CA2908626A1 - Reservoir hydrocarbon calculations from surface hydrocarbon compositions - Google Patents
Reservoir hydrocarbon calculations from surface hydrocarbon compositionsInfo
- Publication number
- CA2908626A1 CA2908626A1 CA2908626A CA2908626A CA2908626A1 CA 2908626 A1 CA2908626 A1 CA 2908626A1 CA 2908626 A CA2908626 A CA 2908626A CA 2908626 A CA2908626 A CA 2908626A CA 2908626 A1 CA2908626 A1 CA 2908626A1
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- drilling fluid
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- 229930195733 hydrocarbon Natural products 0.000 title claims abstract description 26
- 150000002430 hydrocarbons Chemical class 0.000 title claims abstract description 26
- 239000004215 Carbon black (E152) Substances 0.000 title claims abstract description 24
- 239000000203 mixture Substances 0.000 title claims abstract description 11
- 238000004364 calculation method Methods 0.000 title claims abstract description 10
- 238000005553 drilling Methods 0.000 claims abstract description 73
- 239000012530 fluid Substances 0.000 claims abstract description 60
- 230000015572 biosynthetic process Effects 0.000 claims description 42
- 238000000034 method Methods 0.000 claims description 18
- 238000004891 communication Methods 0.000 claims description 4
- 239000007789 gas Substances 0.000 description 100
- 241000894007 species Species 0.000 description 16
- 238000005259 measurement Methods 0.000 description 13
- 238000005520 cutting process Methods 0.000 description 7
- 238000003860 storage Methods 0.000 description 6
- 230000008901 benefit Effects 0.000 description 4
- 238000010276 construction Methods 0.000 description 3
- 238000012545 processing Methods 0.000 description 3
- 238000004458 analytical method Methods 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
- 238000011161 development Methods 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 230000005641 tunneling Effects 0.000 description 2
- 241000251468 Actinopterygii Species 0.000 description 1
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 239000004599 antimicrobial Substances 0.000 description 1
- 230000005540 biological transmission Effects 0.000 description 1
- 238000004587 chromatography analysis Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 230000006870 function Effects 0.000 description 1
- 230000005251 gamma ray Effects 0.000 description 1
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/003—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by analysing drilling variables or conditions
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
Landscapes
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Geochemistry & Mineralogy (AREA)
- Chemical & Material Sciences (AREA)
- Analytical Chemistry (AREA)
- Geophysics (AREA)
- Sampling And Sample Adjustment (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)
Abstract
An apparatus for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions during a drilling operation in a reservoir using a drilling fluid is described herein. The apparatus comprises a processor and a memory device coupled to the processor. The memory device may contains a set of instructions that when executed by the processor cause the processor to determine a raw gas value for a gas species measured at a surface gas analyzer; determine a first set of constant values corresponding to the gas species and the reservoir; determine a fluid characteristic of the drilling fluid; and calculate a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
Description
RESERVOIR HYDROCARBON CALCULATIONS FROM SURFACE
HYDROCARBON COMPOSITIONS
BACKGROUND
The present disclosure relates generally to well drilling operations and, more particularly, to reservoir hydrocarbon calculations from surface hydrocarbon composition.
Gas measurements may be used to determine a variety of formation characteristics that are useful for drilling and hydrocarbon extraction operations. Certain types of gas measurements may be easy and relatively cheap to obtain, while others may be more expensive, difficult, and time-consuming. For example, headspace gas measurements on formation cuttings from a drilling operation may require that captured cuttings are placed in jars that are then filled with water and antimicrobials and left for a month.
Additionally, measurements corresponding to downhole gas concentrations may be difficult to obtain due to temperature and pressure changes between the formation and the surface.
FIGURES
Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.
Figure 1 illustrates an example drilling system, according to aspects of the present disclosure.
Figure 2 illustrates an example information handling system, according to aspects of the present disclosure.
Figure 3A and 3B are charts illustrating example constant values corresponding to certain gas species, according to aspects of the present disclosure.
While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.
DETAILED DESCRIPTION
The present disclosure relates generally to well drilling operations and, more particularly, to reservoir hydrocarbon calculations from surface hydrocarbon composition.
Illustrative embodiments of the present disclosure are described in detail herein.
In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells, and production wells, including natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells; as well as borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes or borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons.
Embodiments described below with respect to one implementation are not intended to be limiting.
