contribution is the Triassic Xu2 play. The key recommendations on future resource assessment include: Carry out a thorough natural gas resource and economic assessment for all the plays (including the established plays and conceptual plays) and prospects (including reservoirs and segments) in the Western Sichuan depression by using GeoX software and other resource assessment tools. Make a comparison between pre-drilling resource estimates and after-drilling reserve calculation to analyze the accuracy of resource assessment and uncertainty of input parameters. Apply the concept and methodology of play assessment introduced by the PPM project to China s future petroleum resource assessment. (3) Exploration and Development options For the future exploration and development of tight sandstone reservoirs, it is necessary (a) to conduct the systematical analysis of accumulation 16 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

24 mechanism of tight gas reservoirs, (b) to select the favorable traps for drilling on the basis of resource and economic evaluation in the levels of play, reservoir and segment, (c) to improve the exploration and development techniques suitable for tight sandstone reservoir, including fracture prediction, horizontal drilling, air drilling, multilayer hydraulic fracturing, etc, (d) to increase the deep drilling rate and to realize the reservoir protection, (e) to emphasize cost control and minimize exploration and development costs, (f) to apply the advance techniques of the development of marginal gas field in the world. (4) Gas market There is a great consumption potential of natural gas in the Western Sichuan region. The further development of gas market in this region requires: Establishment of a legal framework on natural gas, Increase the sale price of natural gas, Issue the tax credit policy for the exploration and development of tight sandstone gas, Increase taxes on more polluting fuels, such as collecting the carbon tax on coal use, and Accelerate the construction of gas pipeline networks and the development of natural gas market, especially natural gas for electricity generation and CNG industry. The objectives of the China case study were met by the Project. The complete report of the China case study results can be found at Volume 2 of this report. The following annexes provide more details of the activities under the China Case Study: Annex 29-32: Workshops Annex 33-36: Expert Visits Annex 37: Dissemination Seminar China Participation in other Case Studies SINOPEC experts shared their experience and expertise, particularly in petroleum resource assessment to other CCOP Member Countries - as resource persons during workshops for the Cambodia case study. SINOPEC representatives (from the technical staff and management) have also participated in the workshops and some expert visits conducted in other PPM case studies countries Philippines, Cambodia and Indonesia. In addition, the Chinese coordinators have participated in the annual seminars conducted in Thailand. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 17

25 4.4 The Indonesia Kutei Basin Case Study The Kutei Basin is situated at the eastern side of Kalimantan, partly onshore and partly offshore underlying Makasar Strait stretching almost to Sulawesi. The basin is characterised as a large basin of more than 50,000 km 2. The offshore part of the basin extends from shallow to very deepwater. The Kutei Basin developed in late Eocene as a rift basin and later in Middle Miocene as a deltaic basin. It is filled with fluvial sediments in the initial phase, and later with shallow marine and delta front/delta plain sediments. Reservoir rocks are coarse clastics and carbonates deposited in regressive periods. Shales constitute effective seals. The source rocks are shale layers of Late Oligocene Early Miocene age. The basin comprises sediment thickness of more than 10 km. The Kutei Basin is an important hydrocarbon producing area today, providing some 15 20% of the Indonesian production. Although several hundreds of exploration wells have been drilled, the basin is characterised as under explored (USGS World Petroleum Assessment 2000). The potential of the Kutei Basin is concentrated in three different plays/areas: Kutei Basin Deltaics, Kutei Basin Turbidites and Kutei Fold and Thrust Belt, whereof the Turbidites seems to hold the best potential. Objectives The objective of the case study is to conduct a resource assessment and economic analysis of parts of or the whole basin. Principles and procedures of geological risk analysis should be discussed and established. The effect of various framework conditions and their impact on profitability of fields and prospects should be evaluated. Strategies for further development of this basin regarding use or sale of oil and gas, and of infrastructure, should be discussed. Expected Results Reports on the resource assessment and economic analyses of prospects, discoveries and fields in the (selected) plays of the study area will be prepared and exploration and development strategy for oil and natural gas in the study area will be formulated. Activities During the 4-year conduct of the Indonesia case study, the PPM Project organized 4 workshops and 2 expert visits to support the case study. The workshops focused on the following topics: 1. General overview of the geology, licensing system Indonesia, and update on petroleum activities in the case study basin 2. Petroleum resource assessment and economic analysis 3. Marginal Fields: Development options, Technology, and Economics 4. IOR/EOR technologies and the role of the government in attracting additional/new investments in a mature basin While the Expert Visit s topics were on: 18 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

26 1. Lecture and Exercises on Petroleum Economics using the GeoX software 2. A Course on Deepwater Technology The host of the Indonesia case study is the Research and Development Centre for Oil and Gas Technology (LEMIGAS), a research agency under the Ministry of Energy and Mineral Resources. Other upstream petroleum agencies in Indonesia that are also members of the Indonesia PPM Team are from MIGAS, PUSDIKLAT MIGAS, and BP MIGAS. Summary of the Results and Recommendations of the Indonesia Case Study The Indonesia PPM Team has submitted a report of the case study that elaborates the Resource Assessment, Licensing Strategy, Fiscal Regime, and Mature Basin Development Policy, challenges encountered, and Conclusions. The results of the resource assessment are shown in the table below. The hypothetical resource was calculated from 93 prospects and leads, coming from 13 Blocks operated by 6 Companies in the Kutai basin. The number of Oil resources is 8,281 MMSTB and gas resources is 55,065 BSCF. The speculative resource was calculated using the GeoX Ver 5.20 software, carried out on those two plays, i.e. the Eocene-Late Oligocene Play and Late Oligocene-Middle Miocene Play, and then aggregated into a total resources in the basin. (1) Eocene-Late Oligocene Play Resource Type Mean F90 F50 F10 Inplace Resource Oil (MMSTB) AsGas (BSCF) 6, , ,355.9 NaGas (BSCF) 1, ,109.6 Condensate (MMSTB) Liquid (MMSTB) Gas (BSCF) 7, , ,702.5 Recoverable Resource Oil (MMSTB) AsGas (BSCF) 2, , ,075.5 NaGas (BSCF) ,671.3 Condensate (MMSTB) Liquid (MMSTB) Gas (BSCF) 3, (2) Late Oligocene-Middle Miocene Play Resource Type Mean F90 F50 F10 Inplace Resource Oil (MMSTB) AsGas (BSCF) 89, , , ,913.7 NaGas (BSCF) 30, , , ,548.8 Condensate 2, , , ,174.8 (MMSTB) Liquid (MMSTB) 2, , , ,260.0 Gas (BSCF) 119, , , ,724.2 Recoverable Resource Volume 1: Final Report of CCOP Petroleum Policy and Management Project 19

27 Oil (MMSTB) AsGas (BSCF) 31, , , ,719.8 Na Gas (BSCF) 19, , , ,306.7 Condensate 1, , , ,713.6 (MMSTB) Liquid (MMSTB) 1, , , ,743.4 Gas (BSCF) 50, , , ,732.7 (3) Total Speculative Resources Resource Type Mean F90 F50 F10 Inplace Resource Oil (MMSTB) AsGas (BSCF) 95, , , NaGas (BSCF) 31, , , ,790.4 Condensate 2, , , ,665.8 (MMSTB) Liquid (MMSTB) 3, , , ,352.8 Gas (BSCF) 127, , , ,830.4 Recoverable Resource Oil (MMSTB) AsGas (BSCF) 33, , , ,336.3 NaGas (BSCF) 20, , , ,422.0 Condensate 1, , , ,837.0 (MMSTB) Liquid (MMSTB) 1, , , ,880.3 Gas (BSCF) 54, , , ,858.2 The Indonesia report made the following conclusions and recommendations: (1) PPM Team Membership The Indonesia PPM Case Study was strongly supported by 2 main governmental agencies, ie. Directorate General MIGAS (DG MIGAS) and BPMIGAS, which was expected to bridge a joint cooperation among the agencies concerned. The team members of the Indonesia PPM are not coming from one agency, but they come from different governmental agencies. The intention of involving other governmental agencies is to bridge a joint cooperation among the agencies concerned, such as BPMIGAS that was expected to facilitate in contacting the oil companies or DG MIGAS which was expected to supply the governmental policy in the petroleum sector. However, the multi-institutional agency could not make the team compact and solid, which created a little problem in the implementation of the PPM activities, such as preparation of workshops, difficult to invite the members from those agencies due their tight schedule of their official jobs. Appreciation to participated Oil Companies, DG MIGAS, BPMIGAS and BPH MIGAS during the workshops held in Indonesia and other case study countries. 20 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

28 (2) Data Availability It was not easy to get the actual data for the case study, although the goal of PPM is to get a hands-on experience using own real data. Most of data in Indonesia are still considered confidential. There is no the so-called data manager either in BPMIGAS or in the DG MIGAS, the data is still kept by the oil companies. Data can be obtained from BPMIGAS after having an approval from DG MIGAS, and the approval process can take some time. (3) Use of GeoX Software The GeoX software is the most useful tool and was used by all case study countries in calculating the potential of the petroleum resources. GeoX is also useful in Indonesia since there are 60 basins many data and new data are added from time to time. However, it is very difficult to convince the government, either DG MIGAS or BPMIGAS, to use GeoX as a tool for resource assessment. The module of GeoX/gFullCycle is beneficial in the economical analysis of a petroleum project. However, in the resource assessment, the economics was not analyzed since the calculation of the resources was based on the play analysis. In the reality, it is very complicated and need more practices to accommodate all scenarios of the Indonesian fiscal regime. The software can not accommodate all elements of the Indonesia fiscal regime, e.g. the First Tranche Petroleum (FTP) which is not similar to Royalty. Most oil companies have their own software to do economic evaluation. The software is powerful and user-friendly. However, it is not widely used as the GeoX license is issued only for a particular computer. (4) PPM in Practice The PPM workshops, in general, were a forum for all CCOP Member Countries to present their experiences in solving their petroleum problems in their own country and they can share their own cases related to the topic of the workshop. The petroleum business in Indonesia is worked out by many oil companies, and there are big oil companies which operate big oil fields. They do the business with their own technologies as well as their own hardware and software. At this point, the technologies shared by the resource persons from Norway could not be applied, e.g. the deepwater technology, even sometime are not appropriate with the condition of the area. However, this situation will be different in the future when Indonesia does the exploration in the deeper part of the area. There are many things in the oil sector in Indonesia which are not touched by the PPM Project, and most are internal aspects; such as the production sharing due to the district autonomy, benefiting from oil and gas production for community development. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 21

29 The Indonesia PPM case study contents are in line with the target and strategic planning of the upstream oil and gas sub-sector as stated in the work program of Ministry of Energy and Mineral Resources The capacity and capability in petroleum resource management have been improved. The PPM Project Coordinator strongly believes that for future projects in upstream petroleum in CCOP, particularly projects dealing with upstream petroleum policy development, the Coordinating agency for Indonesia should be either BP MIGAS or DG MIGAS. These 2 agencies are mainly responsible for the petroleum policy and management in Indonesia. Geoscientific petroleum research projects, however, would still be best coordinated with LEMIGAS. The resource assessment objective of the Indonesia case study was met by the Project. The other objectives were not completely met due mainly to the data issue and cooperation of other agencies which are beyond the control of the Project management. The complete report of the Indonesia case study results can be found at the Volume 2 of this report. The following annexes provide more details of the activities under the Indonesia Case Study: Annex 38-41: Workshops Annex 42-43: Expert Visits Annex 44: Dissemination Seminar Indonesia Participation in other Case Studies Indonesian technical staffs and management representatives from government petroleum agencies have also given their share of support to the Project by sharing their expertise, particularly in petroleum resource management to other CCOP Member countries - as resource persons during workshops in Indonesia and expert visit for the Cambodia case study. Indonesia has also sent participants to other case study workshops and some expert visits conducted in other PPM case studies countries Philippines, Cambodia and China, both to learn from these case studies and at the same time contribute their knowledge and experiences to other countries. In addition, the Indonesian coordinators have regularly attended the annual PPM seminars conducted in Thailand. 22 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

30 5. PPM PROJECT SEMINARS The PPM Project Seminars were conducted annually in Thailand and covers special topics that supported all the case studies. The Seminars are also gatherings of National Coordinators of all the Member Countries participating in the case studies. The Seminar is an opportunity for all participants to report on how information and knowledge learned from PPM case study activities are being disseminated and used to improve their own capacities. An update concerning upstream petroleum business, specifically on current issues and challenges in the Member Countries are also reported during the Seminar. Resource persons were invited to make presentations and lead in the discussions related to the special topics of the Seminar. The Member Countries are also asked to make a presentation related to the Seminar s special topic. Listed below are the 5 Seminars in Thailand. (1) Kick Off (1 st ) Seminar : 11 th 13 th September, Bangkok (2) 2 nd Seminar: September, Pattaya (3) 3 rd Seminar: September 2004, Chiang Mai (4) 4 th Seminar: 4-7 October 2005 (5) 5 th Seminar: July 2006 The details of these Seminars can be found at Annex Volume 1: Final Report of CCOP Petroleum Policy and Management Project 23

31 6. PPM PROJECT WEBSITE The PPM Project website provides complete information of the Project and its activities. Some information on upstream petroleum activities in the CCOP Member Countries can also be found in this website. This site is managed by the CCOP Technical Secretariat and will be active even after the PPM Project s completion. Under the Project, it has been improved for fast accessibility and more user-friendly, with a discussion forum capability. All information posted is public and can be downloaded for free. 24 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

32 7. SOFTWARE AND HARDWARE The following hardware were purchased for the implementation of the Project notebooks (Toshiba and HP) 2. 2 LCD projectors (Toshiba and Infocus) 3. 2 Digital camera (Sony 3.2 MP for Cambodia and Nikon 2MP for CCOP TS) 4. 2 SD cards (128 and 256 MB) 5. 1 I-Omega CD Burner 6. 1 I-Omega external HD (20GB) 7. 1 rat digitizer for Cambodia 8. Computers and printers for Cambodia 9. 1 HP scanjet Skype Phone Mobile Phones The project also paid for the maintenance of the GeoX software, the main tool used for resource assessment and economic analysis in the case studies. But because of the higher quotations received from GeoKnowledge (vendor of GeoX) compared to the budget, only 4 licenses were purchased. CCOP TS with 1 license and the 3 licenses are distributed to the case study hosts - China, Cambodia, and Indonesia. The Philippines has their own license for GeoX through their PhilPRA Project, that is also supported by the Norwegian government. However, in 2004 a similar support arrangement was extended to the Philippines case study by the PPM Project upon the request of the National Coordinators. The maintenance of the licenses was also shared by the case study hosts. The intended maintenance cost split for one license is shown in the table below: TOTAL one license PPM Recipient Year 1 (2003) $ % $ 3124 Free Year 2 (2004) $ % $ % $1562 Year 3 (2005 ) $ % $781 75% $2343 Year 4 (2006 ) $ % $781 75% $2343 The cost for 2004 is a combination of base program maintenance of $2340 and Resource Management Module maintenance of $784 totalling $3124 per license. Actually only China paid their share according to the above arrangements. The Philippines and Indonesia, paid only their share for While Cambodia received full financial support for their GeoX maintenance. Additionally, some special software and hardware were purchased for the Cambodia case study. These consist of GeoCAD mapping software and rat digitizer, and new computers and printers that were used basically to support their activities on resource assessment and economic analysis. More time was also spent for understanding the concept behind the hardware/software s purpose, usage training, and maintenance and management. These education trainings were achieved through expert visits. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 25

33 The Report on the status of the GeoX licenses in the CCOP Member Countries can be found at Annex COORDINATION MEETINGS The National Project Coordination Committee (NPCC) was formed as an instrument to provide guidance to the case study implementation and in securing the availability of data and personnel. The NPCC is chaired by the Permanent Representative of the case study host country and including the Project Coordinator, Deputy Permanent Representative, and management representatives from other agencies participating in the PPM Project case study, as member. NPCC meetings were conducted during planning meetings and other Project activities in Cambodia, the Philippines, China, and Indonesia. The importance of NPCC is highlighted in Annex 2 Chart of PPM Project Management. The Project Coordinator regularly conducts planning meetings with the National Coordinators and members of the case study. The purpose of these planning meetings is to discuss the plans and programs of the case study, taking advantages of the experiences and lessons learned from earlier activities that have been conducted. Many of the Planning meetings were conducted during expert visits and other PPM activities in the case study host countries. The CCOP-MFA-NPD annual meetings were also conducted primarily to report to the Norwegian Authorities the accomplishments of the Project as well as discuss the plans and programs. A separate meeting between CCOP and NPD are conducted prior to the CCOP-MFA-NPD meeting to discuss the activities of the Project based on the plans and program and, also in accordance to the CCOP-NPD institutional cooperation agreement. Also discussed in these two meetings are other relevant matters to further strengthen the CCOP-Norway Cooperation. Representing CCOP in these meetings are the Technical Secretariat Director and Project Coordinator. During the 1 st half of the PPM Project the meetings were conducted in Norway, then later in Thailand. 9. USE OF REGIONAL EXPERTS The PPM Project has taken advantage of the expertise that are available in the CCOP Member Countries. Many of the resource persons that were invited to share their experiences during workshops and expert visits were from the CCOP Member Countries. They were identified through the existing network among National Coordinators and participants in the PPM Project. In fact, the use of regional experts has contributed to significant savings in the PPM Project since the Project only paid for their daily subsistence allowance and plane tickets, some even participated on their own costs. The salary, insurance, and other benefits were shouldered by their mother agency, that in most cases are also actively participating in the Project. In addition to the Project savings, the practice of using regional expertise has also enhanced the spirit of cooperation among Member Countries and provided a good platform for open sharing of experiences, particularly the lessons learned. In a 26 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

34 way, the sharing of experiences has provided solutions to some of the issues faced or will be encountered in the future by some Member Countries. Since many of these issues were already experienced by the other members. The resource persons proficiency and competence on the subject, combined with their accommodating nature, created an atmosphere conducive to productive discussions particularly during exercises and group presentations..overall, the training package is Class A. In all aspects, it rivals, if not surpasses, the commercial courses that are offered by international entities a feedback of the Philippine participants in one of the expert visits conducted by experts from PETRONAS, Malaysia. Below is the list of regional experts that have made noteworthy contribution to the PPM Project. Name Expertise Organization, Country 1. MR.GENEROSO REVILLA Petroleum legology, resource DOE, Philippines assessment, GEOCAD usage and digitizing/mapping 2. MR. NELSO LLABAN Petroleum geology Consultant, Philippines 3. MS. SUPAPORN Petroleum Geology and PTTEP, Thailand PISUTHA-ARNOND Applied Organic Geochemistry 4. MR. ROBERT WONG HIN FATT Petroleum Geophysics, seismic stratigraphy PETRONAS, Malaysia 5. MR. OTHMAN ALI MAHMUD Petroleum Geophysics, seismic stratigraphy PETRONAS, Malaysia 6. DR. ALLEN BEASLEY Natural gas management and ASCOPE Gas policy Center, Malaysia 7. MS. VIC UZARRAGA IT management CCOP TS, Thailand 8. MR. SUPAT Petroleum Engineering DMF, Thailand NAPANOPARATKAEW 9. MS. IRA MIRIAWATI Economics, POD BPMIGAS, Indonesia 10. MS. NELLY EKAYANTI Exploration geologist, POD BPMIGAS, Indonesia 11. MR. WUKAR HUSSAIN B MAZOOR HUSSAIN 12. MR. MOHD ZAKI B AWANG Petroleum Engineering and Production low-k reservoir Petroleum Engineering and Production low-k reservoir 13. MR. YANG DENGWEI Petroleum geology and resource assessment 14. MR. ANON Petroleum engineering and PUNNAHITANON resource assessment PETRONAS CARIGALI, Malaysia PETRONAS CARIGALI, Malaysia SINOPEC, China DMF, Thailand Volume 1: Final Report of CCOP Petroleum Policy and Management Project 27

35 15. MR. AIDIL SHABUDIN Petroleum engineering, development of thin oil reservoir 16. DR. DAE-GEE HUH Petroleum engineering, gas development and production 17. MR. NGUYEN NGOC HOAN Petroleum engineering, oil & gas development and production PSC, Fiscal system 18. MR. ANGELITO V. AGONCILLO 19. MR. JAIME A. BACUD Petroleum Geology and investments promotions 20. MR. ALI BIN MD Petroleum Geology and SHARIFF investment promotions 21. MR. BADRUL HISHAM ISMAIL Petroleum Geology, resource assessment PETRONAS, Malaysia KIGAM, Korea PETROVIETNAM, Vietnam DOE, Philippines DOE, Philippines PETRONAS, Malaysia PETRONAS, Malaysia 22. MS. EDITHA S. ABANGAN Petroleum geology, resource assessment using GeoX DOE, Philippines 23. MS. MA CORAZON STA Petroleum geology, resource DOE, Philippines ANA assessment using GeoX 24. MR. SEUNG HOON, OH Petroleum economics KNOC, Korea 25. MR. JESUS T. TAMANG Natural gas DOE, Philippines 26. MR. DIPA MULIA Data management and investments promotions PERTAMINA, Indonesia 27. MR. HU YUNDONG Resource classification system MLR, China 28. MR. GAO BINGQI Resource management and MLR, China Policy 29. MR. LIU YAN Development and planning SINOPEC, China 30. MR. CHEN ZHAOGUO Petroleum geology, resource SINOPEC, China assessment 31. DR. QIU HAIJUN Petroleum policy MLR, China 32. MS. ZHU XUEQIAN Petroleum engineering, natural gas development SINOPEC, China 33. MR. AUSSIE B. Field development and Total, Indonesia GAUTAMA production 34. MR. NURSYAFRIN ARBI Geophysics UNOCAL, Indonesia 35. MR. STEPHEN DOYLE MultiClient seismic surveys, PGS, Indonesia 28 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

36 36. MR. EKO HARI PDO BPMIGAS, ENDRARTO Indonesia 37. DR. ARSEGIANTO Petroleum economics ITB, Indonesia 38. DR. ABDUL MUIN Petroleum policy BP MIGAS, Indonesia 39. MR. BENNY LUBIANTARA Petroleum economics BP MIGAS, Indonesia 40. MR. EGO SYAHRIAL IOR/EOR research LEMIGAS, Indonesia 41. MR. KUNCORO BARUNO IOR/EOR applications PT Chevron, Indonesia 42. MR. J. HERRY POERWANTO IOR/EOR applications PT VIBRO SISTIM, Indonesia 43. MR. SIMON ROBSON Data management Schlumberger, Indonesia 44. MR. BAMBANG YUWONO Policy and fiscal system BP MIGAS, Indonesia 45. MR. TUMBUR PARLINDUNGAN Petroleum Economics Schlumberger, Indonesia 10. CONTRIBUTION OF THE CCOP MEMBER COUNTRIES The CCOP Member Countries have provided contribution that helped in the successful implementation of the PPM Project. Below is the summary of these contributions. (1) Cambodia a) Time and suitable counterparts to coordinate and help in the preparation of workshops, expert visits, and meetings b) Data for the case study (vintage data) c) Transportation during workshops, expert visits and planning/npcc meetings (2) China a) Time and suitable counterparts to coordinate and help in the preparation of workshops, expert visits, and meetings b) Data and experts for the case study c) Transportation during workshops, expert visits and planning/npcc meetings d) Provided experts as resource person to one of the Cambodia case study workshop e) Financial support (DSA) for 4 participants from the Member Countries during Workshops 1-3 f) Sponsorship of dinners, excursions and guides, hotel-airport-hotel pick up and transportation, computer rentals and office supplies, and covering the cost of local participants, and cost of experts participating in other case study activities Volume 1: Final Report of CCOP Petroleum Policy and Management Project 29

37 (3) Indonesia a) Time and suitable counterparts to coordinate and help in the preparation of workshops, expert visits, and meetings b) Data and experts for the case study and guides during geologic field trips c) Provided experts as resources persons during expert visit to Cambodia case study (BP MIGAS) d) Transportation during workshops, expert visits and planning/npcc meetings e) Covered the cost of local participants, and participation of their experts in other case study activities (4) Korea a) Provided experts as resource persons in the workshops conducted in the Philippines and Cambodia case studies (5) Malaysia a) Provided experts as resource persons in the workshops conducted in the Philippines and Cambodia case studies b) Provided experts as resource persons during expert visits to the Philippines and China case studies, as well as during the 5 th Seminar c) Provided an expert (Mr. Leung Khee Meng, UTP) to conduct a Midterm review of the PPM Project together with a Norwegian Consultant (6) The Philippines a) Provided a Regional Coordinator to the PPM Project b) Time and suitable counterparts to coordinate and help in the preparation of workshops, expert visits, and meetings c) Data and experts for the case study and guides during geologic field trips d) Provided an on-the-job training on petroleum resource assessment to PNG and Cambodia technical staff at the DOE e) Provided experts as resource person during a workshop in China and expert visits in Cambodia case study f) Transportation during workshops, expert visits and planning/npcc meetings (7) Thailand a) Provided experts as resource persons during workshops in Cambodia. Thailand, through DMF, has also shared their experiences in the Gulf of Thailand to the Cambodia case study. b) Provided experts as resources persons during expert visits to the Philippines and Cambodia case studies (8) Vietnam a) Provided experts as resources persons during workshops in the Philippines and Cambodia case studies 30 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

38 The PPM Project paid only for the DSA and plane tickets of the experts coming from the Government agencies participating in the PPM Project. The experts mother agency/company covered the salary, allowance, insurance, cost of preparation, and materials needed by the experts. 11. TECHNICAL ASSISTANCE FROM THE NORWEGIAN PETROLEUM DIRECTORATE (NPD) Under the CCOP-NPD institutional cooperation agreement, NPD provided technical assistance and advice to CCOP for the implementation of the Project. Among the assistance provided was the posting of Mr Gunnar Søiland, an expert from NPD, in the Technical Secretariat in Bangkok as Project Coordinator during the first half of the Project. The Regional Project Coordinator, Mr Simplicio P. Caluyong (DOE, Philippines) was hired after the 1 st year and had an overlap with Mr Soiland for more than one year as designed in the Project. NPD also provided assistance to the Technical Secretariat in the identification and provision of expert as resource persons during many PPM activities. These experts are coming mostly from NPD and the Norwegian Ministry of Petroleum and Energy. Others are from oil companies and consultants in Norway. PETRAD, another Norwegian agency with close ties with CCOP, has also helped in the identification of experts for the Project through PETRAD s networks in the oil business. These Norwegian organizations, through their strong support together with the experts that they have recommended to CCOP significantly contributed to the successful implementation of the PPM Project. Listed below is the list of Norwegian experts that attended the PPM Project activities. Name Expertise Organization 1. MR. GUNNAR SØILAND Petroleum geology, resource NPD assessment, Project management, IOR/EOR 2. MR. ERLING Petroleum geology, resource NPD KVADSHEIM assessment, project management 3. MR. CHARLES STABELL GeoX tools Geoknowledge AS 4. DR. ALFRED KJEMPERUD Resource assessment, petroleum economics, GeoX usage The Bridge Group AS 5. MR. OLE EKERN Marginal fields, petroleum policy, investment promotions strategy NORSK ENERGI & THE BRIDGE GROUP AS 6. MS. INGER PEDERSEN Petroleum geology, resource NPD FJÆRTOFT 7. MS. BENVENUTTA ELISE HENRIKSEN assessment, GeoX usage Petroleum economics, GeoX usage NPD Volume 1: Final Report of CCOP Petroleum Policy and Management Project 31

39 8. MR. TORMOD Petroleum policy NPD SLATSVEEN 9. MR. GAUTE ERICHSEN Petroleum economics and Policy MOPE 10. MR. MORTEN PEDERSEN Petroleum Economics, gas markets NPD 11. MS. MARI KVAAL Petroleum economics NPD 12. MR. TORE BJORDAL Petroleum Engineering, development NPD and production 13. MR. STIG SVALHEIM Petroleum economics, CDM, NPD marginal fields 14. MR. ESPEN MYHRA Petroleum economics, policy, MOPE investment promotions 15. MR. KJELL AALANDSLID Petroleum engineering, marginal field SAGEX AS technology and development options 16. MR. EGIL MEISINGSET Petroleum policy MOPE 17. MR. JAN BYGDEVOLL Petroleum engineering, reservoir NPD management, IOR/EOR, PDO 18. PROF. ARNFINN NERGAARD Deepwater technology UNIVERSITY OF STAVANGER In addition experts from the USA were also invited as resource person, in particular to the activities in the China Case study of gas-tight Sichuan basin. These experts were identified through the efforts of NPD and PETRAD. Below is the list of experts from the USA that participated in the PPM activities. Name Organization 1. MR. CYRUS ESPHAHANIAN CONSULTANT (COLORADO) 2. DR. BEN LAW CONSULTANT (COLORADO) 3. DR. THOMAS A. BLASINGAME TEXAS A & M UNIVERSITY 12. PPM PROJECT BUDGET AND EXPENSES The CCOP Technical Secretariat provided general administration and management of the PPM Project. During the first phase (July 2002 June 2004) a Norwegian petroleum expert from the Norwegian Petroleum Directorate (NPD) coordinated the Project in the CCOP Technical Secretariat in Bangkok and thereafter by a regional project coordinator. Each of the participating Member Countries appointed a national project coordinator. In accordance to the cooperation agreement between CCOP and NPD, the NPD have largely provided technical assistance and support to the Project. In addition, a group of experts was established, consisting of various relevant experts from Norway and from CCOP Member Countries, with a special responsibility of rendering technical assistance on the case studies. The total budget of the PPM Project amounts to NOK million or USD 2.8 Million (exchange rate 6.98). Although the approved budget of the Project is in Norwegian Kroner, this report will use the US Dollar currency and this is because the operating currency of CCOP TS is in USD and almost all of the expenses that were incurred in the Project were paid in USD. The bank account of the Project in Thailand is also in USD. 32 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

40 Of the total Project budget, only USD 2,062,742 was actually spent by the Project (as of 31 July 2006). The bulk of the savings were realized from the use of experts coming from the CCOP Member Countries as resource persons in many expert visits and workshops that were conducted to support the case studies and minimal use of the miscellaneous budget. The expenses for the services of the regional experts were in most cases, for the plane fare and daily subsistence allowance only. The salaries are paid by the experts employers, who are mostly participants and supporter of the PPM Project. Figure 1 shows the summary of the total budget and actual expenses of the PPM Project. In addition, the expenses summary distribution of the Project is shown in the Figure 2 below. Figure 1 ITEM Total Actual Expenses Budget % Workshops 547, , % Seminars 143, , % Expert Visits 196, , % Project Coordinator 603, , % NPD support 138, , % CCOP management fee 178, , % Hardware and Software 95, , % Others 157, , % Total 2,062, ,797, % Note: as of end July 2006 Figure 2- Actual Expenses distribution Hardware and Software 5% Others 8% CCOP management fee 9% Workshops 26% NPD support 7% Seminars 7% Project Coordination 27% Expert Visits 10% The other expenses include the miscellaneous, local operation of the Project Coordinator, review and meetings, and audit expenses. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 33

41 Figure 3 shows the planned versus the actual number and cost of activities (workshops, expert visits, and seminars) that were conducted in each case study. Figure 3 PLANNED ACTUAL COST PPM CASE STUDY ACTIVITIES NUMBER TOTAL COST NUMBER TOTAL COST +/(-) PHILIPPINES CASE STUDY EXPERT VISIT 3 68, ,890 16,878 WORKSHOP AND MC PARTICIPATION 5 171, ,518 32,401 CHINA CASE STUDY EXPERT VISIT 3 68, , WORKSHOP AND MC PARTICIPATION 5 111, ,772 (1,025) INDONESIA CASE STUDY EXPERT VISIT 3 68, ,257 27,511 WORKSHOP AND MC PARTICIPATION 5 171, ,828 49,092 CAM BODIA CASE STUDY EXPERT VISIT 5 68, ,961 33,807 WORKSHOP AND MC PARTICIPATION 5 171, ,611 (691) SEM INARS 5 229, ,787 85,439 TOTAL 39 1,131, , ,455 Notes: 1. Cost in USD. 2. Exchange rate used in the computation is NOK6.98:1USD. A As of end 2005, the exchange rate is 6.2 or stronger by ~10% Dissemination seminars were conducted in each of the 4 case studies 4. As of 31 July 2006 and not yet final. Still waiting for the final invoice from NPD. Figure 4 shows the summary of the costs workshops and seminars organized. The cost of the four dissemination seminars that were conducted in the countries hosting the case studies is included in the cost of the last workshops in each case study. Figure 4 - Actual cost of PPM Workshops and Seminars 34 Cost in USD 60,000 50,000 40,000 30,000 20,000 10,000 - CAW S1 CAWS2 CAW S3 CAWS4 CAWS5 CAW S6 PHWS1 PHWS2 PHWS3 PHWS4 PHWS5 CHWS1 CHWS2 CHWS3 CHWS4 INWS1 INWS2 INWS3 INWS4 SEM1 SEM2 SEM3 SEM4 SEM5 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

