Pulse neutron formation gas identification with LWD measurements

Systems, methods, and devices for quantitatively identifying gas zones irrespective of porosity or lithology using nuclear downhole tools are provided. In particular, because some formation materials such as shales can confound some conventional measurements, a gas detection measurement may be obtained that can be used to qualitatively identify gas zones. The gas detection measurement may be based at least partly on a relationship between inelastic gamma rays, neutron capture gamma rays, and experimental or modeled formation data, such that the gas detection measurement qualitatively indicates a gas zone when a gas zone is present in a formation irrespective of a lithology or a porosity of the formation.

BACKGROUND

The present disclosure relates generally to nuclear well logging and, more particularly, to techniques for identifying gas in certain formations, such as shaly sands.

Nuclear downhole tools are frequently used in the oilfield to determine the properties of a subterranean formation. The valuable information gathered by nuclear downhole tools may indicate, for example, the location and concentration of hydrocarbons such as oil and gas, as well as other properties such as the density or porosity of the subterranean formation. In general, nuclear downhole tools operate by emitting some form of nuclear radiation (e.g., neutrons or gamma rays) into the formation surrounding a borehole. The emitted nuclear radiation interacts with the elements of the formation, the results of which can be detected by nuclear radiation detectors (e.g., neutron detectors or gamma ray detectors) in the downhole tool. Properties of the subterranean formation can then be determined based on the amount and type of radiation detected by the nuclear downhole tool.

Nuclear downhole tools are generally classified as wireline tools or logging-while-drilling (LWD) tools. Wireline tools may be lowered into a borehole to obtain measurements after the borehole has been drilled and/or cased with a casing. Thus, at the time of measurement, materials other than the formation itself may obscure the measurements of the downhole tool. For example, by the time a wireline tool obtains measurements of a subterranean formation, the borehole and surrounding formation may have become invaded by drilling fluid or by hydrocarbons. On the other hand, LWD tools may obtain measurements of the subterranean formation in an openhole reading at the time the borehole is initially being drilled. Since LWD tools take measurements of the formation at the time the borehole is being drilled, fewer materials other than the subterranean formation affect the measurement.

Both wireline and LWD nuclear downhole tools that perform pulse neutron capture (PNC) measurements have been developed. In general, PNC measurements involve emitting pulses of neutrons into the surrounding formation to be “captured” by the nuclei of elements of the formation. When the nuclei capture the neutrons, they emit gamma rays as a result. By measuring the extent to which these capture gamma rays are detected by radiation detectors in the downhole tool, a “capture cross-section” of the formation can be obtained. The capture cross-section of the formation is also referred to as the sigma measurement, and is used to discriminate between hydrocarbons and saline water in the subterranean formation, since chlorine in the salt water has a very large capture cross-section compared to hydrocarbons and reservoir rocks. The greater the total salt count (NaCl per 1,000 ppm) in the water contained by the subterranean formation, the better a PNC tool may quantitatively describe the water saturation.

In certain formations such as shale, sandstone, dolomite, and/or carbonate, however, the sigma measurement may not always accurately indicate certain formation properties. In fact, many large reserves of hydrocarbons in the Gulf of Mexico and elsewhere may have many zones of with significant amounts of shale and other similar rocks. It is believed that some prospects in these reserves apparently looked qualitatively marginal, or even bad, due to the effects of excess shale on PNC measurements. Many of these zones therefore may have been passed up indefinitely or, worse yet, condemned as non-productive.

SUMMARY

In one embodiment, a method includes emitting neutrons into a subterranean formation using a neutron generator. This causes inelastic scattering events that generate inelastic gamma rays and neutron capture events that generate neutron capture gamma rays. The resulting inelastic gamma rays and neutron capture gamma rays may be detected using a gamma ray detector. Data processing circuitry then may be used to determine a gas detection measurement based at least in part on a relationship between the inelastic gamma rays, the neutron capture gamma rays, and experimental or modeled formation data. The gas detection measurement may qualitatively indicate a gas zone when the gas zone is present in the subterranean formation, irrespective of a lithology or a porosity of the subterranean formation.