As will be described below, the present disclosure provides for conversions between easily-accessible surface gas measurements and otherwise expensive and time-consuming gas measurements. In certain embodiments, the surface gas measurements may comprise raw gas values from a surface gas analyzer and the raw gas values may be converted to subsurface gas phases or headspace gas concentrations. "Headspace" is the gas space above a sample in a chromatography vial. Volatile sample components diffuse into the gas space, forming the headspace gas. Headspace analysis therefore may be the analysis of the components present in that gas. In certain embodiments, the raw gas values may be converted using algorithms with gas and formation specific constants that can be calculated using reference measurements of a formation, for example. This may allow the constants to be used for any gas measurements taken within a common formation.
HYDROCARBON COMPOSITIONS
BACKGROUND
The present disclosure relates generally to well drilling operations and, more particularly, to reservoir hydrocarbon calculations from surface hydrocarbon composition.
Gas measurements may be used to determine a variety of formation characteristics that are useful for drilling and hydrocarbon extraction operations. Certain types of gas measurements may be easy and relatively cheap to obtain, while others may be more expensive, difficult, and time-consuming. For example, headspace gas measurements on formation cuttings from a drilling operation may require that captured cuttings are placed in jars that are then filled with water and antimicrobials and left for a month.
Additionally, measurements corresponding to downhole gas concentrations may be difficult to obtain due to temperature and pressure changes between the formation and the surface.
FIGURES
Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.
Figure 1 illustrates an example drilling system, according to aspects of the present disclosure.
Figure 2 illustrates an example information handling system, according to aspects of the present disclosure.
Figure 3A and 3B are charts illustrating example constant values corresponding to certain gas species, according to aspects of the present disclosure.
While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.
DETAILED DESCRIPTION
The present disclosure relates generally to well drilling operations and, more particularly, to reservoir hydrocarbon calculations from surface hydrocarbon composition.
Illustrative embodiments of the present disclosure are described in detail herein.
In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells, and production wells, including natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells; as well as borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes or borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons.
Embodiments described below with respect to one implementation are not intended to be limiting.
As will be described below, the present disclosure provides for conversions between easily-accessible surface gas measurements and otherwise expensive and time-consuming gas measurements. In certain embodiments, the surface gas measurements may comprise raw gas values from a surface gas analyzer and the raw gas values may be converted to subsurface gas phases or headspace gas concentrations. "Headspace" is the gas space above a sample in a chromatography vial. Volatile sample components diffuse into the gas space, forming the headspace gas. Headspace analysis therefore may be the analysis of the components present in that gas. In certain embodiments, the raw gas values may be converted using algorithms with gas and formation specific constants that can be calculated using reference measurements of a formation, for example. This may allow the constants to be used for any gas measurements taken within a common formation.
2
3 PCT/US2013/039550 Fig. 1 is a diagram illustrating an example drilling system 100, according to aspects of the present disclosure. The drilling system 100 comprises a rig 101 positioned at the surface 102 above a formation 103. Although the rig 101 is shown on land in Fig. 1, the rig 101 may be used at sea, with the surface 102 comprising a drilling platform. The rig 101 may be coupled to a drilling assembly 104 that is drilling a borehole 105 within the formation 103. The drilling assembly 104 may be rotated by a rotary table 108 at the surface, and the rotation of the drilling assembly 100 may cause a drill bit 107 at an end of the drilling assembly 104 to rotate, cutting away the formation 103. The drilling assembly 104 may be in fluid communication with a drilling mud reservoir 109 via a pipe 110 and the rotary table 108. Drilling mud 120 may be pumped into an internal bore 106 of the drilling assembly 104 through the pipe 110. The drilling mud 120 may travel through the internal bore 106 of the drilling assembly 104 and exit the drilling assembly 104 through the drill bit 107. Once the drilling mud 120 exits the drill bit 107, the drilling mud 120 may travel to the surface in an annulus 114 between the drilling assembly 104 and a wall of the borehole 105.
The drilling mud 120 may lubricate and cool the cutting surface of the drill bit 107 and carry cuttings from the borehole 104 to the surface 102 in the annulus 114. The drilling mud 120 and cuttings may exit from the borehole through a flow port 111. The flow port 111 may be connected to a gas analyzer 112 positioned at the surface. The gas analyzer 112 may measure raw gas values, such as the concentrations of different gas types or species from the drilling mud 120/cuttings in real-time or close to real time, as the drilling mud 120 flows through the flow port 111. The raw gas values measured at the surface gas analyzer 112 may be received at an information handling system 113 at the surface 103. In certain embodiments, the information handling system 113 may be communicably coupled to the gas analyzer 112 through a wired connection or through a wireless connection, and the raw gas values may be transmitted directly to the information handling system 113. In certain other embodiments, the raw gas values may be stored on a storage medium, such as a Universal Serial Bus (USB) storage device, and physically taken to the information handling system 113.