42 Figure 5 shows the cost of the various expert visits that were conducted in the 4 countries hosting the case studies. Substantial savings were realized with the use of regional experts as resource persons during expert visit activities and minimum use of the miscellaneous budget. Figure 5 - Actual Cost of PPM Expert Visits 20,000 18,000 16,000 14,000 4,000 2,000 - CAEX1 CAEX2 CAEX3 CAEX4 CAEX5 CAEX6 CAEX7 CAEX8 PHEX1 PHEX2 PHEX3 PHEX4 PHEX5 CHEX1 CHEX2 CHEX3 CHEX4 INEX1 INEX2 Notes: 1. CAWS Cambodia case study workshop; CAEX Cambodia expert visit 2. PHWS Philippines case study workshop; PHEX Philippines expert visit 3. CHWS China case study workshop; CHEX China expert visit 4. INWS Indonesia case study workshop; INEX Indonesia expert visit 5. SEM Seminar Cost in USD 12,000 10,000 8,000 6,000 The summary of the total expenses of the PPM Project is attached as Annex IMPACTS OF THE PROJECT The total number of participants in the PPM Project is 395 personnel from the CCOP Member Countries. If we multiply the number of participation of each participants to the activities conducted in the PPM Project, the product would represent the total number of participation that equals to 1,127. Of the total number of participants, more than 70% are geologists and petroleum engineers, the rest are economists, accountants, civil/mechanical/chemical/mining engineers, IT specialist, etc. About 25% are women and more than 20% of the participants have managerial status (ranging from Division Chiefs to Vice President). The chart below illustrates the total number of attendance in the PPM Project activities. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 35

43 Workshop/Seminar/Expert Visit Attendance 90 Attendance 1 or m ore 2 or more 3 or more 5 or more No. of Persons Cambodia China Indonesia Japan Korea Malaysia Papua New CCOP Member Countries Guinea Philippines Thailand Vietnam It is interesting to note that a number of participants have attended many of the supporting activities and followed closely the case studies of the PPM Project. From the report of the National Coordinators, listed below are some of the impacts of the PPM Project in the CCOP Member Countries: a) Improved understanding of the petroleum potential and policies of the CCOP Member Countries, especially the case study countries b) Information and Knowledge learned are disseminated through reporting and conduct of seminars in the participant s respective organization c) Adoption of some concepts learned in basin assessment and exploration investment promotions. This is evident in Cambodia, where the CNPA staffs now, and on their own, have better understanding on resource assessment and have performed realistic assessment of the Khmer basin. The team that participates in the PPM Project from Philippines and Thailand are also members of their investment promotions team and has actually applied the knowledge learned into their own investment promotion campaign d) The Project provided a good forum of building closer relationship and cooperation. The open sharing of experiences of expert in the region during expert visits and workshops are evidence of enhanced (internal) cooperation among Member Countries e) Indonesia supported the education and training of CNPA staff at their petroleum training center (PUSDIKLAT MIGAS) in Chepu f) The technical staff from PNG and Cambodia participated in the resource assessment works in the Philippines DOE as an on-the-job training 36 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

44 g) China supported the attendance of 4 participants from CCOP Member Countries by sponsoring the daily subsistence allowance during the China case study workshops (workshop 1-3). China also covered the cost of workshop materials, equipment rentals, expenses for the field trip, and transportation for airport-hotel-airport h) Experts are provided by Member Countries to address issues and challenges faced a case study country. The mother agency of the experts contributes to the travel expenses. In a way, promotes a Member Country helping another Member Country in CCOP i) PPM is easily implemented based on the already established network. This network also functions outside the project. The collaborative project initiated by KIGAM and LEMIGAS to enhance further the cooperation and knowledge on oil and gas research is open to participation to other members. KIGAM has also offered to cooperate in other petroleum geoscience project with the Member Countries j) Easier facilitation of new projects in the CCOP TS. The experience of the Technical Secretariat in the management and coordinating the PPM project has considerably helped in efficient facilitation of new projects in CCOP. HE Mr. Ho Vichit, Vice Chairman of CNPA, in his closing speech during the dissemination seminar of the Cambodia case study, summed up the achievement of the PPM Project as follows: I also highly appreciate the great achievements realized in the framework of the study as it is witnessed today by the presentations of the results of the study by the CNPA team. Through this study, our officials have gained valuable knowledge that will be very useful for the future development of our petroleum sector as well as for the development of our economy. Our officials have also been provided the unique opportunity to learn from the experiences of their friends from other countries. 14. EVALUATION: GENERAL SUMMARY What did the participants say of the PPM Project activities? Listed below is the general summary of the participants evaluation of workshops, expert visits, and seminars conducted in the PPM Project. (1) Was the Resource Person well prepared? With rating 1-5 and 5 as excellent, the highest score was 4 followed by 5 then 3. (2) Was the Resource Person knowledgeable? With rating 1-5 and 5 as excellent, the highest score was 5 followed by 4 then 3. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 37

45 (3) How were the workshop presentations? With rating of 1-5 and 5 as excellent, the highest score was 4 followed by 5 then 3. (4) Did the Resource Person/workshop help you with your needs/requirements? With rating of 1-5 and 5 as excellent, the highest score was 4 followed by 5 then 3. (5) Was there a good mixture of theory and practice? With rating of 1-5 and 5 as excellent, the highest score was 4 followed by 5 then 3. (6) Were the examples good? With rating of 1-5 and 5 as excellent, the highest score was 4 followed by 5 then 3. (7) Was the workshop relevant to your job? With rating 1-5 and 5 as excellent, the highest score was 5 followed by 4 then 3. (8) Overall workshop assessment. With rating 1-5 and 5 as excellent, the highest score was 5 followed by 4 then 3. (9) Did you enjoy the workshop? Yes (100%) (10) Did the workshop meet your expectations? If you missed something, please clarify. Yes (100%) I wanted to learn some technical knowledge, but the workshop is mainly about the policies and management Not missed something but the timing for discussions are short to make sure of clearing all items. Copies of presentations should be provided in advance to all participants Discussion forum should be conducted before and after the workshops. Networking with other participants from another countries is the best take away benefit of the workshop (11) How many people in your institution/company/organization will benefit from the workshop? (give an estimate) The estimates provided counts all the technical staff and management in the participant s respective organization. (12) What changes do you think could be made to improve the workshop? (quality of documentation / content / venue / facilities, etc. )? The Participants were satisfied with the arrangements of the workshop but some of them recommended the improvement of the quality of documentations and content of the presentations. The handout should be distributed before hand and more time for discussion and group work be given. More detailed presentations on the Case Study from the host team. Presentations should include lessons learned More time for fieldwork (13) Perspectives after the workshop. How would you put value to the knowledge learned? 38 Volume 1: Final Report of CCOP Petroleum Policy and Management Project

46 Apply it directly to my present job and share it to my coworkers. Share the knowledge learned to people related to the topic of the workshop Good knowledge should be put into real practice (14) Comments on the food, accommodation and the venue for the workshop? Most of participants were satisfied with the arrangements. 15. ACKNOWLEDGEMENTS The CCOP Technical Secretariat wishes to express our deepest appreciation to the Governments of Cambodia, The Philippines, China, and Indonesia for having kindly offered to host the PPM case studies. We also thank the scientists from the Member Countries that participated in the PPM project, led by the National Coordinators, for their enthusiasm, dedication and tremendous interest in the project that no doubt have led to the great success achieved. Likewise, a very big Thank You to the Royal Norwegian Government through the Ministry of Foreign Affairs for the generous financial support for the Project. Many Norwegian experts have generously shared their valuable expertise with us that have contributed to the enhancement of knowledge and capability of CCOP scientists. Volume 1: Final Report of CCOP Petroleum Policy and Management Project 39

47 Volume 2: Final Report of the Cambodia Case Study 1. Introduction Frontier Case Study 1: The Khmer Basin, Cambodia The study area is the Khmer Basin offshore Cambodia, proposed by the Cambodian National Petroleum Authority (CNPA). The area has been explored for 30 years. So far 11 exploration wells have been drilled and four gas discoveries have been made. Among these, the Kusrovie Natural Gas discovery is considered for development. No petroleum has been produced from this basin to date. The Khmer Basin is relatively small, situated adjacent to the petroliferous Pattani Basin and Malay Basin. The seismic coverage of the basin is approximately km 2-D and km 3-D. The Khmer Basin is thus described as a frontier to semi-mature basin. 2. Objective The objective of this study is to assist the Exploration & Production Division of the Cambodian National Petroleum Authority and the other participating nations in developing a resource overview of the resources in this semi-mature offshore basin and identifying the critical elements of a gas field development. The objective is further to consider appropriate petroleum policies for an optimal exploitation of the resources and value creation for the society of this, and other similar semi-mature areas. 3. Expected results The results of this project should include an improved understanding and ability of the Exploration & Production Division of the Cambodian National Petroleum Authority and the other participating nations to evaluate the potential of this and similar basins. The study will include a resource assessment of the Khmer Basin, an overview of the development options of the Kusrovie Natural gas discovery, and a discussion of petroleum policy measures to support further exploration and exploitation. 4. Data requirements and availability All necessary data (raw data, interpreted data, reports etc) shall be made available for the project by the host country. The project is only borrowing the data and the participants might, if required by the owners of the data, give a confidentiality undertaking. The data might be made anonymous when and if published in project reports. It is anticipated that the host country covers the cost for copying and making the data available for the study. The relevant data are regional geology, 2-D Seismic, well logs and a description of the framework conditions such as fiscal regime etc. It is estimated that it will take about 3 months to compile the data for the project database. 40 Volume 2: Final Report of the Cambodia Case Study

48 5. Resource assessment The resource assessment in this case study should be two-fold: It will consist of mapping and establishing the proven and potential resources in the Kusrovie Natural gas field, and it should also comprise a review of the discovered and undiscovered potential of the Khmer basin. The latter will involve defining petroleum systems and plays, identifying prospects, defining the procedure of geological risk analysis and the actual resource calculations of any prospects. 6. Development options This will include an assessment of development options for the Kusrovie Natural gas field, including pipeline and terminal facilities. In addition it will include a discussion of operational matters, safety aspects and environmental issues. 7. Marketing options The marketing options for gas in the Cambodian domestic market and possible export options should be analysed. The investment in infrastructure for natural gas supply requires an analysis of long-term demand for energy. This is important because the infrastructure requires large investments, with long technical and economic lifetimes. This long-term investment requirement implies that the analysis of such a project must be performed carefully. Net-back value of gas should be established for relevant market segments. In relation to the utilisation of gas, the connection to the National Power Plan and cooperation with the Electricity Authority of Cambodia (EAC) is important. 8. Economic analyses Economic analyses will be made in order to illustrate the economic return and risk for exploration and development decisions both for the international oil companies and for the government. The economic analysis will include a full-cycle economic analysis before tax of the profitability of the Kusrovie Natural gas project. The objective is to analyse whether the project has a positive effect on the Cambodian economy (positive NPV). Secondly the project will include a full-cycle economic analysis after tax of the profitability of the gas project. The purpose is to illustrate the economic return and risk for exploration and development decisions both for the international oil companies and for the national government. 9. Resource management strategies An exploration and development strategy of natural gas in the study area to achieve optimal recovery rates both for liquid and gas, and sufficient flexibility to cater for market development will be formulated. Possible scenarios of petroleum resource management related to changes of economic and market conditions will also be demonstrated. Volume 2: Final Report of the Cambodia Case Study 41

49 10. Licensing, contractual and fiscal conditions The main objective is to evaluate how the licensing, contractual and fiscal conditions (e.g. Production Sharing Agreements) influence profitability of fields and prospect and the incentives to efficient exploration and exploitation in a frontier - semi-mature basin. 11. Case study team The case study team will consist of people from the Exploration and Production Division of the Cambodian National Petroleum Authority (CNPA) and individuals appointed from the authorities of the other CCOP Member Countries that take part in the case study. A national project leader will be appointed from the CNPA. Technical personnel from the Member Countries will be given the opportunity to participate in the case study, both to gain experience and to contribute their expertise to the project. Below is the table of the List of Cambodian participants to the PPM Project. NAME POSITION / ADDRESS 1) DR. MEN DEN Deputy Permanent Representative of Cambodia to CCOP Director of Petroleum Exploration & Production Division of CNPA ppm_cambodia@online.com.kh, menden@online.com.kh Tel: (855-16) , Fax: (855-23) , (H) 2) MR. LIM VATHA Deputy Director of Upstream Division, CNPA ppm_cambodia@online.com.kh Tel: (855-11) , Fax: (855-23) ) MR. KAO THEARO Director of Downstream Division thearokao@yahoo.com Tel: (855-12) ) MR. KIMTY PHALLY Vice Chief of Downstream Division, CNPA kimtyphally11@hotmail.com Tel: (855-12) , Fax: (855-23) ) MR. CHAP SAMNANG Geologist, Upstream Division, CNPA ppm_cambodia@online.com.kh Tel: (85-12) , Fax: (855-23) ) MR. SE SIM Geologist, Upstream Division simfree2004@yahoo.com Tel: (855-12) ) MS. SEANG SINATH Geologist of Upstream Division, CNPA sinath_seang@yahoo.com Tel: (855-16) , Fax: (855-23) ) DR. LEANG CHHALY Staff of CNPA chhaly@online.com.kh Tel: (855-11) Volume 2: Final Report of the Cambodia Case Study

50 9) MR. CHIN SAROM Geologist, CNPA Tel: (855-12) , Fax: (855-23) ) MR. SUN KOURN Geologist, CNPA Tel: (855-12) , Fax: (855-23) ) MR. NOUCH VIREAK Petroleum Geologist, CNPA Tel: (855-16) , Fax: (855-23) ) MR. SOK SAMNITH Staff of CNPA Mobile: (855-16) Fax: (855-23) ) MR. SITH SONA Staff of CNPA Tel: (855-12) , (855-11) ) MR. VANG SIVUN Staff of CNPA Tel: (855-16) ) MR. CHHEANG DARITH Staff of CNPA Tel: (855-11) ) MR. TIM SOPHEA Staff of CNPA, Upstream Division #13-14, Russian Federation Blvd, Sangkat Kakab, Khan Dangkor, P.O. Box 1442, Phnom Penh, CAMBODIA Volume 2: Final Report of the Cambodia Case Study 43

51 Resource Assessment Results (Annex 51) Petroleum Resources Management Strategy Managing the petroleum resources on the offshore of Cambodia is an important task for the Cambodian National Petroleum Authority (CNPA), as the management of the business processes to recover resources is for the industry and the management of its financial needs for those funding them. One of the principal tasks of the CNPA is to maintain an overview of all the petroleum resources so that the organization can have the best possible basis for planning measures to ensure that they are well managed and to forecast future production and others activities. The CNPA shall manage petroleum resources based on strategies as following: RESOURCES CLASSIFICATION In order to manage in proper manner, the Cambodian National petroleum Authority shall estimate the petroleum resource in both offshore and onshore Cambodia and then the resources are needed to classify. Today, there are many resource classification systems used in the world. In this case, CCOP classification system can be applied. 44 Volume 2: Final Report of the Cambodia Case Study

52 I. The Discovered Resources a. Potential Resources: Potential Resources is defined as the discovered resources that are recoverable but not economically producible at a specific date due to economic, political, environmental or technological reasons. In order to separate between Potential Resources and Reserves, there should be less than 10% probability of the Potential recoverable resources to be commercially recovered if the probabilistic approach is used for definition of reserve categories. b. Reserves: Reserves are those quantities of petroleum, which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves. b.1 Proved reserves: Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves may be assigned on the basis of well logs and/or core analysis that indicate the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. b.1.1 Undeveloped reserves: Undeveloped reserves are expected to be recovered. b.1.2 Developed reserves: Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be sub-categorized as producing or nonproducing. b.2 Unproved reserves: Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves. b.2.1 Possible reserves: Possible reserves are those unproved reserves which analysis of geologic and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves. Volume 2: Final Report of the Cambodia Case Study 45

53 II. Undiscovered resources b.2.2 Probable reserves: Probable reserves are those unproved reserves which analysis of geologic and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. a. Speculative resources: Speculative Resources is referred to the unmapped prospects that have not yet been mapped in the basin. The unmapped resources are estimated by play assessment methods. The total resources of such plays comprise both discovered and undiscovered resources. The unmapped resources are the difference between the plays total resources and the discovered and mapped resources. b. Hypothetical resources: Hypothetical resources comprise resources which are mapped in the form of prospects, but which have not yet been discovered by drilling. It is uncertain if the estimated resources are actually in place. Prospects may be identified in un-drilled frontier provinces as well as in reservoirs underlying or adjacent to producing fields. The resource estimates are given a probability of discovery. LICENSING STRATEGY CNPA has put in place a policy framework for the Exploration & Production of petroleum which: - offers high levels of certainty to all stakeholders and existing investors, - implements the principles of ecologically sustainable development when production and related activities in the permitted area and encourages world best practice in environmental, health and safety, - provides a highly competitive operating environment, - promotes development and production of Cambodia's resources, - encourages more investments in Exploration, Development & Production of Oil & Gas inland & offshore, - allows industry to respond to international challenges and seize international trade and investment opportunities, - provides more opportunities to explore in Khmer basins, - covers Petroleum regulatory requirements on all stages of operations are transparent, and predictable in practice, - keeps them current and appropriate, by continuing review and improve of regulatory requirements, - competes profit-related tax system widely which recognizes the risks of exploration, - allows companies freedom for selling their products to any where they like at market. 46 Volume 2: Final Report of the Cambodia Case Study

54 EXPLORATION Shall explore potential resources for Cambodia that it could arrange the resource for developing and use. The exploitation of Cambodia s offshore petroleum resources makes a major contribution to the Cambodian s prosperity. To maintain and enhance the contribution of the offshore petroleum industry to rising Cambodian prosperity, the Cambodian Government encourages the development of a competitive, innovative and growing petroleum sector that can fully assess Cambodia's petroleum resources. The Cambodian Offshore Petroleum Strategy shall to provide a suitable framework for the efficient exploration of Cambodia s offshore during the next five to 10 years. The strategy will create more certainty in the area release process and give industry more leadtime in considering areas for future release. However, vast sedimentary of Khmer basin remain lightly explored, in the offshore areas where most of the undiscovered resources are thought to exist, and little discovered resources. The strategy shall maintain and build upon the successful elements of past policies. In particular, it updates the program for the regular release of exploration area, and provides for the improved availability of exploration data. DEVELOPMENT Shall enhance the certainty, clarity and predictability of access for oil and gas development through such initiatives as road, pipe line, refinery infrastructure development. While it is discovered petroleum resources in prospective basin, CNPA shall have to develop those potential resources to be produced oil and gas in Cambodia, especially in the Khmer Basin which is yet to be explored adequately, then CNPA shall propose company to drill more wells for developing area. Developing in the area will require standard cooperation among governments, environmentalists and the petroleum industry to a degree. PRODUCTION Based on several factors with growing of demand, the oil and gas industry has made significant investments in finding ways to utilize technology to continue to provide affordable and reliable resources while at the same time contributing to a cleaner environment. CNPA strategy shall seek oil and gas to support economic growth, oil and gas industry greatly reduces impacts on the environment by exploration and production, both onshore and offshore. CNPA shall assure that a fair and effective of CNPA strategy is developed that will prepare it for future growth, by producing the amount of demand. Volume 2: Final Report of the Cambodia Case Study 47

55 MARKETING Shall undertake policies and marketing activities to increase investment in oil and gas resource opportunities in offshore of Cambodia. CNPA is a Regulator, while company discovered potential resources that to be produced in the future, then company has to support DMO and the rest it will export to the countries in the region from wells, pipelines, and storage tank following by market differentiation strategies, market potential estimates, and marketing approaches. INFRASTRUCTURE As demand has risen, so has the efficiency and effectiveness of the oil and gas industry. Similar advances in refinery and pipeline systems contribute to more efficient processes and a cleaner environment. At the same time, these technologies allow development with much less disturbance to the environment. Moreover, complex, time-consuming permitting requirements impede the ability of refiners to expand or retrofit facilities in order to increase capacity. Further, regulations complicate the building of new pipelines to efficiently deliver energy to needed areas. The implementation of the CNPA shall plan including the development and production opportunities to supply domestic. Mid-term to longer-term actions include expanding and supplying petroleum resources exports by increasing production capacity, facilitating pipeline investment, products and services to the market. MODERNIZED REGULATIONS Shall review legislation, regulations, policies and programs, and develop a streamlined results based regulatory framework that considers best practices and/or harmonization with other jurisdictions. In order for Cambodian to continue to benefit from the innovations made possible by the oil and gas industry, significant changes need to be made to existing regulations. A refinery has not been built in Cambodia. Refinery capacity is stretched to the limit, but increased regulation of fuels and refineries limit opportunities for growth. A complex regulatory process also complicates the building of new pipelines to efficiently deliver our energy to needed areas. To comply with changing regulations, the oil and gas industry has invested significant resources in updating operational procedures and applying new technology. When regulations are not coordinated, industry is forced to make costly operational changes that negatively affect their ability to efficiently and effectively meet the Cambodian's energy needs. It is therefore CNPA's regulations provide the industry with the flexibility to allow for technological advances that continue to provide an adequate and affordable energy supply. Without a coordinated and realistic approach to CNPA regulations, the oil and gas industry will be unable to increase domestic capacity in a way that ensures a long-term, reliable and affordable supply that supports and contributes to our way of life. 48 Volume 2: Final Report of the Cambodia Case Study

56 ENVIRONMENTAL MANAGEMENT Today s petroleum activities maintain a generally high level of health, environment and safety. However, these activities have the potential for major accidents which can entail the risk of personal injuries as well as occupational illness and pollution of the environment. The attitudes of management in safety matters are crucial in making safety management a success: it must be a top-down approach. The management s ability to motivate the entire company staff is likewise a key to this success. Safety Management including the following elements: - Setting safety objectives and risk acceptance criteria - Organization the safety responsibilities and work - Motivating people for safety - Identifying the hazards which must be addressed - Assessing the risks associated with these hazards - Implementing and follow-up the results of risk assessment - Monitoring and auditing the safety performance - Planning for the potential emergencies. To protect the environment, businesses and the government are required to determine the impact of their actions on the environment. Potential impacts are identified during environmental impact studies, and are discussed in environmental impact statements. These statements discuss potential impacts to the environment from proposed plans and suggest actions that can be taken to minimize those potential impacts. They have been effective in ensuring environmental protection during development of the Cambodia's resources and infrastructure. LICENSING, CONTRACTUAL AND FISCAL CONDITIONS I - Licensing Condition The Petroleum Regulation in 1991 relating to petroleum activities provides the legal basis for the licensing condition. This regulation authorizes the granting of permits and licenses to explore for and produce petroleum. The Cambodian National Petroleum Authority (CNPA) is responsible for licensing policy on both onshore and offshore Cambodia. A production license gives the licensees an exclusive right to explore for and produce petroleum within a specific area. The CNPA appoints or approves an operator for the area concerned, determines work obligation and decides the duration of the initial period of the license. Invitation for Bid In a case where the Cambodian Government desires to conduct Petroleum Operations by employing a Contractor, the CNPA will issue an invitation for bid and publish notice thereof, in national and international newspaper describing a time limit of at least sixty (60) days for the submission of bids. Volume 2: Final Report of the Cambodia Case Study 49

57 Particulars to be Mentioned in Invitation for Bid The following details shall be mentioned in invitations for bid: (a) The Exploration Blocks open for Petroleum Operations (b) Basic information about the Exploration Blocks (c) Bidding fee (d) Other necessary particulars Particulars to be Mentioned in Bid A company desirous of undertaking Petroleum Operations shall submit a sealed bid to the CNPA in the form prescribed in Schedule 1 with the following details within the time-limit prescribed in the notice published under Article 3. (a) Evidence showing that the bidder is a company. (b) Name and address of the authorized to act on behalf of the bidder. (c) Evidence showing that the bidders commands capital, machinery, equipment, tools and specialists required for undertaking Petroleum Operations. (d) Methods and time schedule of Exploration Operations. (e) Minimum work program and budget for the exploration Period (including two extensions). (f) In the event that the bidder is to be a joint venture of two or more persons, particulars pertaining to their relationship, responsibilities and percentage interests. (g) Annual Work Program and Budget for the first Contract Year. Evaluation of Bids Upon receipt of bids the CNPA shall evaluate them according to the following criteria: (a) Financial competence of the bidder. (b) Technical competence and professional experience of the bidder. (c) Experience of the bidder in marketing of Petroleum. (d) Proposed minimum work and expenditure obligations during the Exploration Period. (e) Proposed allocation of Net Petroleum. (f) Proposed educational and training facilities. (g) Other facilities and benefits proposed. (h) Any other relevant particulars. In the course of evaluation of bids, the CNPA may ask for additional details or clarification on any matters from any bidder. Negotiations After evaluation of bids, the CNPA may undertake negotiations with any qualified bidders. Approval of Bids On the basis of its evaluation of bids and negotiations with bidders, the CNPA will forward the bids with its recommendation to the Cambodian Government for approval and the Cambodian Government shall decide whether or not to sign any Petroleum Agreement. 50 Volume 2: Final Report of the Cambodia Case Study

58 Notice for Signature of the Petroleum Agreement The CNPA shall inform any bidder approved by the Cambodian Government pursuant to Article 7, and notify it of the date, time and place for signing the Petroleum Agreement. In case a successful bidder without proper reason fails to appear for signing the Petroleum Agreement at the time mentioned in the notice sent under sub-article 8.1, the Cambodian Government may make alternative arrangements. Petroleum Agreement - Normally, no bidder shall be granted more than two Exploration Blocks for Petroleum Operations. - A separate Petroleum Agreement shall be signed for each Exploration Block. - A Petroleum Agreement shall be signed in substantially the form prescribed in Schedule 2 with such additions or deletions as may be approved by the Cambodian Government. - The CNPA shall sign Petroleum Agreement on behalf of the Cambodian Government. Direct Negotiation The above mentioned statement is in the Petroleum Regulation of year In another case the bidders may be granted the exploration blocks by direct negotiation with CNPA. II - Contractual Condition No bidder shall be granted more than two exploration blocks for petroleum operations, with total acreage of not exceeding sq.km., but in case for the study of comprehensive reviews and appraisal of the data, which may be considered as non commercial activities, the bidder may be granted several petroleum exploration blocks as mutually agreed. Exploration Period The maximum initial duration of an Exploration Period shall be four (4) Contract Years starting on the Effective Date. The duration of an Exploration Period may be extended twice for periods of up to two (2) Contract Years each. The CNPA may further extend the duration of the Exploration Period for such time as may be reasonably necessary to complete drilling, logging, testing or plugging of any well which is actually being drilled, logged, tested or plugged at the end of an Exploration Period, or to complete any appraisal work, the evaluation of any discoveries the preparation and, submission of detailed development Work Program and Budgets and/or an application for a Production Permit, or to secure an export market( including necessary arrangements and infrastructure) for Petroleum from a Field which has been discovered in a Contract Area. Volume 2: Final Report of the Cambodia Case Study 51

59 Relinquishment of Areas Contractor shall relinquish areas as follows: (a) At least thirty (30) per cent of the original Contract Area, excluding any area falling under a Production Area, by the end of the initial Exploration Period. (b) Twenty five (25) per cent of the original Contractor Area, excluding any area falling under a Production Area, by the end of first extension of the Exploration Period. (c) Subject to sub-article 15.2 of Article 15, all remaining areas of the original Contractor Area, excluding areas falling under a Production Area, by the end of the Exploration Period Explanation: For the purpose of sub-article 16.1, Production Area includes any area over which a request for a Production Permit is under consideration. Notwithstanding anything contained in sub-article 16.1, each area which is relinquished from time to time shall be not less than ten (10) per cent of the original Contract Area and shall be composed of contiguous blocks. The Cambodian Government shall have the right as agreed in the Petroleum Agreement to order a Contractor to relinquish additional areas containing a Field if after the completion of appraisal Work in such areas Contractor does not apply for a Production Permit, in which case Contractor shall relinquish such areas as provided in the Petroleum Agreement. During the Exploration Period, Contractor may at any time relinquish any portion of the Contract Area and all such voluntary relinquishments shall be credited towards the mandatory relinquishments specified in sub-article Work obligations During the initial Exploration Period, Contractor shall complete the following minimum work obligations: acquire and process 2D or 3D seismic data available from previous exploration. Drill two (2) exploratory wells or more, to an estimated depth or economic basement, whichever is reached first. If Contractor believes it to be technically and economically justified after a complete analysis of the previous exploration program, Contractor may drill at it sole option, one (1) more exploratory well(s) which depth shall be mutually agreed and fixed between the Committee and Contractor. During the first extension to the Exploration Period, Contractor shall complete the following minimum work obligations: acquire or reprocess of 2-D or 3-D seismic data, Drill one (1) exploratory well or more to an estimated depth or economic basement, whichever is reached first. If Contractor believes it to be technically and economically justified after a complete analysis of the previous exploration program, Contractor may drill at it sole option, ONE (1) more exploratory well(s) which depth shall be mutually agreed and fixed between the Committee and Contractor. During the second extension to the Exploration Period, Contractor shall complete the following minimum work obligations: drill 1 (one) exploratory well to an estimated depth or economic basement, whichever is reached first. 52 Volume 2: Final Report of the Cambodia Case Study

60 Subject to the approval of the CNPA, Contractor may conduct Exploration Operations other than the works mentioned in sub-article 10.1, 10.2 and 10.3 above which the Contractor considers necessary for exploration of the Contract Area. Appraisal and Development Contractor shall notify the CNPA immediately when Exploration Operations indicate a Discovery in commercial quantities within the Contract Area. This notice shall include all available details of the Discovery. After the date of the CNPA's concurrence in Contractor's notice of a commercial Discovery, Contractor shall submit for approval by the CNPA a detailed appraisal Work Program and Budget to evaluate the commercial development of the Field to which the Discovery relates. The appraisal Work Program, which may be supplemented by further appraisal Work Programs, shall include the drilling and testing of one or more wells and, if appropriate, studies related to recovery, treatment, transport, storage and marketing of Petroleum. The duration of such Work Program shall be for such periods as are reasonable to accomplish the appraisal work, and may be extended for justifiable reasons with the approval of an application submitted to the CNPA. Production Permit and Development Work Program If Contractor considers that the field may be commercially developed, Contractor shall, within a reasonable period, submit an application for a Production Permit to the CNPA which shall include a detailed development Work Program and Budget for the construction, establishment and operation of all facilities and services related to the recovery, treatment, transport and storage of Petroleum from the Field. The Chairman of CNPA shall issue the Production Permit on such conditions as are considered necessary under the Petroleum Regulations and good oil field practice. Relinquishment after Appraisal Period If within ninety (90) days after completion of appraisal work for a Field, Contractor decides not to apply for a Production Permit for that Field and has not relinquished the area covered by the Field, the CNP A may require Contractor to relinquish said area, unless Contractor's reason for not applying for a Production Permit is due to: the need to combine development of another field to make the subject Field commercial, or Contractor's difficulty in securing an export market for Petroleum from a Field which has been discovered in the Contract Area. Production Period The duration of the Production Period shall expire thirty (30) years after the Effective Date. If commercial production from the Field remains possible at the expiration of such Production Period, the CNP A may extend the Production Period for the period of projected commercial production under terms and conditions to be agreed by the CNPA and Contractor, but not for more than five (5) years for Crude Oil and 10 years for National Gas, provided Contractor requests an extension at least ninety (90) days prior to the expiration of such Production Period. Volume 2: Final Report of the Cambodia Case Study 53

