Introduction
After more than 20 years of arduous efforts, PetroChina Company Limited (PetroChina) has made great achievements in overseas oil and gas exploration business. At present, it manages and operates 88 oil and gas cooperation projects in 32 countries of 5 major oil and gas cooperation zones, including 14 projects in 5 countries of the Middle East cooperation zone, 26 projects in 9 countries of the Central Asia & Russia cooperation zone, 17 projects in 7 countries of the African cooperation zone, 12 projects in 6 countries of the Asia-Pacific cooperation zone, and 19 projects[1,2] in 5 countries of the American cooperation zone. These projects have more than 40×108 tons of remaining recoverable reserves, and 2×108 tons of production capacity, in which the scientific and technological progress and innovation play an important role. Over the past 20 years, the overseas oil and gas exploration, starting from the Papua New Guinea project, has experienced four stages of development, namely exploratory exploration, progressive exploration, risk exploration and efficient exploration[3]. At present, the overseas exploration covers 40×104 km2, with a success rate of more than 50% for exploration wells, and a success rate of more than 40% of wildcat wells. The accumulated investment in exploration is US$ 5.2 billion, with an average discovery cost of US$ 1.95 /bbl (equivalent to US$ 12.27 /m3). With the continuous expansion of overseas business, the theory and technology for overseas oil and gas exploration has also developed from the direct borrow of mature domestic technologies in the initial stage, to integrated application, and to research and innovation according to overseas characteristics, during which a series of oil and gas exploration theories and technologies have been established, including exploration theories and technologies for passive rift basins, salt-bearing basins, foreland basin slope zones, global oil and gas geology and resource evaluation, etc[3]. These technologies have enhanced the technological core competitiveness of China's oil and gas industry, achieved good results in application, and provided strong technical support for the discovery of 3 oil fields over 1 billion tons, 4 fields over 500 million tons and 4 fields over 100 million tons reserves.
After more than 20 years of continuous exploration, the situation has undergone profound changes due to the gradual expiration of exploration right for many blocks, the rapidly reducing of exploration area, the increasing difficulty of acquisition of new exploration projects, the ever more complex conditions of the exploration domains, the changing of exploration concept, and the more prominent of benefit ideology. Therefore, in the future, we should keep a keen eye on the world's frontier of oil and gas exploration, enrich and develop the existing characteristic theories and technologies, innovate and develop our advantageous technologies, and accelerate the narrowing of the gap with the world's advanced level in terms of deep water exploration. Our goals are maintaining the international advanced level in terms of theory and technology of conventional onshore oil and gas exploration, innovatively developing the integrated optimization & evaluation technology of global oil and gas resources and assets and construction of information system therefore at the international leading level, and promoting the development of our advantageous technologies towards high-grade and precision and disadvantageous technologies towards comparability with and even occasional superiority to the internationally advanced peers, and occupying a fair share of the technology forefront.
1. Development history
PetroChina's overseas exploration business began in 1994 with the initial trial of a wildcat well in Papua New Guinea. Over the past 20 years, the overseas oil and gas exploration has gone through four stages of development, namely exploratory exploration, progressive exploration, risk exploration, and efficient exploration (Fig. 1). With rapidly increasing reserves and gradually consolidated resource base, great-leap- forward development has been realized.
Fig. 1.
Development history of PetroChina's overseas exploration business.
1.1. Exploratory exploration (1993-1995)
At the beginning of 1994, PetroChina set up a consortium with Japan Petroleum Corporation and Daewoo of South Korea to jointly carry out exploration work in the thrust belt of Papua New Guinea foreland basin, initiating the PetroChina’s overseas exploration attempt. According to the exploration contract signed with Papua New Guinea, one exploratory well would be drilled in the thrust belt of the foreland basin. Further cooperation would be discussed only if discovery was made in this well. By directly applying domestic mature theory, technology and management methods, the first exploratory well started to be drilled in the second half of 1994 and was completed in the first half of 1995. The well encountered the target formation of Paleocene sandstone, but had no oil or gas shows. The drilling of this well is the first step of PetroChina's global strategy. Although failing to make discovery, it has accumulated valuable experience for carrying out international cooperation[3].
1.2. Progressive exploration (1996-2002)
Marked by winning the bid of Areas 1/2/4 project in Sudan in 1996, PetroChina's overseas exploration entered the progressive exploration stage on the peripheral area of existing oil fields, i.e., to carry out autonomous progressive exploration around the oil field for possible expansion at the same time of large-scale development and production of new and old oil fields. In a series of integrated exploration and development projects represented by Sudan Blocks 1/2/4, great successes have been made in overseas exploration through the integrated and innovative application of mature domestic exploration theories and technologies based on the idea of progressive exploration and development of some new technologies based on overseas situations, such as the technologies of high-efficiency exploration and rapid discovery of large oil fields in areas with low exploration degree for Sudan's passive rift basin etc. These successes laid a solid foundation of re-serves for long-term sustainable development, greatly improved the overall efficiency and value of the company, and enhanced the overall strength and level of PetroChina's overseas oil and gas exploration[3,4].