Information handling system 113 may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system 113 may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, read only memory (ROM), and/or other types of nonvolatile memory. Additional components of the information handling system 113 may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system 113 may also include one or more buses operable to transmit communications between the various hardware components.
Fig. 2 is a diagram illustrating an example information handling system 200, according to aspects of the present disclosure. A processor or CPU 201 of the information handling system 200 is communicatively coupled to a memory controller hub or north bridge 202. Memory controller hub 202 may include a memory controller for directing information to or from various system memory components within the information handling system 200, such as RAM 203, storage element 206, and hard drive 207. The memory controller hub 202 may be coupled to RAM 203 and a graphics processing unit 204. Memory controller hub 202 may also be coupled to an I/O controller hub or south bridge 205. I/O hub 205 is coupled to storage elements of the information handling system 200, including a storage element 206, which may comprise a flash ROM that includes a basic input/output system (BIOS) of the computer system.
I/O hub 205 is also coupled to the hard drive 207 of the information handling system 200. I/O
hub 205 may also be coupled to a Super I/O chip 208, which is itself coupled to several of the I/0 ports of the computer system, including keyboard 209 and mouse 210.
According to aspects of the present disclosure, an apparatus for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions may comprise an information handling system similar to the information handling system 200 shown in Fig. 2. In certain other embodiments, the apparatus may comprise at least a processor and a memory device coupled to the processor, similar to processor 201 and hard drive 207.
In the embodiment shown, hard drive 207 may contain a set of instructions that when executed by the processor 201 cause the processor to perform processes to calculate reservoir hydrocarbon concentrations from surface hydrocarbon compositions.
In certain embodiments, the set of instructions may cause the processor 201 to calculate a subsurface gas concentration for a gas species based, at least in part, on a raw gas value, a first set of constant values, and a fluid characteristic. In certain embodiments, the processor 201 may calculate the subsurface gas concentration using the following equation:
Equation(1): X = A *[gas]* eB(V)+C(W)
The drilling mud 120 may lubricate and cool the cutting surface of the drill bit 107 and carry cuttings from the borehole 104 to the surface 102 in the annulus 114. The drilling mud 120 and cuttings may exit from the borehole through a flow port 111. The flow port 111 may be connected to a gas analyzer 112 positioned at the surface. The gas analyzer 112 may measure raw gas values, such as the concentrations of different gas types or species from the drilling mud 120/cuttings in real-time or close to real time, as the drilling mud 120 flows through the flow port 111. The raw gas values measured at the surface gas analyzer 112 may be received at an information handling system 113 at the surface 103. In certain embodiments, the information handling system 113 may be communicably coupled to the gas analyzer 112 through a wired connection or through a wireless connection, and the raw gas values may be transmitted directly to the information handling system 113. In certain other embodiments, the raw gas values may be stored on a storage medium, such as a Universal Serial Bus (USB) storage device, and physically taken to the information handling system 113.
Information handling system 113 may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system 113 may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, read only memory (ROM), and/or other types of nonvolatile memory. Additional components of the information handling system 113 may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system 113 may also include one or more buses operable to transmit communications between the various hardware components.
Fig. 2 is a diagram illustrating an example information handling system 200, according to aspects of the present disclosure. A processor or CPU 201 of the information handling system 200 is communicatively coupled to a memory controller hub or north bridge 202. Memory controller hub 202 may include a memory controller for directing information to or from various system memory components within the information handling system 200, such as RAM 203, storage element 206, and hard drive 207. The memory controller hub 202 may be coupled to RAM 203 and a graphics processing unit 204. Memory controller hub 202 may also be coupled to an I/O controller hub or south bridge 205. I/O hub 205 is coupled to storage elements of the information handling system 200, including a storage element 206, which may comprise a flash ROM that includes a basic input/output system (BIOS) of the computer system.
I/O hub 205 is also coupled to the hard drive 207 of the information handling system 200. I/O
hub 205 may also be coupled to a Super I/O chip 208, which is itself coupled to several of the I/0 ports of the computer system, including keyboard 209 and mouse 210.