In another embodiment, a downhole tool includes an electronic neutron generator, a gamma ray detector, and data processing circuitry. The electronic neutron generator may emit a burst of neutrons into materials surrounding the downhole tool to cause inelastic scattering events that produce inelastic gamma rays and neutron capture events that produce neutron capture gamma rays. The gamma ray detector may detect the inelastic gamma rays and the neutron capture gamma rays, and the data processing circuitry may use these detected gamma rays to determine a qualitative gas detection measurement. This qualitative gas detection measurement may provide an accurate qualitative indication of the presence of a gas zone in a subterranean formation near the downhole tool even when a conventional measurement suggests otherwise.

In another embodiment, a system may include a downhole tool and data processing circuitry. The downhole tool may emit neutrons into a subterranean formation and detect the inelastic gamma rays and neutron capture gamma rays that result. The data processing circuitry may determine several gas detection measurements based at least in part on a relationship between the inelastic gamma rays, the neutron capture gamma rays, and experimental or modeled formation data, or both. The data processing circuitry may plot the plurality of gas detection measurements as a gas detection measurement diagnostic curve in a well log, such that a deflection over a threshold in the gas detection measurement diagnostic curve qualitatively suggests a gas zone when the gas zone is present in the subterranean formation, irrespective of a lithology or a porosity of the subterranean formation.

In another embodiment, an article of manufacture includes one or more tangible, machine-readable media at least collectively comprising processor-executable instructions. These instructions may include, for example, instructions to receive a count rate of inelastic gamma rays and neutron capture gamma rays detected by a pulsed neutron capture tool at some depth in a formation. From these count rates, other instructions may determine a gas detection measurement that accurately indicates the presence of a gas zone in shale, sandstone, dolomite, and/or carbonate. The gas detection measurement may be determined based at least in part on a function taking the count rate of inelastic gamma rays and the count rate of neutron capture gamma rays as variables.

DETAILED DESCRIPTION

Present embodiments relate to well-logging systems and methods for identifying gas zones in a subterranean formation largely irrespective of the lithology or porosity of the formation. Thus, according to present embodiments, gas zones may be detected despite the presence of shale, sandstone, dolomite, and/or carbonate, for example, which might otherwise obscure the detection of gas. For example, a pulsed neutron capture (PNC) tool according to embodiments may emit pulses of fast, high-energy neutrons and detect the gamma rays that result. When the fast, high-energy neutrons interact with the materials surrounding the downhole tool, inelastic scattering events may produce inelastic gamma rays and neutron capture events may produce neutron capture gamma rays. Counts of both of these types of gamma rays may be used to identify gas zones according to the present disclosure.

That is, rather than relying only on the neutron capture gamma rays that are used to calculate the capture cross-section of the formation, or sigma, a qualitative gas detection measurement GasIDmay be determined from both inelastic gamma rays and neutron capture gamma rays. As discussed below, this gas detection measurement GasIDmay be any suitable function (e.g., a polynomial function) that correlates inelastic gamma ray count rates as well as neutron capture count rates to the presence of gas in experimental or computer-modeled data. Because this gas detection technique does not employ a ratio of gamma ray detector values, the measurement will be responsive to the subterranean formation even in a gas-filled borehole when the tool is eccentered.

The gas detection measurement GasIDmay be used to qualitatively identify gas by plotting the gas detection measurement GasIDover depth in a well log. Gas zones may be identified qualitatively by the movement of the plotted curve from a shaly-sand baseline.

This curve may correctly describe the presence of gas in a near-wellbore formation with a large movement from the statistical shale baseline. This qualitative interpretation tool may be used to “flag” areas of the well-log to indicate a need for further studies before condemning the area as non-productive. In addition, this curve presentation may be another quick way for a production engineer to evaluate small or marginal shale-laminated gas zones that may otherwise be overlooked. The magnitude of the response curve of the gas detection measurement may reflect not only the presence of gas but also its density and pressure.

