“Component flow”conditions and its effects on enhancing production of continental medium-to-high maturity shale oil

Based on the production curves,changes in hydrocarbon composition and quantities over time,and production systems from key trial production wells in lacustrine shale oil areas in China,fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity.The concept of“component flow”for shale oil was proposed,and the formation mechanism and conditions of component flow were discussed.The research reveals findings in four aspects.First,a miscible state of light,medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles,which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents,such as heavy hydrocarbons,thereby decreasing shale oil viscosity and enhancing fluidity and outflows.Second,small-molecule aromatic hydrocarbons act as carriers for component flow,and the higher the content of gaseous and light hydrocarbons,the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt,thus increasing their plastic deformation ability and bringing about better component flow efficiency.Third,higher formation temperatures reduce the viscosity of heavy hydrocarbon components,such as wax,thereby improving their fluidity.Fourth,preservation conditions,formation energy,and production system play important roles in controlling the content of light hydrocarbon components,outflow rate,and forming stable“component flow”,which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil.The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil.

Enrichment conditions and distribution characteristics of lacustrine medium-to-high maturity shale oil in China

Successful breakthroughs have been made in shale oil exploration in several lacustrine basins in China,indicating a promising future for shale oil exploration and production.Current exploration results have revealed the following major conditions of lacustrine shale oil accumulation:(1)stable and widely distributed shale with a high organic abundance and appropriate thermal maturity acts as a fundamental basis for shale oil retention.This shale exhibits several critical parameters,such as total organic carbon content greater than 2%,with optimal values ranging from 3% to 4%,kerogen Ⅰ and Ⅱ_(1) as the dominant organic matter types,and vitrinite reflectance(R_(o))values greater than 0.9%(0.8% for brackish water environments).(2)Various types of reservoirs exhibiting brittleness and a certain volume of micro-nanoscale pores are critical conditions for shale oil accumulation,and these reservoirs have porosities greater than 3% to 6%.Moreover,when diagenesis is incipient,pure shales are not favorable for medium-to-high maturity shale oil enrichment,whereas tight sandstone and hybrid rocks with clay content less than 20% are favorable;however,for medium-to-late-stage diagenesis,pure shales with a clay content of 40% are favorable.(3)The retention of a large amount of high-quality hydrocarbons is the factor that best guarantees shale oil accumulation with good mobility.Free hydrocarbon content exceeding a threshold value of 2 mg/g is generally required,and the optimum value is 4 mg/g to 6 mg/g.Moreover,a gas-oil ratio exceeding a threshold value of 80 m^(3)/m^(3) is required,with the optimal value ranging from 150 m^(3)/m^(3) to 300 m^(3)/m^(3).(4)High-quality roof and floor sealing conditions are essential for the shale oil enrichment interval to maintain the overpressure and retain a sufficient amount of hydrocarbons with good quality.Lacustrine shale oil distributions exhibit the following characteristics:(1)major enrichment areas of shale oil are located in semi-deep to deep lacustrine depositional areas with external materials,such as volcanic ash fallout,hydrothermal solutions,and radioactive substances with catalytic action,as inputs;(2)intervals with“four high values and one preservation condition”govern the distribution of shale oil enrichment intervals;and(3)favorable assemblages of lithofacies/lithologies determine the distribution of enrichment area.According to preliminary estimates,China has 131×10^(8) to 163×10^(8) t of total shale oil resources with medium-to-high thermal maturity,among which 67×10^(8) to 84×10^(8) t is commercial.These resources are primarily located in the Chang 7^(1+2) interval in the Ordos Basin,Qing 1+2 members in Gulong sag in the Songliao Basin,Kongdian and Shahejie formations of Cangdong sag,Qikou sag and the Jiyang depression in the Bohai Bay Basin,and Lucaogou Formation in the Junggar Basin.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 2: Geochemistry, Thermal Maturity, Isotopes and Biomarkers

As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated with them.