Challenges and countermeasures of log evaluation in unconventional petroleum exploration and development

To promote adaptation of logging evaluation technologies to the development trend of unconventional oil and gas exploration and development era in China,the current situation and challenges of logging evaluation technologies in China are analyzed systematically.Based on the concept of that demand drives technology development,and referring to the international leading technologies,development strategy of logging evaluation technology in China has been put forward.(1)Deepen petrophysics study:mobile 2 D NMR laboratory analysis technology for full diameter core should be developed,characteristic charts and evaluation standards of different fluid properties,different pore structures and different core exposure times should be established based on longitudinal and traverse relaxation spectra;in-depth digital rock experiment and mathematical and physical simulation research should be carried out to create innovative logging evaluation methods;acoustic and electrical anisotropy experimental analysis technology should be developed,and corresponding logging evaluation methods be innovated.(2)Strengthen target processing of logging data:precise inversion processing technology and sensitive information extraction technology of 2 D NMR logging should be developed to finely describe the micro-pore distribution in tight reservoir and accurately distinguish movable oil,bound oil,and bound water etc.The processing method of 3 D ultra-distance detection acoustic logging should be researched.(3)Develop special logging interpretation and evaluation methods:first,mathematical model for quantitatively describing the saturation distribution law of unconventional oil and gas near source and in source should be created;second,evaluation methods and standards of shale oil and deep shale gas"sweet-spots"with mobile oil content and gas content as key parameter separately should be researched vigorously;third,calculation methods of pore pressure under two high-pressure genetic mechanisms,under-compaction and hydrocarbon charging,should be improved;fourth,evaluation method of formation fracability considering the reservoir geologic and engineering quality,and optimization method of horizontal well fracturing stage and cluster based on comprehensive evaluation of stress barrier and lithologic barrier should be worked out.

New concepts for deepening hydrocarbon exploration and their application effects in the Junggar Basin, NW China

The Junggar Basin is one of the major petroliferous basins with abundant oil and gas resources in onshore China.Around 2010 and thereafter,the hydrocarbon exploration for finding giant fields in the basin faced tough difficulties:in the northwestern margin area,no significant breakthrough has been made for long since seeking to"escape from the step-fault zone and extend to the slope area";in the central part,the exploration for large lithologic-stratigraphic reservoirs stood still;since the discovery of the Kelameili gas field,no important achievement has been made in gas exploration.Under the guidance of"whole sag-oil-bearing"theory in the petroliferous basin,and based on the long-term study and thinking of the petroleum accumulation conditions and characteristics,the authors proposed several new concepts,i.e.,a"thrust-induced second-order fault step"hiding under the northwestern slope area;six"hydrocarbon migrationward surfaces"favorable for hydrocarbon accumulation;promising natural gas resource.These concepts have played an important role in the discoveries of Wells Mahu1 and Yanbei1 as well as the confirmation and expansion of Permian-Triassic billion-ton-scale petroliferous areas in Mahu.The fairway of new discoveries has also appeared for natural gas exploration in Wells Fu26,Gaotan1 and Qianshao2,suggesting that the surrounding regions of the highly matured source kitchen are of high possibility to form gas accumulations.

Characteristics of Abnormal Pressure Systems and Their Responses of Fluid in Huatugou Oil Field,Qaidam Basin

Based on the comprehensive study of core samples, well testing data, and reservoir fluid properties, the construction and the distribution of the abnormal pressure systems of the Huatugou oil field in Qaidam Basin are discussed. The correlation between the pressure systems and hydrocarbon accumulation is addressed by analyzing the corresponding fluid characteristics. The results show that the Huatugou oil field as a whole has low formation pressure and low fluid energy; therefore, the hydrocarbons are hard to migrate, which facilitates the forming of primary reservoirs. The study reservoirs, located at the Xiayoushashan Formation （N1/2） and the Shangganchaigou Formation （N1） are relatively shallow and have medium porosity and low permeability. They are abnormal low-pressure reservoirs with an average formation pressure coefficient of 0.61 and 0.72 respectively. According to the pressure coefficient and geothermal anomaly, the N1 and N1/2 Formations belong to two independent temperature-pressure systems, and the former has slightly higher energy. The low-pressure compartments consist of a distal bar as the main body, prodelta mud as the top boundary, and shore and shallow lake mud or algal mound as the bottom boundary. They are vertically overlapped and horizontally paralleled. The formation water is abundant in the Cl^- ion and can be categorized as CaCl2 type with high safinity, which indicates that the abnormal low-pressure compartments are in good sealing condition and beneficial for oil and gas accumulation and preservation.