With the foregoing in mind,FIG. 1illustrates a wellsite system in which the disclosed gas detection measurement system can be employed. The wellsite system ofFIG. 1may be onshore or offshore. In the wellsite system ofFIG. 1, a borehole11may be formed in subsurface formations by rotary drilling using any suitable technique. A drill string12may be suspended within the borehole11and may have a bottom hole assembly (BHA)100that includes a drill bit105at its lower end. A surface system of the wellsite system ofFIG. 1may include a platform and derrick assembly10positioned over the borehole11, the platform and derrick assembly10including a rotary table16, kelly17, hook18and rotary swivel19. The drill string12may be rotated by the rotary table16, energized by any suitable means, which engages the kelly17at the upper end of the drill string12. The drill string12may be suspended from the hook18, attached to a traveling block (not shown), through the kelly17and the rotary swivel19, which permits rotation of the drill string12relative to the hook18. A top drive system could alternatively be used, which may be a top drive system.

In the wellsite system ofFIG. 1, the surface system may also include drilling fluid or mud26stored in a pit27formed at the well site. A pump29may deliver the drilling fluid26to the interior of the drill string12via a port in the swivel19, causing the drilling fluid to flow downwardly through the drill string12as indicated by the directional arrow8. The drilling fluid26may exit the drill string12via ports in the drill bit105, and circulating upwardly through the annulus region between the outside of the drill string12and the wall of the borehole11, as indicated by the directional arrows9. In this manner, the drilling fluid26lubricates the drill bit105and carries formation cuttings up to the surface, as the fluid26is returned to the pit27for recirculation.

The bottom hole assembly100of the wellsite system ofFIG. 1may include a logging-while-drilling (LWD) module120and/or a measuring-while-drilling (MWD) module130, a roto-steerable system and motor150, and the drill bit105. The LWD module120can be housed in a special LWD drill collar, and can contain one or more types of logging tools. It will also be understood that more than one LWD module can be employed, as generally represented at numeral120A. As such, references to the LWD module120can alternatively mean a module at the position of120A as well. The LWD module120may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment. The LWD module120may be employed to obtain a gas detection measurement GasIDcurve to enable qualitative identification of gas zones largely irrespective of lithology and porosity, as will be discussed further below.

The MWD module130can also be housed in a special MWD drill collar, and can contain one or more devices for measuring characteristics of the drill string and drill bit. It should be appreciated that more than one MWD module130can be employed, as generally represented at numeral130A. As such, references to the MWD module130can alternatively mean a module at the position of130A as well. The MWD module130may also include an apparatus for generating electrical power to the downhole system. Such an electrical generator may include, for example, a mud turbine generator powered by the flow of the drilling fluid, but other power and/or battery systems may be employed additionally or alternatively. In the wellsite system ofFIG. 1, the MWD module130may include, for example, a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and/or an inclination measuring device.

The LWD module120, one example of which appears inFIG. 2, may be used in a system for obtaining a qualitative gas detection measurement GasIDto identify gas zones irrespective of formation lithology or porosity. That is, using the LWD module120ofFIG. 2, a gas detection measurement GasIDcan be determined and used to qualitatively identify gas zones in formations such as shale, sandstone, dolomite, and/or carbonate, for example, which might otherwise obscure the detection of gas. It should be understood that the LWD module120is intended to represent one example of a general configuration of a nuclear downhole tool that can be used to obtain the gas detection measurement GasID, and that other suitable downhole tools may include more or fewer components and may be configured for other means of conveyance. Indeed, other embodiments employing the general configuration of the LWD module120are envisaged for use with any suitable means of conveyance, such as wireline, coiled tubing, logging while drilling (LWD), and so forth. As will be discussed below, however, the gas detection measurement GasIDmay best identify gas when used with logging-while-drilling (LWD) data, since LWD data is obtained before the formation may have been invaded by other materials (e.g., drilling mud or hydrocarbons) not originally present. In addition, the LWD module120ofFIG. 2may or may not include associated data processing circuitry200. Indeed, although the LWD module120and the data processing circuitry200are depicted as independent elements inFIG. 2, the data processing circuitry200may be implemented entirely within the LWD module120, at the surface remote from the LWD module120, or partly within the LWD module120and partly at the surface. By way of example, the LWD module120may represent a model of the EcoScope™ tool by Schlumberger.

