Methods and systems for locating a chemical source include measuring chemical concentration with sensors at a plurality of different positions. Measurements from pairs of positions are cross-correlated to determine an average velocity vector for a group of positions. A convergence region is determined based on a plurality of average velocity vectors to determine a chemical source location.

A method and system are provided for exploration, production and development of hydrocarbons. The method involves analyzing a sample for a geochemical signature, which includes a multiply substituted isotopologue signature and/or a position specific isotope signature. Then, historical temperatures are determined based on the signature. The historical temperature is used to define seal timing, trap timing, migration efficiency and/or charge efficiency, which is used to develop or refine an exploration, development, or production strategy.

A method for identifying in situ presence of a hydrocarbon reservoir or of a pipeline leakage is disclosed. The method can include obtaining a sample from an area of interest, such as a sediment sample or water column sample near a hydrocarbon seep or near an offshore pipeline; analyzing the sample to detect nucleic acid, protein or metabolite signatures that are indicative of cold-shock response; identifying the relative abundance of the cold-shock signatures present in the sample in comparison to the surrounding environment.

Methods for developing equation-of-states (EOS) composition models for predicting petroleum reservoir fluid behavior and understanding fluid heterogeneity in unconventional shale plays are described. In particular, limited geochemical data from samples taken from the reservoir of interested are utilized to build and tune the EOS model and improve predictions. Real-time applications are also described.

A method and system are described that may be used for exploration, production and development of hydrocarbons. The method and system may include analyzing a sample for a geochemical signature, wherein the geochemical signature includes a multiply substituted isotopologue signature and/or a position specific isotope signature. Then, alteration timing may be determined from the signature(s) and used to develop or refine an exploration, development or production strategy.

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for detecting seepage of hydrocarbons in subterranean zones. In one aspect, a method includes detecting hydrocarbon seepage at multiple different sampling depths from a surface in a surveyed geographic region, comparing each of the hydrocarbon seepage at the multiple different sampling depths, wherein hydrocarbon seepage at a reference depth is known, and determining hydrocarbon seepage through the surveyed geographic region based on a result of the comparison.

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for detecting seepage of hydrocarbons in subterranean zones. In one aspect, a method includes detecting hydrocarbon seepage at multiple different sampling depths from a surface in a surveyed geographic region, comparing each of the hydrocarbon seepage at the multiple different sampling depths, wherein hydrocarbon seepage at a reference depth is known, and determining hydrocarbon seepage through the surveyed geographic region based on a result of the comparison.

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for detecting seepage of hydrocarbons in subterranean zones. In one aspect, a method includes detecting hydrocarbon seepage at multiple different sampling depths from a surface in a surveyed geographic region, comparing each of the hydrocarbon seepage at the multiple different sampling depths, wherein hydrocarbon seepage at a reference depth is known, and determining hydrocarbon seepage through the surveyed geographic region based on a result of the comparison.

Embodiments of the present disclosure relate to methods of natural gas production and carbon sequestration. In one embodiment, a method of generating biogas is disclosed, comprising delivering a feedstock downhole to a coal reservoir, generating biogas within the coal reservoir, and harvesting the biogas. In another embodiment, a method for tracing the migration of biogas in a coal reservoir is disclosed. The method comprises delivering a feedstock downhole to a coal reservoir via an injection well, generating biogas within the coal reservoir through microbial action, creating a biogas that is isotopically differentiable from a background gas that is native to the coal reservoir, harvesting the biogas at the injection well and one or more offset wells of the coal reservoir, analyzing the biogas and coal bed methane from the coal reservoir at the injection well and at one or more offset wells within the same coal reservoir, detecting the biogas at the offset wells using isotopic differentiation, and mapping the migration of the biogas from the injection well to the offset wells using the biogas as an isotopic tracer.

A measured wetness of and a carbon isotope ratio associated with a gas sample from a hydrocarbon formation is received wherein the wetness is a percentage of C2+ by mass. The carbon isotope ratio is a ratio of carbon-13 isotopes over carbon-12 isotopes. Calculated wetnesses of and carbon isotope ratios associated with a plurality of gas samples taken from one or more analogous hydrocarbon reservoirs is received. Each wetness is calculated as a percentage of mass within the gas sample. The measured wetness received for the gas sample from among the calculated wetnesses is identified. A carbon isotope ratio is determined from among the carbon isotope ratios that corresponds to the measured wetness of the gas sample. A gas maturity for the gas sample is determined using the determined carbon isotope ratio.