61 After Contractor's development Work Program and Budget have been approved by the CNPA, the CNPA shall issue to Contractor within shortest possible period a Production Permit which shall describe the Production Area. The Production Area shall be a square or a rectangular having geographical coordinates, and shall enclose the area of the Field, plus a buffer zone within the Contract Area not exceeding the area the Field. If Contractor discovers more than one commercial Field within the Contract Area, a separate Production Permit shall be issued for each Field. III - Fiscal Condition Tax rule for upstream activities are based on the ordinary Cambodian Tax Law and tax system as described in the Petroleum Regulation. There are bonus for Production Sharing Contract, the first time Contractor proceeds to a declaration of Commerciality and the first time the average daily production from the Contract Area. In the conduct of Petroleum Operation, a Contractor shall be exempt from payment of all taxes, charges, duties and fees leviable under prevailing law except: Royalty A royalty of at least per cent as prescribed on the value of Petroleum sold or disposed of. Such royalty shall be paid either wholly or partly in Crude Oil or in cash or both may be fixed by the Cambodian Government. Cost Recovery The Balance of Petroleum produced within a Contract area remaining, after retention of Royalty by the Cambodian Government, and payment of Petroleum Costs to Contractor, shall be allocated to the Cambodian Government and to Contractor in accordance with the provisions of the petroleum agreement. At any time, the Contractor considers that Petroleum Costs were incurred before the Commercial Production Day are unlikely to be recovered within five (5) years following the Commercial Production Day; and/or Petroleum Costs that were incurred after the Commercial Production Day are unlikely to be recovered within five (5) years following the date those Costs were incurred; then Contractor's share of Crude Oil available for Petroleum Cost shall be increase to a level so as to ensure the recovery of those Petroleum Cost within the said, appropriate, period of five (5) years. Income Tax Income tax at a rate of per cent of net Income derived from Petroleum Operation. The Cambodian National Petroleum Authority and Contractor may mutually agree and clearly mention in the Petroleum Agreement the agreed rate of Income Tax on behalf of other party. Area Fee The fee for Contract Area other than area under Production Area during initial Exploration Period is ten (10) United States Dollars per square kilometer. The fee for Contract Area other than area under Production Area during the first extension of Exploration Period is twenty (20) United States Dollars per square kilometer. 54 Volume 2: Final Report of the Cambodia Case Study

62 The fee for Contract Area other than area under Production Area during the additional extension of Exploration Period is forty (40) United States Dollars per square kilometer. The fee for Contract Area within a Production Area is five hundreds (500) United States Dollars per square kilometer. Income Tax Income tax at a rate of per cent of net Income derived from Petroleum Operation. The Cambodian National Petroleum Authority and Contractor may mutually agree and clearly mention in the Petroleum Agreement the agreed rate of Income Tax on behalf of other party. Profit Split After the Royalty is pad in cash or in-kind and allocations are made for Petroleum costs, the remaining quantities shall be allocated according to the following schedule according each tier of production. All daily averages shall be derived from total monthly production. Crude Oil Production Percentage (%) (bopd) Government Contractor Up to 10, ,001-25, ,001-50, ,001-75, , , Over 100, Natural Gas Production Percentage (%) (MMm 3 /day) Government Contractor Up to Over Government Participation The Cambodian Government shall have the right to participate in the Petroleum Operations under Petroleum Agreements. The maximum is 10 per cent. Volume 2: Final Report of the Cambodia Case Study 55

63 RECOMMENDATIONS TO MANAGEMENT The Cambodian National Petroleum Authority was established in Related to petroleum industry Cambodia is in the first stage of petroleum activity - exploration. Therefore, CNPA requested to PETRAD to conduct training needs and assessment for its staff. A team from The Bridge Group, Alfred Kjemperud and Svein E. Johansen (the TNA team) were assigned the task in the period of September, There were good recommendations, which should be included in this part of the report. Our recommendations are outlined as following: 1- Develop the organizational structure The organizational chart of CNPA is not clearly defined. Below is an organization chart being presently implemented. Upstream and downstream activities (and mid-stream which is also being defined as a CNPA responsibility) require different approaches and different skills, so this must be considered in the process. In the stage, which Cambodia is in, the priority should be on making the organization able to efficiently handle the upstream activities. CNPA has both an Upstream Department and a Downstream Department. However, upstream activities encompass much more than what is presently covered by the Upstream Department. Elements like promotion, negotiation, licensing, etc. are also integral parts of upstream activities. For downstream activities, the situation is similar. We would strongly advise the management to revise the organization structure of CNPA as soon as possible. 56 Volume 2: Final Report of the Cambodia Case Study

64 2- The legal framework Cambodian National Petroleum Authority was established in 1998, with the important role and responsibility to manage and develop both upstream and downstream activities within the petroleum sector. However regulations for this activity are not in place, and most of the responsibilities regarding downstream presently rest with other governmental bodies. The Petroleum Regulations (1991) with later amendments form the legal foundation for petroleum activities in Cambodia. They concentrate on Upstream activities (Exploration for and production of oil and gas). In Cambodia the situation and the needs for upstream and downstream should be addressed separately. However, in both cases it is important that any process of understanding, reviewing and updating laws and regulations related to the petroleum activities is conducted and controlled by CNPA. If CNPA shall be fully able to control this process, the process of organization development should first be well advanced, and relevant training and workshops for selected CNPA personnel conducted. We would like to recommend developing petroleum law and revised the previous regulation as soon as possible for our society and poverty reduction. 3- Resource classification and assessment To keep an account of the quantity of petroleum on both the continental shelf and on land it is essential to have a good system of classifying it. Simple, good definitions of various types of petroleum are important, and the resources must be capable of being grouped in relation to their degree of maturity as regards investigation, planning and recovery. Many different systems are in use today, which reflect different traditions. On the contrary, CNPA have not been employed any system officially. We therefore would recommend to top management to consider on CCOP resource classifications. The account covers all the areas in offshore where Petroleum Policy and Management (PPM) team has evaluated the resource basis (see the results of resource assessment) using old data of the previous petroleum activities (1990's) except the overlapping claim area between Cambodia and Thailand. Although, we got this result, no one knows exactly how much oil and gas can be produced from the offshore and onshore Cambodia. The estimation of how much can be profitably produced is partly based on assumptions regarding the geology, aspects of reservoir technology, future production and costs, and developments in technology and know-how. We also would like to recommend to management to form a resource assessment team recalculating the resource by adding more data from Chevron. Volume 2: Final Report of the Cambodia Case Study 57

65 4- Task specification for CNPA staff The technical staff CNPA with the totally thirty six (36) people moved from the Ministry of Industry, Mines and Energy since the establishment of CNPA. Most of them are geologists and worked for the petroleum sector. The petroleum sector comprised of five offices: 1) drilling, reservoir engineering, geological, geophysical and mapping. Moving to CNPA they worked for different divisions. Some technical staff works for Upstream, some for Downstream, for Legal and Negotiation, and for Administration Divisions. Although they work in different divisions they are still sometimes trained as technical staff. In this circumstance the staff are not sure what they should do and going to do. It will therefore be important to clarify and create understanding for the mandate and tasks of the various departments in order for them to be able to develop professionally and make meaningful contributions to the Cambodian society. This is also important in order to motivate the staff, and to meaningfully develop their skills. We would recommend that top management gives the works or nominates to attend any workshops/training should assign the persons who have a skill and responsibility related to the topics. 5- CNPA s tasks and sharing of responsibilities with other government bodies The Cambodian national petroleum Authority holds the overall responsibility for facilitating petroleum operations, both upstream and downstream, policy-making, planning and drafting legislation in relation to petroleum management and development in the country. In addition, the other ministries should support and participate actively in the petroleum sector. For example, Ministry of Labor and Social Affairs holds the overall responsibility for the working environment and for safety and contingency measures in relation to the petroleum section. Ministry of Finance has the overall responsibility for ensuring that the state collects taxes, fees and other revenue from the petroleum sector. The Ministry of Agriculture, Forestry and Fisheries is responsible for maintaining adequate contingency measures against acute pollution in the Cambodian waters. Ministry of Environment holds the overall responsibility for management of the Cambodian environment. Another important issue is coordination with agencies, which hold the responsibility for energy sector. For example, Ministry of Industry, Mines and Energy, and Electrical Authority of Cambodia. 6- CNPA staff in general needs training and experience Learnt from Norwegian experiences, Norway started exploration in the mid 1960s and oil production in the early 1970s. At that time Norway could incorporate the knowledge and experience gained over more than a decade of operations. But today it has changed a lot. Based on their knowledge and experiences in petroleum industry Norway is the one of the biggest country in the world. In case of Cambodia, the human resource was destroyed during the Pol Pot regime (period of ). In 1987 the Petroleum Section had formed again under the Department of Geology and Mines (Ministry of Industry, Mines and Energy). The exploration started within short period and stopped, and then started again. We therefore would like to recommend to conduct specific training for CNPA staff and send the staff to work with oil companies. 58 Volume 2: Final Report of the Cambodia Case Study

66 7- Satisfactory competence and experience for the negotiations Negotiations are presently taking place with oil companies for PSCs (Production Sharing Contracts) within the offshore area of Cambodian territory. In order to optimize Cambodia s position in these negotiations, it is important to understand the economic consequences of negotiated terms, and the implications for future exploration and production. It is also necessary to understand the negotiating position and strategy of the oil companies. CNPA has the software tools necessary for assessing the economic consequences of negotiated terms (GeoX), but needs expert advice in the use of this. They also need advice from experts with international experience in order to ensure the best results for Cambodia. Due to the urgency of these negotiations, we recommend that CNPA should aggressively seek to secure the required assistance, possibly with external finance. The negotiations with Thailand for the OCA (Overlapping Claims Area) have similar requirements as the PSC negotiations. The OCA negotiation is much more task than offshore Cambodia. It may relate to boundary problem, which needed assistance from other governmental agencies. These are also urgent, although not with the same immediate urgency. We therefore advice that CNPA also seeks to secure assistance for this, with external finance. 8- Continue cooperating with CCOP Member Countries through CCOP Among the CCOP Member Countries Cambodia is just at the first phase of petroleum activity. No fields in both offshore and onshore areas have been confirmed to exploit. In this regard, the knowledge and experiences of CNPA staff still have also the started level. We therefore need advices from them and the easier way to contact with them only through CCOP. Volume 2: Final Report of the Cambodia Case Study 59

67 Volume 2: Final Report of the Philippines Case Study 1. Introduction Frontier Case Study 2: The Sulu Sea Basins (East Palawan and Sulu Sea Basins), the Philippines The Sulu Sea Basins were nominated by the Philippines, through the Department of Energy (DOE), for Petroleum Policy and Management Project (PPM) case study under the Frontier Basin category. The East Palawan Basin and Sulu Sea Basin are located at the southwest portion of the Philippines and are oriented northeast to southwest covering roughly more than 200,000 square kilometers. East Palawan basin is fully offshore while the Sulu Sea basin is contiguous with the Northeast Sabah Basin of Malaysia. The international boundary between the Philippines and West Malaysia passes through the area. The East Palawan basin is subdivided into the Balabac and Bancauan sub-basins and has an area of 92,000 square kilometers with maximum sedimentary fill of more than 3.5 kilometers. The Sulu Sea basin or Sandakan sub-basin has an area of around 115,000 square kilometres and maximum sedimentary fill exceeding 6 kilometers. The basins are within the 200 m bathymetric contour and deepen toward the northeast where the present shelf within the Philippine waters is much reduced in width, and the water depth increases to more than 4000 m. Figure 1. Map of Sulu Sea Region EAST PALAWAN BASIN SULU SEA BASIN 2. Objectives The main objectives of this case study are to address the geological uncertainties of the nominated frontier area, to evaluate the appropriate incentives to attract petroleum companies to explore in such an area and an evaluation of the potential impacts on the Philippine society, both locally and as a nation. 3. Expected results The results of this project should include an improved understanding and ability of the DOE and the other participating nations to evaluate the potential of this and similar basins. It should include a resource assessment of the Sulu Sea Basin, a view of possible development options, and a discussion of petroleum policy measures. 60 Volume 2: Final Report of the Philippines Case Study

68 4. Resource assessment The resource assessment consisted of reviewing of the undiscovered potential of the Sulu Sea Basins. It involved the defining of petroleum systems and plays, identifying prospects, the procedure on geological risk analysis and the actual resource calculations of prospects and leads. 5. Development options Various potential development options for possible resource scenarios have been discussed as part of the project. Possible added value from economies of scale for the area has been identified as well as the potential increased in recovery due to resource management actions based on coordinated development. 6. Marketing options The project included an analysis of the various options for marketing different hydrocarbon types, pending the results of the resource assessment and development options analysis. The marketing options for gas in the Philippine domestic market and possible export options have to be analyzed. The investment in infrastructure for natural gas supply requires an analysis of long-term demand for energy. This is important because the construction of an infrastructure requires large investments, with long technical and economic lifetimes. 7. Economic analyses Economic analyses will be made in order to illustrate the economic return and risk for exploration and development decisions both for the international oil companies and for the national government. 8. Resource management strategies Exploration and development strategy for the study area to achieve high recovery rates both for liquid and gas, and sufficient flexibility to cater for market development. Possible scenarios of petroleum resource management related to changes in economic and market conditions. 9. Licensing, contractual and fiscal conditions The main part is to evaluate how the licensing, contractual and fiscal conditions influence profitability of fields and prospect and the incentives to efficient exploration in a frontier basin. 10. Case study team The project case study team is from the Petroleum Resources Development Division (PRDD) of the Philippine Department of Energy (DOE). The project has 2 National Coordinators and team members from the PRDD. The project team members represent the various skills required to carry out the different aspects of the case study. Volume 2: Final Report of the Philippines Case Study 61

69 National Coordinators: Mr. Guillermo. H. Ansay Mr. Redentor D. Pascual Team Members: Ms. Arlene Y. A. Magbanua Ms. Ma. Coco V. Sta. Ana Mr. Ed B. Guazon Mr. Rolando Z. Morales Mr. Jed B. Aragones Mr. Andres O. Pangilinan Mr. Neil O. Pesa Ms. Isabel A. B. Nicolas Previous National Coordinators: Mr. Simplicio P. Caluyong (Moved to CCOP) Ms. Editha S. S. Abangan (Retired) Previous Team Members: Mr. Gener P. Revilla (Moved to PNOC) Mr. Jaime A. Bacud (Moved to PNOC) Mr. Jason J. P. Villegas (Moved to Planning) Mr. Winifredo S. Malabanan (Moved to Renewable) National Project Coordination Committee: Mr. Ramon A. V. Oca Mr. Ismael U. Ocampo Some representatives from the Philippine National Oil Company (PNOC) have also attended the workshops conducted for the Philippine case study. 62 Volume 2: Final Report of the Philippines Case Study

70 1. RESULTS OF RESOURCE ASSESSMENT 1.a Area and Exploitation History Exploration in the Philippines portion of the SW Sulu Sea region started in 1965 with a seismic survey conducted by the Visayan Exploration Co. From 1965 to the present, over 50,000 km 2D and sq. km. 3D seismic lines were recorded. The last of these seismic data consisting of 5912 kilometers of 2D data were acquired by Western Geco in The only 3D data located inside the rectangle was acquired by Unocal in the Sandakan block. It covers an area of about 1,800 sq. km. 100 km South China Sea Palawan WesternGeco Sulu Sea Most of these lines are confined within the 200-m bathymetric line. Figure 2. Seismic Map A total of 20 wells were drilled in the area from 1972 to 2004 to test sandstone objectives of Miocene age. Seven of these are in East Palawan basin and thirteen are in the Sulu Sea basin. Six of these wells encountered only minor oil and gas shows. The latest of these wells were the Zebra-1 and Rhino-1, drilled by UNOCAL under Service Contract 41. Discoveries have been reported in the Malaysian side of this basin where gas, oil and condensate have been recovered from Lower to Upper Miocene sandstones. Table 1. Wells Drilled BORNEO Sulu Sea A-1 (1972) Sulu Sea B-1 (1973) Sulu Sea (1973) Sulu Sea (1974) Sulu Sea (1975) Coral-1 (1975) Roxas -I (1979) Dumaran-1 (1979) Paly-1 (1981) Clotilde-1 (1982) SBR-1 (1987) SBR-1 ST (1987) SBR-1A (1987) Dockan-1 (1989) Hippo-1 (1998) Wildebeest-1 (2000) Zebra-1 (2004) Rhino-1 (2004) DEPTH (Km) Table 1 shows in chronological order the wells drilled on the Sulu Sea Region. The deepest well is the Sulu Sea 409 that was drilled to a depth of more than 15,000 feet in This is one of just two or three wells that actually reached the Middle Miocene interval. The Volume 2: Final Report of the Philippines Case Study 63

71 rest were only drilled down to the Upper Miocene, including the recent Hippo and Wildebeest wells. Four of the wells had gas or oil and gas shows while the rest were dry. Many of the wells that are considered dry appear to have been drilled either off structure or are breached by faults (Sulu Sea A-1 - off structure, uncertain closure). The Sulu Sea stratigraphy (Figure 3) can be divided into four major sequences. The oldest sequence A represents Middle Eocene to Late Oligocene clastics and thick lenses of biohermal limestone of slope to deepwater environment. This is followed by sequence B consisting of Early to Middle Miocene clastics of slope and deepwater environment. Overlying B is sequence C of Middle Miocene to Early Pliocene age that consists of fluviodeltaic clastic materials with carbonate facies. The youngest sequence D is a platform carbonate sequence with clastic interbeds. D C B A Figure 3. Sulu Sea Stratigraphy Source Rocks 1.b Petroleum System Hydrocarbon generation had been confirmed by the recovery or indications of petroleum from the wells drilled in the basin. But so far, no commercial production has been 64 Volume 2: Final Report of the Philippines Case Study

72 made. As mentioned by Graves (1997), the real challenge in this basin is the establishment of the volume, quality and distribution of the source rock. From the data available, potential source rocks are present from the Middle Miocene to Late Miocene interval. The Middle Miocene source rocks are believed to have originated from higher plant materials and have average to above average total organic content (TOC). These were encountered by several wells including Coral-1 where samples registered 0.7-2% TOC. Graves also mentioned in his 1997 paper the presence of Early to Middle Miocene source interval that contains marine biomarker with mixed oil and gas potential. These source rocks are believed to be limited in distribution on the distal parts of the delta system. So far, it is only the Wildebeestt-1 well that is drilled in this part of the delta. It reached only the Late Miocene level and the sampled fluids indicate derivation from higher plant materials. Reservoir Rocks Reservoir rocks occur as stacked, good quality, relatively thick (7-25 m), distributary channel sands and delta front/channel mouth bar (Graves). These clastics were encountered by wells from Early Miocene to Late Miocene intervals with porosity range of 10-35%. Sulu Sea A-1 side wall core have porosities of 16-32% but permeabilities of only 35 md. In East Palawan, potential Middle Miocene clastic reservoir rocks have also been encountered with porosities in the range of 22-30%. Seals There is no regional seal identified in the basin. Intraformational claystones and siltstones of Early to Late Miocene age are believed to act as seals in the area. Play Types In the PhilPRA project, we have defined our plays based on the first order closure forming process (Duff and Hall 1996). The play is defined as follows: One or more closures of similar structural, depositional or hydrodynamic style, which result from a specific set of tectonic, depositional/diagenetic or halokinetic processes within a sedimentary basin, and which with suitable reservoir and sealing lithologies, and hydrocarbon charge, may form prospective hydrocarbon traps. This definition emphasizes the closure as the key element of a play, and the major geological processes defining the play. In the Sulu Sea basin, the identified plays include reef build up (RB), anticline (AN) and fault blocks (FB). The AN and FB plays are considered confirmed plays based on the Nymphe Northe-1 and Nymphe-1 discoveries made on the Malaysian side. In East Palawan basin, the identified plays are reef build up (RB), anticline (AN), and stratigraphic traps (ST) but these plays are yet to be confirmed. Volume 2: Final Report of the Philippines Case Study 65

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76 2. RESULTS OF ECONOMIC ANALYSIS An economic analysis has been undertaken for the mapped leads and prospects in the Sulu Sea basin. The two oil prone prospects that were considered for economic evaluation with their respective estimated reserves are shown in the Table 5 below. Table 5. Estimated Resource of Two Prospects for Evaluation Prospect Name Prospect A Prospect B Oil Originally in Place 532 MMBO 1669 MMBO Recoverable Oil 159 MMBO 499 MMBO Probability of Discovery 14% 18% 2.a Production Profile In the design/creation of production profile of a prospect, several factors have been considered, among these are: 1. Number of wells the number of producing wells should be in accordance with the size of the field and also, the position shall be on the optimum percentage of production and recovery. 2. Plateau Production Rate depending on the petrophysical properties of the reservoir and the completion method of the well, the production rate of a well would determine how long the field or the reservoir could be depleted. The rate should not be too high so that gas coning or water inclusion would occur prematurely. 3. Production Period determining how long the field should be produce is important in the economic evaluation and reservoir management of the field for this will be one of the bases in the calculation of the operating expenses that shall be incurred. 4. Cut-off Rate this is the production rate used to determine if producing the field is still economically viable and the cash flow is still positive. 5. Lead Time - the development period (from the time of the exploration to production) gives considerable increase in worth not only to the Net Present Value (NPV) and Expected Monetary Value (EMV) but also to the Total Government Take (TGT) of a project. 6. Plateau Factor during the initial and before the peak of production is attained, the assumed total oil produced should range from 10% to 15% of the total recoverable reserves. 7. Remaining oil at start decline at the start of the decline or when the peak of production was achieved, the total produced oil should be at least 50% of the total recoverable reserve of the field. 8. Decline Rate during the decline of production, a rate of at least 15% of the remaining reserves should be attained per year. The same factors are considered in case of gas production except for the plateau production rate or flow rate, which is dependent on the demand for the natural gas from the end-users. Volume 2: Final Report of the Philippines Case Study 69

77 The production profiles for the prospects evaluated are shown in Figure 4. The assumptions used are shown in Tables 5 and 6. Figure 4. Production Schedule for the 2 Prospects Oil Production Curve Prospect A Prospect B Production (bbls) Year Table 5 - Assumptions: Individual Prospect Production Schedule Parameters Prospect A Prospect B Number of wells 5 wells 9 wells Additional wells 2 wells 6 wells Production Rate/well 10,000 bopd 10,000 bopd Lead Time 4 years 4 years Production Period 12 years 19 years Cut-off Rate 1,500 bopd 1,500 bopd Table 6 - Assumptions: General Production Schedule Parameters Rule of Thumb First Year Production 5% of total resources Plateau Production Before Decline ±50% of total resources Decline Rate ±15% 70 Volume 2: Final Report of the Philippines Case Study

78 2.b Economic Analysis In the economic analysis, several elements must be considered to determine the feasibility of a project. The most important of which is the cost estimates of the project that includes the capital and the operating expenses plus, of course, the abandonment cost that shall be incurred at the end of the production or at the end of life of the field. The exploration costs are likewise considered which are also recoverable from the gross revenue of the project. The costs assumed for the analysis are shown in Table 7. Table 7. Cost Assumption Cost Parameter Prospect A Prospect B Exploration Costs Capital Expenses , % Contingency Expanded Capex , Operating Expenses , Total Costs 1, , Total Project Costs 1, , Cost Data The cost data includes the Capital Expenses (CAPEX, One-Off Costs or Development Expenditures) that normally consists of the amount of development well drilling and completion, well-heads, offshore platform construction and installation, process facilities, flow lines and pipelines which transport oil or gas, supply bases, camps and accommodation, storage vessels, tankers, etc. Also included are the Operating Expenses (OPEX, Periodic Costs ) that occur regularly and are necessary to maintain production from the field. Expressed in terms of expenditure per year or expenditure per barrel or per thousand cubic feet, it consists of field labor costs, maintenance costs, workovers, office overheads, etc. It can be fixed periodic/annual amounts or can be variable and determined as a function of production rate. The other cost data to be considered is the Exploration/Sunk Costs ( historic costs ) that were incurred during the exploration stage of the project. This includes expenses for geological and geophysical studies, expenses in acquiring, processing and interpretation of seismic data, the costs for exploration drilling and succeeding testing and appraisal in case of a discovery, and other studies. Volume 2: Final Report of the Philippines Case Study 71

79 Discount Rate The discount rate applied in the Service Contracts ranges from 10% to 15% but usually the discount rate applied is 12%, depending upon on the negotiations between the government and the contractor. However, in the analysis undertaken for the prospects in Sulu Sea basin, a discount rate of 10% was utilized. The effect of the discount rate in the analysis is significant with regard to the NPV since a 5% increase in the discount rate is equivalent to more than 50% decrease in the NPV. Inflation Rate (data acquired from NEDA) The current average inflation rate of the Philippines as noted from the National Statistics Office of NEDA for 2004 is 3.80%. This is quite higher than the Malaysian and Thailand s inflation rate of 0.9 and 1.8% respectively, but it is similar to other countries like China and South Korea. As shown in Figure 5, there are sudden increases in the inflation rate from 1999 until The high inflation rate during the end of 1998 until 1999 was due to the Asian currency crisis that affected all of the Southeast Asian countries. The increase in 2001 could be attributed to the leadership fiasco that leads to political transformation (EDSA 2) and change of administration. The slight increase in the inflation rate for the first few months of 2004 was in view of the election uncertainty that put the economy in limbo. 200 INFLATION RATE, CONSUMER PRICE INDEX (CPI) FROM mid CPI Inflation Rate Jan May Sep Jan May Sep Jan May Sep Jan May Sep Jan May Sep Jan May Figure 5 Inflation Rate and CPI from 1999 to mid Volume 2: Final Report of the Philippines Case Study

80 Project Net Cash Flow 600 Project Cash Flow 5000 Yearly Net Casf Flow (million US$) Net Cash Flow After Tax Years Net Cash Flow, Cumulative Net Cash Flow, cumulative (million US$) Figure 6. Typical Petroleum Project Cash Flow The typical cash flow of a petroleum project is shown in Figure 6 with an initial exploration and capital expenses incurred in the first few years of the project. The project cash flow will recoup when the project started to produce and generates revenue. The initial revenue from the production is less at the beginning and peaks for at least 2 to 3 years of production before continuously decreases up to the depletion of the reservoir. Oil Price (current, future) With the present world crude oil price, it is very favorable for oil companies to explore and develop even marginal fields. With the oil price of ±$56.00 per barrel, there is no doubt that exploring, finding and developing an oil field is economically feasible although factors such as drilling costs, development costs and operating costs should be considered. For the initial evaluation of the prospects, an oil price of $21.25 per barrel was used, which is relatively very low compared to the present world oil price of $58/bbl. 2.c Economic Indicators In the economic evaluation of the basin, several indicators have been employed and considered to determine or ascertain the feasibility of developing any petroleum project. These indicators are the Net Present Value (NPV), the Internal Rate of Return (IRR), the Payback or Pay Out, and Expected Monetary Value (EMV) or Expected Value (EV). Volume 2: Final Report of the Philippines Case Study 73

81 Results of Analysis for Oil (with FPIA vs. without FPIA) The outcome of FPIA is positive and advantageous to the company as indicated by all of the economic indicators used. The NPV, IRR and EMV increased significantly when there is an additional incentive of FPIA for the consortium. There is no effect to the government take/share if FPIA is applied or not. The comparison for this analysis is shown in Table 8. Table 8 - Comparison of Results of Analysis (with 7.5% FPIA) Prospect A Prospect B PARAMETER w/o FPIA w/ FPIA w/o FPIA w/ FPIA 10% US$229MM US$ 332 MM US$ 1,019MM US$ 1,315MM IRR 21% 24% 29% 32% Payback 7 years/9 yrs 7 years/9 yrs 6 years/9 yrs 6 years/8 yrs EMV US$ 2MM US$ 16MM US$ 148MM US$ 201MM TGT US$ 517MM US$ 517MM US$ 1,810MM US$ 1,810MM Using different discount rates of 10%, 12% and 15%, the result suggests that the IRR is not sensitive to the discount rate while an increase in the discount rate causes a significant decrease to the NPV and EMV of the project. However, whether FPIA is applied or not, the results of economic analysis using different discount rates remains the same. Shown in Table 9 are the results of economic evaluation using different discount rates with FPIA applied. Table 9 - Results with different discount rates (with 7.5% FPIA) Prospect A Prospect B Parameter 10% 12% 15% 10% 12% 15% NPV $332 $246 $150 $1,315 $1,008 $673 IRR 24% 24% 24% 32% 32% 32% Payback 9 yrs 9 yrs 10 yrs 8 yrs 8 yrs 9 yrs EMV $16 $6 -$6 $201 $147 $89 TGT $517 $425 $319 $1,810 $1,452 $1,059 Results of Analysis for Gas (without FPIA) An economic analysis was likewise carried out for the gas prospects mapped and delineated over the Sulu Sea and East Palawan Basins. The prospects over the Sulu Sea basin were analyzed both as stand alone and tied-in to another field, however, the costing were quite the same for the three prospects due to the absence of any infrastructure in the area. Prospect SS6 and SS2 are both analyzed as stand alone and tied-in. Shown in Table 10 are the results of analysis for the gas prospects. 74 Volume 2: Final Report of the Philippines Case Study

82 Table 10 Results of economic analysis for the three gas prospects East Palawan Sulu Sea Basin Basin Parameters SS6 & SS2 SS6 Prospect SS2 Prospect EP1 Prospect Prospects Resources 1,733 BCF 1,310 BCF 3,043 BCF 1,719 BCF Production Period 21 years 21 years 21 years 21 years 12% $1,234 MM $731 MM $2,050 MM $1,218 MM IRR 26% 20% 27% 26% Payback 5 years 7 years 5 years 5 years TGT $7,837 MM $5,962 MM $12,523 MM $7,776 MM The three gas prospects were also evaluated using three discount rates and the results shows the same trend as those of the oil that is, the NPV decreases as the discount rate increases. Shown in Table 11 is the NPV for the three prospects using three discount rates. Table 11 NPV of three gas prospects using three discount rates Discount Rate SS6 Prospect SS2 Prospect EP1 Prospect 10% $1,567 MM $1, 003 MM $1,549 MM 12% $1,234 MM $ 731 MM $1,218 MM 15% $ 841 MM $ 408 MM $ 827 MM Sensitivity Analysis: Spider Diagram of the NPV/IRR The spider diagram shows the sensitivity of the project to the different factors such as the oil price, Capex and Opex. It shows that a variance of ±10% to ±30% of the factors affect the NPV and IRR of the project. If such factor gives a steep increase, it means that the project is very sensitive to variation of that factor. On the other hand, if the leg of the spider increases or decreases gradually, it shows that the project is not so sensitive to the variation and hence, the project is robust. Figures 7 and 8 show the spider diagram of the oil prospects in the Sulu Sea Basin. Volume 2: Final Report of the Philippines Case Study 75

83 NPV (million US$) Price Capex Opex 0 30% 20% 10% 0% 10% 20% 30% Figure 7. Spider Diagram of the NPV 45.0 % 40.0 % 35.0 % 30.0 % IRR 25.0 % 20.0 % 15.0 % 10.0 % 5.0 % Price Capex Opex 0.0 % 30% 20% 10% 0% 10% 20% 30% Figure 8. Spider Diagram of the IRR Decision Tree Analysis The decision tree analysis is the study of a series of connected decisions. It is simply a diagram showing a sequence of decision points and their possible outcomes. a. The first stage of a decision tree is whether to explore or not in a prospect with a certain recoverable reserve. 76 Volume 2: Final Report of the Philippines Case Study

