Giant Gas Field Research Articles

Trace element characterization of bitumen constraints on the hydrocarbon source of the giant gas field in Sichuan Basin, South China

The exploration of high production, natural gas wells (>106 m3/d) has been extremely successful in the Gaoshiti and Moxi areas of the Leshan–Longnvsi paleo‐uplift, in the west‐central Sichuan Basin. This paper focuses on the Sinian and Cambrian reservoirs from the Gaoshiti and Moxi areas, where a dataset of new trace elements in bitumen and potential source rock is reported and where hydrocarbon‐source correlation is attempted based on trace elements characteristics of the 12 potential source rocks and 22 bitumen samples. Results show that the bitumen from the three reservoirs can be distinguished from each other using trace element distribution patterns and redox‐ and provenance‐sensitive elemental ratios. Bitumen in the second and fourth members of the Sinian Dengying Formation were derived primarily from the third member of the source rocks of the Dengying Formation, which represents a self‐sourced paleo‐petroleum system. In contrast, bitumen in the reservoirs of the Cambrian Longwangmiao Formation is derived from the Cambrian Qiongzhusi Formation and third member of Dengying Formation. The trace element method used in this study improves our understanding of the complex hydrocarbon–source relation and confirm the potential target for petroleum exploration in the study area.

The Effect of Deep Burial and Folding on Sandstone Reservoirs in some Giant Gas Fields, South America

The underthrust fold belt of the Andes contains some very large gas fields in which the Lower Palaeozoic Sandstone reservoirs are buried to depths of over 4-6km. The foreland depositional environment received high amounts of metamorphic and igneous rock fragments and deep burial was accompanied by substantial tectonic folding and fracturing. The combined effects of Temperature, Pressure and time on these labile sediments have reduced typical porosities <7% and matrix permeabilities <1mD so that these reservoirs are ultra-tight and effectively unconventional. Nevertheless, the fields contain very large recoverable amounts of gas with minor liquids per well. They provide an intriguing case study that contrasts with the typical concept of a conventional petroleum sandstone prospect and pose the question how many more large gas fields fit this model? These complex structural fields required modelling by 3D-Geo using fractured and folded simulation models. The micro-porosity and micro-permeability has been investigated by Curtin University using nano-scale special core analysis in an attempt to identify where the hydrocarbons reside in these rocks, how they migrate out on production, and how best to estimate and optimize ultimate recovery? High technology characterization included TIMA-SEM to map mineralogy and texture at the nano-scale; X-ray Micro-CT analysis of 3D microstructure; NMR, ultra-low Helium porosity and permeability, Hg injection for capillary pressure; Elastic and Electrical Properties to tie the seismic and log data for the modelling. Tri-axial tests helped understand the structural and tectonic history and its relation to the burial history of the reservoirs.

Resource Growth Through Petroleum Exploration in PNG

Mesozoic and Tertiary clastic and carbonate reservoirs are prolific producers of high quality liquid-rich gas onshore PNG. LNG projects are among the lowest cost and most profitable globally. Accordingly there has been a recent resurgence of petroleum exploration in PNG.In 2015 Oil Search undertook a country-wide petroleum Common Risk Segment analysis that highlighted potential for giant new oil and gas fields of sufficient scale to support future LNG projects. It also concluded that 40 trillion cubic feet of gas plus 550 million barrels of oil resources remain to be found (representing approximately 60% of PNG’s total petroleum resource).In 2016 Oil Search completed an ambitious integrated structural, stratigraphic, burial, maturation, migration, uplift and erosion model of PNG’s total petroleum system to quantify the locations for highly prospective under-explored regions.Tectonic events at plate and basin scales were re-assessed and correlated within a new country-wide PNG Chrono-stratigraphy of regionally mappable sequences and flooding events, some of Global extent.A Base Tertiary Mega-Sequence Boundary is mappable over the entire onshore to deepwater regions. 130 1D burial models combined with restored 2D structural and stratigraphic cross sections, have contributed to a new regional petroleum charge model of the Foldbelts, Foreland and Offshore regions.It is concluded that petroleum was generated pre- foldbelt during Late Cretaceous times in interior PNG while petroleum is currently being generated at the present day mountain front.A holistic 4D charge model explains why very young foldbelt traps are petroleum charged.