According to aspects of the present disclosure, an apparatus for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions may comprise an information handling system similar to the information handling system 200 shown in Fig. 2. In certain other embodiments, the apparatus may comprise at least a processor and a memory device coupled to the processor, similar to processor 201 and hard drive 207.
In the embodiment shown, hard drive 207 may contain a set of instructions that when executed by the processor 201 cause the processor to perform processes to calculate reservoir hydrocarbon concentrations from surface hydrocarbon compositions.
In certain embodiments, the set of instructions may cause the processor 201 to calculate a subsurface gas concentration for a gas species based, at least in part, on a raw gas value, a first set of constant values, and a fluid characteristic. In certain embodiments, the processor 201 may calculate the subsurface gas concentration using the following equation:
Equation(1): X = A *[gas]* eB(V)+C(W)
4 where X comprises a calculated subsurface gas concentration; A, B, and C
comprise constant values from the first set of constant values, as described below; [gas]
comprises the raw gas value for a given gas species; and V and W comprise fluid characteristics of a drilling fluid used in a hydrocarbon drilling operations. The raw gas value may be measured by a surface gas analyzer and communicated to the information handling system 200. In certain embodiments, V
may comprise a drilling fluid viscosity of the drilling fluid used, and W may comprise a drilling fluid density of the drilling fluid.
The processor 201 may determine the raw gas value measured at a surface gas analyzer for the given gas species. The surface gas analyzer may be communicably coupled to the information handling system 200 and the processor 201, and the processor 201 may determine the raw gas value by extracting the raw gas value from a data transmission to the processor 201 from the surface gas analyzer. In certain embodiments, the raw gas value may be stored on a memory device within the information handling system 200, such as the hard drive 207, and the processor 201 may determine the raw gas value by retrieving the raw gas value from the memory device. In other embodiments, the raw gas value may be stored on an external and/or removable memory device, such as a USB drive, and the processor may determine the raw gas value by retrieving the raw gas value from the removable memory device.
The processor 201 may further determine a first set of constant values corresponding to the gas species and the reservoir. The first set of constant values may be based, at least in part, on a reference data set. The contents of the reference data set may depend on the type of reservoir calculation/conversion to be performed by the processor 201.
For example, if the processor 201 will convert the raw gas value into a subsurface gas concentration, the reference data set may include actual subsurface gas concentration measurements taken within the reservoir as well as corresponding reference raw gas values. The processor 201 may determine the first set of constant values, for example, using a least-square fit method and Equation (1). Specifically, element X in equation (1) may be set to an actual subsurface gas concentration, element [gas] may be set to the corresponding raw gas value, the fluid characteristic values may be set, and A, B, and C may be determined to optimize the fit between the actual subsurface gas concentration and the corresponding reference raw gas value. Fig. 3A
is a chart illustrating an example set of constant values for equation (1), with C1-05 representing different gas species.
The processor 201 may further determine fluid characteristics of a drilling mud used in a drilling operation. In certain embodiments, the fluid characteristics may be stored on a memory device within the information handling system 200, such as the hard drive 207, and the
comprise constant values from the first set of constant values, as described below; [gas]
comprises the raw gas value for a given gas species; and V and W comprise fluid characteristics of a drilling fluid used in a hydrocarbon drilling operations. The raw gas value may be measured by a surface gas analyzer and communicated to the information handling system 200. In certain embodiments, V
may comprise a drilling fluid viscosity of the drilling fluid used, and W may comprise a drilling fluid density of the drilling fluid.
The processor 201 may determine the raw gas value measured at a surface gas analyzer for the given gas species. The surface gas analyzer may be communicably coupled to the information handling system 200 and the processor 201, and the processor 201 may determine the raw gas value by extracting the raw gas value from a data transmission to the processor 201 from the surface gas analyzer. In certain embodiments, the raw gas value may be stored on a memory device within the information handling system 200, such as the hard drive 207, and the processor 201 may determine the raw gas value by retrieving the raw gas value from the memory device. In other embodiments, the raw gas value may be stored on an external and/or removable memory device, such as a USB drive, and the processor may determine the raw gas value by retrieving the raw gas value from the removable memory device.
The processor 201 may further determine a first set of constant values corresponding to the gas species and the reservoir. The first set of constant values may be based, at least in part, on a reference data set. The contents of the reference data set may depend on the type of reservoir calculation/conversion to be performed by the processor 201.