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85 depending on the negotiation between the Government and the Contractor, the crude oil can likewise be sold or exported to other countries as specified in the negotiated service contract. Natural Gas The marketing option for the natural gas is to utilize the resources domestically. Some of the main uses foreseen for the gas are as fuel for power generation, transportation purposes, and liquefied natural gas although the cost could be much higher there is also a possibility of converting the gas to liquid. The resources from the two basins shall fuel the power plants that will supply our energy needs. With this uses for natural gas, a concrete gravity structure or fixed production platform and pipeline network are necessary considering the distance of the land and the deepwater nature of the prospects. Another option for the natural gas is to connect the fields to the proposed Trans- ASEAN gas pipeline system (Figure 10) that will supply natural gas to our neighboring countries. Figure 16. Trans-Asean Gas Pipeline System 4. LICENSING, CONTRACTUAL AND FISCAL CONDITIONS 4.a Fiscal Regime The Philippines Fiscal Term is considered as one of best worldwide due to the following features; no royalty has been incorporated to the fiscal regime, no tax is being deducted from the contractor except for the income tax of around 32 percent that is being deducted from the government share, and the Filipino Participating Incentive Allowance (FPIA) in which a maximum of 7.5%, which is equivalent to 30% Filipino company participation to a consortium is deducted from the gross revenue. Another aspect of the fiscal term is that participation of the National Oil Company is not mandatory to a consortium. 78 Volume 2: Final Report of the Philippines Case Study

86 Other features of the Philippine Fiscal term are the depreciation method which consists of double declining balance, a way of spreading capital expenditures such that the doubled rate of annual depreciation declines each successive year, and the straight line, a way of spreading capital expenditures evenly over a specified period of time, and also profit oil/gas in which the remaining project revenue after costs have been recovered is shared between the state and the company at 60% to 40% respectively. Example Computation of Philippine Government Share Gross Proceeds Less: FPIA* 7.50 Cost Recovery Net Proceeds (Profit Oil) Less: Contractor Share (40%) 9.00 Government Share (60%) Less: Income Tax (31.4%) 4.24 Government Share after Taxes 9.26 *FPIA percentage varies from 1.5 to a maximum of 7.5% depending on the participating interest of the Filipino partners. Schedule of Percentage Incentive (P.D. 87 under Special Provisions Section 28) Filipino Participation Incentive Allowance Payments 30% - above 7.5% 27.5% but less than 30% 6.5% 25.0% but less than 27.5% 5.5% 22.5% but less than 25.0% 4.5% 20.0% but less than 22.5% 3.5% 17.5% but less than 20.0% 2.5% 15.0% but less than 17.5% 1.5% Below 15.0% 0.0% A number of bonuses or fees as standard practice in the petroleum industry are included in the Service Contract between the government and the contractor. These include the Signature Bonus payable, in cash and in kind, within 60 days from the date of execution of the contract. The amount depends upon the prospectivity of the contract area and negotiable between the two parties. Another bonus payable to the government is the Production Bonus, which is scheduled as follows: 25,000 bbls of crude oil per day or 250,000,000 cuft of natural gas per day at an average rate for 60 consecutive days = US$ 500,000 50,000 bbls of crude oil per day or 500,000,000 cuft of natural gas per day at an average rate for 60 consecutive days = US$ 1,000,000 Volume 2: Final Report of the Philippines Case Study 79

87 75,000 bbls of crude oil per day or 750,000,000 cuft of natural gas per day at an average rate for 60 consecutive days = US$ 2,000,000 The other payable in favor of the government is the training fund of US$20,000 per year during the exploration stage and US$50,000 per year during the production period. RECOMMENDATIONS TO MANAGEMENT The results of this project included an improved understanding and ability of the Department of Energy (DOE) to evaluate the potential of the East Palawan Basin and Sulu Sea Basin and similar frontier basins in the Philippines. The potential resources of these basins have been updated and the possibilities in developing these resources have been analysed including the economics and marketing options. To develop these potential resources, the following recommendations were proposed to the management of the DOE. 1. Changes in the Fiscal System: Although the Philippine Fiscal System is one of the most attractive in the region, several changes are needed to meet the challenges in exploring the frontier basins. These include the decrease in the minimum acreage both for offshore (8,000 sq km) and onshore (750 sq km) areas. The increase in the percentage of the Filipino Participation Incentive Allowance (FPIA) where the maximum is 7.5 % (equivalent to 30% Filipino company participation to a consortium) is deducted from the gross revenue. The mandatory participation of the national oil company is one of the propose measures to attract investors in the frontier areas. 2. Reduction of Exploration Risk: A comprehensive study of the frontier basin is recommended to reduce the risk from geological uncertainties in these areas. Another way of reducing exploration risk is by encouraging acquisition of new data (multi-client seismic surveys) to increase amount of existing data. 3. Access to Data: Data is one of the most important parts in promoting areas for exploration. With most of the data here in the DOE in paper copies and old tapes, there is a need to convert these data into digital form and accepted industry formats. This will in turn decrease the cost of the data by reduction of the reproduction cost and treatment and conversion of these old tapes. This digital data can also be easily access and use by oil companies. 4. Progressive Incentives: There is a need to adjust and modify the signature bonus with regard to the prospectivity of these frontier basins. Upfront cost is unattractive to companies who want to look at these areas. Lowering the percentage of area relinquishment is also recommended to give more time in studying the contract areas. 5. Promotion: With the adoption of the bid rounds as the means to contract out exploration blocks, preparation for promotion is essential to its success. This also gives exploration companies equal opportunity to look into the offered blocks. It is also recommended that this bid rounds be conducted every 2 years to give time for the evaluation of the blocks being offered in the rounds. 6. PNOC-EC / PETRONAS Joint Study: To fully evaluate the potential of the East Palawan and Sulu Sea Basins, a joint study is recommended between the national oil companies. They have the resources to do this comprehensive evaluation that can lead to the development of these areas. 80 Volume 2: Final Report of the Philippines Case Study

88 Volume 2: Final Report of the China Case Study Case Study 3 (Semi-mature Basin): The Western Depression of the Sichuan Basin, China 1. Introduction China case study area for PPM project is located in the Chengdu Anxian region of the Western Sichuan depression, measuring km 2. It is the major gas-producing area of Sichuan basin, with a great tight sandstone gas resources. The objective of China case study is to assess the natural gas resource potential in the Western Sichuan depression using GeoX software, to set up the exploration and development strategy of natural gas in the Western Sichuan depression, to analysis and predict the natural gas market in Sichuan region, and to make the suggestions for resource management in the Western Sichuan depression. 1.1 Project Organization The Chinese participating organizations for the PPM case study are the Exploration & Production Research Institute, SINOPEC, and the Exploration & Development Institute, Southwest Petroleum Branch, SINOPEC. The member of project team for China case study is listed in the table 1. The Exploration & Production Research Institute (EPRI), an integrated upstream research agency of SINOPEC, is headquartered in Beijing and has 4 subsidiary institutes in Urumuqi, Wuxi and Dezhou respectively. EPRI is the advisory department of petroleum E&P and upstream development strategy, the R&D center of petroleum upstream core technologies, the training center of upstream professionals, and the petroleum E&P information center. The total number of employee is 1,027, including 58 professors and 382 associate professors, of which 109 Ph.D. EPRI has established a good cooperation relationship with 20 oilfield enterprises in China and more than 10 institutes and universities in abroad. The Southwest Petroleum Branch (SPB), SINOPEC, is an enterprise engaging in oil & natural gas exploration, development and marketing. Its headquarter is located in Chengdu city, Sichuan province, with 2,982 staff. There are 6 basic units, 2 subsidiaries and 3 share--holding companies. At present, In the western Sichuan, northeastern Sichuan and northern Sichuan, the Southwest Petroleum Branch has 17 exploratory blocks and 5 developing blocks in the western Sichuan, northeastern Sichuan and northern Sichuan, with A total area of 25,975 km 2. More than 22 gas fields and gas bearing structures have been found after 30 years of exploration, with the natural gas reserve in place of 139.2x10 9 m 3. A Volume 2: Final Report of the China Case Study 81

89 total of 8 gas fields are now in operation, with an annual production of 2.1x10 9 m 3. Table1: The member of project team for China case study Name Position Organization Zhou Qingfan National Coordinator EPRI, SINOPEC Chen Zhaoguo National Coordinator SPB, SINOPEC Wang Chuan National Coordinator EPRI, SINOPEC Yang Dengwei Team Member EPRI, SINOPEC Li Shubing Team Member SPB, SINOPEC Wang Liangguo Team Member SPB, SINOPEC Long Shengxiang Team Member EPRI, SINOPEC Bai Zhengrui Team Member EPRI, SINOPEC Zhang Yonggui Team Member EPRI, SINOPEC He Hong Team Member EPRI, SINOPEC Wang Zhuquan Team Member SPB, SINOPEC An Fengshan Team Member SPB, SINOPEC Zhou Jing Team Member EPRI, SINOPEC Qiu Liwei Team Member EPRI, SINOPEC Guo Baoshen Team Member EPRI, SINOPEC Li Huaji Team Member SPB, SINOPEC Wang Xin Team Member SPB, SINOPEC Yang Kaiae Team Member SPB, SINOPEC 1.2 Activities of China Case Study During the period of , 4 PPM China case study workshops and 4 expert visits were conducted and a total of 61 participants from China joined in the workshops and expert visit meeting of other case study countries as well as the seminars of PPM project.( table 2 ). Table 2: The Chinese participants joined in the workshops and expert visit meeting of other case study countries Cambodia.case Philippine case Indonesia case PPM study workshop study workshop study workshop seminar Expert visit 1 st Cambodia (4) 1 st Philippine (3) 1 st Indonesia (2) 1 st PPM (4) Indonesia,2004 (1) 2 nd Cambodia (3) 2 nd Philippine (3) 2 nd Indonesia (3) 2 nd PPM(3) Indonesia,2005(1) 3 rd Cambodia (3) 3 rd Philippine (4) 3 rd Indonesia (3) 3 rd PPM (4) 4 th Cambodia (3) 4 th Philippine (3) 4 th Indonesia(2) 4 th PPM (3) 5 th Cambodia (3) 5 th Philippine (3) 6 th Cambodia (3) 82 Volume 2: Final Report of the China Case Study

90 PPM China Case Study Workshops 1) The 1 st PPM China case study workshop The first workshop of China case study was held in Chengdu in October 20-25, A total of 35 participants representing the 7 Member Countries of CCOP (Cambodia, China, Indonesia, Korea, Philippines, Thailand and Vietnam) attended this meeting. The subject of the meeting was mainly on play and prospect resource assessment. The resource person, Ms. Inger Pedersen Fjærtoft from Norwegian Petroleum Directorate, gave lectures and guided the practical exercises on the subject., including the procedures and principles of the geological risk analysis of NPD, and new features in GeoX 5.2 and insight on the multisegment tool. China gave the lectures on the brief introduction to the natural gas exploration and development in the Western Sichuan depression (by Mr. Chen Zhaoguo), the application of GeoX software in China (by Mr. Yang Dengwei), and the petroleum geology on Xu2 play (by Mr. Yang Dengwei). Ms.Ma.Corazon Sta.Ana from the Philippines introduced the Philippines experience in using the GeoX multisegment tool. 2) The 2 nd PPM China case study workshop The 2 nd PPM China case study workshop was held in Chengdu in May A total of 38 participants representing the 8 Member Countries of CCOP( Cambodia, China, Indonesia, Korea, Malaysia, Philippines, Thailand and Vietnam ) attended this meeting. The subject of the meeting was mainly on petroleum assessment and petroleum economics. The resource persons, Ms. Inger Pedersen Fjærtoft and Ms. Benvenutta Elise Henriksen, from Norwegian Petroleum Directorate, gave lectures on the subject, including the application of resource assessment principles in presentations of resource figures, the play and prospect analysis, the review on GeoX usage, the multi-segment analysis, the basic petroleum economics, the economic evaluation of petroleum basin and plays, the exploration economics, and the fiscal regimes. China reported the highlights of the 2 expert visits including the results and recommendations from the visits (by Mr.Li Shubing) and introduced the Chinese petroleum resource classification and gas market in the Sichuan basin (by Mr. Yundong and Mr.Chen Zhaoguo). Also, a review of the cost data from the gas fields in the Western Sichuan depression and fiscal regime of China was given in preparation for the exercises on resource assessment and full-cycle analysis (by Mr. Yang Dengwei and Mr. Wang Liangguo). Volume 2: Final Report of the China Case Study 83

91 3) The 3 rd PPM China Case Study Workshop The 3 rd Workshop of the PPM China Case Study was held in Beijing in June, The topics of this workshop were onshore gas development solutions and policies for investment opportunities. A total of 25 participants representing the 7 Member Countries of CCOP (Cambodia, China, Indonesia, Korea, Philippines, Thailand and Vietnam) attended this meeting. Mr. Tormod Slatsveen, Director of the Norwegian Petroleum Directorate covered the topic on policies for investment opportunities. Mr. Cyrus Esphahanian, Consultant-petroleum engineer from the USA, handled the topic on onshore gas development solutions. China s presentations focused on the national policy for exploration, development and production of petroleum resources (by Mr. Gao Binqi), update on the status of exploration and development activities in the Western Sichuan depression (by Mr. Chen Zhaoguo), update on the status of SINOPEC s company-wide operations (by Mr. Liuyan), and the application and disseminations of knowledge learned from the 3 rd expert visit (by Mr. Yang Dengwei). In addition, the participants from Vietnam, Thailand, the Philippines and Indonesia presented their national gas policy, highlighting on the fiscal regimes and updates on gas supply-demand status, development and market. Two group discussions focusing on the identification of the various challenges in the case study area and what and how solutions to the challenges were also carried out. 4) The 4 th PPM China Case Study Workshop The 4 th Workshop of the PPM China Case Study was held in Beijing in 30 May-3 June, The topics of this workshop were exploration and development strategies for low permeability gas reservoirs and the role of the government in achieving the strategies. A total of 43 participants representing the 8 Member Countries of CCOP (Cambodia, China, Indonesia, Korea, Malaysia, Philippines, Thailand and Vietnam ) attended this meeting. Mr. Gaute Erichsen, Deputy Director General of Oil and Gas Department, Ministry of Oil and Energy, Norway, covered the topic on exploration and development strategies for low permeability gas reservoir the role of the government. Dr. Thomas A. Blasingame, Petroleum Engineering, Texas A&M University, handled the topic on exploration and development for low permeability gas reservoir the technical challenges and solutions. China s presentations focused on the development strategy for the natural gas industry in China (Dr. Qiu Haijun), the SINOPEC s technology and challenges for low permeability gas reservoir development (by Ms. Zhu Xueqian), and the summary of the PPM China case study (by Mr. Yang Dengwei). 84 Volume 2: Final Report of the China Case Study

92 The presentations of the CCOP countries focused on the strategies for natural gas development and management, and petroleum exploration opportunities. Group discussions were organized to encourage exchange of knowledge and experiences on various issues related to the workshop s topic. Expert Visits 1) The 1 st Expert Visit The 1 st expert visit to China case study was held in Chengdu on March, The topic of this visit is stimulation and completion of tight sandstone reservoirs. The resource person, Mr. Cyrus Esphahanian from USA, gave lectures and guided the group discussion on the subject, including the resource assessment on Jonah gas field, the case study on shear fault in Wyoming,USA, the Reservoir stimulation in Dfit area, the effect of proppant on the conductivity of proppant supported fractures, the evaluation of fracturing from the operation design, restoring testing and production analysis, the details of fracturing operation on multiple pay zone gas well, the harm analysis and reservoir stimulation of tight gas reservoir, the operation curve analysis for multiple tight sands of Mamm Creek gas field in Piceance basin, Colorado, the current situation and development trend for tight sand gas reservoir, and the production evaluation after reservoir stimulation in Jonah gas field. A total of 16 participants from SINOPEC attended this meeting. Mr. Lin Hui, the deputy chief engineer of Downhole Operation Department, the Southwest Petroleum Branch, SINOPEC, introduced the current situation of drilling, completion and reservoir stimulation technology on the Xujiahe Formation, Western Sichuan depression. During the period of expert visit, a discussion was maintained concerning the following topics, including (1) the current status of well completion techniques in high temperature and high pressure gas wells, (2) development obstacles in sour gas reservoir, (3) the fracturing design in natural fractured gas reservoir, (4) the control of fracture height on the condition of weak barrier,(5) how to decrease the pressure during fracturing operation, (6) how to optimize the perforation procedures in tight gas reservoir, (7) the fracturing operation in gas-bearing horizon, (8) the major problems of reservoir stimulation in horizontal wells. 2)The 2 nd Expert Visit The resource person, Dr. Ben Law from USA, visited the Exploration and Development Institute, Southwest Petroleum Company, SINOPEC and the Exploration and Production Research Institute, SINOPEC, on April, His presentation was focused on the basin-centered gas system (BCG), including (1) the concept of basin-centered gas system, (2) the development history and classification of basin-centered gas system,(3) the distribution of the basin-centered gas system in the USA and world, (4) exploration strategy of basin-centered gas system, and the (5) method to identify BCG.. The Volume 2: Final Report of the China Case Study 85

93 lectures were supported also by a exercise of compiling the cross map of BCG using the drilling and testing data in the Western Sichuan depression. Mr. Li Shubing, the chief engineer of Exploration and Development Institute, Southwest Petroleum Branch, SINOPEC, introduced the petroleum geological characters and current situation of exploration & development in the Western Sichuan depression. During the period of the expert visit, the resource potential of BCG in the Western Sichuan depression and the methods to identify BCG were discussed. 3)The 3rd Expert Visit The 3rd Expert Visit to China Case Study was held in Beijing on April, A total of 30 participants, including 3 national coordinators from Cambodia, Indonesia and the Philippines, attended this meeting. The topic of the expert visit is modeling of exploration projects by using GeoX 5.4. The resource person, Dr. Alfred Kjemperud from Norway, gave lectures and guided the practical exercises on the subject, including the resource assessment general principles, the play analysis methodology, the setting up GeoX 5.4, the general analysis of prospects and segments, the resource and reserve classification, the calculation of prospect number, the basic economic principles, the economic modeling, the petroleum fiscal regimes, and the risk analysis and exploration economy. He also showed some example models from oil and gas fields in Norway and how Geox software was used to assess the viability of these fields. 4) The 4 th Expert Visit The 4 th Expert Visit to China Case Study was successfully conducted in Deyang, Sichuan Province on May The topic of the expert visit is the solutions to the development and production challenges in the low permeability gas reservoirs. The resource persons, Mr. Wukar Hussain B Mazoor Hussain and Mr. Mohd Zaki B Awang from PETRONAS, Malaysia, presented the lessons learned from various processes in the development and production, the economics, the strategies for continuous improvement in the Angsi A field campaign. Mr. Ren Shan, the senior petroleum engineer of the Engineering Technology Institute of SINOPEC Southwest Branch, presented the challenges they are currently facing related to development and production in the low permeability gas reservoirs in the Western Sichuan basin. The visit provided also a forum for discussion on some key development techniques of tight gas reservoir, including the postfracture respond analysis, completion parameter optimization and multiple zone completion etc. The open discussions and exchange of knowledge within and outside the meeting room made the activity achieve its purpose. 86 Volume 2: Final Report of the China Case Study

94 1.3 Project benefits China has benefited the new methods and concepts regarding the assessment and management of natural gas resources from PPM Project. 1) China is familiar with new functions and tools in GeoX 5.4 software and has applied it in assessing natural gas potential in the Western Sichuan depression. 2) New methods and concepts regarding the petroleum resource assessment, petroleum resource management and exploration economy have been introduced from the PPM China case study workshops, such as the principle and procedure of geologic risk analysis, the play and prospect economic analysis, the multiple segment analysis, the natural gas resource management, the DHI risking, the comparison of predrilling estimates and postdrilling results in NPD and the calculation of prospect number, which are helpful for improving our petroleum assessment and management systems. 3) The advanced drilling and completion technology of tight gas reservoir has been introduced from expert visits, including the restoring testing and production analysis, the fracturing operation on multiple pay zone gas well, the harm analysis and reservoir stimulation of tight gas reservoir and the operation curve analysis for multiple tight sands etc., which is potentially adopted in the E & D projects in the Western Sichuan depression. 4) The experiences and knowledge on the marginal field development, the petroleum resource management, the EOR/IOR technology, the deepwater oil and gas exploration and the E & D of fractured basement reservoirs are learned and shared from other case studies. Their experience will be used in the E & D projects in Chinese petroleum basins. 5) Many valuable suggestions and comments regarding the solutions to the challenges in the natural gas exploration and development in the Western Sichuan depression have been provided from expert visits and from group discussion in the China case study workshops. 6) The Cambodia, the Indonesia and the Philippines case studies help us to understand the petroleum geology of the study area and also the petroleum industry of the host countries. 1.4 Project main products Natural gas resource assessment in Western Sichuan depression 1) Training textbook on play assessment. This textbook contains a comprehensive information and ways of thinking with reference to play assessment introduced by CCOP projects. 2) Internal guideline and procedures of geologic risk analysis for the tight sandstone reservoir in the Western Sichuan depression. 3) Natural gas resource assessment for the 4 major plays in the Western Sichuan depression. 4) Natural gas resource assessment for the 9 key prospects in the Western Sichuan Volume 2: Final Report of the China Case Study 87

95 depression. 5) Economic analysis of Xu2 play 6) Comparison for predrilling estimation and postdrilling results 7) GeoX usage manual (Chinese version) Natural gas resource management in the Western Sichuan depression 1) Resource classification scheme in the Western Sichuan depression 2) Analysis and prediction of natural gas market in Sichuan region 3) Suggestion on China s natural gas management 4) Exploration and development strategies of tight gas reservoirs Finally, we would like to express our sincere thanks to Norwegian experts for their technical support, to CCOP Technical Secretariat for its successful organization and management for PPM project, and to all the participants from CCOP Member Countries who give us so many helps in a different ways. 2. Regional Geology and Natural Gas Production in the Western Sichuan Depression 2.1 Tectonic setting The western Sichuan depression is the deeply subsided part of the Sichuan continental basin since late Triassic. (fig.1) It is bounded on the north by Michangsan nappe structure belt, on the east by the Longquansan mountain, on the south by the Yaan-Lesan and on the west by the Longmengsan nappe structure belt. Fig.1 The tectonic setting of the Western Sichuan depression 2.2 Sedimentary fill The Western Sichuan depression is characterized by an eastward-thinning, 12-km-thick sedimentary wedge that consists of about 4 km of shelf and continental margin carbonates of Sinian through Middle Triassic age, and about 8 km of fluvial and lacustrine rocks of Late Triassic through Tertiary age. A generalized stratigraphic column for the 88 Volume 2: Final Report of the China Case Study

96 Western Sichuan depression is illustrated in figure 2. Pre-Upper Triassic rocks in the Western Sichuan depression consist of limestone, dolomite, and mudstone ranging in age from Sinian to middle Triassic, with the total thickness of m. The Upper Triassic rocks can be divided into the Maantang formation, the Xiaotangzi formation, and the Xujiahe formation, which reach the total thickness of m. Both the Maantang and Xiaotangzi formations are called as Xu1 member, which are composed primarily of dark-gray to black marine clayey to silty shale and sandstone and lesser amount of fossiliferous limestone that unconformably overlies the middle Triassic carbonate rocks. The Xujiahe formation consists of four vertically separated facies: a lower sandstone (Xu2 member), a rhythmic unit of sandstone, siltstone and mudstone (Xu3 member), a interbedded layers of detritus sandstones and quartzose sandstones with thin coal seam (Xu4 member), a interbedded layer of detrital sandstones, detrital quartzose sandstones and shale (Xu5 member). The Jurassic rocks include the Baitianba formation, the Qianfuyan formation, the Shaximiao formation, the Suining formation, and the Penglaizhen formation, with the total thickness of m. The Baitianba formation is composed of purplish red conglomerate and mudstone with lesser amounts of sandstone and coal seam. The Qianfuyan formation consists of quartzose sandstone and black carbonaceous shale with thin coal seam. The Shaximiao formation is composed of detrital sandstone and feldspathic sandstone. The Suining formation is a rhythmic unit of purplish red mudstone, silty mudstone, and calcareous mudstone. The Penglaizhen formation consists of a light green-gray, fine-grained detrital sandstones and quartzose sandstones. The lower Cretaceous Jianmenguan formation is a distinct purplish red-colored unit primarily consisting of interbedded conglomerate and sandstone. The middle Cretaceous Jiaguan formation is composed of conglomerate, sandstone, siltstone, and mudstone. The upper Cretaceous Guankou formation consists of sandstone, siltstone and mudstone with minor amounts of gypsum and glauberite. The total average thickness of Cretaceous rocks is 2700 m. The Tertiary rocks are composed of conglomerate, sandstone, and siltstone that unconformably overlie the Cretaceous rocks, with the total maximum thickness of 108 m. Volume 2: Final Report of the China Case Study 89

97 Fig. 2 Stratigraphic Column in Western Sichuan depression 2.3 Geological feature Compared with the other sedimentary basins in China, the geological aspects of the Western Sichuan depression have the following features: Multiple stage of basin evolution The Sichuan basin evolution can be divided into the 7 stages: (1) the passive continental margin stage in Ma-antang period (T 3 m) of Late Triassic; (2) the foreland basin stage from Xiaotangzi (T 3 t) to Xujiahe (T 3 x) period of late Triassic (fig. 3-4):(3) the foreland basin shrinkage and disappear stage in early Jurassic (J 1 ) to Suining period of late Jurassic (J 3 s); (4) the intra-continental depression stage in Penglaizhen period (J 3 p) of late Jurassic; (5) the intra-continental basin shrinkage and disappear stage of early Cretaceous to Eocene epoch; (6) the structural remnant basin stage in Oligocene -Pliocene epoch; and (7) the Quaternary foreland-like basin stage. 90 Volume 2: Final Report of the China Case Study

98 Fig. 3 Sedimentary facies map of Sichuan region in the stage of late Triassic foreland basin Fig. 4 Section of geological structure in the Western Sichuan depression in the stage of late Triassic foreland basin High sedimentary rate The sedimentary rates of Upper Triassic (Xiaotongzi-Xujiahe formations), Upper Jurassic (Penglaizhen and Suinin formations ), and Lower Cretaceous-Tertiary strata in the Western Sichuan depression range from 78 m/ma to 260 m/ma, which are greatly exceed the minimum threshold of rapid subsidence (40m/Ma)(table 3). Volume 2: Final Report of the China Case Study 91

99 Stratigraphy Table 3 The sedimentary rate in Western Sichuan depression Code Duration (Ma) Thickness (m) Sedimentary Rate (m/ma) Xiaotangzi Xujia formations T3x Baitianba formation J1b Qianfuyan formation J2q Shaximiao formation J2 xs-j2s Suining formation J3sn Penglaizhen formation J3p Jianmenguan formation--lowertertiary K1j-E High compaction In the Triassic-Jurassic strata of the Western Sichuan depression, the average porosity is %, the matrix permeability is μm 2 (table 4-5), the average water saturation is %. The medium-deep seated reservoirs of middle Jurassic Shaximiao and Qianfuyan formations are tight reservoirs, the deep seated reservoirs of Triassic strata are tight or super-tight reservoirs except that shallow conventional porous reservoirs are developed in Upper Jurassic Penglaizhen formation. Table 4 The petrophysical property of major prospects in the Western Sichuan depression Prospect Strata Sandstone Sandstone Mudstone Density Porosity(%) Density(g/cm 3 ) (g/cm 3 ) Jinma J 2 s J 2 q Hexin-Chang J 3 p Majing J 3 p K Zhongjiang J 3 p J 2 s Xindu J 3 p K Volume 2: Final Report of the China Case Study

100 Table 5 The petrophysical parameters of gas reservoirs in Xiaoquan-Xinchang region Petrophysical Parameters Average Average Strata Thickness Average Porosity Water permeability (m) (%) (10-3 μm 2 Saturation ) (%) JP J 3 p JP JP J 2 s J 2 q (conglomerate) 2.11 (conglomerate) (matrix) 0.121(matrix) T 3 x T 3 x High heterogeneity of porosity and permeability in reservoir rocks The clastic reservoirs in the Western Sichuan depression are characterized vertically and laterally by high heterogeneity of porosity and permeability due to basin evolution history, complex tectonic movement and differential diagenesis (table 6-7). Table 6 The petrophysical property of the Jurassic Penglaizheng Formation in the Western Sichuan depression region Xiao- Xinchang Dongtai Hexinchang Majing Luodai Xindu Jintang property quan JP 1 JP 2 JP 3 JP 1 Φ(%) K(10 3 µm 2) Table 7 The petrophysical property of the Jurassic Shaximiao Formation in the Western Sichuan depression region Xiaoquan Xinchang Hexincha Zhongji Xinshe Luoda Jinm property ng ang ng i a Φ(%) K(10 3 µm 2) Highly abnormal pressure The most gas reservoirs in the western Sichuan depression are characterized by overpressure (table 8). The under-pressured gas pool has not been discovered to date. In general, the pressure coefficient is increased with buried depth. Volume 2: Final Report of the China Case Study 93

101 Table 8 The Upper Triassic pressure coefficient in the central part in the Western Sichuan depression Yazihe Mianzhu Xiaoquan Hexinchang Shiquanchang Fenggu T 3 x-t 3 x 4 range medium T 3 x 3 -T 3 x 2 range medium Large Mesozoic gas accumulation a. The middle-late Jurassic is the hydrocarbon-generating and expelling peak period (table 9). b. Gas accumulations are controlled by Mesozoic paleouplifts (fig. 5). Table 9 The gas-generative amounts of T3-J1 source rocks in the Western Sichuan depression Age LateT 3 x 3 LateJ 1 Late J 3 Late K 1 Late E Late E Buried depth of source rocks(m) Gas-generating amounts(10 12 m 3 ) (total gas-generative) Fig. 5 The relation between gas accumulations and Mesozoic paleouplifts 2.4 Gas production As at , the natural gas reserves stands at m 3 and the cumulative gas production is m 3 (fig. 6) Natural gas was first discovered in 1982 To date a total of 215 exploration wells (84 wildcat and 131 appraisal wells) had been drilled and Volume 2: Final Report of the China Case Study

102 line-kms of 2D seismic and 2604 km 2 of 3D seismic data were acquired, resulting in the discovery of a total of 15 gas fields and gas-bearing structures. As on , 7 gas fields are in production. The natural gas production in 2005 was 21.1x10 8 m 3 (fig. 7), of which 97% produced from sandstone reservoirs of Upper Jurassic Penglaizhen formation and Middle Jurassic Shajimiao formation (table 10). Fig. 6 Natural gas reserve increase in the Western Sichuan depression Fig. 7 Natural gas production increase in the Western Sichuan depression Fig. 7 Natural gas production increase in the Western Sichuan depression Volume 2: Final Report of the China Case Study 95

103 Table 10 Recoverable reserves and productions of gas fields in Western Sichuan depression in 2004 ( 10 6 m 3 ) field Ultimately Remaining Accumulative 2005 Recoverable Recoverable Production production Xiaoquan Hexinchang Xichang Dongtai Luodai Majin Xindu Total Results of resource assessment and economic analysis During , the internal guideline and procedures of risk analysis for the tight sandstone reservoir in Western Sichuan depression was established and natural gas resource assessment for the 4 major plays and 9 key prospects in the Western Sichuan basin were conducted. 3.1 The internal guideline and procedures of risk analysis for the tight sandstone reservoir in the Western Sichuan depression The key geological probability factors to discovery a natural gas accumulation in Western Sichuan depression are the existence of reservoir rocks, existence of trap, existence of source rocks and retention of natural gas after accumulation. The probability of discovery is defined as the product of the above probability factors. 1) Effective Reservoir (P1) The probability of the existence of an effective reservoir rock with minimum properties as assigned in the volumetric estimate of the prospect (P1) comprises two components. The first of these is the probability of the existence of reservoir. The second is the probability that the porosity will be effective. Probability of effective reservoir (P1) = Probability of reservoir existence (P1a) Probability of effective porosity (P1b) Probability of reservoir existence (P1a): The probability of reservoir existence is the probability of the existence of reservoir facies with minimum properties as assigned in the volumetric estimate of the prospect (such as net/gross ratio and thickness). Its evaluation is based on the measured data of reservoir rock, a geological model for the reservoir rock and regional analog (table 11). 96 Volume 2: Final Report of the China Case Study