1.3. Risk exploration (2003-2013)
Since 2003, PetroChina has signed a number of exploration projects in Niger, Chad, Algeria, Kazakhstan, Bath, Azerbaijan, Ecuador, Amu Darya, Myanmar, etc., which included both low exploration degree, large area, basin-wide risk exploration projects and progressive exploration projects of existing oil fields. By the end of 2005, PetroChina had acquired 23 overseas exploration projects in 14 countries, with a total exploration area of more than 80×104 km2, dominated by basin-wide wildcat exploration projects, marking that PetroChina's overseas exploration business entered the stage of large-scale risk exploration in an all-round way. On the basis of integrated application of mature domestic exploration theories and technologies, a series of new theories and technologies suitable for overseas geological characteristics have been developed, including oil and gas geology and technology of salt-bearing basins, global oil and gas geology and resource evaluation, oil and gas geologic theory and supporting exploration technologies for foreland basins, etc.[3,4]
1.4. Efficient exploration (2014-Present)
Since the oil price plunged in the second half of 2014, the oil industry has been facing unprecedented challenges. The company's overseas oil and gas exploration business has entered a new stage of quality and benefit development from the original speed & scale development, accordingly, an efficient exploration system closely focusing on "low cost, precision and benefit" is being constructed actively. We have taken the following measures: (1) Change the concept from "fast and efficient" exploration in the period of high oil prices to "benefit first" exploration in the period of low oil prices, establish a classification and ranking system of exploration assets, formulate differential exploration strategies, improve the deployment accuracy and reduce the discovery cost of unit reserves. (2) Reduce exploration investment, highlight progressive exploration, make full use of limited exploration funds, strengthen the integrated deployment of exploration and development to seek high-quality, high-efficient reserves able to be produced rapidly, to ensure progressive exploration workload and investment. (3) Taking into account the expiration of contracts, make reasonable overall arrangements, carry out out-stepping exploration in some projects concerning land withdrawal and land preservation, and postpone the implementation of high-risk, high-investment and long-term projects. (4) Upgrade management in an all-round way, strive to reduce exploration costs, further strengthen unified management and centralized decision-making, and adopt a multi-pronged approach to reduce or eliminate ineffective investment. Through the above measures, the discovery cost of unit barrel oil has decreased by 14% compared with the high oil price period, the success rate of exploration wells has increased from 67% to 83%, and the success rate of appraisal wells increased from 80% to 93%, thus achieving the goals of low cost, high efficiency exploration and scale benefit and reserves increase, laying a solid foundation for overseas quality & benefit oriented development. In the meantime, comprehensive research has been strengthened to break through bottlenecks and enrich technologies suitable for overseas exploration characteristics.
2. Development status and achievements
Over the years, great progress has been made in overseas oil and gas exploration theories and technologies, with highlights in four areas: (1) Through combining hydrocarbon geological theories and exploration concepts of rift basins in eastern China with the characteristics of rift systems in West and Central Africa, oil and gas geological theories and exploration technologies for passive rift basins have been worked out innovatively[4,5]. (2) The geologic theory and exploration technology for salt-bearing basins have been formulated by combining the research results of salt tectonic development characteristics, salt associated and related structural styles, salt dome velocity modeling and imaging in the global salt-bearing basins with the petroleum geologic characteristics of the Caspian Sea and Amu Darya basins[6]. (3) Low-amplitude structural and lithological trap identification technology, two-phase accumulation model of foreland slope zone, and logging interpretation and evaluation technology of glauconite sandstone have been developed by combining the petroleum geology understanding of typical foreland basins in South America with the petroleum geological characteristics of foreland slope in Block T of Andes Project, promoting the development of petroleum geology theory and exploration technology of overseas foreland basins[7]. (4) On the basis of domestic and foreign simulation, statistics, prospective area evaluation, and genesis resource evaluation methods[8], combined with the available data of basins with different exploration degrees in the world, a set of conventional oil and gas resource evaluation system with hydrocarbon play as the basic evaluation unit, suitable for basins with different exploration degrees, and unconventional resource evaluation method realizing difference calculation of key evaluation parameters in geological space range by "GIS spatial graphic interpolation" have been established in the process of independent evaluation of 425 basins in the world[9].
2.1. Petroleum geology theory and exploration technology for passive rift basins
The rift system in West and Central Africa is an important field for China's oil and gas exploration overseas. The concept of passive rift, put forward by Sengor and Burke in 1978, means rift basin caused by non-mantle uplift[5]. After embarking on exploration in the two Mesozoic and Cenozoic rift basins of Sudan's Muglad and Melut on the southeast side of the rift system in 1996, by reviewing the experience of domestic exploration of rift basins, and making comparison analysis between rift systems in western and central African and those in eastern China, PetroChina found that there were great differences between active and passive rift basins[10,11,12,13]. The active rift basin has the characteristics of early hydrocarbon generation, large sedimentary thickness in depression structural formation, most basin-controlling faults being listric faults, traps dominated by rollover anticlines, and development of early-stage igneous rock, etc., while passive rift basin has the characteristics of late and long duration of hydrocarbon generation, depression formations composed of multiple secondary fault-depression cycles, frequent sand-mud interbeds, small scale of depression structural layers, high and steep basin-controlling faults, mainly fault block reservoirs, and few large-scale rollover anticlines[5], etc. On this basis, theoretical knowledge on genetic classification, thermal history, hydrocarbon generation history, tectonic and structural style, sedimentation of depression formation and particularity of petroleum geology of passive rift basin have been put forward, and a reservoir formation model[11,12,13] (Fig. 2) featuring early rifting and late accumulation, indigenous oil enrichment and vertical long-distance "trans-epoch" migration in passive rift basin has been established, which has effectively guided the oil and gas exploration in Sudan/South Sudan region. Subsequently, through comparative study of hydrocarbon plays (Fig. 3) under the guidance of the above theory, the exploration domain has gradually relocated towards the central and western parts of the rift system. For Termit Basin in Niger, an innovative superimposed rift reservoir-forming model has been established featuring "large range of marine source rocks in the early rift depression period, sand control in the initial depression period of superimposed rift, control of oil and gas distribution by mudstone caprock in the deep depression period, reservoir control by fault distance and effective allocation of sand body"[14,15]. For Bongor Basin in Chad, an innovative accumulation model[16,17] of severely inverted residual basin has been established that signifies "inversion controlling structure formation, initial rift source-reservoir symbiosis, submarine fan/delta-controlling sand, paleo uplift/fault controlling reservoir, and deep/buried-hill oil enrichment", breaking the monotonous exploration idea of foreign oil companies of searching oil around uplifts in sags and the conventional ideas of continental rift "source control theory". In regard of technology, on the basis of integrated application of domestic mature technologies, three technology series, namely fine interpretation of complex fault blocks, exploration and evaluation of lithologic traps, and comprehensive evaluation of low resistivity oil and gas reservoir by combining well logging, mud logging and production test data have been developed. Besides, two major series of special technologies, namely the rapid evaluation of basins with low exploration degree and the exploration and evaluation of granite buried-hill reservoirs have been innovated. The above theoretical knowledge and technologies have been applied and led to great success in oil and gas exploration in Sudan Block 6, Sudan Blocks 1/2/4, South Sudan Blocks 3/7, Chad Block H and Niger Block Agadem. Consequently, oil fields with an annual output of 1500×104 t have been built in Blocks 1/2/4 and an oil field with an annual output of 300×104 t has been built in Block 6 of Muglad Basin in Sudan; oil fields with an annual output of 1500×104 t have been constructed in Block 3/7 of Melut Basin in South Sudan; the Chad Block H has the reserve base for construction of 600×104 t annual productivity (of which 500×104 t have been constructed) and the Block Agadem in Niger has a reserve base of 500×104 t (of which 100×104 t production capacity has been constructed).