As shown inFIG. 2, the LWD module120may be contained within a drill collar202that encircles a chassis204and a mud channel205. The chassis204may include a variety of components used for emitting and detecting radiation. For example, a neutron generator206may serve as a neutron source that emits neutrons of at least 2 MeV, which is believed to be approximately the minimum energy to create gamma rays through inelastic scattering with formation elements. By way of example, the neutron generator206may be an electronic neutron source, such as a Minitron™ by Schlumberger Technology Corporation, which may produce pulses of neutrons through deuteron-deuteron (d-D) and/or deuteron-triton (d-T) reactions. Thus, the neutron generator206may emit neutrons around 2 MeV or 14 MeV, for example. A neutron monitor208may monitor the neutron emissions from the neutron generator206. By way of example, the neutron monitor208may be a plastic scintillator and photomultiplier that primarily detects unscattered neutrons directly emitted from the neutron generator206, and thus may provide a count rate signal proportional to the neutron output rate from the rate of neutron output of the neutron generator206. Neutron shielding210, which may include lead, for example, may largely prevent neutrons from the neutron generator206from passing internally through the LWD module120toward various radiation-detecting components on the other side of the shielding210.

As illustrated inFIG. 2, the LWD module120can include a near neutron detector212and a far neutron detector216. By way of example, the near neutron detector212may be spaced approximately 10-14 in. from the neutron generator206, and the far neutron detector216may be spaced approximately 18-28 in. from the neutron generator206. A near gamma ray detector218(also sometimes referred to as a short spacing (SS) gamma ray detector) may be located between the near neutron detector212and the far neutron detector216. A far gamma ray detector220(also sometimes referred to as a long spacing (LS) gamma ray detector) may be located beyond the far neutron detector216. For example, the near gamma ray detector218may be spaced approximately 16-22 in. from the neutron generator206, and the far gamma ray detector220may be spaced approximately 30-38 in. from the neutron generator206. Alternative embodiments of the LWD module120may include more or fewer of such radiation detectors, but generally may include at least two gamma ray detectors and at least one neutron detector. The neutron detectors212and216may be any suitable neutron detectors, such as3He neutron detectors. The neutron detectors212and216may detect primarily epithermal neutrons or primarily thermal neutrons (e.g., one or both of the neutron detectors212and216may or may not be surrounded by thermal neutron shielding depending on the energy of the neutrons to be detected).

The gamma ray detectors218and/or220may be scintillator detectors surrounded by neutron shielding. The neutron shielding may include, for example,6Li, such as lithium carbonate (Li2CO3), which may substantially shield the gamma ray detectors218and/or220from thermal neutrons without producing thermal neutron capture gamma rays. As will be discussed below, gamma rays detectable by the gamma ray detectors218and220may be generated when the neutron generator206emits pulses of neutrons into a surrounding formation causing the generation of neutron capture gamma rays and inelastic gamma rays. Neutron capture gamma rays are often employed to determine the neutron capture cross section, or sigma, of the formation, which is frequently used to detect the presence of gas. However, some formations may contain materials such as shale, sandstone, dolomite, and/or carbonate, which may obscure the presence of gas zones according to conventional measurements. According to present techniques, a gas detection measurement GasIDmay be determined to qualitatively identify gas zones largely irrespective of lithology or porosity. The gas detection measurement GasIDmay be determined with a function taking as its variables not only the neutron capture gamma rays, but also the inelastic gamma rays. The gas detection measurement GasIDmay be used to “flag” areas that are likely to contain gas zones despite the presence of formation materials that cause conventional measurements to suggest otherwise.