104 Table 11 The probability of reservoir existence Existence of reservoir is proven by wells or 3D seismic data Probable existence of reservoir is indicated at least by a well and 2D seismic data Reservoir existence is neither confirmed or nor denied by well and seismic data Probable absence of reservoir is indicated by wells and seismic data Existence of reservoir is indicated by sedimentary and diagenetic models Existence of reservoir is indicated by regional analog Absence of reservoir is proven by well and seismic data Absence of reservoir is indicated by sedimentary and diagenetic models Absence of reservoir is indicated by regional analog Probability of effective porosity (P1b): The probability of effective porosity is the probability of porosity being greater than the cut off values for effective reservoir porosity assigned in the volumetric estimate of resource assessment. This probability factor is evaluated by available core data, calculation of porosity-versus-depth and regional analog (table 12), which should be modified by the probability of fracture existence in the risk analysis of Western Sichuan depression (table 13-15) Table 12 The probability of effective porosity The well data (including the laboratory core analysis data and logging data) of study area show that the average porosity of reservoir is equal or more than the cut off values* for effective reservoir porosity assigned in the volumetric estimate of resource assessment. The well data in the field or discovery in immediate vicinity or the well data in similar reservoir within trend show that the average porosity of reservoir might be equal or more than the cut off values. Based on the available data, it is equal chance that the average porosity of reservoir might be more than or less than the cut off values applied in the play and prospect analysis. The regional analog data and laboratory analysis data show that the average porosity of reservoir might be less than its minimum threshold value. Based on geological model and distribution map of sedimentary facies, it is probable that the reservoir rock has porosity equal to or larger than the cut-off value applied in the play and prospect analysis. Volume 2: Final Report of the China Case Study 97

105 Based on geological model and distribution map of sedimentary facies, it is probable that the reservoir rock has porosity less than the cut-off value applied in the play and prospect analysis. Based on regional analog data, it is probable that the reservoir rock has porosity equal to or larger than the cut-off value applied in the play and prospect analysis. Core analysis and logging data show that the reservoir rock has porosity equal to or larger than the cut-off value applied in the play and prospect analysis. the cut-off values: T 3 x 2 : 1.5% ; T 3 x 4 3%; J 2 s: 7%; J 3 p 6% Table 13 The probability of effective fracture Fractures are identified by well or 3-D seismic data. Fractures are mostly the large extensional and wide ones with a good connectivity and fracture density is more than 6-15/m, of which the high-dip fractures account for the 70% of total fractures. Fractures are identified by well or 3-D seismic data Fractures are mostly the large extensional and wide high-dip or horizontal fractures with a better connectivity, of which the high-dip fractures account for the 30% of total fractures. Fracture density is 4-6/m. Effective fractures are neither confirmed or nor denied by well or 3-D seismic data. It is probable that fractures are not developed based on seismic data. Based on core data, fractures are mostly the short but narrow horizontal fractures, with a poor connectivity. Fracture density is less than 2-4/m. Fractures might be presented by regional analog and surface investigation. Based on core data, fractures are mostly the horizontal ones, with a poor connectivity. Fracture density is less than 1-2/m It is probable that fractures are not developed by regional analog and surface investigation. Fractures are not presented by core data or production test data. Table 14 Fr Relation of effective porosity and effective fracture ( for T 3 x 2 and T 3 x 4 plays) P1b Volume 2: Final Report of the China Case Study

106 Table 15 Relation of effective porosity and fracture ( for J 2 s and J 3 p plays) P1b Fr ) Trap mechanism (P2) The trap is a sealed structural closure or geometrical body. The probability of the presence of an effective trap, P2, is the product of the probability of the existence of the mapped structure and the probability of effective seal mechanism. Probability of existence of mapped structure: This probability factor is used to describe the probability of existence of mapped structural body with its area (or bulk rock volume) equal or larger than the minimum value applied in the resource assessment. It is assigned by geophysical data, geological mapping and regional analog (table 16) Table 16 The probability of existence of mapped structure Its existence is proven by wells and seismic data with good quality and sufficient seismic coverage* The style of mapped structure indicated by 3D seismic data is identical with the that of neighboring structure within the same tectonic trend successfully tested. Its existence is probably based on wells and seismic data with acceptable quality and sufficient seismic coverage. The style of mapped structure indicated by 2D seismic data is identical with the that of neighboring structure within the same tectonic trend successfully tested. Its existence is neither confirmed or nor denied by wells and seismic data with open grid size The quality of seismic data (including the interpretation of seismic profiles, construction of time maps of the top and bottom surface,etc.) is poor and structure style is complex with very open seismic coverage. Its existence is based on surface investigation only. Its absence is proven by well, seismic and engineering data or by surface investigation and regional analog. Volume 2: Final Report of the China Case Study 99

107 dense grid size : 90% of prospect area is covered by 3D seismic, area of prospect / grid size is > 10 times. open grid size : % of prospect area is covered by 3D seismic, area of prospect / grid size is > times. very open grid size : <70 % of prospect area is covered by 3D seismic, area of prospect / grid size is < 2.5 times. Probability of existence of effective seal This factor describes the probability of existence of top seal, base seal and lateral seal in mapped body. This probability factor is evaluated by well data, seismic data, laboratory study and regional analog (table 17). 3) Petroleum charge (P3) The probability of petroleum charge, P3, is the product of the probability of the presence of effective source rock, the probability of effective migration, and the probability of suitable timing Table 17 Probability of existence of effective seal Existence of sealing rock unit within this prospect is defined by well data, seismic data and laboratory study (water type, salinity, pressure, etc.) Existence of a thick, regionally extensive and effective sealing rock unit is verified by well and/or seismic data. Same sealing rock unit is successfully tested in trend. The sedimentary environment of sealing rock unit within this prospect existence is identical with that in neighboring region successfully tested. Existence of sealing rock unit is neither confirmed or nor denied by wells and seismic data. Sealing mechanism is determined by unconvincing data or geological model only. Sealing mechanism is demonstrated in regional analog. Absence of sealing rock unit is probably indicated by seal absence is probable based on well data, seismic data and laboratory study (water type, salinity, pressure, etc.). Absence of sealing rock unit is verified by well data, seismic data and laboratory study (water type, salinity, pressure, etc.). Absence of sealing rock unit is demonstrated in regional analog. Presence of effective source rocks This factor is used to describe the probability that the hydrocarbon amount generated and expelled from source rocks is large enough for forming a oil and gas pool in a play. The presence of effective source rock is evaluated using quality of potential source rock and spatial distribution of mature source rock within play area (table 18). 100 Volume 2: Final Report of the China Case Study

108 Table 18 The probability of the of presence of effective source rock Commercial production of hydrocarbons in play area Wells have tested movable hydrocarbons. Hydrocarbon shows have been found in wells and surface. Effective source rock is verified by laboratory analytical data. Its hydrocarbon-generating density is larger than the cut off values of pool size applied in the hydrocarbon resource assessment*. Presence of effective source rocks in play area is neither identified or nor denied by well and laboratory data. Presence of source rocks is identified by laboratory analysis data, but its maturity is very low Presence of effective source rocks is only indicated by regional analog or theory study. No hydrocarbon shows are known in play area and no source rocks are not found in well or outcrop; based on basin modeling data, source rocks are immature Absence of effective source rocks is proven by well and laboratory analysis data; its hydrocarbon-generating density is less than the cut off values of pool size in the hydrocarbon resource assessment. * Hydrocarbon-generating density > 10 x 10 8 m 3 /km 2 ( for T 3 x 2 and T 3 x 4 ) or 20 x 10 8 m 3 /km 2 (for J 2 s and J 3 p ) ; hydrocarbon-generating density > 5 x 10 8 m 3 /km 2 (for T 3 x 2 and T 3 x 4 ) or 10 x 10 8 m 3 /km 2 (for J 2 s and J 3 p ), if hydrocarbon migration is mainly lateral migration. Hydrocarbon migration This factor describes the probability of efficient migration of hydrocarbons from the source rock to the mapped structural body (table 19). Volume 2: Final Report of the China Case Study 101

109 Table 19 The probability of hydrocarbon migration Based on seismic and well data, the migration mechanism on the prospect is identical with the that of neighboring structure within the same tectonic trend successfully tested. Seismic and well data verify that the prospect is situated within a dominant migration path. Based on available data, it is probable that the hydrocarbon migration mechanism on the prospect is similar to that of neighboring traps within the some tectonic trend successfully tested. Seismic and well data indicate that the prospect is probably situated within a migration path. Hydrocarbon effective migration is neither confirmed nor denied by well and seismic data. Seismic and well data verify that the prospect is not situated within a dominant migration path. Complicated or tortuous migration path is indicated by the analog of adjacent area The prospect is in the shadow area of migration. The effective migration condition is not existed within the study area by geological mode. Suitable timing This factor describes the probability that the mapped structure body has been present before the end of hydrocarbon generation (table 20). Table 20 The probability of suitable timing Seismic and well data verify that trap was in existence to or was basically contemporary the end of main hydrocarbon -expelling phase. Seismic and well data indicate that trap was probably in existence to or was basically contemporary the end of main hydrocarbon-expelling phase Based on the seismic and well data, it is equally probable that hydrocarbons have migrated into the trap or have avoided the trap. Seismic and well data indicate that trap was not probably in existence to or was basically contemporary the end of main hydrocarbon-expelling phase Based the geological model, that trap was in existence to or was basically contemporary the end of main hydrocarbon -expelling phase. Based the geological model, that trap was not in existence to or was basically contemporary the end of main hydrocarbon -expelling phase Seismic and well data verify that trap was in existence to or was basically contemporary the end of main hydrocarbon -expelling phase. 102 Volume 2: Final Report of the China Case Study

110 4) Efficient retention after accumulation This factor describes the probability of efficient retention of hydrocarbons after accumulation in the mapped structure body. The efficient retention is evaluated using by potential fault reactivation, regional uplift, geological history of the trap after accumulation and local fracturing of sealing rocks, etc (table 21) Table 21 The probability of efficient retention after accumulation Unambiguous data (such as well and seismic data) verify that there is no indication of tectonic reworking after accumulation. Well and seismic data verify that efficient retention mechanism after accumulation in the prospect is identical with that in neighboring structure in the same tectonic trend successfully tested. The trap was tilted but its top point and volume are not considerably changed. The overlying sediments were eroded after accumulation, but the trap is in connection with source rock that are still generating hydrocarbons. Based on the available data with poor to fair quality, it is probable that the efficient retention mechanism after accumulation in the prospect is similar to that in neighboring structure in the same tectonic trend successfully tested. Efficient retention after accumulation is neither confirmed nor denied by the available data (such as well and seismic data etc.). Sealing mechanism after accumulation is poorly defined due to intensively structural activity or faulting. The trap is situated within positive anomalous field of geochemical prospecting. Based on the regional analog data, it is probable that the trap has not experienced disturbances by tectonic movements. Sealing mechanism after accumulation is poorly defined due to intensively structural activity or faulting. The trap is situated within positive anomalous field of geochemical prospecting. Based on the regional analog data, it is probable that the trap has not experienced disturbances by tectonic movements. 3.2 Resource assessment of Xu2 play The Triassic Xu2 sandstone play is located in the region between Chengdu and Deyang cities, with an area of km 2. By the end of 2005, a total of 21 exploratory wells and 1 appraisal well were drilled, resulting in 3 gas discoveries (Hexingchang gas field, Xinchang gas field and Fenggu gas Volume 2: Final Report of the China Case Study 103

111 field) with the in place reserves of X 10 8 m 3 of natural gas (4.12X 10 8 m 3 recoverable). The Exploratory well density is 0.05 well / km 2. 1) Petroleum Geology The Source rocks consist of the black mudstone and shale, interbedded locally with thin coal seam and carbonaceous shale, in the Upper Triassic Xiaotangzi Formation (T 3 m), the Maantang Formation (T 3 t) and the second member of Xujiahe formations (T 3 X 2 ) (table 22). The gas-generative density is 10-40x10 8 m 3 / km 2 Table 22 The TOC and Ro of source rocks in Xu2 play Kerogen type TOC(%) Ro(%) T3m+t II T3X2 III The reservoir rocks are generally a light green, well-sorted, fine grained to medium-grained detrital sandstones and quartzose sandstones deposited in the fluvial-deltaic environment, with a thickness of m. The detrital sandstones contain 54-67% of quartz, 3-7% of feldspar, and 28-40% of rock fragments. The quartzose sandstones contain 73 to 86 % of quartz, 2-3 % of feldspar, and % of rock fragments. Porosity and matrix permeability range from 1.5 to 10 % and from to μm 2, respectively, which exhibit a great variation in vertical and lateral extents (table 23). Fractures, which are reported in some core samples, should enhance their effective permeability. Table 23 The porosity and permeability of reservoir rocks n Xu2 play Porosity (%) Permeability (10-3 μm) min av. max min av. max Hexingchang gas field * Xinchang gas field ** * Fractures are present in samples ** Log calculation Sealing rock is the mudstone and shale of the third member of Triassic Xujiahe Formation, with the thickness of more than 300 m. All prospects are defined as anticline structures. 104 Volume 2: Final Report of the China Case Study

112 2) Result of resource assessment The assessment data form is shown in table 24 and the result of resource assessment can be summarized as the following (table 25, fig. 8): - The unconditional prospect probability of Xu2 play is Total gas resource in place is estimated to range from 697 to m 3, at the 0.90 and 0.10 probability levels. Mean in place value is calculated to be m 3. - The yield factor of gas resource in place ranges from 4.34 to m 3 / m 3 pore space, with the mean value of 9.48 m 3 / m 3 pore space. - Based on the mean value of pool size by rank, the number of gas accumulation is estimated to be 11. Play Attitudes Prospect Attitudes Table 24 The assessment data form for Xu2 play Attribute Probability of Favorable or Present Source Rock 1.00 Timing 1.00 Migration 1.00 Reservoir Facies 1.00 Marginal Play Probability 1.00 Trapping Mechanism 0.8 Effective Porosity 0.5 Hydrocarbon Accumulation 0.9 Conditional Deposit Probability 0.36 Attributes probability P95 P50 P5 Hydrocarbon volume parameters Area of closure (km2) Reservoir thickness (m) Geometric factor Effective porosity (%) Hydrocarbon saturation (%) Trap fill (%) Reservoir depth (m) Recovery gas factor (%) 50 / 60 Hydrocarbon mix (%) 100 The number of prospect Volume 2: Final Report of the China Case Study 105

113 Table 25 Geologic risk-resource evaluation in Xu2 play Risk analysis Marginal play probability Conditional deposit probability Unconditional prospect probability Play risk Resources in place (10 8 m 3 ) Resources recoverable (10 8 m 3 ) Pool size by rank (10 8 m 3 ) Mean value P90% P50% P10% Mean value P90% P50% P10% total Fig. 8 Distribution of recoverable natural gas resources in place in Xu2 play 106 Volume 2: Final Report of the China Case Study

114 3) Economic analysis The economic analysis of Xu2 play was completed in 3 steps :(1) calculating the Pool size distribution by rank (gplayr); (2) economic evaluation for each prospect (gfullcycle); and (3) economic analysis of Xu2 play (gportfoliov). Its results indicate that the NPV value ranges from to USD, with the mean value of USD, if natural gas of OE is produced (table 26). Table 26 Performance index of portfolio value analysis in Xu2 play Parameters Mean F90 F50 F10 NPV (10 6 USD) Total produced (106OE) Resource assessment of Xu4 play The Xu4 play consists of paleostructural-lithological traps in sandstone reservoirs of Late Triassic age. Drilling depths range from 3800 to 4400 m. By the end of 2005, a total of 3 exploratory wells were drilled, resulting in 1 gas discoveries (Fenggu gas field). 1) Petroleum Geology The reservoir rocks consist of a light green, well-sorted, fine grained to medium-grained detrital sandstones and quartzose sandstones deposited in deltaic environment. Thickness of as much as m have been penetrated by wells. Porosity may ranges from 3 to 15%, with the mean value of 7.35%, and average permeability is 0.25 md. Abnormally high fluid pressures are expected in this play. Potential source rocks may be the black mudstone and shale, interbedded locally with thin coal seam and carbonaceous shale in the third member (Xu3) and forth member (Xu4) of Xujiahe formations (table 27). Table 27 The TOC and Ro of source rocks in Xu4 play Kerogen type TOC(%) Ro(%) Xu3 III Xu4 III Sealing rocks are the mudstones of the fifth member of Xujiahe formations immediately overlying this play, with average thickness of 246 m. Postulated traps in this play are mostly paleostructural-lithological trap or superposed structure trap. Volume 2: Final Report of the China Case Study 107

115 2) Result of resource assessment The assessment data form is shown in table 28 and the result of resource assessment can be summarized as the following (table 29 and fig. 9): Table 28 The input parameters of geologic risk analysis in Xu4 play Probability of Favorable or Attribute Present Play Attitudes Prospect Attitudes Source Rock 1.0 Timing 1.0 Migration 1.0 Reservoir Fancies 1.0 Marginal Play Probability 1.0 Trapping Mechanism 0.8 Effective Porosity 0.5 Hydrocarbon Accumulation 0.9 Conditional Deposit Probability 0.36 attributes probability P95 P50 P5 Hydrocarbon volume parameters Area of closure (km2) Reservoir thickness (m) Geometric factor Effective porosity (%) Hydrocarbon saturation (%) Trap fill (%) Reservoir depth (m) Recovery gas factor (%) 50 / 60 Hydrocarbon mix (%) 100 The number of prospect The unconditional prospect probability of Xu4 play is The total gas resource in place is estimated to range from 630 to m 3, at the 0.90 and 0.10 probability levels. Mean in place value is calculated to be m 3. - The yield factor of gas resource in place ranges from 10.3 to 18.8 m 3 /m 3 pore space, with the mean value of 14.2 m 3 /m 3 pore space. - Based on the mean value of pool size by rank, the number of gas accumulation is 108 Volume 2: Final Report of the China Case Study

116 estimated to be 11. Table 29 Geological risk-resource assessment in Xu4 play Play Deposit Probability of marginal conditional Risk analysis play discovery probability probability Play risk Resource assessment Mean value P90% P50% P10% Natural gas resources in place (10 8 m 3 ) Natural gas resources recoverable (10 8 m 3 ) Pool size by rank (10 8 m 3 ) Mean value P90% P50% P10% total Fig. 9 Distribution of recoverable natural gas resources in place in Xu4 play Volume 2: Final Report of the China Case Study 109

117 3.4 Resource assessment of Shaximiao play The Shaximiao play consists of combination traps in sandstone reservoirs of Middle Jurassic age. Drilling depths range from 1900 to 2800m. By the end of 2005, a total of 21 exploratory wells and 1 appraisal well were drilled, resulting in 3 gas discoveries (Hexingchang gas field, Xinchang gas field and Fenggu gas field) with the in place reserves of m 3 of natural gas ( m 3 recoverable). The Exploratory well density is 0.05 well / km 2. 1) Petroleum geology The reservoir rocks consist of a light green-gray, well-sorted, medium grained to fine-grained detrital sandstones and feldspathic sandstones deposited in lake-river deltaic environment. Thickness of as much as m. have been penetrated by wells. Porosity may ranges from 4 to 16 %, with the mean value of 6.1%, and average permeability is 0.51 md. Abnormally high fluid pressures are expected in this play. Potential source rocks may be the black mudstone and shale in the fifth member of Xujiahe formations, with the average TOC content of 2.71% and average Ro value of 1.13%. Kerogen of type III has been identified. In addition, it is probable that the gas in this play is provided from the source rocks of the 2 nd, 3 rd and 4 th members of Xujiahe formation. Sealing rocks consist of as much as 1000 m. of mudstones of the upper part of Shaximiao formation and overlying Suining and Penglaizhen formations. Postulated traps in this play are mostly paleostructural-lithological trap or structural-lithological trap. Table 30 The input parameters of geologic risk analysis in Shaximiao play Attribute Probability of Favorable or Present Play Attitudes Prospect Attitudes Source Rock 1.0 Timing 1.0 Migration 1.0 Reservoir Facies 1.0 Marginal Play Probability 1.0 Trapping Mechanism 0.8 Effective Porosity 0.6 Hydrocarbon Accumulation 0.9 Conditional Deposit Probability Volume 2: Final Report of the China Case Study

118 attributes probability P95 P50 P5 Hydrocarbon volume parameters Area of closure (km2) Reservoir thickness (m) Geometric factor Effective porosity (%) Hydrocarbon saturation (%) Trap fill (%) Reservoir depth (m) Recovery gas factor (%) Hydrocarbon mix (%) 100 The number of prospect ) Result of resource assessment The assessment data form is shown in table 30 and the result of resource assessment can be summarized as the following (table 31 and fig. 11): - The unconditional prospect probability of Shaximiao play is The total gas resource in place is estimated to range from 1383 to m 3, at the 0.90 and 0.10 probability levels. Mean in place value is calculated to be m 3. - The yield factor of gas resource in place ranges from 16.6 to 24.9 m3/m3 pore space, with the mean value of 20.5 m3/m3 pore space. - Based on the mean value of pool size by rank, the number of gas accumulation is estimated to be 14. Table 31 Geological risk-resource assessment in Shaximiao play Play Deposit Probability of play marginal conditional Risk analysis discovery probability probability Play risk Resource assessment Mean value P90% P50% P10% Natural gas resources in place (10 8 m 3 ) Natural gas resource recoverable (10 8 m 3) Pool size by rank (10 8 m 3 ) Mean value P90% P50% P10% Volume 2: Final Report of the China Case Study 111

119 , total Fig. 10 Distribution of natural gas in place in Shaximiao play 3.5 Resource assessment of Penglaizhen play The Penglaizhen play consists of structural-lithological combination traps in sandstone reservoirs of Upper Jurassic age. Drilling depths range from 400 to 1600 m. By the end of 2005, a total of 30 exploratory wells and 60 appraisal well were drilled, resulting in 7 gas discoveries (Hexingchang gas field, Xinchang gas field and Majing gas field, Xiaoquan gas field, Dongtai gas field, Xindu gas field, and Luodai gas field) with the in place reserves of m 3 of natural gas ( m 3 recoverable). The Exploratory well density is 0.01 well / km Volume 2: Final Report of the China Case Study

120 1) Petroleum geology The reservoir rocks consist of a light green-gray, fine-grained detrital sandstones and quartzose sandstones deposited in river channel, deltaic plain and front sand bar environments, with the thickness of m. Porosity may ranges from 4 to 20 %, with the mean value of 13%, and average permeability is 3.6 md. Potential source rocks may be the black mudstone and shale in the fifth member of Xujiahe formations. In addition, it is probable that the gas in this play is provided from the source rocks of the 2 nd, 3 rd and 4 th members of Xujiahe formation. Sealing rocks consist of the mudstones of the upper part of Penglaizhen play reservoirs and as much as 100 m. of Cretaceous mudstones. Postulated traps in this play are mostly structural-lithological trap or superposed structure trap. 2) Result of resource assessment The assessment data form is shown in table 32 and the result of resource assessment can be summarized as the following (table 33 and fig. 12): - The unconditional prospect probability of Penglaizhen play is The total gas resource in place is estimated to range from 667 to m 3, at the 0.90 and 0.10 probability levels. Mean in place value is calculated to be m 3. - The yield factor of gas resource in place ranges from 6.68 to m 3 /m 3 pore space, with the mean value of 9.84 m 3 / m 3 pore space. - Based on the mean value of pool size by rank, the number of gas accumulation is estimated to be 12. Table 32 Play Attitudes Prospect Attitudes The input parameters of geologic risk analysis in Penglaizhen play Attribute Probability of Favorable or Present Source Rock 1.0 Timing 1.0 Migration 1.0 Reservoir Facies 1.0 Marginal Play Probability 1.0 Trapping Mechanism 0.8 Effective Porosity 0.8 Hydrocarbon Accumulation 0.8 Conditional Deposit Probability Volume 2: Final Report of the China Case Study 113

121 attributes probability P95 P50 P5 Hydrocarbon volume parameters Area of closure (km2) Reservoir thickness (m) Geometric factor Effective porosity (%) Hydrocarbon saturation (%) Trap fill (%) Reservoir depth (m) Recovery gas factor (%) Hydrocarbon mix (%) 100 The number of prospect Table 33 Geological risk-resource assessment in Penglaizhen play Play Deposit Probability of play marginal conditional Risk analysis discovery probability probability Play risk Resource assessment (108m3) Mean value P90% P50% P10% Natural gas resource in place Natural gas resource recoverable Pool size by rank (108m3) Mean value P90% P50% P10% Total Volume 2: Final Report of the China Case Study

122 Fig.11 Distribution of natural gas resources in place in Penglaizhen play 3.5 Summary of gas resource assessment in the middle part of the Western Sichuan depression The results of gas resource assessment in the middle part of Western Sichuan depression indicate that (1) The total natural gas resources in place is estimated to be m 3 and undiscovered gas resource in place is m 3, with the 35% of discovery maturity (percentage of ultimately proven and probable reserves with respect to total resources, (2) The number of gas accumulation is calculated to be 48, with the size of gas accumulation ranging from 33 (P90%) to 230 (P10%) 10 8 m 3,(3) The most significant play in terms of undiscovered resource contribution is the Xu2 play, containing approximately 34 percent of total undiscovered resources in Western Sichuan depression. Following this play, in order of decreasing importance, are the Xu4 play and the Shaximiao play, accounting for approximately 30 and 29 percent in total undiscovered resources in Western Sichuan depression, respectively (table 34). Table 34 Natural gas resource assessment in Western Sichuan depression Xu2 Xu4 Shaximiao Penglaizhen play play play play Total Resources in place (10 8 m 3 ) % of total resource in place / Proven reserves (10 8 m 3 ) / Probable reserves (10 8 m 3 ) Undiscovered resource in place (10 8 m 3 ) % of total undiscovered resource in place / Number of gas accumulation Discovery maturity Volume 2: Final Report of the China Case Study 115

123 3.7 Play economic analysis Based on the pool size by rank, economic analysis of prospect and minimum economic size of natural gas field, the economic analysis are conducted for the Xu2, Xu4, Shaximiao and Penglaizhen plays (table 34). The analysis results indicate that 1) the highest investment-income ratio can be available in Xu2 play in term of the unit NPV of recoverable resource, 2) the total NPV is yuan for Xu2 play, yuan for Xu4 play, yuan for Shaximiao play and yuan for Penglaizhen play, respectively, and investment along proper lines should be focused on Xu2 play, Xu4 play and Shaximiao play because the Penglaizhen play is mature play, 3) the expectably discovered gas pools in the Xu2 play, Xu4 play, Shaximiao play and Penglaizhen play are economically recoverable. Play Recoverable resources (10 8 m 3 ) Table 34 Play economic analysis Unit NPV of recoverable resources (USD/10 3 m 3 ) Unit revenue of recoverable resources (USD/10 3 m 3 ) Pe minimum economic size (10 8 m 3 ) Total NPV (10 8 USD) Expected NPV (10 8 USD) Xu Xu Shaximiao Penglaizhen Total Volume 2: Final Report of the China Case Study

124 3.8 Resource and economic analysis of key prospects in the Western Sichuan depression A total of 9 prospects, i.e. Xinchang, Fenggu, Xindu, Weijiang, Luojiang, Bailuchang, Dayuanbao, Majin and Hexinchang prospects, are selected for resource and economic analysis (fig. 12, table 35). Fig. 12 The location map of key prospects Volume 2: Final Report of the China Case Study 117

125 Table 35 Resource-economic evaluation of key prospect in the Western Sichuan depression Probability Resource in Prospect of discovery place(10 8 m 3 ) Xu2,Dayuanbao T2L,Dayuanbao Dayuanbao Xu2,Dayuanbao T2L,Bailuchang Decision tree economic economic Bailuchang Penglaizheng,Xindu Shaximiao,Xindu economic Xindu Penglaizheng,Wenjiang non-economic Xu2,Luojiang Xu4,Luojiang economic Luojiang Xu4,Xinchang Xu2,Xinchang economic Xinchang Results of resource and economic analysis 1) For the Xu2 and Xu4 plays, the Xu2 reservoir of Xinchang prospect is considered to be the first priority for gas exploration; the Xu4 reservoir of Fenggu prospect and Xu2 and Xu4 reservoirs of Luojiang prospect are evaluated to have a great gas resource and economic potential. 2) For the Shaximiao play, the Xindu prospect is considered to have the first priority for gas exploration. 3) For the Bailuchang and Dayuanbao prospects located in the upper (hanging) wall and lower wall of Longmenshan thrust belt, respectively. Their Leikoupo reservoir (Middle Triassic, T 2 L) and Xu2 reservoir (Upper Triassic) have a better exploration potential. The joint distribution of discovery probability and natural gas resources of T 2 L and Xu2 reservoirs in the Bailuchang and Dayuanbao prospects are shown in Table and Fig respectively. 118 Volume 2: Final Report of the China Case Study

126 4) Table 36 Resource assessment and economic analysis in Dayuanbao prospect Mean P90 P50 P10 Gas in place (10 8 m 3 ) Gas recoverable (10 8 m 3 ) Condensate recoverable (10 6 m 3 OE) NPV (10 6 USD) IRR(%) EMR (10 6 USD) NTER(Yr) Total revenue (10 6 USD) Capex (10 6 USD) Opex (10 6 USD) Total tax (10 6 USD) Net cashflow after tax (10 6 USD) Table 37 Resource assessment and economic analysis in Bailuchang prospect Mean P90 P50 P10 Gas in place (108m3) Gas recoverable (108m3) Condensate recoverable (10 6 m 3 OE) NPV (10 6 USD) IRR(%) EMR (10 6 USD) NTER(Yr) Total revenue (10 6 USD) Capex (10 6 USD) Opex (10 6 USD) Total tax (10 6 USD) Net cash flow after tax (10 6 USD) Volume 2: Final Report of the China Case Study 119

127 Table 38 Joint discovery probability of Dayuanbao Prospect Xu2 T2L Prob. (%) Cum.(%) : discovery ; : dry Table 39 Joint discovery probability of Bailuchang Prospect Xu2 T2L Prob. (%) Cum.(%) : discovery ; : dry 120 Volume 2: Final Report of the China Case Study

128 Fig. 13 Production profile in Dayuanbao Prospect Fig. 14 Net cash flow after tax in Dayuanbao prospect Volume 2: Final Report of the China Case Study 121

129 Fig 15 Decision tree in Dayuanbao prospect 3.9 Comparison of predrilling estimates and afterdrilling results In order to analysis the accuracy of resource assessment and the uncertainty of input parameters, a comparison between predrilling resource estimates and afterdrilling reserve calculation are made for the Xu2 reservoir of Hexingchang prospect, the Xu4 reservoir of Fenggu prospect, the Shaximiao reservoir of Majing prospect and the Penglaizhen reservoir of Xindu prospect (table 40-41). Its results indicate that the in place reserves for the Xu2 reservoir of Hexingchang prospect, the Shaximiao reservoir of Majing prospect and the Penglaizhen reservoir of Xindu prospect account only for 44-64% of their predrilling gas resources, which is mainly caused by the overestimates of closure area and reservoir thickness in predrilling estimates. Table 40 Comparison between natural gas resources and reserves (10 8 m 3 ) Xu2 Hexingchang Xu4 Fenggu Shaximiao Majing Penglaizhen Xindu Resource in place P90%-10% Mean value Resource recoverable Mean value Reserves in place (mean value) Recoverable reserves ( mean value) Volume 2: Final Report of the China Case Study

130 Table 41 Comparison of major parameters in resource assessment and reserve calculation Major parameters Xu2 Hexingchang Xu4 Fenggu Shaximiao Majing Penglaizhen Xindu ( mean value) resource reserve resource reserve resource reserve resource reserve Area of closure (km 2 ) Reservoir thickness(m) Effective porosity(%) Hydrocarbon saturation (%) Gas recovery (%) Gas volume factor (m 3 /10 3 m 3 ) Reserve in place(10 8 m 3 ) Recoverable reserve (10 8 m 3 ) Exploration and development options 4.1 The exploration and development technique for the Western Sichuan Depression 1) Gas reservoir description technique The technique of tight gas reservoir description has been developed based on the integrated study of petroleum geology and geophysics, including the regional geology, seismology, well testing, production testing, special processing and analysis of geophysical prospecting and nerve-network technology, which can be used for the accurate exploration and development of tight gas reservoir. 2) Fracturing techniques A special sand fracturing techniques has been developed, by which the potential fractures can be fractured and new fractures can be successfully created in the tight sandstone reservoirs with the buried depths of less than 3500 m. Volume 2: Final Report of the China Case Study 123