Fig. 2.
Trans-epoch hydrocarbon accumulation model in Melut Basin, South Sudan (revised according to Reference [13]).
Fig. 3.
Comparison of hydrocarbon play and hydrocarbon distribution in main basins of western African rift system (revised according to Reference [14]).
2.2. Petroleum geology theory and exploration technology for salt-bearing basins
Salt-bearing basins contain 89% and 80% of proven oil and natural gas reserves of the world's total respectively, so they are an important domain of global hydrocarbon distribution. Caspian Sea and Amu Darya in Central Asia which PetroChina holds mining rights are representatives of such basins. In particular, the salt dome in the Caspian Sea basin is extremely thick, with a thickness of 500-3000 m in general, and has characteristics of wide coverage and formidable lateral changes[6]. The evaporite in the Amu Darya basin has the characteristics of "three gypsum and two salt layers". The thickness of evaporite is about 0-1000 m, and the salt rock and gypsum layers vary greatly in thickness, leading to large lateral variation of seismic velocity, poor seismic imaging under salt, difficulty in structural identification and reservoir prediction[18]. The former Soviet Union, Europe and the United States companies etc. have explored the basin for decades, but without commercial discoveries. Therefore, in view of the geological characteristics of salt-bearing basins such as the Caspian Sea and Amu Darya River and the above-mentioned problems, PetroChina carried out physical simulation research on salt structural deformation and reservoir formation (Fig. 4) on the basis of key researches such as early salt dome boundary imaging processing, salt dome velocity field modeling and variable velocity mapping, pre-salt structural imaging, and pre-salt carbonate reservoir prediction. The research results show that: the salt-gypsum layers are of two origins, evaporation and deep hot brine, the salt tectonic deformation is caused by 3 mechanisms, differential compaction, salt bottom detachment and gravity detachment, distribution patterns of source rock in 3 kinds of salt-bearing basins, pre-salt, between-salt and post-salt, and 4 kinds of salt-related hydrocarbon migration pathways, namely piercing necking channels, minor salt welding zones, salt leaching residual channels and anhydrite intergranular pores have been figured out, and 5 kinds of reservoir forming patterns in salt-bearing basins, namely post-salt, pre-salt, superimposition, crossover and recombination have been sorted out, according to the configuration relationship between salt beds and hydrocarbon source-migration path-hydrocarbon reservoir[6]. For the pre-Caspian basin, we have proposed the new understandings that the salt layer has effective protection to the pre-salt reservoir, the oil and gas pre-salt mainly migrated stepwise for long distance laterally, and pre-salt near-source paleo-uplifts are favorable area for hydrocarbon accumulation[6]. For the Amu Darya Basin, we proposed creatively that there developed widespread margin gentle slope reef-shoal complex in the middle, superimposed grain shoal in the west and thrust fault block fracture-cave body in the east of the Amu Darya right bank, and the multi-stage oil and gas filling and reservoir formation happened in the upper gentle slope reef-bank group and superimposed shoal in the inherited uplift in the middle and west, and the late oil and gas filling and reservoir formation took place in Cenozoic thrust structure in the east[18,19,20]. These new understandings overthrow the traditional idea that large fields only developed in shoal dike reef zone, and lead to great expansion of the exploration domain. In view of problems of poor imaging quality, abnormal velocity and inaccurate prediction of structural reservoirs, innovative technologies such as pre-salt trap identification, prediction of pre-salt carbonate reservoirs and fluids, salt associated trap evaluation, and pre-salt lithologic- stratigraphic trap evaluation etc. have been worked out. These theories and technologies have been successfully applied to the exploration of the Caspian Sea, Amu Darya, Eastern Siberia, and Tajikistan basins etc. and led to the discovery of a large oil field with 2.4×108 t reserves in North Truva in the middle block of eastern pre-Caspian Basin, and the discovery and confirmation of more than 7000×108 m3 of gas geological reserves on the right bank of Amu Darya Basin. These theories and technologies have also provided guidance for PetroChina's oil and gas exploration in pre-salt carbonate formation of the Middle East, South America and other regions.
Fig. 4.
Results and analysis of physical experiment of salt structures in the southern margin of Pre-Caspian Basin (modified from Reference [6]).
