Patent Application
20170321549
In aspects, the present disclosure relates to characterizing underground formations and/or features. In further aspects, the present disclosure relates to methods and devices for estimating one or more parameters relating to fluids from a subterranean formation.
Wells, tunnels, and other similar holes formed in the earth may be used to access geothermal sources, water, hydrocarbons, minerals, etc. and may also be used to provide conduits or passages for equipment such as pipelines. Such a hole is commonly referred to as a borehole or wellbore of a well and any point within the borehole is generally referred to as being downhole. Boreholes are commonly used in significant capital commercial developments, such as hydrocarbon fields. Therefore, before field development begins, operators desire to have as much information as possible in order to evaluate the reservoir for commercial viability. Such information may be acquired at the seismic exploration phase, during well construction, prior to well completion and/or any time thereafter. A vast amount of the information used for characterizing reservoirs is based directly or indirectly on measurements made in a borehole traversing a hydrocarbon reservoir of interest.
In aspects, the present disclosure is directed to devices, systems and method that may be utilized to obtain or improve information that may be used for characterizing a formation or a formation fluid.
The present disclosure is directed to a method for evaluating a formation fluid. The method may include the steps of drilling a borehole with a drill string, the borehole intersecting a formation containing the formation fluid, the formation being at a depth uphole of a well bottom; circulating a drilling fluid in the borehole; selectively liberating a fluid from the formation, the liberated fluid including the formation fluid; injecting the liberated fluid into the drilling fluid returning to the surface; drawing a sample of the returning drilling fluid; and estimating at least one parameter of the drawn sample at the surface.
The above-recited examples of features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.
For detailed understanding of the present disclosure, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
The present disclosure relates to devices and methods for gas logging and fluid sampling. Disclosed are methods and related systems wherein gas is selectively liberated at one or more desired depth over a specific time, and measuring the liberated gas with a surface system. Thereafter, “cleanup” gas data may be compared to downhole cleanup sensor data and/or gas data, which was recorded when the rock at the corresponding depth was crushed for the first time. They are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles described herein, and is not intended to limit the disclosure to that illustrated and described herein. Accordingly, the embodiments discussed below are merely illustrative of the applications of the present disclosure.
In aspects, the teachings of the present disclosure can increase the certainty of the presence of formation fluid types and compositions by implementing a novel gas logging and fluid sampling methodology. Illustrative methods according to the present disclosure involve selectively liberating, for a specified time period, a fluid from a formation, injecting the liberated fluid into a flowing drilling fluid, and monitoring the formation fluid that is pumped to a borehole annulus using surface gas analysis equipment to provide compositional information on the liberated formation fluid in real-time. Optionally, this information may be combined with information on fluid properties from in-situ (downhole) fluid analysis. The gas being analyzed may be a hydrocarbon and/or a non-hydrocarbon (e.g., helium). This information can help inform the decision making early during a well development. Additionally, monitoring the fluid pumped to the annulus may also be used to conduct drilling operations more safely.
Referring initially to
In one non-limiting embodiment, a surface logging system 30 may be used in conjunction with the formation evaluation tool 16 to obtain real-time or near real time information about the fluids in the formation 10. The surface logging system 30 may include a fluid sampling line 32 that is in direct fluid communication with the annulus 26 and one or more instruments configured to analyze one or more components of the return fluid 24. Illustrative instruments include mass spectrometers, gas chromatographs, and other sensors configured to provide chemical, compositional, and physical information regarding the components of the return fluid 24. The surface logging system 30 may include an information processor (not shown), a data storage medium (not shown), display devices, and suitable circuitry for storing and implementing computer programs and instructions. The data storage medium may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. The data storage medium may store a program and data collected during the testing process.
The formation evaluation tool 16 may be configured to selectively liberate a fluid from the formation 10. The liberated fluid 34 is released into the annulus 26 and flows upward to the surface as it comingles with the other return fluid 24. If reverse circulation is used, then the liberated fluid 34 is released into the fluid flowing to the surface via a bore of the drill string. The formation evaluation tool 16 may include known devices as a sampling probe 50 and a fluid analysis module 52 that includes one or more pumps, packer(s), and fluid circuitry that can direct pumped fluid into sample tanks and/or the annulus 26. Thus, the fluid flows into the tool 16 via the probe 50 and then exits the tool 16 via a suitable outlet (not shown). The formation evaluation tool 16 may also include sensors for estimating one or more parameters relating to the fluid before the fluid is injected into the annulus. For estimating properties of downhole fluids (naturally occurring or engineered), the formation evaluation tool 16 may include sensors for estimating aromatic content; asphaltene content; bacterial content; bubble point; chemical composition (this overlaps the parameters with the word “content”); color; density; specific gravity; hydrate (gas hydrate) content; naphthenic content; nitrogen content; odor; oxygen content; radioactivity; salt content; solids content; sulfur content; paraffinic content; pH (acidity/alkalinity); phase (defined as gas or liquid); pressure; temperature; viscosity. Illustrative devices include, but are not limited to, fluorescence spectrometers, mass spectrometers, dielectric sensors, optical analyzers, detectors using gas chromatography, ion selective sensors, resonators (e.g., tuning forks), sound speed sensors, refractometers, nuclear magnetic resonance tools, etc.