Hydrocarbon-Gas Cycling Improves Recovery in the Arun Gas Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186280, “Review of 20 Years of Hydrocarbon-Gas Cycling in the Arun Gas Field,” by Suhendro, SPE, Pertamina Hulu Energi, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed. Lean-gas injection has been used as an alternative method in gas fields to maintain reservoir pressure, minimize condensate banking near the wellbore, and mitigate oversupply operations during low-market periods. In this paper, past gas-cycling operations were examined to identify subsurface implications and effects on operability aspects for the Arun giant gas field offshore Indonesia in the North Sumatra Basin. Production and pressure data show that gas cycling contributes significantly to the improvement of field-recovery factors. Reservoir and Fluid Description The Arun gas field was discovered in 1971. The formation is carbonate reef, created during the Miocene age. It lies between two thick shale layers, Bampo on the bottom and Baong on the top. The Bampo formation is identified as source rock, with Baong shale as caprock. The field trends north to south, with a width of 18.5 km and a length of 5 km. Gas/water contact, to the south and west, was tilted toward the southern part of the field. A gas-condensate reservoir at a depth of 10,000 ft was found to have an average thickness of 503 ft and an area of 21,450 acres, with 7,100-psig initial pressure and a temperature of 352°F. Initial condensate/gas ratio (CGR) was 50 bbl/MMcf. The reservoir has 16.2% average porosity and 17% initial water saturation. Volumetric original gas in place (OGIP) is calculated to be 17 scf. The current production rate from the field is approximately 80 MMcf/D with 2,400 bbl of condensate/day. Fluid expansion and gas injection are determined to be the two main drive mechanisms on the basis of material-balance analysis. Hydrocarbon production uses four clusters with approximately 21 wells in each cluster. Each cluster is equipped with the same typical surface facilities. All produced fluid is pooled at Point A before being piped to gas-processing facilities. Initially, the produced gas was delivered to the Arun liquefied natural gas (LNG) plant for liquefaction but, in late 2014, the plant was shut down because of contract termination. In the second quarter of 2015, the facilities were reactivated for an LNG regasification terminal, Perta Arun Gas (PAG). Currently, the produced gas is transported to PAG for separation and dehydration before downstream processing. The northern part of the field contains fair porosity; the middle part is dominated by good and fair porosity, while the southern part has a greater incidence of poor porosity. Clusters II and III, which are located at the middle part, contribute more cumulative gas production and condensate compared with Clusters I and IV. Thus, better reservoir properties and parameters are contributing to better production.

Quasi-continuous hydrocarbon accumulation: An alternative model for the formation of large tight oil and gas accumulations

It has been revealed that the formation of most giant tight oil and gas fields is inconsistent with both the typical basin-centered/continuous hydrocarbon accumulation (CHA) model and the discontinuous hydrocarbon accumulation (DHA) model. We argued that hydrocarbon accumulations in tight reservoirs are dominated by an intermediate form between these two models, termed quasi-continuous hydrocarbon accumulation (QHA). This accumulation model is akin to the CHA in that both are extensively distributed with no distinct boundaries. However, oil and gas in the CHA occur within source rocks, accumulate mainly at or nearby where they are generated, have undergone no significant migration, and their occurrence is not controlled by traps. The QHA, however, occurs in tight reservoirs in the vicinity of source rocks. The accumulation of oil and gas occurs in multiple closely related lenticular or blanket-like reservoirs that are laterally adjacent and vertically stacked. Neither noticeable inversion of oil/gas and water nor complete bottom water or edge water is present. The charging of hydrocarbons is pervasive and the migration is mainly driven by overpressures, while the effects of buoyancy are limited. Hydrocarbon accumulation is not controlled by anticlinal traps but mainly governed by non-anticlinal traps. In fact, the CHA and DHA represent two end-member types of hydrocarbon accumulation and the QHA is a transitional mechanism by which most giant tight oil and gas fields are formed.

Где искать новые крупнейшие, гигантские и уникальные газосодержащие месторождения в Северной Евразии?

Где искать новые крупнейшие, гигантские и уникальные газосодержащие месторождения в Северной Евразии?