2.3. Petroleum geology theory and exploration technology for foreland basins in South America
Foreland basin is a kind of basin most abundant in oil and gas and has the most oil and gas fields discovered in the world. The foreland basin in South America is a typical foreland basin related to Type B subduction, in which fault activation controls the distribution of oil and gas in the ramp zone. In 2005, PetroChina won the exploration right for Block T, the largest exploration and development block in Ecuador's Oriente Basin, located in the ramp zone of a typical South American foreland basin. In this area, the traps are low in amplitude, small in area each, but connected into large pieces, and very subtle. Previously, foreign companies haven’t got clear understandings on the formation mechanism and distribution pattern of low-amplitude structures, lacked means of structural identification, and have considered the glauconite sandstone with high natural gamma, high density and low resistance as a non-reservoir formation and thus not paid attention to. Through research, PetroChina confirmed that the Cretaceous source rock in the ramp zone was high-abundance, high-quality and mature source rock, breaking the previous understanding that the source rock in the ramp zone couldn’t form reservoirs, and proposed a "two-stage" hydrocarbon charging mode comprising the general biodegradation of crude oil charged into the ramp zone in the early stage and the mixing of light crude oil in the later stage. Consequently, it is concluded that the later conventional crude oil and the early degraded crude oil jointly control the distribution of high-quality reserves and the density of crude oil in the ramp zone increases regularly from the northwest to the west of the mudstone zone distributed in the ramp zone, making clear the future direction of hydrocarbon exploration in Block T[7]. Our study shows that glauconite sandstone is the cause of high natural gamma, high density and low resistance, glauconite is the rock framework instead of filling material, inclusion of glauconite is the main cause of "high density" of reservoir logging response, and high bound water is the main cause of "low resistivity" of the reservoir logging response. Based on these understandings, we proposed a mixed genetic model of "endogenous glauconite" (Fig. 5) and "exogenous quartzite"[21], established a glauconite-quartzite mixed framework volumetric model, and put forward 8 identification methods in 3 categories for glauconite sandstone reservoirs, realizing comprehensive logging interpretation and evaluation of glauconite sandstone reservoirs. As a result, a new set of oil-bearing strata in the upper part of the existing oil field in the basin has been found for the first time, having new reserves of 100 million tons[7]. Technically, new technologies that integrate phase-shift profile interpretation technology, residual structure correction technology, post-stack frequency extension seismic processing, frequency division attribute inversion and facies- controlled reservoir prediction have been developed to identify low-amplitude structures and predict reservoir. While maintaining amplitude, these technologies can improve the resolution of thin sand bodies and the identification accuracy of low-amplitude structures, enabling the accurate identification and description of structures and lithologic trap complexes with closure amplitude greater than 3 m. The geological knowledge on exploration technologies for the ramp zone of foreland basin have effectively guided exploration deployment and practice in Block T of Andean project in Ecuador, adding geological reserves of more than 2×108 t through refined, high-efficiency exploration in mature exploration areas.
Fig. 5.
Genetic model of glauconite sandstone in the ramp of the Andean foreland basin (modified from Reference [21]).
2.4. Global hydrocarbon geology and resources evaluation technology
Data on global hydrocarbon resources have long been monopolized by the United States Geological Survey. Independent evaluation is the only way for China to fundamentally get rid of dependence on and restriction from foreign countries, improve our ability to share global hydrocarbon resources and to ensure national energy security. Since the China's 11th Five-Year Plan, PetroChina seized the opportunity of major scientific and technological projects of the state and the company, started from the basic research of global hydrocarbon geology, and innovated the reconstruction technologies of prototype basins, lithofacies paleogeography and reservoir forming factors on paleo-plates to trace the origin of hydrocarbon. Through these efforts, the temporal and spatial relationship between global plate tectonic evolution and prototype basins, lithofacies paleogeography, reservoir forming factors and their control on hydrocarbon in 13 geological periods have been revealed[8], and key areas, key basins and main strata of global hydrocarbon enrichment have been sorted out. A technical system for the evaluation of hydrocarbon resources based on "hydrocarbon play" has been established, breaking the international conventional method of evaluating global hydrocarbon resources based on "hydrocarbon systems or basins". By using this evaluation method, PetroChina has completed the quantitative evaluation of conventional hydrocarbon resources of 678 "hydrocarbon plays"[22] and the potential and spatial distribution of 7 types of unconventional hydrocarbon resources[23] in 425 overseas basins (Tables 1-3). By using the reserve growth evaluation technology of existing conventional hydrocarbon fields based on the "probability analysis and piecewise cumulative multiplication" method, 11 reserve growth models of discovered oil and gas fields in different regions of the world[24] have been worked out, improving the accuracy of predicting the potential growth of large hydrocarbon fields in the world by using a single model by the international authoritative organizations. More suitable for complicated and changeable geological conditions in various types of oil and gas fields in different regions, these models enabled us to predict the reserve growth potential of more than 28 000 oil and gas fields in the world in the next 30 years, providing scientific basis for evaluating the potential value of hydrocarbon field development assets. An unprecedented "global hydrocarbon resource information system" that integrates data, resource evaluation, mapping and data mining has been built. It comprises 3 core components, namely, the global hydrocarbon resource information knowledge base, resource evaluation software system and digital mapping system and 3 major functions, big data management, quantitative resource evaluation and graphical display of results, providing a secure and reliable hydrocarbon resource big data information platform for the country. The achievements were released globally from Beijing in 2017 and 2018, ending the absence of China in this field and greatly enhancing China's voice in the international hydrocarbon industry[25,26].
Table 1 Data sheet of evaluation results of global conventional oil and gas resources (revised from References [8, 25]).
| Region | Discovered reserves | Future reserve growth | Amount of prospective resources | Total/108 t | |||||
|---|---|---|---|---|---|---|---|---|---|
| Oil/108 t | Gas/1012 m3 | Oil/108 t | Gas/1012 m3 | Oil/108 t | Gas/1012 m3 | ||||
| Africa | 311 | 26 | 114 | 13 | 184 | 17 | 1055 | ||
| Middle East | 1514 | 100 | 288 | 28 | 346 | 38 | 3356 | ||
| Central Asia | 99 | 28 | 34 | 9 | 52 | 23 | 681 | ||
| Russia | 402 | 66 | 114 | 14 | 176 | 47 | 1750 | ||
| South America | 688 | 16 | 79 | 4 | 368 | 14 | 1416 | ||
| North America | 295 | 19 | 86 | 5 | 207 | 25 | 993 | ||
| Asia Pacific | 214 | 26 | 81 | 18 | 72 | 12 | 819 | ||
| Europe | 143 | 21 | 23 | 5 | 68 | 10 | 525 | ||
| Total | 3666 | 301 | 820 | 96 | 1474 | 187 | 10595 | ||
Table 2 Statistics on global unconventional oil prospective resources (revised from References [8, 25]).