One non-limiting method 80 using the teachings of the present disclosure is shown in
Optionally, the
The
Next, the borehole 12 is drilled using the drill string 14 until the formation evaluating tool 16 is at the depth 40. The depth 40 is uphole of a wellbore bottom 41. Drilling is stopped and the probe 50 of the formation evaluation tool 16 is then extended to a borehole wall 42. Upon being energized, the formation evaluation tool 16 pumps fluid from the formation 10 into the annulus 26 while drilling fluid is circulating. In many situations, the drilling mud in the annulus 26 may be at-balanced or over-balanced (i.e., at the same pressure or a greater pressure than the fluid in the formation 10). In other situations, this drilling mud may be under-balanced. It should be noted that the fluid being liberated from the formation 10 at depth 40 is not the fluid being liberated at the wellbore bottom 41 (if such fluid is present). At the same time, one or more sensors (not shown) at the formation evaluation tool 16 may estimate one or more parameters of the pumped fluid before it is ejected into the annulus 26.
During the drilling and throughout the fluid sampling activity, the surface gas analysis system 30 generates a continuous log of one or more gas properties. The circulating drilling fluid transports the liberated fluid 34 to the surface and a sample is drawn using the fluid sampling line 32. The drawn fluid is a mix of the liberated fluid 34 and the return fluid 24. Hydrocarbons and/or non-hydrocarbons from the formation 10 evaporate into gaseous phase at the surface under atmospheric conditions. Depending on the mud, its temperature and hydrocarbon combination, the amount of hydrocarbons in solution may vary and single components may have a different solubility. In one non-limiting arrangement, hydrocarbon extraction is accomplished by feeding the drilling fluid through a vessel with a mechanical agitator and using a vacuum pressure to suck the evaporated hydrocarbons from a headspace of a trap towards the gas logging system 30. Other arrangements such as a membrane system may be used.
Next, the drawn fluid is analyzed by the gas logging system 30. This analysis can be performed by evaluating the released hydrocarbons and non-hydrocarbons using any suitable sensor, such as those described above. Advantageously, the depth at which the liberated fluid 34 enters the annulus 26 is known. Thus, the “lag time,” or the time required for the liberated fluid 34 to reach the fluid sampling line 32 can be estimated based on drilling fluid flow rates and other operating parameters. The formation evaluation tool 16 pumps the liberated fluid 34 into the annulus 26 preferably until the readings at the surface stabilize.
Generally, after correction for lag time, a correlation can be observed from the in situ measurements and the surface measurements at phases 132 and 134 of
In a next step this “cleanup” gas data can be compared to downhole cleanup sensor data and/or gas data, which was recorded when the rock at the corresponding depth was crushed for the first time. This comparison may contain information related to depth of invasion of the drilling mud filtrate, thus it could be an invasion monitor.
Another correlation may be made using the gas log data obtained while initially drilling the formation 10 and the information obtained by the formation evaluation tool 16. For example, the gas logs created while the formation was initially being disintegrated by the drill bit 20 may not be overly affected by filtrate invasion into the formation 10. The subsequent combined in situ and surface analysis described above may be compared with the initial gas logs to gain insight into filtrate invasion into the formation 10.
From the above, it should be appreciated that what has been described includes a method for evaluating a formation fluid from a formation. The method may include drilling a borehole with a drill string, the borehole intersecting the formation having the formation fluid, the formation being at a depth uphole of a well bottom; circulating a drilling fluid in the borehole; selectively liberating a fluid from the formation using a fluid sampling tool, the liberated fluid including the formation fluid; injecting the liberated fluid using the fluid sampling tool into the drilling fluid returning to the surface; drawing a sample of the returning drilling fluid at the surface; and estimating at least one parameter of the drawn sample at the surface to generate surface fluid data.
From the above, it should also be appreciated that what has been described includes a system for evaluating a formation fluid. The system may include a drill string configured to drill a borehole intersecting a formation having the formation fluid; a fluid circulation system circulating a drilling fluid in the borehole; a fluid sampling tool conveyed by the drill string, the fluid sampling tool being configured to selectively liberate a fluid from the formation and inject the liberated fluid into a drilling fluid returning to the surface; and a surface logging system configured to estimating at least one parameter of a sample of the returning drilling fluid returning to the surface, the sample being drawn at the surface.
The foregoing description is directed to particular embodiments of the present disclosure for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope of the disclosure. Thus, it is intended that the following claims be interpreted to embrace all such modifications and changes.