Hybrid Sand-Consolidation Fluid Offers Versatility in Treatment of Shallow Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189548, “Tunu: From Laboratory to Field Application With a New Hybrid Inorganic/Organic Sand-Consolidation Fluid as Primary Treatment of Shallow Reservoirs,” by J. Andrieu, B. Kutzky, and B.T. Schackmann, Engineered nanoProducts Germany, and A. Mahardhini, SPE, I. Abidiy, SPE, and H.M. Poitrenaud, Total, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed. The Tunu giant gas field is in the Mahakam region of the South China Sea. Because of the maturity of the field, the producing layer has moved from the deep zone of consolidated sand into the shallow zone of unconsolidated sand. Hydrocarbon production from the shallow zone is unmanageable without primary sand control downhole. In this paper, a new type of sand-consolidation low-viscous binding material, based on a combination of inorganic and organic components, is presented. Introduction Tunu produces almost 40% of total gas production in the Mahakam region. Hundreds of wells have been drilled in the field. Its primary-zone reservoirs are between 2000 and 5000 m true vertical depth (TVD) and typically consist of medium to fine sandstone with strong consolidation and high porosity. Above the primary zone, between 1500 and 2000 m TVD, is the Intra Beta section, with high porosity and sufficient consolidation. In the top layer of the field, shallow reservoirs, above 1500 m TVD, are typically poorly consolidated, with high porosity (28%) and permeability (greater than 1 darcy). Tunu’s shallow zone is an unconsolidated zone that requires sand control; types that have been used include gravel pack, standalone screen, and sand consolidation. Sand consolidation can be a challenging option because of the difficulty in finding a balance between compressive strength and regained permeability after treatment. Field Application After the first laboratory-testing phase, detailed in the complete paper, showed promising results, the decision to perform field trials on five wells was validated. Wells in Tunu are typically completed using 3.5- or 4.5-in. tubingless completion inside 7- or 9⅝-in. casing. A coiled-tubing (CT) unit was chosen for pumping into the target reservoir. First Campaign (2012–2013). The primary objective of the first campaign was to acquire experience with the composite binding material in the field without taking the risk of plugging the wells. Therefore, a large amount [6 pore volumes (PV)] of overflush was used. Several tests and subsequent adjustments were developed to tailor the product to actual field conditions. The first campaign began in October 2012 and ended in July 2013 after treatment on five wells. On the basis of laboratory test results, the treatment comprises the following steps: Activation of binding material by dissolving the initiator Injection of preflush fluid (0.75-fold binding material volume) Injection of the binding system, followed by a small pill of spacer (maximum 0.5 bbl of preflush) Post-flushing or overflushing (six-fold binding material volume for first campaign)

New progresses in basic geological theories and future exploration domains of natural gas in China

As natural gas exploration expands to deep, ultra-deep and unconventional areas, more and more complex exploration targets are encountered. In this circumstance, it is necessary to improve the existing basic natural gas geological theories for guiding the exploration and discovery of more giant gas fields. In this paper, the researches on basic natural gas geological theories since the beginning of the 12th Five-Year Plan were engaged, and then the key exploration target zones were analyzed. Some results were obtained. (1) The theory of whole-process hydrocarbon generation of organic matters was improved and the geologic theories of organic matter hydrocarbon generation (e.g. the thermal evolution model of kerogen degradation and the successive gas generation of organic matters) were developed. (2) Multi-element natural gas genesis identification method, quantitative evaluation method for different types of seals/caprocks, tight sandstone gas accumulation theory for low hydrocarbon generation intensity region, and hydrocarbon accumulation theory for giant ancient carbonate gas field were established, and the geological theories of gas generation, genesis identification and hydrocarbon accumulation were developed to provide the effective guidance for the exploration breakthrough and discovery of giant gas fields in the key basins of China recently. Four conclusions were reached: (1) ancient carbonate rock, tight sandstone, foreland region, shale and volcanic rock are primary exploration targets for discovering giant gas fields; (2) craton and foreland basins are still the key exploration areas, and ancient uplift, gentle slope and thrust belt are the main enrichment zones; (3) ancient strata and deep formations are critical gas exploration targets in the future; (4) oil cracking gas in marine basins, tight sandstone gas and shale gas are the important replacement resources for future gas reserves and production growth.