Oil Source of Reservoirs in the Hinterland of the Junggar Basin

Through oil-oil and oil-source correlation and combined with the comprehensive study of hydrocarbon generation and accumulation history, the oil sources of typical reservoirs of different geologic periods in the hinterland of the Junggar basin are revealed. It is concluded that the crude oils in the study area can be classified into four types： The oil in the area of well Zhuang-1 and well Sha-1 belongs to type-I, which was generated from Cretaceous to Paleogene （K-E） and its source rocks are distributed in the Fengcheng formation of the Permian in the western depression to the well Pen-1. The oil in the area of well Yong-6 （K1 tg） belongs to type-Ⅱ, which was generated from Cretaceous to Paleogene and its source rocks are distributed in the Wuerhe formation of the Permian in the Changji depression. The oil in the area of well Yong-6 （J2x） belongs to type-III, which was generated at the end of the Paleogene and its source rocks are distributed in the coal measures of the Jurassic in the Changji depression. The oil of well Zheng-1 and well Yong-1 belongs to type-IV, which was generated in the Paleogene, and its source rocks are distributed in the Wuerhe formation of the Lower Permian and coal measures of the Jurassic. It is indicated that the hydrocarbon accumulation history in the study area was controlled by the tectonic evolution history of the Che-Mo palaeohigh and the hydrocarbon generation history of well Pen-1 in the western depression and Changji depression.

Theoretical understandings, key technologies and practices of tight conglomerate oilfield efficient development: A case study of the Mahu oilfield, Junggar Basin, NW China

A series of theoretical explorations and field tests have been carried out to efficiently develop the Mahu tight conglomerate oilfield in the Junggar Basin.Concepts of steered-by-edge fracturing and proactive fracturing interference were proposed.A series of innovative technologies were developed and implemented including optimization of 3-D staggered well pattern,proactive control and utilization of spatial stress field,and synergetic integration of multiple elements.Different from shale,the unique rock fabric and strong heterogeneities of tight conglomerate formation are favorable factors for forming complex fractures,small space well pattern can proactively control and make use of interwell interference to increase the complexity of fracture network,and the"optimum-size and distribution"hydraulic fracturing can be achieved through synergetic optimization.During pilot phase of this field,both depletion with hydraulically fractured vertical wells and volume fracturing in horizontal wells were tested after water injection through vertical wells,then the multi-stage fracturing with horizontal well was taken as the primary development technology.A series of engineering methods were tested,and key development parameters were evaluated such as well spacing,lateral length,fractures spacing,fracturing size,and fracturing operation process.According to geoengineering approach,the 100 m/150 m tridimensional tight-spacing staggered development method was established with systematic integration of big well clusters,multiple stacked pay zones,small well spacing,long lateral length,fine perforation clustering,zipper fracturing and factory operation.According to half-year production performance,100 m/150 m small spacing wells outperformed 500 m/400 m/300 m spacing wells.Its average estimated ultimate recovery(EUR)of wells was identical with those best wells from large-spacing area.Compared with the overall performance of Mahu oilfield,the drainage efficiency and estimated recovery factor of this pilot were significantly boosted with improved economics.

CNPC's Future Exploration Targets for Giant Gas Fields

Potential exploration targets for giant gas fields Based on the distribution of remaining gas resources,the exploration targets selection as well as an analysis of controlling factors for giant gas

Defining stratigraphic oil and gas plays by modifying structural plays:A case study from the Xihu Sag,east China Sea Shelf Basin