131 3) Reservoir prediction technique A reservoir prediction technique has been developed on the basis the special processing and interpretation of geophysical prospect data and nerve-network technique, which can be used for the accurate prediction of the shallow to medium-deep tight gas reservoirs with the buried depths of less than 3500 m. 4.2 Exploration and development problems and difficulty in the Western Sichuan depression 1) Development technique for difficultly produced-reserves The difficultly produced-reserves, caused by the poor permeability and porosity of gas reservoirs and low productive capacity of gas wells, account for the 30% of the total reserves in the Western Sichuan depression. How to develop economically this part of reserves is the main challenge faced with the gas production in the Western Sichuan depression. 2) Low drilling rates in the deep gas reservoirs In the Xu2 and Xu4 plays, the burial of tight sandstone reservoirs range from 4600 to 4900 m. The drilling rate is very low due to the high abrasiveness property of the tight sandstones. The reservoirs are easy to be harmed under the high temperature and high pressure conditions. Therefore, how to increase the drilling rates in the deep reservoirs and to protect the reservoir effectively are the another challenge faced on the gas exploration and development in the Western Sichuan depression. 3) Fracture prediction technique The percolation of fracture to storage space is the key to obtain the commercial flow from the tight sandstone gas reservoirs, especially from the deep tight sandstone gas reservoirs. At present, the prediction of natural fracture is still very difficult, which lead to the low success ratio of exploratory wells in the Western Sichuan depression. 4) Rupture pressure indexes of deep reservoir is too high to fracture the reservoir The rupture pressure index of deep (more than 4000 m.) reservoir is as high as 3.0 in the Xu2 and Xu4 plays. A matter of the utmost concern is that if deep fracturing can be carried out and artificial fractures can be created on the condition that natural fractures can not be effectively predicted at present. 4.3 The countermeasure to the exploration and development problems of the Western Sichuan depression In accordance with the above exploration and development problems, the countermeasures taken by the Southwest Petroleum Company, SINOPEC are as follows: 124 Volume 2: Final Report of the China Case Study

132 1) Developing the difficultly produced reserves As for the development of difficultly produced- reserves, it is necessary (1) to carry out the test of horizontal drilling and horizontal fracturing in order to get the effective development parameters, (2) to apply the advanced techniques of the development of marginal gas reservoirs in the world. 2) Increasing the deep drilling rate and realizing the reservoir protection At present, the techniques for increasing the deep drilling rate, such as composite work model, air drilling technique, and suitable mud formula technique are researching. 3) Improving the accuracy of fracture prediction 4) Importing the advanced equipments and technology for the effective fracturing of deep reservoirs 5. Marketing options 5.1 Gas resources and market in China China s natural gas in place resource is estimated to be 47.4 trillion cubic meters, mostly distributed in Tarim, Qaidam, Ordos, Sichuan, Songliao, East China Sea and South China Sea basins (fig. 16), among which the gas resources of Tarim, Qaidam, Ordos and Sichuan basins reach 28.4 trillion cubic meters, accounting for 60% of the national total. At year-end 2005, the estimate of recoverable reserves of gas remaining in China was around 2.09 trillion meters. It is expected that the China s recoverable reserves in 2020 may reach 5.6 trillion cubic meters based on the average annual rate of reserve addition in and geologic characteristics of Chinese petroleum basins. The consumption of natural gas in China in 2005 is m 3, of which the chemical industry sector and industrial fuel sector account for 39% and 32% of the China s total consumption, respectively (table 42-43). It accounts only for 3% of all the primary energy consumed in China, which is far lower than the world average (24%) and the Asian average (8.8%). The gas market in China can be subsided into 7 consumption regions: (1) Southwest market centered at Chengdu and Chongqing; (2) Jing-jin market centered at Beijing and Tainjin; (3) East China market centered at Nanjing, Shanghai and Hangzhou; (4) Shangdong market centered at Qingdao and Jinan; (5) Northeast China market centered at Changchen.; (6) South China market centered at Guanzhou and Hongkong; (7) Central market centered at Wuhan, Xian and Zhengzhou. It is forecasted that the consumption of natural gas in China will be increased into m 3 in Volume 2: Final Report of the China Case Study 125

133 By the end of 2003, the total length of the natural gas pipelines in China was 21 thousand km., represented by such long-distance gas pipelines as West-East pipeline, Jingbain-Beijing pipeline, Sebei-Xining-Lanzhou pipeline and Ya 13-1-Hong Kong pipeline (fig. 17). Table 42 Natural gas consumption in China Percentage in gas consumption Chemical industry 39 Industrial fuel 32 Residential & commercial 24 Electric power 5 Table 43 Supply and demand of natural gas in China Production (10 8 m 3) Demand (10 8 m 3 ) Volume 2: Final Report of the China Case Study

134 Fig. 16 Petroliferous basins in China Fig. 17 Natural Gas Pipelines in China Volume 2: Final Report of the China Case Study 127

135 5.2 Natural gas price and pricing mechanism in China 1) The natural gas price in China is obviously lower than that in international market. The natural gas price in China in 2003 is RMB/m 3, while the natural gas price in international market in the same period is 1.8 RMB/m 3. 2) There are two pricing mechanism systems in China, i.e. the pricing mechanism system under government management and the pricing mechanism system under market competition. 5.3 Natural gas consumption in Sichuan region In Sichuan region, the consumption of natural gas is m 3 in 2004, of which the natural gas sealed and distributed by the Southwest Petroleum Company, SINOPEC, accounts for 21%. Its consumption structure is shown in table 44. Table 44 Natural gas consumption in Sichuan region consumption (10 8 m 3 ) percentage Chemical fertilizer Other industry Residential Commercial Total Chemical fertilizer and industry fuels are the two largest uses of natural gas in Sichuan economy, consuming 49 percent and 37.6 percent, respectively, of the Sichuan s total gas requirement. In general, the basic situation of gas production and demand in Sichuan region is the following: - The increased trend gas consumption will be continuously maintained in building material, CNG, gas generation and residential usage. - There is considerable potential for increased gas consumption in methyl alcohol production. The yearly addition of the gas demand will achieve m 3 if the 20% of vehicle-used oil is replaced by the methyl alcohol---the main product of the chemical industry sector. - There is possibility for decreased gas consumption in chemical fertilizer, especially urea production. If the natural gas industry can successfully expand its production and distribution capability, maintain its energy price advantage, and continue the development of energy efficient gas-fired technologies, there is significant opportunity for greater consumption of natural gas in the Western Sichuan region. - For electricity generation, the gas consumption increased from m 3 to m 3 in By future plan, the gas turbine power plants will be built with the total installed capacity of KW. The yearly addition of gas consumption is forecasted to be m 3 for electricity generation. 128 Volume 2: Final Report of the China Case Study

136 - In order to reduce the manmade contribution of greenhouse gases to atmosphere, the government has issued the energy policy to encourage and support the development of CNG industry. By the end of 2002, there are more than 200 CNG station and CNG-powered vehicles in Sichuan region. It is forecasted that the yearly addition of gas consumption will be m 3 for CNG industry in near future. 5.4 Prediction of natural gas price The natural gas price in Western Sichuan region was increased from RMB/m 3 in 1990 to RMB/m 3 in 2006, with a yearly increase rate of 4.8%, which is much lower than that of other energy. It is forecasted that the natural gas price will be increased into RMB/m 3 in 2010 and RMB/m 3 in 2020, respectively (table 45 and fig.18). Table 45 Prediction of natural gas price in Western Sichuan region Years Price (RMB/m 3 ) Fig.18 Prediction of natural gas price in Western Sichuan region 6. Resource management strategies 6.1 Establishing the natural gas related laws` Currently, there are no special laws governing the oil and natural gas industry in China. To promote the orderly competition and standardized operation, China should lose no tome in accelerating the establishment and completion of the laws and regulations related to the oil and natural gas industry. Volume 2: Final Report of the China Case Study 129

137 6.2 Increasing the sale price of natural gas The ongoing pricing system cannot provide enough economic incentive for significantly increased gas exploration and development activity, which make natural gas short of the competitive edge compared to other substitutive energies. Some gas fields are still losing money. Unreasonable prices will lead to the unreasonable utilization of resources. The sale price of natural gas should be increased to reflect the changes of the relationship between supply and demand in the market. 6.3 Formulating the environment protection rules The State environment protection organization should lay down the environment protection rules, such as collecting the carbon tax on coal use and reducing the tax on natural gas use and fired-gas equipments. 6.4 Tax credit The natural gas in the Western Sichuan depression is mainly produced from tight sandstone reservoirs. The daily production of most wells is less than m 3. Therefore, in order to encourage and support oil company for developing and utilizing the low-grade natural gas resources, there is a need for government to carry out a tax (income tax, added value tax, etc.) credit policy. 6.5 Strengthening environment protection It is obvious that increased use of natural gas would reduce the air pollution. In Xinchang gas field, 1m 3 gas is equivalent to 1.5 kg coal by their heat value based on the heat value of natural gas. The natural gas production in Xinchang gas field in 2003 is m 3, which means that the SO 2 and smoke particulate emissions would be reduced by t/year and t/year, respectively, if coal is replaced by gas. On the other hand, natural gas exploration and production have also the potential to disrupt the agricultural ecosystems around gas fields due to road and wellsite construction. The report on the environment evaluation of development project in the Shuangyang oil and gas field indicates that in second plowing land the crop production is significantly decreased and the protein and fat contents of crops are also lower than that of reference points (table 46). This is important issues that merit further research. 130 Volume 2: Final Report of the China Case Study

138 Table 46 testing results of crop samples in second plowing land Sampling 43m wellsite from 50m from wellsite 60m from wellsite Reference point location Testing results protein content,% fat content,% Fluorine content(μg/kg) Weight of 100 seeds (g) Production (kg/10 3 are) Length of crop ear (cm) Mercury content (mg/kg) <0.005 <0.005 <0.005 <0.005 Cadmium content (mg/kg) <0.003 <0.003 <0.003 < Licensing,contractual and fiscal conditions 7.1 Licence Terms 1) Offshore Exploration and Production A. Offshore Exploration Area: There are no restrictions on the area available. The contract area comprises a number of "basic blocks", which are defined as areas of 10 minutes latitude by 10 minutes longitude. Duration: Seven years divided into three phases (3+2+2). The final period may be extended for appraisal work. There is an additional holding period for a gas discovery of up to 10 years from the end of the exploration period if it does not reach target volumes for purchase by China s national oil company or agreement on the terms of the purchase has not been reached. Relinquishment: The relinquishment at the end of each phase of the exploration period is shown in the Table 47. Table 47 Relinquishment obligations of offshore oil and gas exploration Phase Relinquishment Obligations 1 (end of Year 3) 25% of original contract area 2 (end of Year 5) 25% of remaining contract area excluding development and production areas 3 (normally end of Year 7 or later if extended) The remaining contract area excluding development areas, production areas and/or appraisal areas Volume 2: Final Report of the China Case Study 131

139 Exploration Obligations: Negotiable exploration commitments are expressed in terms of minimum work commitments and expected minimum expenditures for each phase of the exploration period, with work commitments taking precedence over expenditure commitments. Bonuses and Fees: All four offshore licensing rounds had signature bonuses of US$ 1 million. The third and fourth round terms provided for signature bonuses to be paid in three installments - US$ 250,000 at contract signature, US$ 250,000 on entry into the second exploration phase (or in the prior event of beginning appraisal operations), with the balance payable on approval of the development plan for the first oil or gas field in the contract area. The signature bonus is a non-recoverable cost. For the 2002 deep water round the signature bonus was not required to be paid until a development plan was submitted, meaning in effect the bonus was not paid until discovery. Rental: None. B. Offshore Production Area: The development and production areas are selected by the operator in accord with China s national oil company. Duration: The development period begins on the date of approval of the overall development programme and ends on the date of completion of the development operations approved under the overall development programme. The production period runs for 15 years beginning on the date of commencement of commercial production. Extensions to the production period may be granted. There is also provision for the temporary suspension of production, with the duration of the production period extended accordingly. However, it cannot be extended beyond 15 years except in the event of force majeure. Bonuses and Fees: There are no production bonuses. The contractor is required to prepare separate training and technology transfer programmes for Chinese personnel in the development phase and the production phase of the project. Indicative amounts for these programmes are understood to be around US$ 50,000 per annum. Training costs are recoverable. Rental: None. 2) Onshore Exploration and Production A. Onshore Exploration Area: There are no restrictions on the area available. The contract area comprises a number of "basic blocks" which are defined as areas of 10 minutes latitude by 10 minutes longitude. 132 Volume 2: Final Report of the China Case Study

140 Duration: Under the terms of the 2001 round, the exploration period is five to seven years divided into two to three phases. The exploration period for the first round and third rounds was eight years (4+2+2), the extra year reflecting the remote location of the Tarim and Junggar basin acreage. The exploration period for the second round was seven years divided into three phases (3+2+2). There is a holding period of up to seven years after the end of the exploration period for a gas discovery which is potentially commercial but for which there is no market at the time. Relinquishment: A relinquishment schedule is established for each bidding round in the model contract. However, in practice the schedule can be negotiated to reflect the nature of the block. The relinquishment in 2001 round schedules were as follows (table 48): Table 48 Relinquishment obligations of onshore oil and gas exploration End of Exploration Phase Area Reduction 1st 2nd 3rd 40% of original contract area 25% of remaining contract area less development/production areas The remaining contract area, except for development/production areas, retention areas, and/or appraisal areas Exploration Obligations: Negotiable commitments are expressed in terms of minimum work commitments and expected minimum expenditures for each phase of the exploration period, with work commitments taking precedence. Bonuses and Fees: A signature bonus of US$ 1 million is required and not recoverable. There is a mandatory training fee throughout the entire project, indicatively US$ 250,000 per annum. Rental: None. B. Onshore Production Area: The development and production area as selected by the operator, demarcated by the Joint Management Committee (JMC) and approved by China s national oil company. Duration: The development period begins on the date the development programme is approved and ends when commercial production begins. The development contracts and enhanced oil recovery (EOR) contracts provide for a two year pilot test period. The production period runs for 15 years beginning on the date of commencement of commercial production for exploration projects or after the pilot test period in the case of EOR projects, and 20 years after the pilot test period for development contracts. Extensions to the Volume 2: Final Report of the China Case Study 133

141 production period may be allowed. However, the overall contract term must not exceed 30 years in the case of exploration contracts and development contracts and 20 years in the case of EOR contracts. Bonuses and Fees: No provision for a production bonus. Annual training fees apply (see above under Exploration). Rental: None for the production phase. 7.2 Fiscal Terms Royalty - Offshore: The incremental sliding scale is based on the following percentages of annual gross crude oil production from each field in the contract area (table 49): Table 49 Royalty Rate of offshore oil and gas exploration Increment of Annual Oil Production Royalty Rate Million tonne/year MBOPD* % < 1.0 < > 4.0 > * Assumes 1 tonne = 7.3 barrels Royalty on gas from each field in the contract area is paid on the following incremental sliding scale (table 50-54): 134 Volume 2: Final Report of the China Case Study

142 Table 50 Increments of Annual Gross Production Billion cubic metres (m³) /year The royalty rate of gas fields Royalty Rate MMCFD* % < 2.0 < > 5.0 > * assumes 35.3 cubic feet (CF) = 1 m³ (cubic metre) Royalty - Onshore: Table 51 The Royalty on Oil Fields - Qinhai Province, Tibet Autonomous Region, Xinjiang Vigur Autonomous Region and Shallow Sea Areas Increment Gross Production Royalty Rate Million tonnes/year MBOPD* % < 1.0 < > 4.0 > * Assumes 1 tonne = 7.3 barrels Volume 2: Final Report of the China Case Study 135

143 Table 52 The Royalty on Gas Fields - Qinhai Province, Tibet Autonomous Region, Xinjian Vigur Autonomous Region and Shallow Sea Areas Increment Gross Production Billion cubic metres (m³)/year Royalty Rate MMCFD* % < 2.0 < > 5.0 > * assumes 35.3 cubic feet (CF) = 1 m³ (cubic metre) Royalty on Oil Fields - Other Onshore Areas: Increments of Annual Gross Production Million tonnes/year Royalty Rate MBOPD* % < 0.5 < > 4.0 > * assumes 7.3 BBL = 1 tonne Table 54 the Royalty on Gas Fields - Other Onshore Areas Increments of Annual Gross Royalty Rate Production Billion m³ /year MMCFD* % < 1.0 < > 5.0 > * assumes 35.3 cubic feet = 1 cubic metre 136 Volume 2: Final Report of the China Case Study

144 Cost Recovery: All costs are expensed and recovered from a maximum of 60% of gross production in the case of an oil field and 70% of the gross production in the case of a gas field. Ring Fence for Cost Recovery: There is a ring fence around the contract area for cost recovery purposes. Profit Sharing: Oil production remaining after royalty, VAT and cost recovery is identified as "remainder oil" which is divided into "share oil" of the Chinese side and "allocable remainder oil". Allocable remainder oil (i.e. the contractor's profit oil) is determined annually on an incremental sliding scale linked to average daily production. The allocable remainder oil is then shared by the parties to the contract in proportion to their participating interests in the development costs. Typically this would be 51% to China and 49% to the other party or parties which make up the contractor. Thus, a foreign investor's profit share would typically be 49% of the values shown under the allocable remainder oil columns in the table above. There is a provision for the profit sharing for natural gas to be different from that for oil. The profit shares for gas are to be agreed by negotiation between the parties such that the contractor is able to obtain a reasonable economic benefit from the project. Taxation: 33% (comprising 30% national income tax plus a 3% local income tax) of cost recovery plus profit share less operating costs, E&A costs and depreciation of development capital over six years on a straight-line basis. The local component of income tax may be and is often waived. Deductions and Depreciation: Expenses incurred before the conclusion of the contract (e.g. geophysical survey expenses and signature fees) may be amortized (over a minimum of one year) against income from the fields in production. Exploration expenditures are treated as capital and are deductible from taxable income in the year in which they occur. Development expenditures are capitalized and depreciated over a minimum six years straight-line starting from the month after commercial production begins. Capital expenditure incurred after the start of commercial production, is accumulated on a yearly basis and starts to be depreciated over a minimum of six years from the following year. Ring Fence for Income Tax: There is a ring fence around the contract area for tax purposes. However, the General Taxation Bureau of the Ministry of Finance announced modifications in 1988 relaxing the ring fence. Abortive exploration expenses anywhere in China maybe offset against taxable income, although costs cannot be amortized for less than one year. If a foreign operator terminates a sole contract, expenses from that operation can be carried over to reduce income taxes payable on any new contract signed within 10 years of the termination date of the first agreement. These modifications were enshrined in the 1991 Income Tax Law. Volume 2: Final Report of the China Case Study 137

145 Value Added Tax: The model contracts require the contractor to pay VAT in accordance with relevant regulations of the People's Republic of China. Withholding Tax: Profits of foreign investment enterprises and foreign enterprises either in the nature of dividends or branch profits are not subject to any withholding tax when remitted outside the People's Republic of China. Timing of Payments: Tax payments are due quarterly in arrears. The tax year is the calendar year. Outstanding tax liability must be settled within five months of the end of the tax year. Valuation: Market price is used for tax purposes. Domestic Supply Obligation: None. The contractor may freely dispose of its crude oil apart from certain destinations excluded for political reasons. 8. Recommendations 8.1 Exploration risk The internal guideline and procedures of risk analysis for the major Chinese petroleum basin should be developed to estimate the probability of making a discovery in play and prospect levels. 8.2 Resource assessment and economic analysis Carry out a thorough natural gas resource and economic assessment for all the plays and prospects in the Western Sichuan depression using GeoX software and other resource assessment tools. Make a comparison between predrilling resource estimates and afterdrilling reserve calculation to analyze the accuracy of resource assessment and uncertainty of input parameter. The concept and methodology of play resource assessment and economic analysis introduced by PPM project can be applied in China s future petroleum resource assessment. 8.3 Exploration and Development options Conduct the systematical analysis of accumulation mechanism of tight gas reservoirs. Select the favorable traps for drilling on the basis of resource and economic evaluation in the levels of play, reservoir and segment. Improve the exploration and development techniques suitable for tight sandstone reservoir, including fracture prediction, horizontal drilling, air drilling, multilayer hydraulic fracturing, etc. 138 Volume 2: Final Report of the China Case Study

146 Increase the deep drilling rate to realize the reservoir protection. Apply the advanced techniques of the development of marginal gas field in the world. 8.4 Gas market Establish a legal framework on natural gas. Establish a reasonable pricing mechanism of natural gas. Issue the tax credit policy for the exploration and development of tight sandstone gas. Accelerate the construction of gas pipeline networks and the development of natural gas market in the Western Sichuan depression, especially the consumption of natural gas in electricity generation and CNG.. Volume 2: Final Report of the China Case Study 139

147 Volume 2: Final Report of the Indonesia Case Study Case Study 4 (Mature Basin): Kutei Basin, Indonesia 1. Introduction The Kutai Basin of the East Kalimantan was nominated by Indonesia for a case study under the Mature Basin category. During the conduct of the case study, 4 workshops and 2 expert visits have been organized in Indonesia with a total number of 230 participants attended those events, of which 69 persons were from the CCOP Member Countries. The Research and Development Center for Oil and Gas Technology LEMIGAS as the focal point in the PPM Project of the Mature Kutai Basin Case Study, is the National Coordinator of the Project under the National Project Coordinator Committee. The Chairman of this Committee is the Permanent Representative of Indonesia to CCOP, the Head of the Geological Agency of Indonesia. The team of the Indonesia PPM, host of the case study, consists of 44 persons composed mostly geoscientists from PPPTMGB LEMIGAS, Directorate General of MIGAS, Pusdiklat MIGAS, BPMIGAS, BPH MIGAS and PERTAMINA. As a member of CCOP, Indonesia also participated in attending the workshops and expert visits conducted by other case studies with a total number of 35 persons, 12 persons to the Cambodia Case Study, 10 persons to the China Case Study, 5 persons to the Philippines Case Study, and 8 persons attended the PPM Seminars. The objective of the case study is to conduct a resource assessment and economic analysis of parts or the whole basin. The principal and procedures of geological risk analysis were discussed during the workshops. The effect of various framework conditions and their impact on profitability of fields and prospects were also evaluated through the workshops. Team Members When the Project team was first established, the core consisted of: No. Name Position Governmental Agency 1. Bambang Wicaksono National Coordinator LEMIGAS 2. Sasongko Hadipandoyo National Coordinator LEMIGAS 3. Barlian Yulihanto Sr. Geologist LEMIGAS 4. Agus Guntur Sr. Geologist LEMIGAS 5. Silambi Palamba Sr. Economist LEMIGAS 6. Jonathan Setyoko Geologist LEMIGAS 7. Achmad Nurdjajadi Geologist LEMIGAS 8. Suprijanto Geologist LEMIGAS 9. Doddy Pribadi Geologist DG Migas 10. Bayu Wahyudiono Geologist DG Migas 11. Abdullah Sodik Reservoir Geologist BPMIGAS 12. Djoko Sumalyo Geologist BPMIGAS 13. Sutoyo Lecturer PUSDIKLAT MIGAS 14. Yohannes P. Koesoemo Geologist Lecturer PUSDIKLAT MIGAS 140 Volume 2: Final Report of the Indonesia Case Study

148 The supporting team was then established as the case study progressed, which consisted of: No. Name Position Governmental Agency 1. Rida Mulyana Petroleum Engineer LEMIGAS 2. Tunggal Petroleum Engineer LEMIGAS 3. Yusep C. Kartiwa Petroleum Engineer LEMIGAS 4. Andi Ruswandi Sedimentologist LEMIGAS 5. Sundoro Geologist LEMIGAS 6. Suprayitno Munadi Sr. Geophysicist LEMIGAS 7. Bambang Wiyanto Geologist LEMIGAS 8. Sri Wijaya Geologist LEMIGAS 9. Isnawati Geophysicist LEMIGAS 10. Anjar Sumarsono Geologist LEMIGAS 11. Fina Riandra Geologist LEMIGAS 12. Bambang Widarsono Petroleum Engineer LEMIGAS 13. Sugihardjo Petroleum Engineer LEMIGAS 14. Letty Brioletty Petroleum Engineer LEMIGAS 15. Nurkamelia Petroleum Engineer LEMIGAS 16. Sigit Pudiarto Petroleum Engineer LEMIGAS 17. Supriyatno Petroleum Engineer LEMIGAS 18. Septi Anggraeni Petroleum Engineer LEMIGAS 19. Supriadi Petroleum Engineer LEMIGAS 20. Diana Dwiyanarti Petroleum Engineer LEMIGAS 21. Hermansyah Geophysicist LEMIGAS 22. Laode Sulaiman Economist LEMIGAS 23. Bob Yulian Geophysicist BPMIGAS 24. Sulistya Hastuti Geologist BPMIGAS 25. Eddy Hermanto Geologist BPMIGAS 26. Eddy M. Suharyadi Geologist BPH MIGAS 27. Sri Wahyu Purwanto Geologist BPH MIGAS 28. Hazuardi Geologist Lecturer Pusdiklat Migas 29. Asyik Kurniawan Geologist Lecturer Pusdiklat Migas 30. Teguh Wibowo Geologist PERTAMINA Activities conducted Activities Date Location Topic Number of Participants Workshops Workshop I Jul 2003 Yogyakarta General overview of the case study basin, petroleum activities and resource assessments methodology Workshop II 8-13 Mar 2004 Bandung POD (1), Fiscal System, and Economical Analysis using GeoX Software 38 (11 MC) 47 (19 MC) Workshop III Jul 2005 Surabaya POD(2), Marginal Field 54 (15 MC) Workshop IV Jun 2006 Jakarta EOR/IOR Technologies and the Role of 45 (14 MC) Volume 2: Final Report of the Indonesia Case Study 141

149 Government to Attract New/Additional Investment in a Mature Basin Expert Visits Expert Visit I 6-9 Dec 2004 Jakarta Short Course on Economic Modeling For Oil and Gas Fields and Expert Visit II Dec 2005 Carita, Banten Prospects Short Courses on Deepwater Technology 23 (3 MC) 23 (7 MC) Total number of participants = 230 CCOP Member Countries = Resource Assessment Kutai Basin is the largest and the deepest basin in the Western Indonesia. It occupies an area of about sq. km in the onshore an offshore area of East Kalimantan (Figure 1). Sediment thickness is up to 14 km thick in the deepest part of the basin. The basin is bounded to the north by the Mangkalihat High; to the south the basin hinges on the Adang- Flexure (Adang-Paternoster Fault); to the west it is terminated by the Kuching High of the Kalimantan Central Ranges; and to the east it opens into the Strait of Makassar. Figure 1. Location map of Kutai Basin 142 Volume 2: Final Report of the Indonesia Case Study

150 Exploration History in Kutai basin began in the late nineteenth century, followed by discovery at Sanga-Sanga in 1897, Balikpapan in 1898, Semberah-Pelarang in 1906, and Samboja in The latest discovery is West Seno (2001). 3. Regional Geology a. Tectonic Setting Structurally the Kutai Basin can be divided into Upper Kutai Basin in the west and Lower Kutai Basin in the east. Upper Kutai Basin located in the onshore area, while Lower Kutai Basin occupies offshore area. The onshore portion of the Mahakam Delta overlies a series tightly folded anticlines and broad synclines known collectively as the Samarinda Anticlinorium (Figure 2), which resulted from inversion of the Palaeogene basin (Chambers and Daley, 1995). Offshore Mahakam Delta areas show at least two phases of deformation. Middle Miocene and older rocks exhibit compressional folding and thrusting, while the overlying Upper Miocene- Pliocene strata are only affected by extensional faulting (Malecek et al., 1993). Toward offshore area, the Lower Kutai Basin passes laterally into the North Makassar Basin. The offshore Kutai Basin is estimated to have over 9,000 m sediments fill. However, only the upper 6,000 m, of Neogene sediments are the main interest for petroleum exploration activities. Volume 2: Final Report of the Indonesia Case Study 143

151 Figure 2. Tectonic elements of Kutai Basin b. Stratigraphy The stratigraphy of Kutai Basin consists of Tertiary rocks overlain Pretertiary Basement (Figure 3). The first sedimentation in Kutai Basin occurred when Tanjung Group (Kiham Haloq Formation, Beriun Fm., and Mangkupa Fm.) unconformably overlies Cretaceous metamorphic basement during Middle to late Eocene. It comprises a fine upward sequence with terrestrial sandstones at the base and marine shales at the top. The Early Oligocene sediments in the Lower Kutai Basin/North Makassar Basin was deposited on a marine shelf that regionally transgressed the top of the Middle Eocene sediment. Generally, the area of the North Makassar Basin and its adjacent area were quite during this period, limestones were developed in the shallower part (kedango Fm.), and deep marine shales were deposited in the depocentre (Atan Fm). The Upper Oligocene-Lower Miocene sediment (Mandai Group) marks the base of the Neogene section and the oldest sediments penetrated in the offshore Kutai Basin. The 144 Volume 2: Final Report of the Indonesia Case Study

152 Pamaluan Formation comprises of black carbonaceous shales with rare thin beds of fine sandstones interpreted as bathyal marine deposit in much of the onshore and all of the offshore areas. The Lower Miocene Bebulu Group overlays the Pamaluan Formation and consists of a shelf edge bioclastic limestones in the onshore area (Maruat Fm) and a slope to bathyal sandstones, siltstones and shales sequence offshore (Pulau Balang Fm). In the Lower Kutai Basin/North Makassar Basin, the Lower Miocene sequence (Bebulu Group) is mainly formed as carbonate and marine shales deposition. Carbonate was mainly formed in the shallow part of the basin and laterally passes to the open marine shales in the offshore part of the Kutai Basin. The Middle Miocene was marked by eastward an initial out building of the delta systems over shelf to slope sediment, with carbonates developed locally on the shallow marine shelf. The Middle Miocene deltaic sediments of the Balikpapan Group overlays the Bebulu Group and is composed of two units: a paralic-deltaic sequence of massive sandstones with occasional shales interbeds and a sequence of shales, siltstones with occasional shales interbeds and a sequence of shales, siltstones, limestones and rare sandstones which represent a shelf-slope-bathyal marine transition in the offshore areas. The Middle Miocene deltaic sequences that developed in the onshore Kutai Basin laterally change to the distal outer shelf, slope, and basin floor fan. During the Late Miocene-Pliocene times, the eastern part of Kutai Basin contained deltaic to shallow marine facies laterally changes to the distal outer shelf, slope and basin floor sediments of Late Miocene-Pliocene lowstand deposits. The Late Miocene Pliocene Kampung Baru Group supersedes the Bebulu Group and continues the west to east basin fill progradation. Onshore and near offshore sediments consist of interbedded sandstones, siltstones, shales and coals, interpreted as a paralic-deltaic sequence (Tanjung Batu Fm). Distant offshore areas contain shales and siltstones with some thin sandstones and limestones interpreted as shallow marine shelf sequences (Sepinggan Fm). The Mahakam Group (Handil Dua and Attaka Formations) overlays the Kampung Baru Group and its upper surface form the present-day seafloor. The Handil Dua Fm represents the onshore sub aerial delta plain of mixed fluvial and tidal-marine delta environments. The lithologic composition is intercalated sands, silts, clays and lignites. Offshore, the Attaka Formation consists of interbedded fossiliferous clays, coarse-fine, unconsolidated sands and some bioclastic shell beds interpreted as an open to restricted shallow marine shelf deposits (Marks et al, 1982). Volume 2: Final Report of the Indonesia Case Study 145

153 Figure 3. General Stratigraphy of Kutai Basin 4. Petroleum System a. Source Rocks The source rocks for oil and gas in Kutai basin are Carbonaceous shales of Tanjung Formation, and Balikpapan Formation (Figure 4). The shales are deposited in Parallic/deltaic to restricted marine environments. Geochemical analysis of outcrop samples indicates the Miocene shales, claystones and coals of the delta and pro-delta are fair to good waxy oil and gas prone source rock. The 146 Volume 2: Final Report of the Indonesia Case Study