The field test confirms the prognosis of the location of giant oil and gas fields in the Andes of South America made in 1986

1986 saw the publication of a prognostic map for discovering giant oil and gas fields in the Andes in South America based on the recent block structure of the Earth’s crust. The model assumes that petroleum moves to the traps through permeable channels created at the intersection of deep faults. The technology of creation that the prognostic maps use involves (1) maps of morphostructural zoning, which outline the morphostructural knots (intersections of faults), and (2) a pattern recognition program that identifies knot-containing giant oil/gas fields. It was forecasted that, in the Andes of South America 11 knots, which had not been developed at that time, contain giant oil or gas fields. These 11 sites covered only 15% of the total area of all the Andes basins. Since then, six giant oil/gas fields have been discovered in the Andes region: Cano-Limon, Cusiana, Capiagua, and Volcanera (Llanos basin, Colombia), Camisea (Ukayali basin, Peru), and Incahuasi (Chaco basin, Bolivia). All these discoveries were made in places shown on the 1986 prognostic map as promising areas.

Theory, technology and prospects of conventional and unconventional natural gas

Abstract The development of natural gas in China has entered a golden and leap-forward stage, which is a necessary bridge to clean energy. This in-depth study on the status quo, theory, technology and prospect of natural gas development shows: (1) The global remaining proven recoverable reserves of natural gas are 186×1012 m3 and the reserves-production ratio is 52.4, indicating a solid resource base for long-term and rapid development. (2) Ten formation and distribution laws of conventional and unconventional natural gas reservoirs have been proposed. In terms of exploration geology, the theory of conventional “monolithic” giant gas fields with different gas sources, and an unconventional gas accumulation theory with continuous distribution of “sweet areas” in different lithologic reservoirs have been established; in terms of development geology, a development theory of conventional structural gas reservoirs is oriented to “controlling water intrusion”, while a development theory of unconventional gas is concentrated on man-made gas reservoirs. (3) With the geological resources (excluding hydrates) of 210×1012 m3 and the total proven rate of the resources less than 2% at present, the natural gas in China will see a constant increase in reserve and production; by 2030, the proven geological reserves of natural gas are expected to reach about (6 000− 7000)×108 m3 the production of conventional and unconventional natural gas each will reach about 1 000×108 m3 and the gas consumption will reach 5500×108 m3. The dependence on imported natural gas may be 64% by 2030, and 70% by 2050. (4) Ten measures for future development of natural gas have been proposed, including strengthening exploration in large-scale resource areas, increasing the development benefits of unconventional gas, and enhancing the peak adjusting capacity of gas storage and scale construction of liquified natural gas.

Diagenesis in Mesozoic carbonate rocks in the North Pyrénées (France) from mineralogy and fluid inclusion analysis: Example of Rousse reservoir and caprock