The study focuses on an area of relatively mature oil and gas exploration located in the western slope of the Xihu Sag,East China Sea Shelf Basin.Three stratigraphic oil and gas plays are introduced to replenish the shrinking prospect inventory in the area.The reservoirs of these plays are traditional pay intervals of the Eocene Pinghu Formation and Baoshi Formation composed of tide-dominated delta front,tidal flat and delta front sand bar facies.By investigating conventional seismic data,seismic inversion volumes,and well log data,multiple tidal-influenced delta front channels,beach sand packages have been mapped out in different reservoir sand intervals of the Pinghu Formation and Baoshi Formation.We recognize four types of stratigraphic terminations:channel flank pinch-outs,axial pinch-outs of sand-fills,channel mouth sand bar pinch-outs,and onlap pinch-outs for the Baoshi Formation.Both the depositional facies and relatively low sand-shale ratio of the reservoir formations favor the occurrence of stratigraphic terminations.The closure mechanism of all these plays are similar to the traditional structure plays in the area:fault blocks or fault-bounded rollover anticlines,except that one or more closing faults are replaced by these stratigraphic terminations.Several small-sized closures should exist but the relatively large ones are centered around a major intra-slope rise,raising the exploration potential in this maturely explored area.The new exploration drilling campaign has so far tested the play of delta front channel facies,with three out of four wells commercially successful.These play concepts open up a novel approach to identify new traps in the study area and many other rift basins with similar settings in eastern China.

Construction of well logging knowledge graph and intelligent identification method of hydrocarbon-bearing formation

Based on the well logging knowledge graph of hydrocarbon-bearing formation(HBF),a Knowledge-Powered Neural Network Formation Evaluation model(KPNFE)has been proposed.It has the following functions:(1)extracting characteristic parameters describing HBF in multiple dimensions and multiple scales;(2)showing the characteristic parameter-related entities,relationships,and attributes as vectors via graph embedding technique;(3)intelligently identifying HBF;(4)seamlessly integrating expertise into the intelligent computing to establish the assessment system and ranking algorithm for potential pay recommendation.Taking 547 wells encountered the low porosity and low permeability Chang 6 Member of Triassic in the Jiyuan Block of Ordos Basin,NW China as objects,80%of the wells were randomly selected as the training dataset and the remainder as the validation dataset.The KPNFE prediction results on the validation dataset had a coincidence rate of 94.43%with the expert interpretation results and a coincidence rate of 84.38%for all the oil testing layers,which is 13 percentage points higher in accuracy and over 100 times faster than the primary conventional interpretation.In addition,a number of potential pays likely to produce industrial oil were recommended.The KPNFE model effectively inherits,carries forward and improves the expert knowledge,nicely solving the robustness problem in HBF identification.The KPNFE,with good interpretability and high accuracy of computation results,is a powerful technical means for efficient and high-quality well logging re-evaluation of old wells in mature oilfields.

Current Situation and Outlook of CBM Industry in China

Current situation of CBM industry in China China is abundant in CBM with a resource buried shallower than 2000 meters of 36.81 tcm and recoverable resource of 10.87 tcm. This resource base is favorable

CNPC's Future Exploration Targets for Giant Gas Fields

The 21st century is regarded as an era of natural gas for the petroleum industry. That is one of the reasons why CNPC had

Influence of tectonic uplift-erosion on formation pressure

The formation of abnormally low-pressure hydrocarbon reservoirs in petroliferous basins has a close relationship with tectonic uplift and the consequent erosion. In order to understand abnormally low-pressure reservoirs and to provide a scientific basis for exploration and development, we established, through numerical simulation and theoretical analysis, a set of equations for the formation pressure in a closed system influenced by uplift-erosion, discussed the relationship between the genesis of abnormal pressure and uplift-erosion, and put forward the concept of balance pressure （P b ）. The results showed that abnormally high pressure coefficient may form when the current formation pressure was higher than P b , and abnormally low pressure may form when the current formation pressure was lower than P b . In the Santanghu Basin, the current formation pressure of abnormally low pressure reservoirs is lower than P b , so tectonic uplift-erosion leads to the decrease of the pressure coefficient. There is a positive correlation between the pressure drop caused by the decrease of fluid temperature and the rebound of rock porosity and strata erosion. Calculation results indicated that the reservoir pressure of Jurassic strata in the Santanghu Basin was decreased by 11.6-17.1 MPa due to tectonic uplift-erosion during the Late Yanshanian period.

Application Research of Oil Development Costs in Reservoir Management

Based on oil development costs, the application research in the technical and economic limits calculation of oil development and the production optimal allocation to all the oilfields, was finished. At the same time, according to the regression of real development costs, a new method for oil well economic water cut and oil well economic rate are set up, the production optimal allocation is developed with satisfactory results.