| Region | Heavy oil Amount of prospective resources, in 108 t | Oil sand Amount of prospective resources, in 108 t | Tight oil Amount of prospective resources, in 108 t | Oil shale Amount of prospective resources, in 108 t | Total/108 t | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Recoverable | Geologic | Recoverable | Geologic | Recoverable | Geologic | Recoverable | Geologic | Recoverable | Geologic | |||||
| North America | 318 | 3177 | 395 | 3947 | 91 | 2540 | 699 | 3279 | 1503 | 12943 | ||||
| Asia | 88 | 449 | 156 | 599 | 77 | 1555 | 570 | 1927 | 891 | 4530 | ||||
| Russia | 409 | 4092 | 0 | 0 | 68 | 1954 | 150 | 280 | 627 | 6326 | ||||
| Middle East | 82 | 224 | 18 | 54 | 26 | 700 | 354 | 2334 | 480 | 3312 | ||||
| Africa | 130 | 502 | 48 | 273 | 79 | 2050 | 120 | 137 | 377 | 2962 | ||||
| South America | 177 | 1208 | 0 | 0 | 13 | 357 | 102 | 176 | 292 | 1741 | ||||
| Europe | 63 | 186 | 24 | 140 | 42 | 1191 | 68 | 115 | 197 | 1632 | ||||
| Oceania | 0 | 0 | 0 | 0 | 18 | 871 | 36 | 97 | 54 | 968 | ||||
| Total | 1267 | 9838 | 641 | 5013 | 414 | 11218 | 2099 | 8345 | 4421 | 34414 | ||||
Table 3 Statistics on global unconventional natural gas prospective resources (revised from References [8, 25]).
| Region | Shale gas Amount of prospective resources, in 1012 m3 | Tight gas Amount of prospective resources, in 1012 m3 | Coalbed methane Amount of prospective resources, in 1012 m3 | Total/1012 m3 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Recoverable | Geologic | Recoverable | Geologic | Recoverable | Geologic | Recoverable | Geologic | ||||
| North America | 34 | 136 | 5 | 40 | 17 | 28 | 56 | 204 | |||
| Asia | 26 | 108 | 9 | 42 | 14 | 21 | 49 | 171 | |||
| Russia | 15 | 53 | 0 | 3 | 15 | 24 | 30 | 80 | |||
| Middle East | 21 | 94 | 0 | 2 | 0 | 0 | 21 | 96 | |||
| Africa | 19 | 73 | 0 | 0 | 0 | 0 | 19 | 73 | |||
| South America | 19 | 75 | 0 | 1 | 0 | 1 | 19 | 77 | |||
| Europe | 16 | 67 | 1 | 3 | 0 | 1 | 17 | 74 | |||
| Oceania | 11 | 44 | 2 | 4 | 3 | 6 | 16 | 51 | |||
| Total | 161 | 650 | 17 | 95 | 49 | 81 | 227 | 826 | |||
3. Imminent challenges
Overseas exploration differs from domestic exploration and has particularities in terms of resource ownership, contract mode, cooperation mode, investment environment, timeliness of exploration, and project economics, etc. One of the most prominent characteristics is that the blocks and resources are owned by the government of the host countries. The oil company is only an exploration and development operator within a definite period of time. The exploration contract is short in duration and pressing in time. The exploration period is generally 3-5 years and can be extended for 1-2 times at most. At the end of each exploration phase, a portion of the exploration area must be returned. At the end of the extension period, all remaining exploration areas must be returned except for those that have been applied for development. Under such pressing exploration term, oil companies must find large-scale hydrocarbon reservoirs in the blocks as fast as possible within the valid period of the contract under the existing technical conditions, so as to enter the development period and realize the recovery of investment. Otherwise, all investment will sink as the exploration blocks are returned to the host country. Therefore, there are three major difficulties in overseas exploration at present: (1) main exploration blocks have successively expired after several rounds of extension (Fig. 6), and the exploration area has been greatly reduced after returning the exploration blocks to the host countries successively. It is estimated that 92% of newly added reserves after 2021 will be from newly acquired exploration projects in the future, but the evaluation and acquisition of new exploration projects are becoming increasingly difficult. (2) The exploration of reserved areas is also becoming more and more difficult, as the exploration pushed toward ever more complex areas, including complex structures, complex lithology, complex offshore areas, and deeper layers. (3) Since the drop of oil price, overseas oil and gas business had to change from the pursuit of scale & speed to the pursuit of quality & benefits. The exploration investments and workload have dropped drastically. The exploration concept has shifted to the success rate of exploration, the economy of targets and the convertibility of exploration findings.
Fig. 6.
Change trend of area and number of blocks in overseas exploration projects of PetroChina.
In the future, overseas exploration efforts will concentrate on 3 major domains, namely conventional onshore exploration, unconventional exploration and deep-water exploration. For conventional onshore exploration, the first step is to continuously deepen the progressive exploration of existing projects, wherein the emphasis shall be on the exploration of rift systems in West Africa, South Turgay Rift in South Central Asia, salt-bearing basins, and foreland basins in South America, consequently, hydrocarbon geological theories and exploration technologies for passive rift, salt-bearing basins and foreland basins must be further enriched and developed. Secondly, we must actively carry out comprehensive geological evaluation of the East African Rift Valley, North African Craton, Middle East deep layer and Zagros thrust belt as well as the Russian region, to prepare for acquiring new exploration projects. Accordingly, we must innovate and develop hydrocarbon geological theory and exploration technology for conventional onshore exploration fields such as active rift basin. For unconventional exploration, the first key point is to enrich and enhance the evaluation and prediction technology for "sweet spots" of existing projects such as coalbed methane in Australia, and oil sand and shale gas in Canada. The second key point is to proactively carry out the evaluation of tight oil in Argentina's Neuquen Cretaceous, North Africa's Paleozoic Silurian, UAE's Jurassic-Cretaceous, and West Siberia's Jurassic formations, to make preparation for acquiring new exploration projects. Accordingly, overseas tight oil geological theory and exploration technology should be developed. For deep-water exploration, the first key point is to actively absorb foreign deep-water hydrocarbon exploration theories and technologies, to ensure the steady development of the existing projects in Brazil, Bay of Bengal, East Africa and Australia. The second key point is to actively carry out comprehensive geological research on both sides of the Atlantic Ocean, the Gulf of Mexico, Argentina and other sea areas in order to win new exploration projects. Correspondingly, overseas deep- water hydrocarbon exploration theories and technologies should be developed.