Fluid-rock interaction is of key interest for deciphering the geodynamic history of complex geological environments. In this paper, we describe the mineralogy and petrography of the Rousse reservoir (the Upper Jurassic “Dolomie de Mano” formation) as well as the reconstruction of its thermal and pressure history. We also investigate the base of the reservoir caprock (the Campanian breccia). A satellite of the giant gas field of Lacq in the south-west of France, Rousse was a gas producer until it moves to a CO2 storage site in 2010. Rousse is located within a deep, isolated, faulted, carbonate Jurassic horst overlain by a 4500 m thick overburden that is composed of a series of turbiditic flysch deposits of Upper Cretaceous (Cenomanian) to Tertiary (Eocene) age. Cores were sampled from two wells, Rousse 1 and 2, and were analyzed by ICP-MS, XRD, SEM, EPMA, TEM, cathodoluminescence and fluid inclusion techniques. Pressure-Temperature (P-T) conditions were derived by modeling data from fluid inclusions trapped in the fracture minerals of the “Dolomie de Mano” formation and the Campanian breccia. In the “Dolomie de Mano”, diagenesis was dominated by three dolomite episodes followed by a calcite stage in fractures. The second and third dolomitizations were associated with fracturing episodes. These dolomites precipitated from low-saline (<1 mol·kg−1 eq. NaCl) hydrothermal fluids at temperatures around 150 °C. These two characteristics exclude dolomitization during a synsedimentary slope brecciation event and also the role of hypothetical secondary brines. In the Campanian breccia, dolomitization is marginal and the main precipitation is calcite. In association, two types of fluid inclusion (liquid water-vapor and vapor) can be distinguished in the two formations and are marked by predominant CH4 and variable CO2 contents. The presence of gas inclusions in the reservoir as in the caprock is indicative of several gas invasions. A P-T modeling of the geologic evolution of the area reveals two periods of fluid circulation: a first stage (150–170 °C, 20 MPa) during the Late Jurassic to Early Cretaceous for the reservoir rock, corresponding to the rifting period of the North-Pyrénées western zone; and a second stage (170 °C, 41 MPa) during the late Eocene period in breccias, corresponding to the Pyrenean compression period. The petrophysical properties of the reservoir, marked by an intense fracture network, were acquired early during an extensional period, whereas the impact of fluids associated with a period of compression appears to have been limited in space to drainage of tectonic origin. Finally, we note significant similarities between the petrographic and fluid signatures of the Chaînons béarnais, in the folded orogenic wedge located south of the North Pyrenean Frontal Thrust, and Rousse, located in the foreland basin to the North. Nevertheless, the temperature recorded in the Chaînons béarnais reached 300–350 °C, much higher than in Rousse due to its position in the vicinity of an over-thinned palaeomargin during the early Cretaceous.

Petroleum geological conditions and exploration importance of Proterozoic to Cambrian in China

Abstract The discovery of the giant Anyue gas field in Sichuan Basin gives petroleum explorers confidence to find oil and gas in Proterozoic to Cambrian. Based on the reconstruction of tectonic setting and the analysis of major geological events in Mesoproterozoic-Neoproterozoic, the petroleum geological conditions of Proterozoic to Cambrian are discussed in this paper from three aspects, i.e. source rocks, reservoir conditions, and the type and efficiency of play. It is found that lower organisms boomed in the interglacial epoch from Mesoproterozoic-Neoproterozoic to Eopaleozoic when the organic matters concentrated and high quality source rocks formed. Sinian-Cambrian microbial rock and grain-stone banks overlapped with multiple-period constructive digenesis may form large-scale reservoir rocks. However, because of the anoxic event and weak weathering effect in Eopaleozoic-Mesoproterozoic, the reservoirs are generally poor in quality, and only the reservoirs that suffered weathering and leaching may have the opportunity to form dissolution-reconstructed reservoirs. There are large rifts formed during Mesoproterozoic-Neoproterozoic in Huabei Craton, Yangtze Craton, and Tarim Craton in China, and definitely source rocks in the rifts, while whether there are favorite source-reservoir plays depends on circumstance. The existence of Sinian-Cambrian effective play has been proved in Upper Yangtze area. The effectiveness of source-reservoir plays in Huabei area depends on two factors: (1) the effectiveness of secondary play formed by Proterozoic source rock and Paleozoic, Mesozoic, Cenozoic reservoir rocks; (2) the matching between reservoirs formed by reconstruction from Mesoproterozoic- Neoproterozoic to Eopaleozoic and the inner hydrocarbon kitchens with late hydrocarbon generation. As for Tarim Basin, the time of Proterozoic and the original basin should be analyzed before the evaluation of the effective play. To sum up, Proterozoic to Cambrian in the three craton basins in China is a potential exploration formation, which deserves further investigation and research.

Characteristics of source rocks, resource potential and exploration direction of Sinian-Cambrian in Sichuan Basin, China