154 Miocene shales, claystones and siltstones have a Total Organic Content (TOC) varying from 0.14% to 15.37% with the majority between 0.5% and 1.0%. The sediments contain only terrestrial derived organic matter and are waxy oil and gas prone from mixed kerogen types or exclusively gas prone. It is concluded that terrestrially derived organic matter within the Miocene deltaic sequences have generated hydrocarbons prior to the section being uplifted 4,500 feet and eroded away. b. Reservoir Rock The main productive reservoirs in the East Kutai Basin are fluvial deltaic and nearshore marine sandstones of Middle Miocene-Pliocene age. These sands are part of a series of prograding deltaic sequences that filled an ancient deep-water basin. Petrographically, the sandstones are classified as feldspathic sandstones. Another reservoir rocks are the Paleogen sediments of Eocene Tanjung Formation sandstone and Oligocene carbonate. The sandstone of Tanjung Formation are the basal sands of fluvial channel, high energy and coarse-grained sandstones of estuarine/deltaic environment and shallow marine sandstones Shallow core samples have measured porosity of 13 to 25% and permeabilities of up to 450 md suggesting that these sands may have excellent reservoir properties for both oil and gas. The Oligocene reservoir consists of monotonous grey mudstones with thin sandstones, siltstones and limestones. c. Seal Rocks The regional seal rocks of Kutai Basin are the Oligocene marine shales and Intraformational shale of Miocene to recent Deltaic sediments. d. Traps Hydrocarbon traps in the basin can be divided into structural trap (anticline), combination of stratigrapic and structural trap (faulted carbonate build-ups), and stratigraphic trap (carbonate build-ups and pinch-out sand). Most of the traps are anticline associated with deltaic sediments. e. Generation and Migration Eocene Source rocks of Kutai Basin entered level of early maturation for hydrocarbon generation in Middle Miocene time and younger for the Miocene source rocks. Oil and gas migration occurred during the timing of traps formation in the late Miocene Time. This condition is favorable for hydrocarbon accumulation. Volume 2: Final Report of the Indonesia Case Study 147

155 Figure 4. General Petroleum System Chart of Kutai Basin f. Hydrocarbon plays There are two (2) play types which can be identified in the basin, i.e. the Eocene-Late Oligocene Play and Late Oligocene-Middle Miocene Play, which were used in the hydrocarbon play assessment. 1. Eocene-Late Oligocene Play coarse clastic fluvial sediments (lower part), followed by the deposition of coarse clastic marine sediments (upper part) mostly found in the western part of the basin clastic fluvial and clastic shallow marine are the reservoir 2. Late Oligocene-Middle Miocene Play deltaic sediments mostly found in the eastern part of the basin delta plain and delta front sands are the reservoir 5. Result of Resource Assessment 5.1 Hypothetical Resources The hypothetical resource was calculated from 93 prospects and leads, coming from 13 Block that operated by 6 Companies in the Kutai basin. The number of Oil resources is 8,281 MMSTB and gas resources is 55,065 BSCF. 5.2 Speculative Resources 148 Volume 2: Final Report of the Indonesia Case Study

156 The speculative resource was calculated using the GeoX Ver 5.20 software, carried out on those two plays, i.e. the Eocene-Late Oligocene Play and Late Oligocene-Middle Miocene Play, and then aggregated into a total resources in the basin. a. Eocene-Late Oligocene Play Resource Type Mean F90 F50 F10 Inplace Resource Oil (MMSTB) AsGas (BSCF) 6, , ,355.9 NaGas (BSCF) 1, ,109.6 Condensate (MMSTB) Liquid (MMSTB) Gas (BSCF) 7, , ,702.5 Recoverable Resource Oil (MMSTB) AsGas (BSCF) 2, , ,075.5 NaGas (BSCF) ,671.3 Condensate (MMSTB) Liquid (MMSTB) Gas (BSCF) 3, b. Late Oligocene-Middle Miocene Play Resource Type Mean F90 F50 F10 In place Resource Oil (MMSTB) AsGas (BSCF) 89, , , ,913.7 NaGas (BSCF) 30, , , ,548.8 Condensate 2, , , ,174.8 (MMSTB) Liquid (MMSTB) 2, , , ,260.0 Gas (BSCF) 119, , , ,724.2 Recoverable Resource Oil (MMSTB) AsGas (BSCF) 31, , , ,719.8 Na Gas (BSCF) 19, , , ,306.7 Condensate 1, , , ,713.6 (MMSTB) Liquid (MMSTB) 1, , , ,743.4 Gas (BSCF) 50, , , ,732.7 c. Total Speculative Resources Resource Type Mean F90 F50 F10 In place Resource Oil (MMSTB) AsGas (BSCF) 95, , , NaGas (BSCF) 31, , , ,790.4 Condensate 2, , , ,665.8 (MMSTB) Liquid (MMSTB) 3, , , ,352.8 Volume 2: Final Report of the Indonesia Case Study 149

157 Gas (BSCF) 127, , , ,830.4 Recoverable Resource Oil (MMSTB) AsGas (BSCF) 33, , , ,336.3 NaGas (BSCF) 20, , , ,422.0 Condensate 1, , , ,837.0 (MMSTB) Liquid (MMSTB) 1, , , ,880.3 Gas (BSCF) 54, , , , Licensing Strategy The oil and gas business activities in Indonesia are controlled by the government, while the management structure of this business is divided into 2 parts, namely the development parts and the supervision part. The development part of the structure goes to Directorate General of MIGAS, such as developing the upstream business activity, downstream business activity, and the programmes. All of these are under each directorate. The supervision part goes to the upstream and downstream sectors. In the upstream sector, the role of Directorate General of MIGAS is in implementing the Government of Indonesia affairs in the field of oil and gas business activities, as well as in the determining of the policies. The administrative management, such as licensing of the oil and gas working areas, to arrange the acreage to be offered, is also part of the role of DG MIGAS. The technical supervision of the operation of oil and gas businesses is hold by the BPMIGAS, the Upstream Oil and Gas Executing Agency. In the downstream sector, the role of BPH MIGAS, named as the Downstream Oil and Gas Regulatory Body, is to establish the regulation and supervision of the oil fuel supply and distribution, as well as the natural gas transportation through the people. Based on the Oil and Gas Law No. 22/2001, the hydrocarbon resources be made available for domestic use in an effective and efficient manner. In promoting the exploration, the Government of Indonesia has the authority to mine, promote and assign the contract areas, determine the contractors to explore and develop the resources within the area in accordance with a cooperation contract. To benefit both parties, the government and the contractor, the government sets the type and terms of the cooperation contract, and they will dependent on the resource potential of each contract area. BPMIGAS has been authorized to sign the cooperation contract and to manage of the petroleum operations. In the cooperation contract, the contractor provides all funds, technological expertise and has to have the ability the necessary abilities, and takes all risks in the exploration. The period of exploration is six (6) years and maybe extended for another four (4) years. If commercial production is found, the contract could be for thirty (30) years. The contractor is also obliged and required to relinquish the area in stages. When the contract is signed, the contractor is required to make firm written commitments for the first three (3) years of the exploration period; and during which time the contractor has to keep and maintain is majority interest in the contract area. 150 Volume 2: Final Report of the Indonesia Case Study

158 There are two (2) ways to acquire an exploration block, namely the regular tender and the direct offer. a. Regular Tender This procedure is announced by the Government at least once a year, with a window for evaluation period for the contractor within 5-6 months. Based on a study conducted by DG MIGAS, approximately acreage blocks are offered, which are opened to all who are interested. Due to policy of the government to attract more investor to come to Indonesia to explore in the eastern part of the area, the blocks are commonly high risk and no commercial discovery. The area offered is either onshore or offshore, conventional area or frontier area. In June 2005, 14 blocks were offered in the bidding round, and the winner of any bidder contractor has not been made during this report was written (July 2006). The cost to bid a block is about minimum of 1,025,000 US$, which consist of purchasing the Bid Information 5,000 US$, Data Package of minimum about 20,000 US$ and Signature Bonus of minimum about 1,000,000 US$. b. Direct Offer There are three (3) types of offering: The Direct Offer is intended to offer the remaining and available unsold block from the previous bidding round. Any contractor is interested in any block of those remaining and unsold blocks, and then the company can prepare and propose the block. DG MIGAS will evaluate the proposal and prepare the terms and conditions. Any contractor is interested in any block of those remaining and unsold blocks, and then the contractor can make a joint study with DG MIGAS, The block is prepared and designed based on the result of the joint study. All companies applying for the block shall propose and conduct a presentation to DG MIGAS, which covers the technical assessment of the block potential and the company profile. In June 2005, together with the regular tender, 13 blocks were offered. The evaluation period from announcement date to bid submission is one (1) month, and the awardees have signed the contracts in October The cost to bid a block is about minimum of 1,105,000 US$, a little bit expensive to be compared with the regular tender, which consist of purchasing the Bid Information 5,000 US$, Joint Study about 50, ,000 US$, and Signature Bonus of minimum about 1,000,000 US$. Roughly, a total of 194 available blocks in region consisting of: Java 21 % Central Sumatra 7 % South Sumatra 20 % Natuna Sea 5 % Kalimantan 20 % Sulawesi 3 % Irian Jaya 14 % Timor 1 % North Sumatra 9 % Volume 2: Final Report of the Indonesia Case Study 151

159 7. Fiscal Regime The Production Sharing Contract concept has been applied since Although it has been subject to several important revisions, its basic principles have not changed. Those basic principles were that the management authority was with PERTAMINA. The contractor had an obligation to supply domestic market demand in prorates, up to a maximum of 25% of its oil share, and the Government revenue/share was guaranteed through the First Tranche Petroleum (FTP). Based on the changes to the Production Sharing Contract terms, PSC can be divided into three generations, i.e.: 1. Production Sharing Contract Generation I ( ): This generation of PSC was first applied with REFICAN in North Sumatra and then followed with IIAPCO at Java Sea. These contracts were based on production split of 65% for the government and 35% for the contractor, with 40% cost recovery ceiling. 2. Production Sharing Contract Generation 11( ): At the beginning of this period, internationally the oil price was very good; therefore, it was felt that the PSC terms need to be revised. At the PSC Generation II, the cost recovery was not limited to 40% of total production anymore. The contractor may get the full cost recovery within that year, but the production split was change to 85/15 for oil and 70/30 for gas. The full cost recovery term for the contractor has brought the consequence of a close government cost auditing, i.e. pre, current, and post audit. 3. Production Sharing Contract Generation III (1988-now): This PSC Generation III was basically the same as the PSC Generation II. The only difference is the implementation of First Tranche Petroleum (FTP), to secure government income/revenue. This FTP was introduced to compensate for the full cost recovery terms and the elimination of economic commercial limitation of a field. In general, all existing mineral, oil and gas, within the statutory mining territory of Indonesia are national richest controlled by the State, and the Government holds the exclusive authority to mine. For this purpose, as billed in the new Oil and Gas Law in 2001, the government established the Executive Agency for Upstream Oil and Gas Business Activity (BPMIGAS). The business entities conduct oil and gas business based on cooperation contracts with BPMIGAS, mostly in the form of Production Sharing Contract (PSC). Thus, the PSC contracting parties are Contractor and BPMIGAS, and this shall prevent the government from any liability arising from the oil and gas business. A simple chart of the PSC scheme is illustrated in Fig Volume 2: Final Report of the Indonesia Case Study

160 PRODUCTION FIRST TRANCHE PETROLEUM INVESTMENT CREDIT COST RECOVERY EQUITY TO BE SPLIT INDONESIA SHARE CONTRACTOR SHARE DMO - - DMO FEE + TAXABLE INCOME TAX - INDONESIA TAKE CONTRACTOR TAKE Fig. 1. PSC scheme First Tranche Petroleum (FTP) First Tranche Petroleum of 20% deducted before the recovery of Investment Credit and Operating Costs FTP shared between BPMIGAS and CONTRACTOR Designed to ensure the minimum income for the State Investment Credit Investment credit: 17% of the capital investment costs required for production facilities commencing in the earliest production Year. Cost Recovery Volume 2: Final Report of the Indonesia Case Study 153

161 The cost recovery consists of mostly the current year non-capital costs, the current year s depreciation for capital costs, and the un-recovered operating costs of the previous year. The expenditures consist of the capital and non-capital expenditures. The capital expenditure consists of tangible drilling cost and developing costs (utilities/auxiliaries, housing/welfare; production facilities; movables, etc), while the non-capital is the cost of exploration and production. Equity to be split The sharing splits include tax component (split before the tax applied as a gross split). The splits are as follow: After tax Tax Rate (%) Contractor Share Indonesia Share (%) split (before tax, %) 85: /(100-56) = /(100-48) = /(100-44) = : /(100-56) = /(100-48) = /(100-44) = Domestic Market Obligation (DMO) The term DMO is an obligation of the Contractor to sell and deliver a portion of the share to the domestic market. This obligation is 25% of the sharing split of the production, and the price is in US$ per barrel or FOB as stated in the contract. Tax If the operating cost can not be recovered, then this DMO is released. The Contractor has to pay the income tax, and excluded other taxes and levies. For a 100% taxable income, then the taxes consist of the corporate tax of 30% and the dividend tax of 14%. All together are 44 %, the effective tax rate. 8. Mature Basin Development Policy The last status on the Indonesian oil reserves (January 2006) shows that the total proven and potential oil reserve is around 8, MMSTB. The biggest oil reserves is found in Central Sumatera with its reserves of around 4,270.8 MMSTB, followed by South Sumatra of MMSTB, East Java of around MMSTB, and East Kalimantan of MMSTB. The total proven and potential gas reserve is around TSCF with the biggest gas reserve comes from Natuna with its reserve of TSCF having high volume of associated CO 2 gas, followed by the gas reserves on East Kalimantan which is around TSCF, South Sumatera with its reserve of TSCF and Irian Jaya with its reserve of TSCF. Although those figures describe the potential oil and gas reserve, it does not supply 154 Volume 2: Final Report of the Indonesia Case Study

162 the oil and gas demand in Indonesia. Recent oil discoveries are relatively small in reserves. Combined with a low oil price, these finds sometimes are not commercially attractive to be developed. The oil production profile has been declining since 1994 from 1,600 MBPOD down to 1,000 MBPOD, and it was predicted that this curve will goes to 300 MBPOD on Efforts have to be done to maintain the production level at 1,200 MBPOD by developing the brown fields, the marginal fields, and new potential developments. a. Brownfield By definition, a Brownfield, as defined by the Brownfield KKKS Team, is an existing producing field, producing field in decline, or previously developed field. uneconomic under the current terms & conditions require incentives to stimulate new or additional investment in order to enhance production and/or add reserves While Schlumberger defines that a Brownfield is a mature field in a state of declining production or reaching the end of their productive life. The effort of the government to encourage the development of brownfields, is to give incentives for enhancing the oil recovery of the secondary recovery, i.e. 17% of the investment credit and DMO Holiday of during 5 years after production. In the tertiary recovery, incentive is given in the form of changing the split of the equity. For the non-eor technique, incentive is not given yet and still in the finalization process. Another incentive alternative is given, such as the DMO Holiday of 60 months, Cost Recovery Uplift, and Interest Cost Recovery. There are some applied IOR/EOR technologies which have been done, such as the following: a. Water-flood: in the field of Minas, Kotabatak, Bekasap, and Widuri. All of these fields are in the Central Sumatra, which are operated by the Chevron Pacific Indonesia. b. Steam-flood: in the Duri oil fields, and also the candidates are in the Batang, Kulin and Rantau Bais oil fields. All of these fields are in the Central Sumatra, which are operated by the Chevron Pacific Indonesia. c. Gas Lead Injection: in the Handil oil field of Total Indonesia. d. Chemical Flooding: in the Minas oil field, Central Sumatra, as a pilot project of he Chevron Pacific Indonesia. The impact of new technology on increasing the oil recovery is the well-known Duri Steam Flood. At the beginning, the RF was only 8-11%, and after employing the steam flood technology, the RF was tremendously increased up to 50-80%. Another story is the success story of the Handil Oil Field in enhancing the oil recovery. In 1979 the oil production rate was dropped down to bopd, and when the water injection was applied the rate was increased up to bopd, and then getting down slowly to about bopd in In the 1996, when the production rate was only bopd, the first EOR was applied, and in 2000 the second EOR was applied. b. Marginal Field Volume 2: Final Report of the Indonesia Case Study 155

163 There are some problematic definitions in defining what a marginal field is, such as The standard definition in the PSC is not flexible enough A modified dynamic definition and new criteria is required if significant additional capacity of future oil supply is expected It should also cover most of small fields & some larger fields that become uneconomic at current PSC term and condition at various maturity stage Needs strong effort and political will Some economic parameters have been defined, such as: the recoverable reserves and production current economic conditions: oil price assumption, productive life, MARR operating methods: good reservoir management, innovative optimum development scenario, fit for purpose technology, infrastructure, minimum facilities concept design, joint facilities & infrastructure concept government regulations: PSC terms & conditions, and win-win" incentives Without developing those marginal fields, Indonesia is in danger of reaching a net importer country status faster. Therefore, there is no choice but to find ways that enable us to develop the marginal fields in order to keep the production at the current level. The problem now is how we can make marginal fields more economically attractive to the investor. The challenges in developing marginal fields are: Most of oil fields and many larger gas fields are already mature. The exploration & development prospects (particularly for oil) are getting smaller and harder to find Numerous smaller discoveries, leads and prospects, as well as depleted fields, may contribute significant future additional capacity of supply that can be commercialized Major challenges for MF developments and program are related to: Redefinition of a better MF terminology Negotiation of an acceptable MARR Acceptable incentives adoption and implementation Simplification of procedures and processes Building up commitments & political will to realize the programs The new definition of marginal field defines that a marginal field is an oil field located within a producing block that, under the current PSC terms and conditions, is not economics to be developed. c. Incentives The new incentives for marginal field development, as decreed by the Minister of Energy and Mineral Resources (MEMR) No. 0008/2005), stated that the Operating Cost Recovery Uplift is 20%. Under PSC condition, the Operation Cost consists of current year s Non Capital Cost and current year s Depreciation for Capital Cost. Other incentive packages maybe applied for marginal field in accordance with the prevailing PSC, Laws and Regulation. It can be concluded that the efforts and challenges of developing the mature and marginal field is to create a joint task force among BPMIGAS, Oil Companies, and the 156 Volume 2: Final Report of the Indonesia Case Study

164 Service Companies which function is to re-evaluate the economics of marginal fields. If those fields are not economic, then define the method to improve the economics of the marginal fields. Again, if it is still not economic, then define what incentives are required to encourage the companies to develop the field. Efforts needed for new policy breakthrough as the role of BPMIGAS and Government of Indonesia, such as: 9. Conclusions a. Production Sharing Contracts (if necessary). - Incentives (for Exploration in New Frontier) - Incentives (Marginal & Brown fields and New EOR) b. Efficient Process for POD, Work Programme and Budget, and Authorization for Expenditure Approval - Reorganization of BPMIGAS to provide a Proper Vehicle - Legal support for Fast Track Development Policy c. Better Fiscal Regimes There are some points to conclude the implementation of the Indonesia PPM Case Study as follow: a. PPM Team Membership The Indonesia PPM Case Study was strongly supported by 2 main governmental agencies, ie. Directorate General Migas and BPMIGAS, which was expected to bridge a joint cooperation among the agencies concerned. The team members of the Indonesia PPM are not coming from one agency, but they come from different governmental agencies. The intention of involving another governmental agencies rather than LEMIGAS alone, is to bridge a joint cooperation among the agencies concerned, such as BPMIGAS that was expected to facilitate in contacting the oil companies or DG MIGAS which was expected to supply the governmental policy in the petroleum sector. However, the multi-institutional agency could not make the team compact and solid, which created a little problem in the implementation of the PPM activities, such as preparation of workshops, difficult to invite the members from those agencies due their tight schedule of their official jobs. Appreciation to participated Oil Companies, DG MIGAS, BPMIGAS and BPH MIGAS during the workshops held in Indonesia and other case study countries. b. Data Availabilty When PPM touched about data, then the problem comes. It was not easy to get the real data, although the goal of PPM is to get a hands-on experience using own real data. Most of data are still considered confidential. There is no so-called data manager either in BPMIGAS or in the Directorate General of Oil and Gas, the data is still kept by the oil companies. Data can be obtained from BPMIGAS after having an approval from DG of Oil and Gas, and it takes time to approach the data availability. c. Use of GeoX Software Volume 2: Final Report of the Indonesia Case Study 157

165 The GeoX software is the most useful tool and was used by all case study countries in calculating the potential of the petroleum resources. This is also help Indonesia, since there are 60 basins of which the data are varied and dynamics due to the more and more additional new data. However, it is very difficult to convince the government, either DG MIGAS or BPMIGAS, that this software is helpful in considering the policy in the petroleum sector. The module of GeoX/gFullCycle is beneficial in the economical analysis of a petroleum project. However, in the resource assessment, the economics was not analyzed since the calculation of the resources was based on the play analysis. In the reality, it is very complicated and need more practices to accommodate all scenarios of the Indonesian fiscal regime. The software cannot accommodate all elements of the Indonesia fiscal regime, e.g. First Tranche Petroleum (FTP) which is not similar to Royalty. In the home country, most oil companies have their own software to do economic evaluation. The software is powerful and user-friendly. However, it is not widely used as the GeoX license is issued for a particular computer. d. PPM in Practice The PPM workshops, in general, were a forum for all CCOP Member Countries to present their experiences in solving their petroleum problems in their own country, depend on the topic of the workshops. The important thing that this was a place where they can share their own case related to the topic of the workshop. The petroleum business in Indonesia is worked out by many oil companies, and there are big oil companies which operate big oil fields. They do the business with their own technologies as well as their own hardware and software. At this point, the technologies shared by the resource persons from Norway could not be applied, e.g. the deepwater technology, even sometime are not appropriate with the condition of the area. However, this situation will be different in the future when Indonesia does the exploration in the deeper part of the area. There are many things in the oil sector in Indonesia which are not touched by PPM, and most are internal aspects; such as the production sharing due to the district autonomy, get the benefit of being oil and gas producer, the community development. The Indonesia PPM case study contents are in line with the target and strategic planning of the upstream oil and gas sub-sector as stated in the work programme of Ministry of Energy and Mineral Resources e. Achievement of the PPM goals National petroleum management and policy are determined by government, as approved by the House of Representative. The revision and improvement of the petroleum management and policy arrangements due to changes in political, economic and market conditions, have to be approved by the House of Representative. The capacity and capability in petroleum resource management have been improved. 158 Volume 2: Final Report of the Indonesia Case Study

166 1. Introduction Volume 2: Final Report of CCOP Member Country Participating in the PPM Project -KOREA- Korea has actively participated in the CCOP PPM Project 4 case studies. During the 4-year implementation of the Project more than 20 personnel, mostly researchers and management representatives have participated in the PPM Project representing KIGAM, KNOC, KOGAS, MOCIE, and Industry. The personnel participating in specific activity are selected according to their experience and expertise. Their participation in the discussions and exchanges of knowledge and experience among the CCOP members has given them opportunities to improve their knowledge and understanding, as well as to enhance Korea s cooperation and partnership with the other Member Countries. Listed below are the Korean participants to the various activities of the PPM Project. Name Organization 1. Dr. Dae-Gee Huh - National KIGAM Coordinator 2. Dr. Hyun-Tae Kim KIGAM 3. Dr. Young-In Kwon KIGAM 4. Dr. Ho-Young Lee KIGAM 5. Dr. Jin-Dam Son KIGAM 6. Dr. Byeong-Kook Son KIGAM 7. Dr. Won-Suk Lee KIGAM 8. Dr. Se-Joon Kim KIGAM 9. Dr. Dae-Hung Kim KIGAM 10. Dr. Hyun-Bock Lee KIGAM 11. Dr. Jae-Hyoung Lee KIGAM 12. Dr. Ji-Hoon Kim KIGAM 13. Dr. Young-Joo Lee KIGAM 14. Dr. Ji-Whan Kim KIGAM 15. Dr. Byung-Jae Ryu KIGAM 16. Dr. Se-Jin Park KNOC 17. Dr. Kook-Sun Shin KNOC 18. Dr. Jeong-Hwan Lee KOGAS 19. Ms. Jeong-Min Han KOGAS 20. Dr. Seung-Chul Park MOCIE 21. Dr. Hyung-Woo Park MOCIE 22. Dr. Jeong-Ho Lee MOCIE 23. Dr. Man-Eop Kim MOCIE 24. Dr. Keun-Ha Lee MOCIE 25. Dr. Young-Ho Cheon Industry 26. Dr. Dong-Soo Choi Industry Volume 2: Final Report of Korea, PPM Project 159

167 2. Knowledge Dissemination The KIGAM staffs participating in the PPM Project activities are required to conduct an in-house seminar to disseminate the information and knowledge learned to the PPM Project team members and other colleagues. In addition, KIGAM organizes annually Short Courses on Petroleum Exploration and Production under the support of Korea Petroleum Association (KPA) with some of the PPM Team members as major resource persons. The main topics are policy and legislation of domestic and overseas petroleum exploration, petroleum geology and geophysics, well testing, reservoir evaluation and engineering, reserve estimation and economics, etc. Below are details of these seminars and short courses: 1 st Dissemination Short Course (2004) Date: November, 2004 Venue: KIGAM, Daejeon, Korea Participants: 20 persons from Korea Petroleum Association (KPA), Korea National Oil Corporation (KNOC), Korea Gas Corporation (KOGAS), Korea Eximbank, Daesung Industrial, Seoul City Gas (SCG), LG Caltex, SK Gas, Heesong Geotech Resource Persons: Experts from KIGAM, KPA, Korea Eximbank, LG Caltex, Energy Holdings, Kwangju University, Korea Maritime University 2 nd Dissemination Short Course (2005) Date: 30 May 2 June, 2005 Venue: KIGAM, Daejeon, Korea Participants: 20 persons from Korea Petroleum Association (KPA), Korea National Oil Corporation (KNOC), Korea Gas Corporation (KOGAS), Daesung Industrial, Daewoo International, Seoul City Gas (SCG), GS Caltex, Korea Electric Power Cooperation (KEPCO) Resource Persons: Experts from KIGAM, KPA, Korea Eximbank, Energy Holdings, Sejong University, Korea Maritime University 3 rd Dissemination Short Course (2006) Date: June, 2006 Venue: KIGAM, Daejeon, Korea Participants: 31 persons from Korea Petroleum Association (KPA), Korea National Oil Corporation (KNOC), Korea Gas Corporation (KOGAS), Korea Electric Power Cooperation (KEPCO), GS Holdings, GS Caltex, Samsung Cooperation, POSCO, SK Gas, SK E&S, STX Corp., Samchully Co., Samwhan Corp., Keangnam Enterprises, SeRim Co., Woolim Construction Co., HS Holdings, EPC Resource Persons: Experts from KIGAM, KPA, Korea Eximbank, LG Caltex, Energy Holdings, Korea Maritime University 160 Volume 2: Final Report of Korea, PPM Project

168 Some of the pictures of the dissemination short courses are shown below: 1 st dissemination short course (2004) 2 nd dissemination short course (2005) 3 rd dissemination short course (2006) 3. Collaboration with CCOP Member Countries Through the PPM Project, KIGAM has entered into collaboration project with Indonesia to enhance further the cooperation and knowledge on oil and gas research. The purpose of the cooperation between LEMIGAS of Indonesia and KIGAM is to further enhance practical knowledge on petroleum policy and management studying in-depth field data. Some of the examples of the joint study are petroleum system, reservoir simulation and economic analysis (Fig.1 & Fig.2). This early stage of cooperation can be extended to another bilateral collaboration with other Member Countries. Petroleum system analysis Reservoir simulation analysis Volume 2: Final Report of Korea, PPM Project 161

169 4. Conclusions Topics of PPM Workshop is excellent Benchmark to Korea; for example, Marginal Field Development, Policies for Investment Opportunities and Development Solutions The collaboration among CCOP Member Countries should be pursued: we consider this cooperation a Great Asset New Ideas, Concepts, Methodology and Development Technologies in the Upstream Industry are very useful to Korea and also to the CCOP Member Countries participating in the PPM Project 162 Volume 2: Final Report of Korea, PPM Project

170 1. Introduction Volume 2: Final Report of CCOP Member Country Participating in the PPM Project -MALAYSIA- Malaysia is among the CCOP Member Countries that have actively participated in petroleum-related Projects in CCOP. Majority of the Malaysian participants are from PETRONAS, the national oil company of Malaysia. In the PPM Project, PETRONAS has assigned multi-skill personnel comprising of geoscientist, development/ reservoir engineers, planners and economists to participate in the workshops, seminars and expert visits that were conducted to support the 4 case studies. In addition, PETRONAS have also sent their experts as resource persons to the case study countries to address specific issues faced by these countries relative to the case studies. Their participation in the discussions and exchanges of knowledge and experience among the CCOP members has given them opportunities to improve their knowledge and understanding, as well as to enhance Malaysia s cooperation and partnership with the other Member Countries. 2. List of Participants Listed below are the names of the PETRONAS staff who have participated in the PPM Project. PPM SEMINAR DATE VENUE PARTICIPANTS 1 st September 2002 Bangkok Mr. Ali Md Shariff Mr. Badrul Hisam Ismail 2 nd 3 rd September 2004 Chiang Mai Mr. Nordin Ramli 4 th 4-7 October 2005 Hua Hin Mr. Nordin Ramli 5 th July 2006 Bangkok Mr. Nordin Ramli Mr. Sharir Mustafa Mrs. Che Zan Yassin PHILIPPINE CASE STUDY DATE VENUE PARTICIPANTS WORKSHOP 1 st March 2003 Pasig City 2 nd January 2004 Manila Mr. Badrul Hisam Ismail Mr. Ali M Shariff 3 rd August 2004 Baguio City Mr. Badrul Hisam Ismail Mrs. Mursyidah Abd Hamid 4 th March 2005 Manila Mr. Rosli Abd Rahim Tg. Norina Tg. Nasarudin 5 th March 2006 Cebu Dr. Jaizan Hardi Jais Nur Azah Zulkifli Volume 2: Final Report of Malaysia, PPM Project 163

171 CAMBODIA CASE STUDY WORKSHOP DATE VENUE PARTICIPANTS 1 st 24 February 4 March 2003 Phnom Penh 2 nd Mr. Mansor Ahmad August 2003 Sihanoukville Mr. Aidil Shabudin Mr. Mansor Ahmad 3 rd 29 March Phnom Penh 3 April 2004 Mr. Aidil Shabudin 4 th 1-5 December 2004 Phnom Penh Mr. Rozmee Ismail 5 th 29 August 2 September 2005 Sihanoukville 6 th February 2006 Siem Reap INDONESIA CASE STUDY DATE VENUE PARTICIPANTS WORKSHOP 1 st July 2003 Yogyakarta 2 nd 7-14 March 2004 Bandung Mr. Azhar Yusof Mr. Awalludin Harun 3 rd July 2005 Surabaya Mr. Emry Ismail 4 th June 2006 Jakarta Dr. Nasri Rahman Nurhayati Hashim CHINA CASE STUDY DATE VENUE PARTICIPANTS WORKSHOP 1 st October 2003 Chengdu 2 nd May 2004 Chengdu Mr. Nordin Ramli Mr. Donny Maga 3 rd June 2005 Beijing 4 th 30 May - 3 June 2006 Beijing Mr. Abd Rahman Harun Dr. Nasri Dasman Below is the list of PETRONAS staff who attended the PPM Project activities as resource persons. PROGRAMME DATE VENUE RESOURCE PERSONS 1 st Philippines Workshop March 2003 Manila Mr. Badrul Hisham Ismail 2 nd Philippines Workshop May 2004 Manila Mr. Ali M Shariff 3 rd Cambodia Workshop June 2005 Sihanoukville Mr. Aidil Shabudin 4 th Philippines Workshop May 2005 Manila Expert Visit May 2006 Deyang Mr. Robert Wong Hin Fatt Mr. Othman Ali Mahmud Mr. Wukar Hussein Mazoor Husani Mr. M Zaki Awang 5 th PPM Seminar July 2006 Bangkok Mrs. Che Zan Yassin 164 Volume 2: Final Report of Malaysia, PPM Project