For example, if the processor 201 will convert the raw gas value into a subsurface gas concentration, the reference data set may include actual subsurface gas concentration measurements taken within the reservoir as well as corresponding reference raw gas values. The processor 201 may determine the first set of constant values, for example, using a least-square fit method and Equation (1). Specifically, element X in equation (1) may be set to an actual subsurface gas concentration, element [gas] may be set to the corresponding raw gas value, the fluid characteristic values may be set, and A, B, and C may be determined to optimize the fit between the actual subsurface gas concentration and the corresponding reference raw gas value. Fig. 3A
is a chart illustrating an example set of constant values for equation (1), with C1-05 representing different gas species.
The processor 201 may further determine fluid characteristics of a drilling mud used in a drilling operation. In certain embodiments, the fluid characteristics may be stored on a memory device within the information handling system 200, such as the hard drive 207, and the
5 processor 201 may determine the fluid characteristics by retrieving the fluid characteristics from the memory device. In other embodiments, the fluid characteristics may be stored on an external and/or removable memory device, such as a USB drive, and the processor may determine the raw gas value by retrieving the raw gas value from the removable memory device.
In certain embodiments, the set of instructions further may cause the processor 201 to also calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, a second set of constant values, and at least one formation characteristics of the reservoir. In certain embodiments, the processor 201 may calculate the headspace gas concentration using the following equation:
Equation(2) Y = m * (resistivity gamma) *[gas]+ b where Y comprises a calculated headspace gas concentration; m, n, and b comprise constant values from the second set of constant values, as described below; [gas]
comprises the raw gas value for a given gas species; and resistivity and gamma comprise the formation resistivity and gamma value of a particular reservoir. The raw gas value may be measured by a surface gas analyzer and communicated to the information handling system 200.
The processor 201 may further determine the second set of constant values corresponding to the gas species and the reservoir. The second set of constant values may be based, at least in part, on a second reference data set. The contents of the second reference data set may include actual headspace gas concentration measurements as well as corresponding reference raw gas values. The processor 201 may determine the second set of constant values, for example, using a least-square fit method and Equation (2). Specifically, element Y in Equation (2) may be set to an actual headspace gas concentration, element [gas] may be set to the corresponding reference raw gas value, the formation characteristic values may be set, and m, n, and b may be determined to optimize the fit between the actual headspace gas concentration and the corresponding reference raw gas value. Fig. 3B is a chart illustrating an example set of constant values for equation (1), with C1-05representing different gas species.
The processor 201 may further determine formation characteristics of a reservoir in which a drilling operation is currently taking place. The formation characteristics may include a formation resistivity value for the reservoir and a formation gamma value for the reservoir, as described above. The formation resistivity value may be determined through a secondary operation using survey tools well known in the art. For example, the formation resistivity value may be determined by lowering a wireline resistivity tool into a borehole, taking measurements,
In certain embodiments, the set of instructions further may cause the processor 201 to also calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, a second set of constant values, and at least one formation characteristics of the reservoir. In certain embodiments, the processor 201 may calculate the headspace gas concentration using the following equation:
Equation(2) Y = m * (resistivity gamma) *[gas]+ b where Y comprises a calculated headspace gas concentration; m, n, and b comprise constant values from the second set of constant values, as described below; [gas]
comprises the raw gas value for a given gas species; and resistivity and gamma comprise the formation resistivity and gamma value of a particular reservoir. The raw gas value may be measured by a surface gas analyzer and communicated to the information handling system 200.
The processor 201 may further determine the second set of constant values corresponding to the gas species and the reservoir. The second set of constant values may be based, at least in part, on a second reference data set. The contents of the second reference data set may include actual headspace gas concentration measurements as well as corresponding reference raw gas values. The processor 201 may determine the second set of constant values, for example, using a least-square fit method and Equation (2). Specifically, element Y in Equation (2) may be set to an actual headspace gas concentration, element [gas] may be set to the corresponding reference raw gas value, the formation characteristic values may be set, and m, n, and b may be determined to optimize the fit between the actual headspace gas concentration and the corresponding reference raw gas value. Fig. 3B is a chart illustrating an example set of constant values for equation (1), with C1-05representing different gas species.
The processor 201 may further determine formation characteristics of a reservoir in which a drilling operation is currently taking place. The formation characteristics may include a formation resistivity value for the reservoir and a formation gamma value for the reservoir, as described above. The formation resistivity value may be determined through a secondary operation using survey tools well known in the art. For example, the formation resistivity value may be determined by lowering a wireline resistivity tool into a borehole, taking measurements,
6 and communicating those measurements to the surface. The resistivity values may be stored on hard drive 207 of the information handling system 200, and the processor 201 may determine the formation resistivity value be accessing the value within the hard drive 207.