The Anyue giant gas field was discovered in the Sinian-Cambrian Central Sichuan region of the Sichuan Basin in 2013, with geological reserves up to 1 × 1012m3, which is the first time for the exploration of natural gas paleo-reservoirs in the world. The gas source studies suggest that the Sinian natural gas is originated from the Sinian and Cambrian hydrocarbon source rocks, and the systematical study on the Sinian and Cambrian ancient source rocks has important scientific and practical significance for the global oil and gas geologic domain of the ancient stratum. Based on the drilling data and field profile observation of Sinian and Cambrian in Sichuan Basin, with adoption of the interpretation data of 28000 km-seismic and new drilling data, combined with geochemical analysis of source rocks of 2315 samples, this paper systematically studied the high quality hydrocarbon source rock center, where the source rocks are mainly distributed along the Mianzhu-Changning craton inner rift, with a accumulative thickness reaching 200–450 m, and 50–100 m for the thickness of source rocks in other areas. The hydrocarbon source rocks of the Sinian-Cambrian contributed about 56 %–63% of natural gas resources of the whole basin. Systematical evaluations have been conducted to the mudstone source rocks and their distribution in the III-section of Sinian Dengying Formation, where TOC value is ranging from 0.04% to 4.73%, with an average of 0.65%. The thickness of the source rocks in Central Sichuan region is ranging from 10 to 30 m. The oldest Sinian source rocks that can form large gas fields in China were systematically studied for the first time, and the total gas production intensity of the Sinian source rocks in the great Central Sichuan region is (15–28) × 108 m3/km2, where the gas source conditions for the formation of large gas fields are available. By using the genetic method and analogy method, the amount of natural gas resources of the Sinian-Cambrian in the basin are re-evaluated as (4.65–5.58) × 1012 m3, and the resources potential of natural gas is huge. The amount of natural gas resources in the Central Sichuan block accounts for about 66% of the total basin resources, which is the preferred selection for current exploration.

PETROLEUM POTENTIAL OF THE WEATHERED, FRACTURED, AND HYDROTHERMALLY ALTERED BASEMENT RESERVOIRS: CASE STUDY FOR UKRAINE

The weathered crystalline crust (WCC) is a transitional geobody occurring between the intact basement and sedimentary cover and representing the result of complex geological and geochemical processes called weathering that impacted the topmost part of the crystalline bedrock. WCC studies are important for useful ore minerals and hydrocarbon exploration. Until present, around 450 of the discovered petroleum fields in the world are solely or partly attributed to the weathered, fractured and altered basement rocks of different consolidation age and known for all continents excluding Antarctica. Much more petroleum production comes from weathered and altered volcanics, and metasedimentary Precambrian, Paleozoic, and Mesozoic rocks, usually considered incorrectly as barren ones. Giant oil and gas fields produce crudes from crystalline basement and granite wash in the USA, Venezuela, Brazil, Libya, Kazakhstan, Russia, China, Yemen, Vietnam, etc. The commercial discoveries of oil and gas took place during the last decades in the weathered basement along the buried Northern flank of the Late Devonian Dnieper-Donets paleorift as well in Ukraine. Some basement reservoirs are characterized by unique geochemical features and may contain commercial reserves of noble gases like helium. A sophisticated new technique applying a joint inversion of seismic and gravity data and adjusted by other geological and production data allows building of a geodensity model of a WCC reservoir and confident delineation of prospective basement reservoirs.

Characteristics of source rocks of the Datangpo Fm, Nanhua System, at the southeastern margin of Sichuan Basin and their significance to oil and gas exploration

In recent years, much attention has been paid to the development environment, biogenetic compositions and hydrocarbon generation characteristics of ancient source rocks in the deep strata of the Sichuan Basin because oil and gas exploration extends continuously to the deep and ultra-deep strata and a giant gas field with the explored reserves of more than 1 × 1012 m3 was discovered in the Middle and Upper Proterozoic–Lower Paleozoic strata in the stable inherited paleo-uplift of the central Sichuan Basin. Based on the previous geological research results, outcrop section of the Datangpo Fm, Nanhua System, at the southeastern margin of the Sichuan Basin was observed and the samples taken from the source rocks were tested and analyzed in terms of their organic geochemistry and organic petrology. It is shown that high-quality black shale source rocks of the Datangpo Fm are developed in the tensional background at the southeastern margin of the Sichuan Basin between two glacial ages, i.e., Gucheng and Nantuo ages in the Nanhua Period. Their thickness is 16–180 m and mineral compositions are mainly clay minerals and clastic quartz. Besides, shale in the Datangpo Fm is of high-quality sapropel type source rock with high abundance at an over-mature stage, and it is characterized by low pristane/phytane ratios (0.32–0.83), low gammacerane abundance, high-abundance tricyclic terpane and higher-content C27 and C29 gonane, indicating that biogenetic compositions are mainly algae and microbes in a strong reducing environment with low salinity. It is concluded that the Datangpo Fm source rocks may be developed in the rift of Nanhua System in central Sichuan Basin. Paleo-uplifts and paleo-slopes before the Caledonian are the favorable locations for the accumulation of dispersed liquid hydrocarbons and paleo-reservoirs derived from the Datangpo Fm source rocks. In addition, scale accumulation zones of dispersed organic matter cracking gas and paleo-reservoirs originated from the Datangpo Fm source rocks may be discovered in the stable area inside the Sichuan Basin.