4. Development goals and technologies
4.1. Development goals
In the future, we must keep a keen eye on the world's frontier of oil and gas exploration, enrich and develop the existing characteristic theories and technologies, innovate and develop our advantageous technologies, and narrow the gap with the world's advanced level in deep water exploration technology faster. Our goals are to maintain an international advanced level in theory and technology of conventional onshore oil and gas exploration; innovate and develop integrated optimization and evaluation technology of global oil and gas resources and assets and construct the corresponding information system, to achieve a leap from "keeping pace with" to "setting pace for" peers and reach the internationally leading level; integrate, apply and develop deep-water exploration technologies and gradually narrow the gap with the world's advanced level; evaluate more than 90% global hydrocarbon resources, maintain above 50% success rate of exploration wells in complex rift basins, keep the discovery cost below 3 US$ /bbl, promote the development of our advantageous technologies towards high-grade and precision and disadvantageous technologies to catch up or even overtake the internationally advanced peers, and occupy a fair share in the technological forefront.
4.2. Developing key theories and technologies
4.2.1. Technologies for integrated optimization and evaluation of global oil and gas resources and assets and construction of an information system
Given the huge potential of global oil and gas resources, as the understanding and technical level advance, overseas exploration and development space and fields will continue to expand. The implementation of China's "Belt & Road" initiative will also bring new opportunities to overseas oil and gas cooperation. During the "11th Five-Year Plan" and "12th Five-Year Plan" periods, we have evaluated conventional and unconventional resources in 425 major hydrocarbon-bearing basins in the world and studied hydrocarbon distribution patterns in major hydrocarbon-rich regions in depth. In the future, global hydrocarbon resources evaluation technology will go toward the following two directions.
(1) Technologies for integrated optimization and evaluation of global oil and gas resources and assets. In the future, the global evaluation of hydrocarbon resources will become more and more systematic, scientific, strategic and foresight and cover conventional, unconventional, deep water, deep formations, natural gas hydrate and other fields, in the meantime, formulate a set of integrated optimization & evaluation technology for global hydrocarbon resources and assets creatively. Emphasis will be placed on the development of integrated optimization & evaluation technology for conventional and unconventional, deep water and deep formation, natural gas hydrate and other resources and assets.
(2) Global oil and gas resource asset information system. We will develop the GRIS3.0 software platform integrating global geological information, resource evaluation and asset evaluation. For a long time, we rely on internationally renowned databases such as IHS, Wood Mackenzie, C&C, etc. for global hydrocarbon resources evaluation, and have to spend a lot of money to purchase data usage rights every year, which is the key technical bottleneck in the global oil and gas resource evaluation. For future database construction, in addition to enriching and improving the global hydrocarbon resources information system, the focus will be placed on building a global hydrocarbon resources and asset database that integrates information on oil and gas geology, oil and gas fields, exploration and development dynamics, economic evaluation, and asset transactions, etc.
4.2.2. Exploration theory and supporting technology for complex rift basins
As the exploration degrees in rift systems in the West and Central Africa, Turgay rift basin in South Central Asia, and back-arc rift in Central Sumatra, Indonesia go higher, and the future exploration fields turn toward rift systems in East Africa, Karoo rift, Siberian rift and other fields, the exploration in overseas rift basins will also get more and more difficult, the exploration areas will also gradually expand from early passive rift basins to active rift basins. Therefore, the exploration theory and technology for rift basins will develop toward the following three directions in the future.
(1) Theory and technology of deep complex lithology exploration. As the exploration degree in the remaining blocks goes higher, there is an urgent need to make breakthrough in the theoretical understanding of hydrocarbon geology in deep reservoirs such as the deep lower play in Niger's Termit Basin, Cretaceous in South Sudan's Melut Basin, and Jurassic in South Turgay Basin etc, and to tackle bottlenecks in exploration technologies for complex lithology such as deep complex fault blocks, lithologic strata, granite buried hills and metamorphic buried hills. Therefore, it is imperative to innovate and develop exploration theories and supporting technologies for complex rift basins.
(2) Exploration theory and technology for major inversion rift basin. In the future, the focus of exploration of rift systems in West and Central Africa will gradually shift to major inversion rift basins, such as Doseo and Salament, close to the shear zone in Central Africa. Due to severe denudation of strata above the Upper Cretaceous, these basins differ widely from other rift systems in West and Central Africa in terms of sedimentary strata characteristics, play characteristics, structural development characteristics and hydrocarbon distribution patterns, and we have no clear geological understanding on these rift basins. Therefore, it is urgent to innovate and develop the exploration theory, play evaluation and exploration target optimization techniques for strong inversion rift basins to improve the exploration success rate.
(3) Exploration theory and technology for rift basins with wide development of igneous rocks. Future exploration areas in overseas rift basins will be gradually relocated to new areas such as East African rift systems. Igneous rocks are better developed in these rift basins and have great influence on hydrocarbon exploration. For example, due to the shielding effects of igneous rocks, exploration in the southern depression of the Melut basin in South Sudan has not achieved any scale discovery after nearly 20 years of exploration. Therefore, It is urgent to develop exploration theory and technologies for rift basins with igneous rock, for example, low-frequency seismic source acquisition technology able to overcome the igneous rock shielding, seismic processing technology under igneous rock shielding, complex igneous rock identification technology, technology to identify igneous rock development mode, and get new geological understandings on the effect of igneous rock on the genetic mechanism and distribution pattern of igneous reservoirs.