Likewise, formation gamma may be determined using one or more downhole tools, which may generate a formation evaluation gamma ray log that records the variation with depth of the natural radioactivity of earth materials in a wellbore. This may also be stored in a hard drive 207 of the information handling system 200. Notably, the formation resistivity and gamma of a particular reservoir may be generally consistent, meaning the values may be used at multiple drilling locations within the same reservoir.
According to aspects of the present disclosure, methods for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions during a drilling operation in a reservoir using a drilling fluid are described herein. One example method may include determining a raw gas value for a gas species measured at a surface gas analyzer and determining a first set of constant values corresponding to the gas species and the reservoir. The may be determined at an information handling system based on data obtained from other equipment, including a surface gas analyzer as well as downhole survey tools.
The method may also include determining a fluid characteristic, such as a formation viscosity of the drilling fluid.
Based at least in part, on the raw gas value, the first set of constant values and the fluid characteristic, the method may include calculating a subsurface gas concentration for the gas species based. The subsurface gas concentration may be calculated, for example, using equation (1), described above.
The method may further include determining a second set of constant values corresponding to the gas species and the reservoir and determining a formation characteristic of the reservoir. The second set of constant values and the formation characteristics may also be determined at an information handling system based on data obtained from other equipment.
Based at least in part on the raw gas value, the second set of constant values and the formation characteristic, the method may include calculating a headspace gas concentration for the gas species based. The headspace gas concentration may be calculated, for example, using equation (2), described above.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein
Likewise, formation gamma may be determined using one or more downhole tools, which may generate a formation evaluation gamma ray log that records the variation with depth of the natural radioactivity of earth materials in a wellbore. This may also be stored in a hard drive 207 of the information handling system 200. Notably, the formation resistivity and gamma of a particular reservoir may be generally consistent, meaning the values may be used at multiple drilling locations within the same reservoir.
According to aspects of the present disclosure, methods for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions during a drilling operation in a reservoir using a drilling fluid are described herein. One example method may include determining a raw gas value for a gas species measured at a surface gas analyzer and determining a first set of constant values corresponding to the gas species and the reservoir. The may be determined at an information handling system based on data obtained from other equipment, including a surface gas analyzer as well as downhole survey tools.
The method may also include determining a fluid characteristic, such as a formation viscosity of the drilling fluid.
Based at least in part, on the raw gas value, the first set of constant values and the fluid characteristic, the method may include calculating a subsurface gas concentration for the gas species based. The subsurface gas concentration may be calculated, for example, using equation (1), described above.
The method may further include determining a second set of constant values corresponding to the gas species and the reservoir and determining a formation characteristic of the reservoir. The second set of constant values and the formation characteristics may also be determined at an information handling system based on data obtained from other equipment.
Based at least in part on the raw gas value, the second set of constant values and the formation characteristic, the method may include calculating a headspace gas concentration for the gas species based. The headspace gas concentration may be calculated, for example, using equation (2), described above.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein
7 shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces.
8
Claims (20)
1. An apparatus for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions during a drilling operation in a reservoir using a drilling fluid, comprising:
a processor;
a memory device coupled to the processor, wherein the memory device contains a set of instructions that when executed by the processor cause the processor to:
determine a raw gas value for a gas species measured at a surface gas analyzer;
determine a first set of constant values corresponding to the gas species and the reservoir;
determine a fluid characteristic of the drilling fluid; and calculate a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
a processor;
a memory device coupled to the processor, wherein the memory device contains a set of instructions that when executed by the processor cause the processor to:
determine a raw gas value for a gas species measured at a surface gas analyzer;
determine a first set of constant values corresponding to the gas species and the reservoir;
determine a fluid characteristic of the drilling fluid; and calculate a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
2. The apparatus of claim 1, wherein the set of instructions cause the processor to calculate the subsurface gas concentration using equation (1):
Equation(1): X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
Equation(1): X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
3. The apparatus of claim 1, wherein the set of instructions that cause the processor to determine the first set of constant values further cause the processor to calculate the first set of constant values based at least in part on a first reference data set.
4. The apparatus of claim 3, wherein the first reference data set comprises at least one measured subsurface gas concentration and at least one reference raw gas value corresponding to the measured subsurface gas concentration; and the first set of constant values are generated using equation (1), the at leas one measured subsurface gas concentration, and the at least one reference raw gas value corresponding to the measured subsurface gas concentration.