Condensate origin and hydrocarbon accumulation mechanism of the deepwater giant gas field in western South China Sea: A case study of Lingshui 17-2 gas field in Qiongdongnan Basin

Abstract Based on the geochemical characteristics of condensates and gases, in combination with geological background, the origin and formation of condensate and oil-gas accumulation mechanism of the deepwater Lingshui 17-2 gas field in the Qiongdongnan Basin, western South China Sea are discussed. The condensate from Lingshui 17-2 gas field has the features of low density, low wax content and high Pr/Ph value. The condensate is generated at mature stage while the co-existing gas is dominated by high mature gas. The oil and gas are derived from the Oligocene Yacheng Formation source rocks rich in terrestrial organic matter. The formation of the condensate is related not only to the source rock, but also to the later “gas-washing”. The light oil and gas which was generated at oil-window stage and accumulated in reservoirs have strong reaction of evaporation fractionation during “gas-washing” by high mature natural gas injected largely at later period. The Yacheng source rocks provided sufficient gas and some light oil, diapiric fractures formed migration paths for oil and gas, and two stages of hydrocarbons charged and accumulated. The Miocene Huangliu Formation turbidite sandstones lithologic trap and Paleogene structural trap close to source Kitchen in the central canyon have favorable oil-gas exploration potential.

A golden era for natural gas development in the Sichuan Basin

Owing to the technical innovation as well as a better understanding of gas exploration, nine giant gas fields have been successively discovered in the Sichuan Basin with cumulative proven gas reserves of 3.69 trillion cubic meters, where the annual natural gas productivity ranks the second in China. The CNPC latest oil & gas resources evaluation results demonstrate that natural gas resources in the Sichuan Basin takes the first place among those petroliferous basins all over China, but its proved gas reserves is only 10%, so the exploration prospect is bright. Over the past decades, PetroChina Southwest Oil & Gas Field Company has made great efforts to complete its technical systems, improve gas pipeline networks, and streamline gas markets, laying a robust foundation for the natural gas development in the Sichuan Basin. To further enhance the natural gas reserves and productivity in this basin and to achieve the biggest gas province in China, this company presents the following major projects: progressive multi-strata exploration and development in the central Sichuan area, Safe and efficient development of high-sulfur gas fields in the northeastern Sichuan area, Demonstrative exploration and development of deep marine carbonate gas reservoirs in the northwestern Sichuan area, Exploitation and development of large Cambrian pre-salt structural gas reservoirs in the eastern Sichuan area, and Extensive and beneficial development of shale gas in southern Sichuan. As the key to the Southwest growth pole, the above projects cover all the important, hard and hot fields of the whole basin and multiple gas-bearing strata and layers. With all the projects fulfilled, natural gas productivity will be 25–29 billion cubic meters (bcm) in 2020, accounting for most parts of this company's whole planning production (30 bcm in total), and will reach up to 50–70 bcm in 2030. It is predicted that natural gas development in the Sichuan Basin will be in a golden era in the long term.