4.2.3. Prediction technology for complex pre-salt carbonate reservoir and fluid
Salt-bearing basins are widely distributed in the world. With the deepening of theoretical understanding and the advancement of technical level, exploration will extend to new domains constantly. In the future, the focus of overseas salt-bearing basin exploration will shift to the pre-salt carbonate rocks in Brazil and the Middle East. In Santos basin of Brazil, although the salt domes are similar to those in Caspian basin, due to the influence of mid-Atlantic ridge, igneous rocks are abnormally developed; the overlying salt dome and igneous rocks make it difficult to predict pre-salt carbonate reservoirs and fluid. Hence, the development direction of salt-bearing basin technology in the future will gradually shift from early salt dome imaging, and identification of pre-salt traps etc. to prediction of pre-salt carbonate pore types and fractured reservoirs, identification and prediction of pre-salt igneous rocks, and prediction of pre-salt carbonate fluids, which requires further improvement in seismic imaging precision of carbonate rocks, identification capability of igneous rocks, conformity rate of carbonate reservoir prediction, identification capability of oil, gas, water and carbon dioxide.
4.2.4. Deep-water oil and gas exploration theory and technology
Oil and gas resources in the oceans are abundant around the world but low in overall exploration level. Up to 2017, in ocean areas, the remaining technically recoverable reserves accounted for 43.7% of the world's total reserves, the density of exploration wells was less than 2 wells/104 km2, and the output exceeded 20×108 t equivalent, so ocean areas are the main battlefield for resource allocation of major oil companies[25,26]. In the near future, key deep-water oil and gas exploration areas will include both sides of the Atlantic Ocean, Gulf of Mexico, eastern Mediterranean, East African offshore, Australian offshore, Arctic offshore and other areas. PetroChina has gradually dabbled into the offshore domain since 2005, but lags in deep-water hydrocarbon exploration theory and technologies behind major international oil companies. In the future, China needs to gradually establish its own unique deep-water hydrocarbon geological theory, vigorously develop submarine node seismic acquisition technology, new offshore seismic source and multi-source synchronous excitation technology, high-precision seismic data target processing technology, deep-water sedimentary system evaluation technology, deep-water and ultra-deep water play evaluation technology, and hydrocarbon detection technology, etc., to enhance its technical strength of hydrocarbon exploration in the oceans, deep waters and ultra-deep waters.
4.2.5. Unconventional evaluation technology for "sweet spots"
Since 2010, PetroChina has successively embarked on exploration and development of unconventional resources like coalbed methane in Bowen and Surat Basins of East Australia, and oil sands, tight gas and shale gas in Canada. Since the drop of oil prices, overseas unconventional areas have experienced arduous trials, making the economic and effective production the biggest problem currently confronting us. The economy of unconventional resource is affected by factors such as the size of "sweet spot". In the future, overseas unconventional resource evaluation will focus on the scale evaluation of economically recoverable reserves of "sweet spots" and the key technologies for the transformation of "sweet spots" to the core area, strengthen the evaluation of integrated exploration and development engineering market, optimize the evaluation parameters of "sweet spots", clarify the size and distribution scope of "sweet spots", and confirm the resource quantity of "sweet spots", to provide a solid resource basis for the transformation to the core area.
4.2.6. Supporting techniques for oil and gas exploration in polar alpine regions
Polar alpine region is located south of 60°S latitude and north of 66°34' N latitude. It has a wide area, low exploration and development degree, large resource potential, and about 15% of the global prospective resources, making it an important strategic area for future hydrocarbon exploration and development[25]. Rosneft, Gazprom, Novatek, Total, and Equinor companies etc. have successively entered into this domain. PetroChina owns two development projects in the Arctic Yamal Peninsula. In view of the above-mentioned field, it is urgent for China to stock up key engineering equipment and technologies for low-temperature and ultra-low-temperature environments. Key technologies to be developed include sub-ice seismic acquisition and processing technology, low temperature-ultra low temperature drilling technology, and high efficiency drilling technology for extended-reach horizontal wells.
5. Conclusions
PetroChina has made great achievements in overseas oil and gas business after more than 20 years of arduous efforts. The overseas oil and gas exploration technology has also gone through the development process from direct borrow of mature technologies in China, to integrated application in line with geological characteristics of overseas oilfields, and to innovative research and development and establishment of a series of characteristic technologies. Leap forward progress has been made in theoretical understandings on and exploration technologies for passive rift basin, salt-bearing basin, overseas foreland basin, and global hydrocarbon geology and resource evaluation, which have supported the global deployment and rapid development of overseas oil and gas business. Looking back at the development in the past over 20 years, the overseas exploration field is gradually expanding, and the advancement in theoretical understanding and technology is playing an increasingly important role. Looking to the future, given the general trend of increasing worsening of global hydrocarbon resources grade, and under the background of lingering low international oil price, the improvement of theoretical understanding and technological progress is of vital importance to the economic benefit of overseas projects. Therefore, we must deepen theoretical understanding on conventional onshore oil and gas, develop supporting exploration technologies towards higher precision and high-end direction, improve the economic efficiency and effectiveness of unconventional technologies, enhance technical strength in deep water & ultra-deep water exploration, and seize strategic commanding point of targeted technology development for polar and alpine regions. Global hydrocarbon resource evaluation and advanced zone selection technology should be based on large basins in the world and focused on development of advanced evaluation technologies for key frontier areas. The advancement of above theoretical understanding and technologies will surely provide strong technological support for overseas high-quality, efficient and sustainable development.