5. The apparatus of claim 2, wherein the set of instructions further cause the processor to determine a second set of constant values corresponding to the gas species and the reservoir;
determine a formation characteristic of the reservoir; and calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic.
determine a formation characteristic of the reservoir; and calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic.
6. The apparatus of claim 5, wherein the set of instructions cause the processor to calculate the headspace gas concentration using equation (2):
Equation(2):Y = m* (resistivity÷gamma)n *[gas]+ b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
Equation(2):Y = m* (resistivity÷gamma)n *[gas]+ b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
7. The apparatus of claim 6, wherein the set of instructions that cause the processor to determine the second set of constant values further cause the processor to calculate the second set of constant values based at least in part on a second reference data set.
8. The apparatus of claim 7, wherein the second reference data set comprises at least one measured headspace gas concentration and at least one reference raw gas value corresponding to the measured headspace gas concentration; and the second set of constant values are generated using equation (2), the at leas one measured headspace gas concentration, and the at least one reference raw gas value corresponding to the measured headspace gas concentration.
9. An method for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions during a drilling operation in a reservoir using a drilling fluid, comprising:
determining a raw gas value for a gas species measured at a surface gas analyzer;
determining a first set of constant values corresponding to the gas species and the reservoir;
determining a fluid characteristic of the drilling fluid; and calculating a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
determining a raw gas value for a gas species measured at a surface gas analyzer;
determining a first set of constant values corresponding to the gas species and the reservoir;
determining a fluid characteristic of the drilling fluid; and calculating a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
10. The method of claim 9, wherein calculating the subsurface gas concentration comprises using equation (1):
Equation(1) : X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
Equation(1) : X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
11. The method of claim 9, wherein determining the first set of constant values comprises calculating the first set of constant values based at least in part on a first reference data set.
12. The method of claim 11, wherein the first reference data set comprises at least one measured subsurface gas concentration and at least one reference raw gas value corresponding to the measured subsurface gas concentration; and the first set of constant values are generated using equation (1), the at leas one measured subsurface gas concentration, and the at least one reference raw gas value corresponding to the measured subsurface gas concentration.
13. The method of claim 10, further comprising determining a second set of constant values corresponding to the gas species and the reservoir;
determining a formation characteristic of the reservoir; and calculating a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic,
determining a formation characteristic of the reservoir; and calculating a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic,
14. The method of claim 13, wherein calculating the headspace gas concentration comprises using equation (2):
Equation(2) : Y = m * (resistivity÷gamma)n *[gas]+b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
Equation(2) : Y = m * (resistivity÷gamma)n *[gas]+b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
15. The method of claim 14, wherein determining the second set of constant values comprises calculating the second set of constant values based at least in part on a second reference data set.
16. The method of claim 15, wherein the second reference data set comprises at least one measured headspace gas concentration and at least one reference raw gas value corresponding to the measured headspace gas concentration; and the second set of constant values are generated using equation (2), the at leas one measured headspace gas concentration, and the at least one reference raw gas value corresponding to the measured headspace gas concentration.
17. A system for performing reservoir hydrocarbon calculations from surface hydrocarbon compositions while drilling a borehole in a reservoir using a drilling fluid, comprising:
a gas analyzer positioned at a surface above a reservoir, wherein the gas analyzer is in fluid communication with the borehole;
an information handling system communicably coupled to the gas analyzer, wherein the information handling system comprises a processor and a memory device coupled to the processor containing a set of instructions that when executed by the processor cause the processor to:
receive a raw gas value for a gas species from the gas analyzer;
determine a first set of constant values corresponding to the gas species and the reservoir;
determine a fluid characteristic of the drilling fluid; and calculate a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
a gas analyzer positioned at a surface above a reservoir, wherein the gas analyzer is in fluid communication with the borehole;
an information handling system communicably coupled to the gas analyzer, wherein the information handling system comprises a processor and a memory device coupled to the processor containing a set of instructions that when executed by the processor cause the processor to:
receive a raw gas value for a gas species from the gas analyzer;
determine a first set of constant values corresponding to the gas species and the reservoir;
determine a fluid characteristic of the drilling fluid; and calculate a subsurface gas concentration for the gas species based, at least in part, on the raw gas value, the first set of constant values and the fluid characteristic.