To determine the gas detection measurement GasID, the count rates of gamma rays from the gamma ray detectors218and/or220(and/or count rates of neutrons from the neutron detectors212and216) may be received by the data processing circuitry200as data222. The data processing circuitry200may receive the data222and perform certain processing to determine various measurements that can be used to determine properties of the surrounding formation. By way of example, the data processing circuitry200may include a processor224, memory226, and/or storage228. The processor224may be operably coupled to the memory226and/or the storage228to carry out the presently disclosed techniques. The processor224and/or other data processing circuitry may carry out certain instructions executable by the processor224, which may be stored using any suitable article of manufacture that includes one or more tangible, computer-readable media at least collectively storing these instructions. The article of manufacture may include, for example, the memory226and/or the nonvolatile storage228, which may represent, for example, random-access memory, read-only memory, rewriteable flash memory, hard drives, and optical disks.

The LWD module120may transmit the data222to the data processing circuitry200via, for example, internal connections within the tool, a telemetry system communication uplink, and/or a communication cable. From within the LWD tool120and/or at the surface, the data processing circuitry200may determine a qualitative gas detection measurement GasIDin a report230. The report230may include many other measurements, and may represent a well log. Specifically, the qualitative gas detection measurement GasIDmay be plotted against depth in such a well log. By observing the shape of the resulting gas detection measurement GasIDdiagnostic curve, the data processing circuitry200and/or a production engineer may identify probable gas zones. A few specific examples of well logs that include a gas detection measurement GasIDdiagnostic curve are discussed further below with reference toFIGS. 7 and 8. The report230may be stored in memory or may be provided to an operator via one or more output devices, such as an electronic display.

The gamma ray measurements used to generate the gas detection measurement GasIDmay be collected during a well-logging operation. For example, as shown in a well-logging operation240ofFIG. 3, the LWD module120may be used to obtain a gas detection measurement GasIDthat can be used to qualitatively identify gas zones in variety of formations242, including shales, sandstone, dolomite, and/or carbonate, for example. As seen inFIG. 3, the well-logging operation240may involve lowering the LWD module120into the formation242through the borehole11. In the example ofFIG. 3, the LWD module120can be lowered into the borehole11while drilling, and thus no casing may be present in the borehole11. However, in other embodiments, a casing may be present. It should be appreciated that when the gas detection measurement GasIDis determined based on LWD data, the gas detection measurement GasIDmay be more likely to be accurately identify gas zones than otherwise.

In the well-logging operation240, the neutron generator206may emit one or more pulses or bursts246of neutrons248out toward the formation242. At the outset of each neutron pulse or burst246, the fast neutrons248may interact with elements of the borehole and/or formation by way of inelastic scattering250. Inelastic neutron scattering250occurs when fast, high-energy neutrons248interact with heavy nuclei in the formation242and borehole11. During inelastic scattering250, the high-energy neutron248imparts more of its kinetic energy to the struck nucleus than is predicted by a simple elastic collision. This inelastic collision excites the struck nucleus, raising it to one of its higher bound energy states. The excited nucleus will then normally return to its ground state by emitting one or more gamma rays252. Because the gamma rays252originate from an inelastic scattering250event, these gamma rays252will be referred to as “inelastic gamma rays.”

Generally, after the initial inelastic scattering250events, neutron capture254events may begin to dominate. Neutron capture254events occur by when a neutron248is “thermalized” to a lower-energy state in an element of the formation242or the borehole11. Specifically, the neutron248will lose a substantial amount of energy through elastic scattering through elements of the formation242or borehole11after being emitted in the neutron pulse or burst246. Eventually, the neutron248may have an energy level low enough to be absorbed in a collision with a denser element. As a result, a gamma ray256may be released from the host element. Because the gamma rays256originate from a neutron capture254events, these gamma rays256will be referred to as “neutron capture gamma rays.”

The inelastic gamma rays252and neutron capture gamma rays256may be detected by the near and far gamma ray detectors218and220. It should also be noted that, although not necessarily used for determining the gas detection measurement GasID, the neutrons248that scatter in the borehole11and formation242and return to the LWD module120may be detected by the near neutron detector212and the far neutron detector216. The inelastic gamma rays252and the neutron capture gamma rays256may be distinguished from one another based on the timing of the neutron pulse or burst246. For example, as shown by a timing diagram260inFIG. 4, the occurrence of the pulse or burst246of neutrons248may begin a period T during which the inelastic gamma rays252and neutron capture gamma rays256are detected. By way of example, the period T may be between approximately 20-45 μs (e.g., 20 μs, 2 μs, 30 μs, 35 μs, 40 μs, or 45 μs, etc.).