Reference
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Approximately 40 percent of the world’s population relies on solid fuels, including wood, dung, grass, crop residues, and coal, for cooking (Bonjour and others 2013). Household air pollution (HAP) arising from this use of solid fuels results in 3 million to 4 million deaths yearly from acute lower respiratory infection (ALRI) in children and chronic obstructive pulmonary disease (COPD), ischemic heart disease (IHD), stroke, and lung cancer in adults. This burden constitutes approximately 5 percent of global mortality, ranking highest among all environmental risk factors contributing to global ill health (Forouzanfar and others 2015; Smith and others 2014). In India, the reliance on solid fuels and the estimated related burden of disease are pronounced. An estimated 770 million individuals—approximately 70 percent of the total population (Government of India 2011)—living in 160 million households continue to use solid fuels as a primary energy source for cooking (Venkataraman and others 2010). Among all risk factors contributing to ill health in India, exposure to HAP from cooking ranks second for mortality, with approximately 925,000 premature deaths yearly; it ranks third for lost disability-adjusted life years (DALYs), amounting to approximately 25 million lost DALYs per year (Forouzanfar and others 2015). An estimated 4 percent of the deaths occur in children under age five years because of pneumonia, which overall accounts for 12 percent of total child deaths in India. Attempts to reduce this burden fall into two primary categories: (1) those that seek to make biomass combustion cleaner and more efficient, and (2) those that seek to replace biomass use with liquid fuels or electricity (Foell and others 2011; Smith and Sagar 2015). Private and public sector actors have taken action in India to reduce this large burden of disease. Private sector endeavors include research, development, marketing, and distribution of biomass stoves by large multinational corporations, such as Philips and BP, and smaller Indian and international firms, such as Envirofit, Greenway, First Energy, BioLite, and Prakti. In all cases, the evaluations of the viability of these interventions for long-term use, which would be required to reduce exposures and thus the health burden, have been mixed (Brooks and others 2016; Pillarisetti and others 2014; Sambandam and others 2015). The government of India has undertaken a number of policy initiatives to address HAP through improved biomass combustion, beginning in the 1980s with a failed National Programme on Improved Chulhas (Kishore and Ramana 2002) and continuing in 2010 with a National Biomass Cookstoves Initiative. More recently, two innovative programs—the Give It Up (GIU) and Smokeless Village (SV) campaigns—are seeking to bring clean cooking via liquefied petroleum gas (LPG) to the rural poor (Smith and Sagar 2015). Both GIU, which encourages better-off Indian households to voluntarily give up their LPG subsidies and redirects those subsidies one-for-one to below-poverty-line (BPL) families, and SV, which connects every household in a village to LPG, occur in close collaboration with India’s three national oil companies. In mid-2016, Indian Prime Minister Narendra Modi introduced Pradhan Mantri Ujjwala Yojana (Ujjwala), a program to extend the GIU and SV campaigns by making free LPG connections available to all BPL households. This policy will affect approximately 50 million households. These programs have the potential to substantially reduce the mortality and morbidity associated with the use of solid fuels for cooking, if one assumes near-complete transitions to clean fuels (Smith and Sagar 2015). This chapter describes an extended cost-effectiveness analysis (ECEA) of policies designed to promote uptake of hypothetical HAP control interventions aligned with three national government programs: A low-cost, mud chimney stove, as was promoted in the National Programme on Improved Chulhas that operated from about 1983 to 2002 (We evaluate this program under the same current conditions as the other programs.) An advanced combustion cookstove, like that being promoted in the current National Biomass Cookstoves Initiative. A transition to LPG being promoted in the national Give It Up campaign. Our scenarios simplify complex behavioral issues by assuming full use of all intervention stoves in order to estimate best-case health and welfare benefits of clean cooking transitions. We evaluate the sensitivity of our use assumption in annex 12A. Our goal is to indicate the types of policy-relevant analyses that are possible using ECEA and the magnitude of potential benefits of LPG adoption. Traditional economic cost-effectiveness analyses, such as that by Mehta and Shahpar (2004), focus on the U.S. dollars spent per death or per DALY averted. ECEA also considers the financial implications of policies across wealth strata of a population (introduced in Verguet, Laxminarayan, and Jamison 2015), in this case, by income quintile. ECEAs assess the consequences of financial or other policies that influence the aggregate uptake of an intervention and its health and financial consequences across income groups. Verguet, Laxminarayan and Jamison (2015), for example, looked at public finance and enhanced borrowing capacity as policies to affect tuberculosis treatment in India. Verguet and others (2015) assessed the consequences of a policy to increase tobacco taxes in China. Including distributional analysis by income quintile enables novel policy evaluations, as well as an evaluation of the GIU campaign. This ECEA focuses on policies to reduce exposure to HAP in Haryana, India. This state has a population of 20 million, about 55 percent of whom use solid fuels for cooking, although significant heterogeneity exists between both rural and urban areas and between available datasets for analyses. 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A great number of published data and our experimental results of interfacial tensions between hydrocarbon compounds and CO2 were collected and screened. Based on these experimental data, the changing laws of interfacial tensions between different kinds of hydrocarbon compounds and CO2 were obtained, interfacial tensions between different kinds of saturated chain hydrocarbons and CO2 were compared with each other, and interfacial tensions of three different binary system (monocyclic hydrocarbon compounds-CO2 system, hydrocarbon compounds monocyclic and chain structure-CO2 system and dicyclic hydrocarbon compounds-CO2 system) were compared with those of saturated chain hydrocarbon compounds-CO2 system. It is found that molecular structure is the main factor to affect the sizes of interfacial tensions between hydrocarbon compounds and CO2; when carbon numbers of different kinds of hydrocarbon compounds are equal, their proper order from big to small in interfacial tension is: polycyclic hydrocarbon, hydrocarbon monocyclic and chain structure, monocyclic hydrocarbon, saturated chain hydrocarbon. The comparison results at different pressure conditions were respectively used to establish the conversion relations in equivalent carbon number between interfacial tensions of cyclic hydrocarbon-CO2 systems and those of saturated chain hydrocarbon-CO2 systems.