172 During the course of Malaysia s participation in the PPM Project, the National Coordinator, Mr. Nordin Ramli has reported that their original plan was to assign technical staff to follow each 4 case studies from the start up to its conclusion. However, they have found it difficult to implement this plan due mainly to Staff s tight job and schedule. Staff movement/ transfer Staff involved in specific projects 3. Feedback / Comments It was difficult to follow certain programmes in the PPM Project due to participants different backgrounds. There is a need to allocate more time in explaining the general working of a software before start using them to have a better appreciation of the software capability. Should maintain dedicated and same team members to follow through each case studies to really gained experiences and for continuity and effective staff capability development. Credit to the Government of Norway for funding the PPM project and also to CCOP for the excellent management of the Project. Credit to the host countries of the case studies for their effort and willingness to share the information and hosting the workshops. National data would still be an issue. However, it would depend on the requirements. Data exchange can be made on case-to-case basis (Joint venture, tripartite, etc). The University Technology PETRONAS (UTP) there may be a possibility for Cambodia to apply for geoscience scholarship. Cambodia will have to make a special request for scholarship support to PETRONAS. This is to help address the urgently needed geoscience capability of Cambodia. 4. Experiences From the PPM Project Workshops/ Seminars Overall Well-organized and has met the Project Goal and Objectives. Enable to exchange ideas, experience and sharing knowledge. Establish contact and foster relationship amongst Member Countries. Key Technical Benefits Comprehensive mastery and utilization of GeoX and other system for petroleum resource assessment work. Possibility to relate some G&G understanding of Sulu Sea-East Palawan Basin to North East Sabah Basin. Variety of basin categories in case studies frontier, semi-matured and matured basins which are relevant to Malaysia. Good example of developing thin gas reservoirs in highly faulted structures in Pattani Basin potential to be adopted in some Malay Basin gas fields. Awareness of other country petroleum arrangements system. Volume 2: Final Report of Malaysia, PPM Project 165

173 5. Disseminations of PPM Case Studies Adopting some concepts learned from the case studies in developing ultradeepwater block areas and SE Sabah Basin in Malaysia. PPM case studies information was extended to relevant department through and participation in relevant topics accordingly. Use of GeoX Risk Assessment software to further enhance our resource assessment. The management is fully aware on PPM project and very supportive of PETRONAS participation. 6. Conclusions We strongly believe that the PPM Project has benefited all Member Countries through: a. The sharing of experiences and knowledge in petroleum operations in the respective countries, especially on the required geology and hydrocarbon systems in the respective basins. b. A good forum of building closer relationship and cooperation among the CCOP Member Countries. Malaysia has benefited through new ideas from this forum and has partly applied it in assessing hydrocarbon potential in the frontier basins and promoting our exploration acreages. The new PPM website is very informative and user-friendly and hopefully will be frequently visited by more PETRONAS personnel (PMU and PCSB). The cooperation among CCOP Member Countries may be broadened to other projects e.g. FDP (Field Development Plan) approval process and joint operation such as the Tripartite Team. For the Post-PPM Project: a. PETRONAS will do its best to identify the right personnel to attend the relevant programmes and to provide the right resource person whenever required. b. In addition to the planned technical activities, we suggest to include the sharing of information on the application of new technology eg. Sea bed logging in the deepwater exploration and gas hydrates (as a special topic of interest). 166 Volume 2: Final Report of Malaysia, PPM Project

174 1. Introduction Volume 2: Final Report of CCOP Member Country Participating in the PPM Project -PAPUA NEW GUINEA- Papua New Guinea (PNG) is among the CCOP Member Countries that have participated in the PPM Project. The participants are all coming from Department of Petroleum and Energy (DPE) and but participation were only limited to the few activities in the Indonesia case study, Cambodia case study, and Philippine case study. They also participated in the first 3 seminars that were conducted in Thailand. They were not able to participate in the China case study. The main reason provided is due primarily to the limited staff and the workload at DPE. Listed below is the list of DPE personnel that have participated in the PPM Project activities. Name MR. SILO VAI Geologist MR. GREGORY BALAVUE Geologist MR. DOMINIC SEBONG Economist MR. FRANCIS LOLA Acting Director Petroleum Division & Assistant Director Legal MR. ROGER KEWA-AVINAGA Assistant Director Petroleum Policy MR. PHILIP KIMALA Senior Petroleum Geologist MR. PETER WOYENGU Assistant Director MS. LARISSA SOLOMON- NOMBE Petroleum Geologist MS. JOY IRENE MATAENGE Petroleum Geologist MS. JENNIFER KAPI Petroleum Geologist MR. JIMMY HAUMU Acting Assistant Director, Exploration Branch MR. KILA VINI GARE Policy Officer (Economist) PPM Activity Cambodia 2 nd Workshop Cambodia 2 nd, 3 rd, 4 th Workshop and 3 rd Seminar Cambodia 4 th WS Cambodia 5 th WS and 3 rd Seminar Cambodia 5 th WS Philippines 2 nd, 3 rd WS and 2 nd Seminar Philippines 2 nd, 3 rd WS and Indonesia 2 nd WS Indonesia 1 st WS and Philippines 5 th WS Philippines 5 th WS 2 nd Seminar 1 st Seminar 1 st Seminar Volume 2: Final Report of Papua New Guinea, PPM Project 167

175 Information and Knowledge Dissemination Upon return of the participants, they are required to submit a report to the National PPM Coordinator and to the management (Director and Assistant Directors). The reports give a summary of the activity topic presentations and discussions, and copies are also provided to other Geoscientists (participants). DPE Officers were interested in participating in the PPM Project because; opportunity to enhance and to learn and acquire new knowledge and skills opportunity to meet and work with other professions in other countries. opportunity to use knowledge learnt, in-house Participants in the four workshops in 2004 expressed high interest. Agendas were beneficial and workshop exercises were good refreshers, for some. Here are some of the benefits: 1) Utilize skills such as GeoX Application and Performance Base Calculation to analyze hydrocarbon potential of fields. Utilize skills in our up-coming Petroleum Resource Evaluation Study Utilize skills to evaluate our producing Fields so as to maximize production A venue for Transfer of Technology, confidence in work, strenthening weaknesses 2) To be able to address the challenges in PNG, such as: Low exploration activity, improved exploration decisions Lower production, oil discovered in deeper sands Under explored basins, new acreages awarded 3) Application of Knowledge in our organization: Give a brief seminar/written report on the workshop and introduce colleagues to the new skills, software acquired from the case study Utilize skills/knowledge on frontier basins (basin analysis) and the up-coming Petroleum Resource Evaluation Study Provide copies of notes from workshops to colleagues on similar issues in office for better understanding Management are updated via reporting, feedbacks are generally satisfactory, based on performance on related issues 4) Have the expectations from the Project: Learned and acquired new knowledge and skills Exposed to the new and changing technology for oil and gas exploration and development Fostered good relationships with participants of other Member Countries. 168 Volume 2: Final Report of Papua New Guinea, PPM Project

176 3. Recommendations for case studies to be useful Compare similarities between the case studies and the cases in PNG, and adopt the techniques used to achieve the best results for a Field or Prospect. Application of what acquired in workshop in own office and update in next workshop if necessary Geo-X acquisition and training for in-office resource evaluation study 4. Areas where CCOP PPM projects can provide assistance to DPE PNG needs to establish Policies and Guidelines on how to address Marginal Fields and PPM assistance may be needed on the following: Definition of Marginal Field Criteria for determining marginality Typical incentives Construction of appropriate model Volume 2: Final Report of Papua New Guinea, PPM Project 169

177 1. Introduction Volume 2: Final Report of CCOP Member Country Participating in the PPM Project -THAILAND- During the 4-year implementation of the PPM Project, Thailand has been active in all the workshops and seminars conducted to support the 4 case studies. Thailand has also provided resource persons to expert visits conducted in Cambodia and Philippines case studies. Thailand s experiences in resource assessment, economic evaluation and modeling, development options, plan for development evaluation, and fiscal system have been thoroughly shared to the Cambodia case study team - the Cambodia National Petroleum Authority (CNPA) during workshops. The Pattani basin in the Gulf of Thailand has been used as analogue basin in the Cambodia case study. 2. Participation in the PPM Project The Thai team in the Project is composed mostly of geologists, engineers and economists from the Department of Mineral Fuels (DMF). PTTEP, the national oil company of Thailand has also sent their experts as resource persons during expert visits and workshops in Cambodia and Philippine case studies. The Thai personnel participating in specific activity are selected according to their experience and expertise. Their participation in the discussions and exchanges of knowledge and experience among the CCOP members has given them opportunities to improve their knowledge and understanding, as well as to enhance Thailand s cooperation and partnership with the other Member Countries. Below is the list of PPM Project participants from Thailand. Name Position/Organization PPM Project Activity participated MR. SUNTON SRIGULWONG MR. SUNGKOM BUNBOON Director of Petroleum Potential Assessment Group and PPM National Coordinator, DMF Senior Geologist, DMF 1 st 5 th Seminar 1 st and 4 th China WS 5 th Philippine WS 3 rd Cambodia WS 3 rd, 4 th, and 5 th Seminar 1 st and 3 rd China WS 5 th Expert visit, Philippines DR. PHUMEE SRISUWON Senior Geologist, DMF 5 th Seminar 2 nd, 3 rd, 6 th Cambodia WS 4 th China WS MR. KRIANGKRAI POMIN Senior Geologist, DMF 1 st and 5 th Seminar 1 st Philippine WS 2 nd, 4 th, 6 th Cambodia 170 Volume 2: Final Report of Thailand, PPM Project

178 MR. TANANCHAI MAHATTANACHAI MR. SUPAT NAPANOPARATKAEW MR. WIJAIYUT PRAPAWIT Geologist, DMF Petroleum Engineer, DMF Geologist, DMF WS 2 nd China WS 1 st and 4 th Seminar 4 th and 5 th Cambodia WS 3 rd Expert visit, Indonesia 5 th Cambodia WS 7 th Expert Visit, Cambodia 4 th and 5 th Seminar 5 th Philippine WS MR. SOMBOON Petroleum Engineer, DMF 1 st - 5 th Seminar VACHALACHAISULAPON DR. SIREE NASAKUL Petroleum Engineer, DMF 2 nd Seminar 1 st, 2 nd, 3 rd, and 4 th Indonesia WS MS. DHITIPORN Geologist, DMF 1 st, 3 rd, and 4 th BUAPRASERT Indonesia WS MS. AREE RITTIPAT Geologist, DMF 1 st Seminar 1 st, 2 nd, and 4 th Philippine WS MR. ANON Geologist, DMF 2 nd and 3 rd Cambodia PUNNAHITANON WS MS. YUWADEE KOLAE Geologist 4 th Seminar MS. VARANGKANAR Geologist, DMF PHUANGKAEW 4 th Seminar MR. NITHIT Geologist, DMF CHAROENTHAM 4 th Seminar MR. PIPAT JIRAPONGPIPAT Geologist, DMF 4 th Seminar MRS. KETSUDA Geologist, DMF SUPPASOONTHORNKUL 3 rd Philippine WS MR. SURACHAI SIRIJIRAPATANA Geologist, DMF 3 rd Seminar 2 nd and 3 rd China WS MS. KAMONWAN SUKSAWAT Geologist, DMF 2 nd Seminar 2 nd and 3 rd Philippine WS 3 rd Seminar 4 th Philippine WS 3 rd Seminar MS. BOONBANDAN Engineer YUVANASIRI MS. CHATCHAWAN Geologist, DMF GLADNAKA MR. PAKPOOM Senior Geologist, DMF 3 rd Seminar SRIYARAK MR. WITSARUT Petroleum Engineer, DMF 3 rd Seminar THUNGSUNTONKHUN MS. SUPASPORN Engineer, DMF 3 rd Seminar RUANGTHIANG MR. APHICHAT Geologist, DMF 3 rd Seminar Volume 2: Final Report of Thailand, PPM Project 171

179 BOOTPISED DR. WANIDA CHANTONG Geologist, DMF MS. SUPAPORN Senior Geologist, PTTEP PISUTHA-ARNOND MR. AMPOL New Ventures, PTTEP SONGMUANG MR. SUWIT Senior Geologist, PTTEP JAROONSITHA MR. PIYA New Ventures Coordinator, WICHITCHANYA PTTEP 5 th Seminar 3 rd Cambodia WS 2 nd Expert Visit 1 st Seminar 1 st Seminar 3. Impacts of the PPM Project Thailand has reported the impacts of the Project as follow: a. They have learned the general background (geology, fiscal system, investment promotion strategies, etc.) particularly of the case study host Countries b. Learned the Knowledge on concept and how to use the GeoX Software & Resource evaluations c. The information and Knowledge learned from participating in the PPM Project activities are used/applied in evaluation and approval of works in the DMF d. PPM has enhanced the Good relationship of Thailand with other CCOP Member Countries The 19 th Petroleum Bidding round that run from July 2005-June 2006 has successfully resulted in 19 applications from 22 oil companies 28 blocks in the Gulf of Thailand and Andaman Sea. The DMF staffs who have participated in the PPM Project are heavily involved in the promotion activities and evaluation of applications in the bidding round. 172 Volume 2: Final Report of Thailand, PPM Project

180 1. Introduction Volume 2: Final Report of CCOP Member Country Participating in the PPM Project -VIETNAM- The Petroleum Policy and Management (PPM) Project funded by Norwegian Agency for Development (NORAD) aims at the development of human resources and institutional capacity-building in the petroleum management of the CCOP Member Countries. The goal of the project is to enable government organizations responsible for petroleum resource management to: Establish a sustainable and efficient national petroleum management and policy. Envisage the mechanism and importance in revising and improving their petroleum management and policy arrangements due to changes in political, economic and market conditions. Enhance their capacity and capability in petroleum resource management based upon a realistic assessment of their own petroleum potentials utilising national data. The objective of the CCOP Petroleum Policy and Management Project is to transform gained knowledge into efficient petroleum resource management models in the public domain of the CCOP Member Countries with respect to: Exploration strategies and licensing procedures Models and arrangements of regulations and framework conditions for the petroleum industry, and their consequences on the exploration and development activities Balancing between the government take and the industry profit, in order to maximize the economic potential derived from the petroleum resources Enhancing the expertise in petroleum resource management of CCOP Member Countries Optimal development of the petroleum resources with good environmental consideration and good management practice The PPM project consists of four case studies: frontier Sulu Sea & East Palawan basins (Philippine), immature Khmer offshore basin (Cambodia), semimature Western Sichuan depression (China), and mature Kutei basin (Indonesia) and addresses questions related to exploration strategies, gas development and marginal field problems. VIETNAM PPM case study team has been taking part in 4 case studies, as well as its relevant workshops, seminars and expert visits, showing in the following table. Volume 2: Final Report of Vietnam, PPM Project 173

181 PPM case studies and seminars Cambodia case study: The immature Khmer offshore basin China case study: The semi-mature Western Sichuan depression Indonesia case study: The mature Kutei basin Philippine case study: The frontier Sulu Sea & East Palawan basins PPM seminars in Thailand VIETNAM PPM case study team Nguyen Quoc Thap Nguyen Manh Huyen Nguyen Ngoc Hoan Pham Tuan Viet Tran Viet Dung Nguyen Viet Anh Trinh Xuan Cuong Ta Vinh Hien Nguyen Xuan Thanh Hoang Van Hoa Nguyen Trong Tin Ngo Thi Viet Nga Nguyen Huy Tien Hoang Van Hoa Nguyễn Xuân Phong Nguyen Quang Bo Bui Thieu Son Trinh Viet Thang Nguyen Van Dac Khuc Hong Giang Tran Duc Chinh Duong Dang Thu Do Van Hai Selected Vietnamese members for the case studies are experts who have much practical experience on petroleum policy, petroleum exploration and production, and economic sectors. Their participation in the discussions and exchanges of knowledge and experience among the CCOP members has given them opportunities to improve their knowledge and understanding, as well as to enhance Vietnam s cooperation and partnership with the other Member Countries. 2. Results of resource assessment a) Basin analysis and Petroleum system evaluation Despite the difference in researches, exploration levels and real data of case studies, the presentations of the case study Host Countries covered the overview of the general geology and current activities of the case study areas. With respect to the presentation of the experience on resource assessment, the core team from the case study Host Countries made presentations on the methodologies, play, prospect and discovery analysis, and results of resource assessment. Various group discussions focused on strategies for the resource estimate update, experience earned by host country and other Member Countries. The presentations on the case study workshops have helped members of Vietnamese PPM case study team not only systematize method of basin analysis and petroleum system evaluation and analyze risks, but also expand knowledge about geological structure 174 Volume 2: Final Report of Vietnam, PPM Project

182 and petroleum system of sedimentary Tertiary basins such as: Kutei basin (Indonesia), Sulu Sea & East Palawan basins (Philippine), Khmer offshore basin (Cambodia). The presentations especially allow participants to have an understanding of a specific Mesozoic Western Sichuan depression in China, where tight sand reservoirs are dominant, and become priority study focus of oil companies to increase exploration and production efficiency of this object. Chinese experts experiences on stimulation and production technologies (fracturing, acidizing, multi tight zones completion, selection of completion zones with different reservoir quality, etc.) are exchanged and evaluated that these techniques can be applied for tight sand reservoirs in Ha Noi trough of Vietnam. Risk analysis for basin potential evaluations, among the important topics, was presented and discussed. The procedures, principles and guidelines related to risk analysis from NPD experts are very useful and valuable lessons for CCOP countries and very good for participants works. Through relevant discussions in the case study workshops, participants exchanged their knowledge and shared their experience. Case study Host Country and NPD experts experiences and knowledge on selection of input data and risk analysis, as well as on applying GeoX for basin analysis are highly appreciated. Most exercises are selected and very useful to participant s works as well as help them to improve their skills on managing petroleum exploration and production activities. At the case study workshop in China, a new concept for basin analysis (Basin Centered Gas-BCG) has presented by international experts. This concept can be applied for Sichuan basin as well as many similar basins. The coal bed methane (CBM) studies in China are also mentioned. These topics are still new in Vietnam and will be studied and applied in the future to evaluate potential resources and produce coal bed methane in Ha Noi trough where holds unevaluated massive coal potentials with hundreds of billion ton. However, like other member countries not directly involving in these case studies, Vietnam can only access limited amount of information about the case studies, thus reducing the opportunity for participants to learn and benefit from the lessons and outcomes of these studies. The lack of updated suitable software supporting the examples under the case studies has also created certain difficulties for the participants in their work in the future. Short discussion time for each topic is also a limitation that needs to be mentioned. b) Reserve classification Classification of the petroleum resources is a basis for analyses and decisionmaking: Government to keep control with the Nation s total petroleum resources and for the Company to manage portfolio and business processes. Therefore, reserve classification is extremely important in petroleum resource management. Reserve classification systems of CCOP, NPD and some ASEAN countries were presented in the workshops, among of them, China resource and reserves classification system is more detailed and slightly different from the western system. In Vietnam, prior to 2005, there existed two different reserve classification systems: One originated from Soviet Union (so-called Russian today) and the other came from Western Countries applied by foreign contractors. Disadvantages and advantages of these systems and their application on resource assessment and Volume 2: Final Report of Vietnam, PPM Project 175

183 inventory, as well as predictions of future production rate were analyzed and discussed. Based on workshop discussions and experiences on petroleum reserve assessment, we found that PetroVietnam needs to establish a new petroleum reserve classification system conforming to international standards to meet the requirement of current petroleum activities in Vietnam as well as improve the effectiveness of management works. Consequently, the newest petroleum reserve classification of PetroVietnam was established and approved by the Ministry of Industry for promulgation in In addition, a PRIS Categories basing on project exploration and production level was also constructed within VITRA database project in order to unify PRIS system of PetroVietnam. c) Software GeoX software has been used to carry out resource assessment works in most countries participating in the case study. Many exercises using GeoX on specific plays in case studies have been done. Through these exercises, the participants skill and experience on using GeoX have been improved and exchanged. Philippine and NPD experts experience is highly appreciated, especially experience on new features of GeoX for full cycle analysis. PetroVietnam has benefited from new tools of GeoX and gained valuable experience by using this software in PPM case studies. 3. Results of economic analysis a) Economic evaluation The evaluation of economic effectiveness and identification of the petroleum fiscal terms play a very important role in petroleum management. Some important topics such as: basic economic principles, the concept of risk in a fiscal context, petroleum fiscal regimes basic concepts, fiscal regimes and project economy, PSCs in a changing world, investment decisions, and economic modeling were presented by Dr. Alfred Kjemperud, The Bridge Group AS from Norway on case study workshops and seminars. In addition, NPD representatives have presented criteria for economic evaluation applying for exploration projects and how government authorities in Norway conduct necessary economic evaluations on new areas prior to their licensing round and also their internal process of evaluating and approval for a development plan in Norway. GeoX software is used for these evaluations. In general, presentations are based on both economic and related risk evaluations, providing basic information about economic evaluation in investment of petroleum exploration and production generally and in case studies specifically. Experiences of NPD experts on play and prospect analysis in the Norwegian continental shelf are very useful. Some exercises on economic analysis for gas prospect (formation T3Xu2) in the West of Sichuan basin, economic parameters and sensitivity with fiscal regime (profit share, government take) applied for marginal field in Kutei basin (Indonesia) were carried out basing on the current economic criteria in host countries and compared with other CCOP countries. Through these exercises, participants 176 Volume 2: Final Report of Vietnam, PPM Project

184 understood more about costs of exploration, development and production activities in the Sichuan and Kutei basins as well as economic analysis methods and fiscal policy of the host country governments for petroleum projects. At the workshops, influences of fiscal policy such as taxes, royalty, cost recovery and profit sharing, etc. to petroleum projects were carefully analyzed. The comparison on fiscal policy among Norwegian, host country governments, and other CCOP countries allows participants to have a better evaluation of the status of fiscal policy of their governments. b) Software The economic evaluation software is suitable for quick calculation and very useful for manager level. This software also needs to be flexible for actual economic evaluation works for petroleum projects. The results of economic evaluation exercise indicate that GeoX full cycle can be applied for requirements of VITRAII project. Therefore, PetroVietnam has upgraded and use GeoX5.2 in parallel with VITRA II software for resource assessment, risk and economic analysis and inventory works. However, the number of experts participating in workshops and seminars is still few. In addition, economic evaluation exercises and short discussion time for each exercise are also in limitation. Therefore, we still need assistance from CCOP to organize training courses and seminars in order to apply effectively this software for economic evaluations. The coordination between technical and economic groups is very necessary but there is still a big gap; therefore, experience exchanges and supports from CCOP to the member countries are needed to ensure that final results are scientific and can be used for petroleum projects. 4. Development options The NPD presentations focused on the Norwegian experiences related to development and production technology, fiscal framework and economics that can be applied to the case study areas and showed practical, applicable and feasible lessons for other CCOP member countries in selection of development options. The participants from Vietnam, Thailand, Malaysia, and Indonesia presented their own experiences on offshore marginal field development highlighting their government s strategies that improved the economics of the fields. Indonesia s POD (Plan of Development) and its approval system are very interesting for all companies, who have interest of investment to Indonesia. Selecting development options is the golden key of project success. Especially, selection of the right solution in development of marginal offshore fields will bring great economic effectiveness. The discussions on technology solutions, economics of the case studies are good opportunities for learning experience and exchanging knowledge, especially in 3D survey with PSDM processing, field development in deepwater areas, oil recovery enhancement, horizontal drilling, etc., among CCOP Member Countries. Volume 2: Final Report of Vietnam, PPM Project 177

185 5. Marketing options Natural gas is a fresh and clean energy source. Thus, every country has policy with incentives to encourage effective utilization of this resource. In comparison with other regional countries, Vietnam gas market is still underdeveloped. The Government pays special attention to gas industry because gas industry has an important role in the national strategy of socio-economic development and energy security. It is one of the leading industries in the industrialization and modernization, and a key element to stimulate exploration development in Vietnam. To utilize Vietnam's considerable gas potential effectively, PetroVietnam has considered gas market such as: Gas-fired power plants, Gas in industry, In Buildings, Gas in Transport, LNG Terminals and actively implemented White Tiger gas utilization project, raising gas transportation capacity onshore to million cubic meters per day for power generation; completing the construction of and putting into operation the Dinh Co liquefied petroleum gas plant to meet the LPG and condensate demand in domestic; completing gas production, pipeline and utilization projects for the gas from Nam Con Son basin and implementing South West gas projects for the gas from Malay-Tho Chu basin to meet the raw material and fuel demand of urea power complexes in Phu My and Ca Mau respectively. Power generation, which is usually considered the most important market for the use of gas, is the traditional market for hydro and coal, which are indigenous and have an intimate close relationship with other essential socio-economic issues. However, hydro and coal-fired powers are estimated, by the specialists, to be limited, and they are technical-economically inferior to the gas-fired power plants. Therefore, the competition in the immediate future may be unfavorable to the gas, but in the long term, the picture will be undisputedly reversed. To spearhead industrial growth and increate the gas production up to 13 BCM in 2010 and 18 BCM in 2020, PetroVietnam has to develop the gas market and expand the gas utilization for family life, transportation and other, and invest and construct 03 industry zones utilizing gas: South East area: with capacity of 9 BCM/year. South West area: with capacity of 8 BCM/year. North ThaiBinh area: with capacity of 2 BCM/year. For each natural gas project, PetroVietnam, as authorized by Government, has participated around 25% - 30% of contractor s share. All of natural gas produced in Vietnam has to be sold to PetroVietnam at the gas sales point in onshore through the GSPA. Then PetroVietnam will resell to the end-users by the GSA, based on long term gas contracts, and take or pay provisions with the pricing mechanism under market competition, which close to the natural gas price in international market Gas producers have to sign the TA with the transporters to transport natural gas from offshore to onshore. To further intensify gas exploration and production to meet increasing gas utilization demand, the Government continuously considers revising the legal and fiscal regimes of Vietnam in order to attract foreign investments. 178 Volume 2: Final Report of Vietnam, PPM Project

186 6. Resource management strategies Resource management strategies are extremely important for every country in term of energy policy generally, and for oil companies specifically. Petroleum resources management strategies can be thought of as a system, defined as a set upstream and downstream facilities, operating rules, and incentives (economic, regulatory, judicial, environmental pressure) applied to in situ petroleum resources, producing fields and related land infrastructures. There will always be some variation in the strategies of governments towards petroleum exploration reflecting differences in political and social philosophies. Presentations of host country, NDP experts from Norway, and other Member Countries have indicated that each country has resources management strategies to ensure not only national privileges, but also Oil Company s benefit to attract foreign investments. The government needs to have a realistic view of the total petroleum resource base, the total activities over time and of the efficiency of exploration and exploitation activities, particularly as following: Making available incentives to the exploration risk takers to stimulate exploration and exploitation activities Ensuring the development and depletion of discovered fields as a pace consistent with perceived national needs incorporating the employment of producing systems satisfactory from an environmental view point and leading to a high overall recovery factor Achieving a fair government take without discouraging investment from foreign oil companies Maintaining some degree of national control of resources Minimizing the nation s financial risk in petroleum activities by an appropriate degree of investment risk sharing with foreign companies Developing a national technology and expertise through transfer technology, training, actual involvement of nationals in petroleum operations Thus, the government, through the State oil company, is in charge of the management of the petroleum resources. The evaluation of petroleum potentials in sedimentary basin, or in each block plays a very important role. It will tell us how much asset we have discovered and yet to be discovered. The evaluation process also provides assistance in: petroleum resource management, policies of foreign investments as general and of individual licensing round in particular areas as specific, and selection of potential areas for exploration. Acknowledging the importance and significance of petroleum resource assessment, PetroVietnam has been implementing VITRA project with support of Norwegian Government to establish petroleum resource database of sedimentary Tertiary basins in Vietnam and general guidelines for reporting of petroleum resource assessment. With experiences and lessons learned from case study workshop of PPM project, core working team of VITRA project continues to update resource assessment data in the database according to projects, (both mature and frontier basins), in yearly basis. Volume 2: Final Report of Vietnam, PPM Project 179

187 International oil companies needs to make new exploration investment decisions and manage the business processes in order to achieve a reasonable return on company s investment taking into account the exploration risk and the long leadtime between the exploration and the exploitation. Classifying petroleum resources in a structured way reflects the business decisions helping companies to focus upon high value resources (proved and proved developed resources) and de-emphasizes low value resources and exploration and production potential that can not be quantified. It is because you have to know what you have before you can plan how to deal with it. 7. Licensing, contractual and fiscal conditions Licensing, contractual and fiscal conditions are vitally important and very sensitive in global competition that aims to attract foreign investments for petroleum exploration of different countries. In the case study workshops and seminars, the participants of host and CCOP countries and resource experts from Norway introduced very useful reality experiences such as Government management, exploration strategies, attracting investment for exploration in the frontier basin, licensing mechanism, contractual and fiscal conditions, and challenges in their countries. Through discussions among participants in the case study workshops, the Vietnamese participants have gained knowledge and more clearly and better understanding in fiscal regime, licensing rounds, challenges and petroleum policies in the CCOP Member Countries as well as Norway. Licensing, contractual and fiscal conditions in Vietnam are simpler and more flexible such as: Applying different petroleum contract types: PSC, JV, JOC, BCC. It should be reasonably considered type and fiscal terms for each petroleum contract. Providing flexible invitation for bids including: licensing round, limited bidding, direct negotiation depending on number of blocks and projects. Due to flexible policies, all bidding invitations achieve good results, even in areas that were used to be contracted and returned to PetroVietnam without success. Nevertheless, Vietnam is still facing many challenges for attracting foreign investment in petroleum E&P fields, including laws and regulations, management, information services. In order to create better investment environment for foreign investors, we need to consider and improve the following issues: A country should set up a strategy for attracting investment in petroleum exploration Provision of technical/contractual/policy information as much as possible can help to gain belief from investors. Business environment should always be considered to improve with more incentives given Information services and good promotion program should be organized. It is the effective way to demonstrate country s advantages and attract investment. 180 Volume 2: Final Report of Vietnam, PPM Project

188 The Vietnamese government will continue to encourage, support and promote the open of petroleum industry to the outside world, and try to create the contract fiscal terms for incentive projects (marginal fields, deep water, etc.) to attract foreign investments and increase petroleum activities. 8. Conclusions and Recommendations to management Vietnam as a member of CCOP has benefited from the project by following up the project and by designating its personnel to take part in the case studies as well as the relevant workshops and seminars organized within each case study. Through their participation in these project activities, the Vietnamese participants could approach a modern way of working as an international team work. Moreover, thought case study, Vietnam experts could update information of petroleum technical, economic and management in area and worldwide and have gained knowledge and experience, which are useful to their works as well as help them to improve their skills on managing petroleum exploration and production projects. Besides, the benefits gained from the exchange of knowledge and experience among the members of different countries, the workshops and seminars also give Vietnam an opportunity to establish its contacts and networking with technical personnel and managers from other member countries, contributing to its existing cooperation and partnership with other countries in the region. In our opinion, case studies are chances to send capacity experts to workshop in order to learn about the experiences of operation and management. If the participants from non-hosting countries receive relevant documents and information before attending the actual events, it will be easier for them to follow and learn the case studies. PetroVietnam enthusiastically follows the progress of the PPM project and ensures that the outcomes of the project are reported to the relevant level of authorities within the petroleum sector of the country. The personnel designated by the organization to participate in each case study are required to report their participation in the project activities and the knowledge and experience gained by them through these activities. Certain knowledge and experience from the PPM case studies have started to be applied in the oil and gas exploration affiliates of PetroVietnam as well as in the management of PetroVietnam head office. Moreover, such information has reached the higher level of authorities, i.e. ministerial or governmental levels but its anchor at these levels is still not stable. To build fundamental basis for managing petroleum resource appropriately and effectively to attract greater amount of foreign investments in petroleum exploration and production, PetroVietnam continues to launch VITRA project and use GeoX5.2 in parallel with VITRA II software for resource assessment, risk and economic analysis and inventory works. Simultaneously, PetroVietnam keep studying and doing researches on contract models that provide competitively economic conditions to attract international oil companies. Volume 2: Final Report of Vietnam, PPM Project 181

189 Because the number of experts participating in seminars and workshops are limited, with short discussion time for each exercise, we have not yet gained much experience, especially in new issues. There should be an assistant or sponsor from CCOP to help countries not managing case studies to practice similar cases in their countries. PetroVietnam proposes CCOP to support and organize training courses use of the GeoX tool for full-cycle analysis and seminars on a new concept for basin analysis (BCG concept) and CBM in the post PPM Project. 182 Volume 2: Final Report of Vietnam, PPM Project

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