18. The system of claim 17, wherein the set of instructions cause the processor to calculate the subsurface gas concentration using equation (1):
Equation(1): X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
Equation(1): X = A *[gas]* e B(V)+C(W) where X corresponds to a calculated subsurface gas concentration value; A, B, and C comprise constant values from the first set of constant values; [gas]
comprises the raw value for the gas species; V comprises a drilling fluid viscosity of the drilling fluid; and W
comprises a drilling fluid density of the drilling fluid; and wherein the drilling fluid viscosity and the drilling fluid density comprise fluid characteristics of the drilling fluid.
19. The system of claim 18 wherein the set of instructions further cause the processor to determine a second set of constant values corresponding to the gas species and the reservoir;
determine a formation characteristic of the reservoir; and calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic.
determine a formation characteristic of the reservoir; and calculate a headspace gas concentration for the gas species based, at least in part, on the raw gas value, the second set of constant values and the formation characteristic.
20. The system of claim 19, wherein the set of instructions cause the processor to calculate the headspace gas concentration using equation (2):
Equation(2) Y = m * (resistivity÷gamma)n *[gas]+ b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
Equation(2) Y = m * (resistivity÷gamma)n *[gas]+ b where Y corresponds to calculated headspace gas concentration value; m, n, and b comprise constant values from the second set of constant values; [gas]
comprises the raw gas value for the gas species; resistivity comprises a formation resistivity value of the reservoir; and gamma comprises formation gamma value for the reservoir; and wherein the resistivity and gamma comprise formation characteristics of the reservoir.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| PCT/US2013/039550 WO2014178883A1 (en) | 2013-05-03 | 2013-05-03 | Reservoir hydrocarbon calculations from surface hydrocarbon compositions |
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| CA2908626A1 true CA2908626A1 (en) | 2014-11-06 |
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| CN (1) | CN105121779A (en) |
| CA (1) | CA2908626A1 (en) |
| DE (1) | DE112013007027T5 (en) |
| GB (1) | GB2528398A (en) |
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| GB2597649B (en) * | 2020-07-06 | 2022-10-19 | Equinor Energy As | Reservoir fluid property estimation using mud-gas data |
| WO2024064788A1 (en) * | 2022-09-21 | 2024-03-28 | Schlumberger Technology Corporation | Prediction of surface gas concentrations in drilling fluid |
| WO2024064790A1 (en) * | 2022-09-21 | 2024-03-28 | Schlumberger Technology Corporation | Prediction of gas concentrations in a subterranean formation |
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|---|---|---|---|---|
| US4635735A (en) * | 1984-07-06 | 1987-01-13 | Schlumberger Technology Corporation | Method and apparatus for the continuous analysis of drilling mud |
| US5277263A (en) * | 1992-04-09 | 1994-01-11 | Amen Randall M | Method for measuring formation fluids in drilling fluid |
| RU2010114583A (en) * | 2007-09-13 | 2011-10-20 | Шлюмбергер Текнолоджи Б.В. (Nl) | METHODS FOR OPTIMIZING AN ANALYSIS OF THE COLLECTOR |
| US20100132450A1 (en) * | 2007-09-13 | 2010-06-03 | Pomerantz Andrew E | Methods for optimizing petroleum reservoir analysis |
| CN102782252B (en) * | 2010-01-13 | 2015-09-16 | 圣托斯有限公司 | Measure the gas content of unconventional reservoir rock |
| US20130311096A1 (en) * | 2012-05-21 | 2013-11-21 | Carl Thomas Greer | Application of engineering principles in measurement of formation gases for the purpose of acquiring more consistent, standardized and authentic gas values for surface logging while drilling |
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- 2013-05-03 DE DE112013007027.8T patent/DE112013007027T5/en not_active Withdrawn
- 2013-05-03 WO PCT/US2013/039550 patent/WO2014178883A1/en active Application Filing
- 2013-05-03 US US14/239,701 patent/US20160123141A1/en not_active Abandoned
- 2013-05-03 CA CA2908626A patent/CA2908626A1/en not_active Abandoned
- 2013-05-03 GB GB1516093.0A patent/GB2528398A/en not_active Withdrawn
- 2013-05-03 CN CN201380075187.5A patent/CN105121779A/en active Pending
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| GB201516093D0 (en) | 2015-10-28 |
| WO2014178883A1 (en) | 2014-11-06 |
| DE112013007027T5 (en) | 2016-01-28 |
| GB2528398A (en) | 2016-01-20 |
| CN105121779A (en) | 2015-12-02 |
| US20160123141A1 (en) | 2016-05-05 |
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