At the start of the timing diagram260ofFIG. 4, the neutron pulse or burst246may take place over an initial burst gate262. The burst gate262represents the amount of time during which the pulse or burst246of neutrons is occurring and may be relatively short. For example, the burst gate262may endure approximately 5-15 μs (e.g., 5 μs, 10 μs, or 15 μs, etc.). During the burst gate262, the gamma rays detected by the near gamma ray detector218and far gamma ray detector220generally may be inelastic gamma rays252that arise due to inelastic scattering. In particular, it may be appreciated that the inelastic gamma ray population is a function of the neutron248“slowing down length” and density of the material through which the gamma rays252travel. The inelastic gamma ray252count rate response is therefore directly proportional to the number of high-energy neutron248collisions that occur generally during the burst gate262. The number of these inelastic collisions increases considerably with decreases in hydrogen density in the borehole11and the formation242. A decrease in hydrogen nuclei decreases the number of elastic energy-reducing collisions and allows more high-energy neutrons to come in contact with heavy borehole11and formation242nuclei.

Also, it may be noted that variations in liquid-filled porosity of the borehole11and the formation242can affect the hydrogen index, which can be used to indicate the presence of a gas zone in many formation242materials. The hydrogen index, which is a measurement often obtained based on the detection of the neutrons248, increases as the density decreases, and vice versa. However, the inelastic gamma ray252count rate is relatively insensitive to changes in liquid-filled porosity. In porous rock, as the water is removed and replaced with gas, the hydrogen index decreases and the density decreases. This causes a net increase in the observed inelastic gamma ray252count rates. The sensitivity to gas-filled porosity decreases as the porosity decreases and/or the distance from the LWD tool120to the formation242increases. It should further be appreciated that the measurement of inelastic gamma rays252results in a very shallow depth of investigation (DOI), on the order of a few inches in some cases. As such, the inelastic gamma ray252measurement is thus much more sensitive to changes in the borehole11region than in the formation242when gas is present in the borehole11, the inelastic gamma ray252measurement will show an anomalous, high reading.

Following the burst gate262is the early gate264. The early gate264may be shorter in duration than the burst gate262, and generally represents the span of time immediately following the end of the pulse or burst246of neutrons248. By way of example, the early gate264may last approximately 3-10 μs (e.g., 3 μs, 4 μs, 5 μs, 6 μs, 7 μs, 8 μs, 9 μs, or 10 μs, etc.). During the early gate264, the amount of inelastic scattering250events may decline precipitously, such that the number of inelastic gamma rays252produced declines accordingly. At the same time, the percentage of total gamma rays being generated due to neutron capture254events begins to rise.

By the time of the late capture gate266, the vast majority of gamma rays detected by the near gamma ray detector218and far gamma ray detector220are neutron capture gamma rays256that arise due to neutron capture254events. Thus, in some embodiments, the gamma rays detected by the gamma ray detectors218and/or220during the burst gate262may be inferred to be inelastic gamma rays252. The gamma rays detected by the gamma ray detectors218and/or220during the late capture gate266may be inferred to be neutron capture gamma rays256. In other embodiments, the inelastic gamma rays252may be distinguished from the neutron capture gamma rays256using any other suitable technique.