Introduction of the 1st Asia-Pacific Geophysics Student Conference(APGSC 2020)

The Asia-Pacific Geophysics Student Conference(APGSC 2020)is the first student-led and student-organized international geophysics conference in the Asia-Pacific region.The theme of APGSC is"Bridging the Gap between Exploration and Solid-Earth Geophysics".This conference is designed to provide a platform for gathering students with different geophysical backgrounds to exchange ideas,show research results,and explore the frontiers of geophysics and related fields.Students could better understand current and future developments of geophysics and build a bridge between exploration and solid-earth geophysics.The 1st Asia Pacific Geophysical Student Conference(APGSC 2020)is successfully held online on September 6-9,2020 Beijing time.This conference is hosted by the University of Science and Technology of China(USTC)and the Society of Exploration Geophysicists(SEG).More than 30 universities and scientific research institutions at home and abroad give strong support as co-organizers.The academic committee of the conference is composed of more than 50 experts and scholars.

China's Natural Gas Output to Double in 10 Years

China’s natural gas output will at least double the present volume in the coming decade to reach 150 billion to 200 billion cubic meters, according to PetroChina Vice President Jia Chengzao. As the country’s leading natural gas producer, PetroChina alone has reported an annual output rise of 10 billion cubic meters for two consecutive years. 'We will strive to keep the same growth rate this year,' said Jia. His company produces about 75 percent of China’s total natural gas output.

Changbei Wells:Shell Drills Gas Project in China

The Changbei field area in the Ordos plateau, at the southern tip of the Gobi Desert, is twice the size of Beijing city.To supply gas for the Olympics, Shell is drilling the longest horizontal wells ever attempted in

The porosity origin of dolostone reservoirs in the Tarim, Sichuan and Ordos basins and its implication to reservoir prediction

Origin of dolostone remained a controversial subject, although numerous dolomitization models had been proposed to date. Because of the dolomitization's potential to be hydrocarbon reservoirs, one debatable issue was the role of dolomitization in porosity construction or destruction. Based upon case studies of dolostone reservoirs in various geological settings such as evaporative tidal flat(Ordos Basin, NW China), evaporative platform(Sichuan Basin, SW China), and burial and hydrothermal diagenesis(Tarim Basin, NW China), here we systematically discuss the origin of porosity in dolostone reservoirs. Contrary to traditional concepts, which regarded dolomitization as a significant mechanism for porosity creation, we found two dominant factors controlling reservoir development in dolostones, i.e., porosity inherited from precursor carbonates and porosity resulted from post-dolomitization dissolution. Actually, dolomitization rarely had a notable effect on porosity creation but rather in many cases destroyed pre-existing porosity such as saddle dolostone precipitation in vugs and fractures. Porosity in dolostones associated with evaporative tidal flat or evaporative platform was generally created by subaerial dissolution of evaporites and/or undolomitized components. Porosity in burial dolostones was inherited mostly from precursor carbonates, which could be enlarged due to subsequent dissolution. Intercrystalline porosity in hydrothermal dolostones was either formed during dolomitization or inherited from precursor carbonates, whereas dissolution-enlarged intercrystalline pores and/or vugs were usually interpreted to be the result of hydrothermal alteration. These understandings on dolostone porosity shed light on reservoir prediction. Dolostone reservoirs associated with evaporative tidal flat were laterally distributed as banded or quasi-stratified shapes in evaporite-bearing dolostones, and vertically presented as multi-interval patterns on tops of shallowing-upward cycles. Dolostone reservoirs associated with evaporative platform commonly occurred along epiplatforms or beneath evaporite beds, and vertically presented as multi-interval patterns in dolostones and/or evaporite-bearing dolostones of reef/shoal facies. Constrained by primary sedimentary facies, burial dolostone reservoirs were distributed in dolomitized, porous sediments of reef/shoal facies, and occurred vertically as multi-interval patterns in crystalline dolostones on tops of shallowing-upward cycles. Hydrothermal dolomitization was obviously controlled by conduits(e.g., faults, unconformities), along which lenticular reservoirs could develop.

