FIELD

This application relates to methods and apparatus to characterize subterranean formations. Specifically, embodiments described herein relate to collection, preparation, and analysis of properties of rock of a subterranean formation.

BACKGROUND

Reservoir quality is largely controlled by reservoir parameters such as porosity, hydrocarbon saturation, permeability, minerology and thermal maturity. Generally, high vertical resolution log measurements and core analysis can provide accurate reservoir parameters for assessing reservoir quality in vertical wells. Similar technologies can be extended to characterize reservoir parameters for assessing reservoir quality in highly-deviated production wells for unconventional plays, including the conveyance of traditional wireline tools, measurements behind the bit, and measurements collected by passing the tool through the bit. However, the length and conditions of these highly-deviated wells makes these measurements challenging and not economically viable, resulting in most lateral wells not being logged or logged only with gamma ray (GR) tools. Instead, multiple vertical wells are placed across the extent of the basin and formation properties, such as bed boundaries, pinch-out points, porosity, mineralogy, and organic-matter content, are determined and assumed to be linearly uniform. Depending on the unconventional play, this indirect method of reservoir characterization may fail to capture the variation in porosity and fluid types, insoluble hydrocarbon (kerogen) concentrations, minerology, and clay-type and clay-volumes that impact reservoir quality laterally. Without a record of the well obtained by logs, little information is available in the event of poor production of a lateral well after drilling and completion.

Completion quality is an engineering assessment of factors that determine the effectiveness of stimulation treatments (particularly hydraulic fracture treatments) in unconventional reservoirs, and includes the ability to initiate and create an induced fracture network, the degree of reservoir contact of the newly created fractures, the level of connection to the natural fracture system of those created fractures and ability of the stimulated reservoir to deliver gas or oil into the well. Important inputs to the derivation of completion quality include the rock's mineralogy, porosity, mechanical properties, compressive strength and tensile strength. In addition, the presence and state of natural fractures, the in-situ stresses and the formation pore pressure can also be provided as inputs to the derivation of completion quality.

Nuclear Magnetic Resonance (“NMR”) relaxometry has been gaining ground as a reliable approach to core analysis due to its capabilities to characterize fluids in reservoir rocks and measure them quantitatively. The NMR relaxometry measurements yield fluid types and wettability non-destructively and in a relatively quick fashion. These aid in assessing reservoir quality and reserve estimates and in core-log correlations. The porosities derived from the NMR log have been shown to compare favorably to the measured core porosities and to represent the potentially producible fluid fractions and/or the fluids fractions contained within the rock sample. NMR laboratory measurements are typically made at frequencies similar to the NMR logging tools (˜2 MHz), on 1.5″×1.5″ rock core samples that are trimmed and surface ground to fit in the NMR probe, resulting in a high filling factor of the radio frequency (RF) probe to achieve optimum signal-to-noise ratios (SNR). The1H (proton) NMR measurements are mainly used to obtain the volumes of the fluids in the pores (pore volume). When combined with the bulk volumes measured using calipers on regular shaped cores, porosity can be calculated.

Although the value of NMR measurements of unconventional shale rocks has been shown on cores and logs in vertical pilot wells, the absence of routine logs and reliable core measurements from horizontal wells make it challenging to obtain a more complete understanding of unconventional reservoirs.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In embodiments, methods and systems are provided for characterizing properties of a rock sample obtained from a subterranean formation, which involve performing an NMR measurement on the rock sample, performing an IR spectroscopy measurement on the rock sample, and using results of the NMR measurement and results of the IR spectroscopy measurement to determine data representing at least one property of the rock sample.

In embodiments, the IR spectroscopy measurement can be a DRIFTS spectroscopy measurement or other IR spectroscopy measurement.

In embodiments, the rock sample can be a core plug, cuttings, and some other rock sample form.

In one embodiment, the rock sample can be cuttings formed by drilling operations that use oil-based drilling fluid. The cuttings are obtained from the subterranean formation and split to provide a first lot of cuttings separate and distinct from a second lot of cuttings. An NMR measurement is performed on the first lot of cuttings without cleaning the first lot of cuttings with a solvent that would remove certain organic components from the first lot of cuttings. An IR spectroscopy measurement is performed on the second lot of cuttings after cleaning the second lot of cuttings with a solvent that removes certain organic components from the second lot of cuttings. The results of the NMR measurement performed on the first lot of cuttings can be analyzed to determine data characterizing pore volume of the cuttings obtained from the subterranean formation. The results of the IR spectroscopy measurement performed on the second lot of cuttings can be analyzed to determine data characterizing matrix density of the cuttings obtained from the subterranean formation. Data representing bulk volume of the cuttings obtained from the subterranean formation can be calculated based on the pore volume data and the matrix density data of the cuttings. And data representing porosity of the cuttings obtained from the subterranean formation can be calculated based on the pore volume data and the bulk volume data of the cuttings.