The count rate of the neutrons248, the inelastic gamma rays252and the neutron capture gamma rays256may be employed to determine many characteristics of the subterranean formation242other than the gas detection measurement gas detection measurement GasID. To provide one brief example, neutron capture gamma rays256are frequently used to generate a log output curve called “sigma,” which represents the “capture cross-section” of the formation242. Typically, sigma is used to discriminate between hydrocarbon and saline water in the formation242, since the chlorine in the saline water has a very large capture cross-section compared to hydrocarbon and reservoir rocks. The greater the total salt count (NaCl per 1,000 PPM) in the formation242waters, the quantitative description of the water saturation of the formation242. It may be noted that the effects of water salinity, porosity, and shaliness on the measured parameter sigma (that is, the quantitative part of the water saturation solution) are similar to those on resistivity logs. Thus, the two are easily correlated. One simple interpretation model presumes that the sigma of the formation242is equal to the sum of the constitute sigma values weighted by the fractional volume occupied:
Σlog=Σma(1−Φe−Vsh)+VshΣsh+ΦeSwΣwa+Φc(1−Sw)Σhyd(1),
where Σlogrepresents a sigma log value in capture units (cu), Σmarepresents a sigma matrix value in capture units (cu), Σshrepresents a sigma shale value in capture units (cu), Σwarepresents a sigma water apparent value in capture units (cu), and Σhydrepresents a sigma hydrocarbon value in capture units (cu). The variable Vshrepresents the percent volume due to shale, which may be obtained from gamma ray measurements using correlations (e.g., linear, Clavier, Stieber, Larionov, etc.), Swrepresents the percent of water saturation, and Φerepresents the effective porosity of the formation242in porosity units (pu).

From Equation 1 above, it may be seen that the sigma log value Σlogcan be used to calculate moveable water saturation Sw. Transformation of the functional volume model in Equation 1 yields the classic shaly sand model solution for moveable water saturation Sw:

This quantitative solution for movable water saturation Swdirectly identifies the moveable water content of the effective porosity. It should also be appreciated that several factors may interfere with a simple measurement of the formation242sigma: borehole fluid, borehole hardware (e.g., a gravel pack), and diffusion effects. As such, the LWD module120may employ any suitable technique to characterize borehole effects, such as a two-component diffusion model. Such an approach separates the borehole11and formation242components of the neutron capture gamma ray256signals.

In certain types of formation242materials, such as shaly sand, sandstone, dolomite, and/or carbonate, the petrophysical characteristics of the formation242may defy the interpretive methods of traditional sigma measurements to identify gas in the formation242. In fact, it is believed that many of the large reserves of gas and hydrocarbons in the Gulf of Mexico and elsewhere may have had many gas zones that might have been left behind. Specifically, it is believed that prospects that apparently looked qualitatively marginal, or even bad, due to the effects of excess shale might have been left behind. In some cases, the formation242may have been too laminated for the vertical resolution of the neutron capture gamma ray256measurement to be employed to define. Indeed, it is believed that a crossover of near gamma ray detector218to far gamma ray detector220count rate curves may have indicated opposite conditions (e.g., a neutron-density porosity curve crossover might have been indicative of gas, while the overlay of these curves indicated “fluid-filled” porosity on the respective logs). As a result, it is believed that these zones were often passed up indefinitely or, worse, condemned as non-productive.

To better identify gas zones in materials such as shaly sand, sandstone, dolomite, and/or carbonate, the LWD module120may be employed to determine a qualitative gas detection measurement GasID. The gas detection measurement GasIDis a function of both the inelastic gamma rays252as well as neutron capture gamma rays256. Specifically, as illustrated by a flowchart270ofFIG. 5, the LWD tool120may be employed while the borehole11is being drilled (block272) or, in alternative embodiments, be lowered into the borehole11using any suitable means of conveyance (e.g., wireline, coiled tubing, etc.). The neutron generator206may periodically emit pulses or bursts246of neutrons248(block274). For example, the neutron generator206may emit a pulse or burst246in the manner discussed above with reference to the timing diagram260ofFIG. 3.

The near gamma ray detector218or far gamma ray detector220, or both, may detect the inelastic gamma rays252using any suitable technique (block276). For example, the inelastic gamma rays252may be understood to be present primarily during a burst gate262(FIG. 3). Thus, the gamma rays detected by the near gamma ray detector218or far gamma ray detector220, or both, during the burst gate262may be understood to be inelastic gamma rays252.