Process and mechanism for oil and gas accumulation, adjustment and reconstruction in Puguang Gas Field, Northeast Sichuan Basin, China

With the discoveries of a series of large gas fields in the northeast of Sichuan Basin, such as Puguang and Longgang gas fields, the formation mechanism of the gas reservoir containing high H2S in the ancient marine carbonate formation in superposition-basin becomes a hot topic in the field of petroleum geology. Based on the structure inversion, numerical simulation, and geochemical research, we show at least two intervals of fluid transfer in Puguang paleo-oil reservoir, one in the forepart of late Indo-Chinese epoch to early Yanshan epoch and the other in the metaphase of early Yanshan epoch. Oil and gas accumulation occurred at Puguang structure through Puguang-Dongyuezhai faults and dolomite beds in reef and shoal facies in Changxing Formation (P2ch) - Feixianguan Formation (T1f) in the northwest and southwest directions along three main migration pathways, to form Puguang paleo-oil reservoir. Since crude oil is pyrolysised in the early stage of middle Yanshan epoch, Puguang gas reservoir has experienced fluid adjusting process controlled by tectonic movement and geochemical reconstruction process controlled by thermochemical sulfate reduction (TSR). Middle Yan-shan epoch is the main period during which the Puguang gas reservoir experienced the geochemical reaction of TSR. On one hand, TSR can recreate the fluid in gas reservoir, which makes the gas drying index larger and carbon isotope heavier. On the other hand, the reciprocity between fluid regarding TSR (hydrocarbon, H2S, and water) and reservoir rock induces erosion of the reservoir rocks and anhydrite alteration, which improves reservoir petrophysical properties. Superimposed by later tectonic movement, the fluid in Puguang reservoir has twice experienced adjustment, one in the late Yanshan epoch to the early Himalayan epoch and the other time in late Himalayan epoch, after which Puguang gas reservoir is finally developed.

Formation Mechanism of Underpressured Reservoir in Huatugou Oilfield of Qaidam Basin

Underpressured reservoirs are widespread in the Huatugou （黄土沟） oUfield of the western uplift in Qaidam basin, western China. At depths between 462 and 1 248 m, the pressure of Neogene reservoirs in the Huatugou oUfield is only about 40% to 80% of hydrostatic pressure. Based on a study of the geological characteristics of these underpressured reservoirs, this work used fluid inclusion analysis and numerical simulation to investigate the mechanism creating these abnormal pressures and to evaluate the characteristics of the hydrocarbon distribution. The results show that the underpressured reservoirs are all well-sealed by undercompacted and thick mudrocks. The large-scale tectonic uplift in the late Himalayan plays an important role in the generation of underpressure in the Huatugou oilfield. At the beginning of this movement, the field was overpressured due to episodic petroleum accumulation. Later, structural uplift and erosion led to porous rebound and a temperature decrease, which produced the underpressure.

CO2 flooding strategy to enhance heavy oil recovery

CO_(2) flooding is one of the most promising techniques to enhance both light and heavy oil recovery.In light oil recovery,the production pressure in CO_(2) flooding in general keeps constant in order to maintain the miscibility of injected CO_(2) and crude oil;while in heavy oil recovery,a depleting pressure scheme may be able to induce foamy oil flow,thus the oil recovery could be further enhanced.In this study,different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one.Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO_(2) flooding strategies.For the core-flooding experiments,1500 mD sandstone cores,formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition(55℃ and 11 MPa)were used.Before each CO_(2) flooding test,early stage water-flooding was conducted until the water cut reached 90%.Different CO_(2) injection rates and production pressure control strategies were tested through core-flooding experiments.Experimental results indicated that a slower CO_(2) injection rate(2 ml/min)led to a higher recovery factor from 31.1%to 36.7%,compared with a high CO_(2) injection rate of 7 ml/min;for the effects of different production strategies,a constant production pressure at the production port yielded a recovery factor of 31.1%;while a pressure depletion with 47.2 kPa/min at the production port yielded 7%more oil recovery;and the best pressure control scheme in which the production pressure keeping constant during CO_(2) injection period,then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5%of the initial OOIP.For the numerical simulations study,the same oil relative permeability curve was applied to match the experimental results to all tests.Different gas relative permeability curves were obtained when the production pressure schemes are different.A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases.The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes.Through this study,it is suggested that the pressure control scheme can be optimized in order to maximize the CO_(2) injection performance for enhanced heavy oil recovery.