In another embodiment, results of the NMR measurement performed on the rock sample can be analyzed to determine data representing mass fractions of certain organic components in the rock sample. Results of the IR spectroscopy measurement performed on the rock sample can be analyzed in conjunction with the data representing mass fractions of certain organic components in the rock sample as determined from the NMR measurement to obtain data representing a residuum IR spectrum representative of kerogen in the rock sample. The data representing the residuum IR spectrum can be processed to generate data that characterizes properties (such as thermal maturity or kerogen density) of kerogen in the rock sample.

In one embodiment, the data representing mass fractions of certain organic components (such as oil and bitumen and possibly others) in the rock sample can be determined from the NMR measurement by obtaining data representing a T1-T2 distribution of the rock sample, processing the data representing the T1-T2 distribution to obtain data representing volumes for the certain organic components, and using the data representing volumes for the certain organic components and mass of the rock sample to compute the data representing mass fractions of certain organic components. The data representing the residuum IR spectrum can be determined by using the data representing mass fractions of the certain organic components as determined from the NMR measurement to subtract contribution of the certain organic components (such as oil and bitumen) from a measured IR spectrum.

In embodiments, the IR spectroscopy measurement can be performed on cuttings that are cleaned to remove contaminants and certain organic components from the cuttings. For example, the cuttings can be rinsed with a base oil or clean drilling fluid (such as diesel) to remove contaminants and wash away mobile hydrocarbon components from the cuttings. Then, the cuttings can be heated in an oven to evaporate hydrocarbon components (such as solvents or naturally occurring mobile hydrocarbon components) from the cuttings. Then, the cuttings can be washed with soapy water to remove residual hydrocarbon components (i.e., solvent, drilling fluid, naturally occurring mobile hydrocarbon components) from the cuttings and then dried. Then, the cuttings can be cleaned with a solvent (such as pentane) to remove certain organic components from the cuttings. The cuttings can also be crushed to reduce cutting size and thereafter cleaned with a solvent (such as pentane) to remove certain organic components from the crushed cuttings. Such cleaning can be carried out over a vacuum filter and/or at elevated temperature and pressure.

In yet another aspect, a method is provided that employs multi-nucleic NMR measurements to determine porosity of a rock sample. The method involves three different calibration NMR measurements. A first calibration NMR measurement is performed on a known-volume of a first fluid that contains hydrogen nuclei, wherein the first calibration NMR measurement is performed at a first frequency for measuring hydrogen nuclei in the first fluid. A second calibration NMR measurement is performed on a known-volume of a second fluid that contains non-hydrogen nuclei, wherein the second calibration NMR measurement is performed at a different second frequency for measuring non-hydrogen nuclei in the second fluid. A third calibration NMR measurement is performed on a sample holder filled with the second fluid, wherein the third calibration NMR measurement is performed at the second frequency. The rock sample (e.g., cuttings) is added to a sample holder filled with the second fluid. An NMR measurement is performed on the sample holder filled with the second fluid and the rock sample, wherein the NMR measurement is performed at the second frequency. The results of the NMR measurement performed at the second frequency, the results of the third calibration NMR measurement, the results of the second calibration NMR measurement and the known-volume of the second fluid are processed to determine data representing bulk volume of the rock sample. Another NMR measurement is performed on the sample holder filled with the second fluid and the rock sample at the first frequency. The results of the NMR measurement performed at the first frequency, the results of the first calibration NMR measurement, and the known-volume of the first fluid are processed to determine data representing pore volume of the rock sample. Data representing porosity of the rock sample can be determined based on the bulk volume data and the pore volume data of the rock sample.

In embodiments, the first fluid can be a hydrogen-based fluid (such as water or heavy water), the second fluid can be a fluorine-based fluid (such as a fluorocarbon), and the second frequency can be selected for measuring fluorine nuclei in the fluorine-based fluid.

In embodiments, a maximum signal amplitude that results from the NMR measurement performed at the second frequency can be subtracted from a maximum signal amplitude that results from the third calibration NMR measurement to determine data characterizing a difference in signal amplitude, where such data is divided by data representing a maximum signal amplitude that results from the second calibration NMR measurement and multiplied by data representing the known-volume of the second fluid to determine the data representing bulk volume of the rock sample. Furthermore, a maximum signal amplitude that results from the NMR measurement performed at the first frequency can be divided by data representing a maximum signal amplitude that results from the first calibration NMR measurement and multiplied by data representing the known-volume of the first fluid to determine the data representing pore volume of the rock sample.