Formation and distribution characteristics of Proterozoic\u2013Lower Paleozoic marine giant oil and gas fields worldwide

There are rich oil and gas resources in marine carbonate strata worldwide. Although most of the oil and gas reserves discovered so far are mainly distributed in Mesozoic, Cenozoic, and upper Paleozoic strata, oil and gas exploration in the Proterozoic–Lower Paleozoic (PLP) strata—the oldest marine strata—has been very limited. To more clearly understand the oil and gas formation conditions and distributions in the PLP marine carbonate strata, we analyzed and characterized the petroleum geological conditions, oil and gas reservoir types, and their distributions in thirteen giant oil and gas fields worldwide. This study reveals the main factors controlling their formation and distribution. Our analyses show that the source rocks for these giant oil and gas fields are mainly shale with a great abundance of type I–II organic matter and a high thermal evolution extent. The reservoirs are mainly gas reservoirs, and the reservoir rocks are dominated by dolomite. The reservoir types are mainly karst and reef–shoal bodies with well-developed dissolved pores and cavities, intercrystalline pores, and fractures. These reservoirs are highly heterogeneous. The burial depth of the reservoirs is highly variable and somewhat negatively correlated to the porosity. The cap rocks are mainly thick evaporites and shales, with the thickness of the cap rocks positively correlated to the oil and gas reserves. The development of high-quality evaporite cap rock is highly favorable for oil and gas preservation. We identified four hydrocarbon generation models, and that the major source rocks have undergone a long period of burial and thermal evolution and are characterized by early and long periods of hydrocarbon generation. These giant oil and gas fields have diverse types of reservoirs and are mainly distributed in paleo-uplifts, slope zones, and platform margin reef-shoal bodies. The main factors that control their formation and distribution were identified, enabling the prediction of new favorable areas for oil and gas exploration.

Geochemical characteristics and origin of natural gas from Wufeng-Longmaxi shales of the Fuling gas field, Sichuan Basin (China)

As the first giant shale gas field in China, the Fuling gas field has recently been regarded as one of the most important regions for natural gas exploration and production in the Sichuan Basin. However, the origin of natural gas from Upper Ordovician Wufeng and the bottom of Lower Silurian Longmaxi (WL) shales in the Fuling gas field is poorly understood to limit a comprehensive understanding of gas generation, accumulation and exploration.In this work, based on molecular and stable carbon isotopic composition of a total of 24 gas samples from five shale gas wells in the Fuling field, we analyzed the geochemical characteristics and gas origin, and discussed the cause for the geochemical anomalies (carbon isotopic reversals). Molecular composition results show that gases from the Fuling gas field are dry and mainly composed of methane (97.9–98.9%), with a very low level of ethane (C2H6), propane (C3H8) and non-hydrocarbon gases (mainly CO2 and N2). These dry gases are classified as oil-associated gas and mainly derived from secondary cracking. Due to the lack of gas samples across a maturation gradient from immature to late mature, the WL gases in the Fuling field show an unclear evolution trend between the δ13C2 and wetness values; however, all these samples are located in the isotopic reversal zone. Carbon isotopes of gaseous alkanes clearly display full isotopic reversals (δ13C1>δ13C2>δ13C3), which is indicative of a relatively high thermal maturity and consistent with the measured vitrinite reflectance and modeled values (~3.0% Ro). The observed complete carbon isotopic reversals in the WL gases are caused by a combination of several mechanisms, in which isotope exchange at high temperature is the primary controlling factor. Other secondary factors include Rayleigh-type fractionation of C2H6 and C3H8, secondary cracking and gas diffusion mixing of gases at different thermal maturity levels.

Mapping of fracture zones and small faults using VSP and Cross Dipole Sonic in Eastern Siberia Carbonate Reservoirs, Yurubchansky Field, Russia

Zero offset VSP, two Walkaway lines, ultra sonic and cross dipole sonic were used to interpret fracture zones and small faults in the vicinity of a deviated well drilled through carbonate reservoirs of the Yurubchansky giant oil and gas field, Russia. The fractures and small faults are the main flow conduits and storage of the hydrocarbons within mainly low porosity carbonate reservoir of the Proterozoic age. The wells are only successful if they intersect these “sweet spots” in the reservoir. This is a challenge in developing the Yurubchansky field. The 3D seismic over the field has low resolution, strong heterogeneous reservoirs, varying degrees of anisotropy, multiples contamination and therefore cannot be used to map the “sweet spots” reliably.An incoherency attribute was used to guide fracture and fault interpretation. Two major fault zones and small faults were interpreted from VSPs. One of the fault zones within the reservoir corresponds to fractured core, intensive fracture zones interpreted from ...