The near gamma ray detector218or far gamma ray detector220, or both, also may detect the neutron capture gamma rays256using any suitable technique (block278). For example, the neutron capture gamma rays252may be understood to be present primarily during the late capture gate266(FIG. 3). Thus, the gamma rays detected by the near gamma ray detector218or far gamma ray detector220, or both, during the late capture gate266may be understood to be neutron capture gamma rays256.

Based on the detected count rate of inelastic gamma rays252and neutron capture gamma rays256, a qualitative gas detection measurement GasIDmay be determined. This gas detection measurement GasIDmay not rely on any formation242salinity values for compensation interruption. Indeed, porosity and lithology changes can cause changes in a traditional PNC count rate ratio similar to those encounters in gas. However, using only the inelastic gamma rays and neutron capture gamma rays256as detected by the far gamma ray detector220, the gas detection measurement GasIDmay be used to resolve the presence of gas in a manner that is not sensitive to lithology or porosity. The gas detection measurement may generally be described as according to the following relationship:
GasID=ƒ(inelastic counts,neutron capture counts)  (3),
where the gas detection measurement GasIDfunction ƒ may take any functional form (e.g., one or more polynomials) that relates, through characterization measurements and/or nuclear modeling, the inelastic gamma rays252, the neutron capture gamma rays256, and the presence of gas zones in a formation242. Thus, when the gas detection measurement GasIDfunction ƒ is a polynomial, the coefficients of such a function may be derived during the characterization of the LWD module120in various experimental and/or modeled settings. In addition, the gas detection measurement GasIDfunction ƒ may be dependent on the neutron generator206strength, the sensitivity of the gamma ray detectors218and/or220, and the environment of the borehole11. Therefore, the calculation coefficients may be adaptable to the specific PNC tool being used and the borehole11environment. In some embodiments, the gas detection measurement GasIDfunction ƒ may employ a fixed equation. In that case, the coefficients may be normalized for each well-logging operation240. When the coefficients are normalized, the gas detection measurement GasIDmay be used to form a gas diagnostic curve with fixed scaling on a well log. Therefore, all curve scale parameters on the log will be the same, as opposed to sliding the ratio and varying the count rate scale presentations.

The gas detection measurement GasIDmay not employ a ratio of near-to-far gamma ray detectors218and220values, but rather may use only those gamma rays detected by the near gamma ray detector218or the far gamma ray detector220. As such, the gas detection measurement GasIDmay be responsive to the formation242even in a gas-filled borehole11when the LWD tool120is eccentered. That is, gas in the borehole11will cause the results to read high. However, because the results can be normalized, along with gas-corrected porosity and sigma values, gas-filled formation242intervals can still be identified using the gas detection measurement GasID.

As mentioned above, the gas detection measurement GasIDcan be used to qualitatively identify gas in the formation242. For example, as shown by a flowchart300ofFIG. 6, the various gas detection measurements Gaspdetected at various depths throughout the formation242may be plotted in a log (block302). The diagnostic curve that results describes gas presence in the formation242near the borehole11based on a large movement from a statistical shale baseline. Since qualitative interpretation tools are designed to “flag” areas that require further study before condemning them as non-productive, this curve presentation represents a quick way for a production engineer to evaluate small or marginal shale-laminated gas zones that might otherwise be overlooked.

As such, the data processing system14and/or a production engineer or operator may identify deflections in the plotted curve (block304). If these deflections result in the gas detection measurement GasIDremaining beneath a threshold (decision block306), the zone in question is probably not a gas zone (block308). On the other hand, if a deflection in the gas detection measurement GasIDcurve exceeds the threshold, the zone in question may be identified as a probable gas zone that warrants further investigation (block310).

FIGS. 7 and 8provide two specific examples that illustrate the use of the gas detection measurement GasIDin shaly sand zones. As mentioned above, the appearance of a shaly sand zone in the formation242might otherwise obscure any gas zones located within them according to some conventional measurements. The examples ofFIGS. 7 and 8represent data obtained experimentally in the field, showing the manner in which the gas detection measurement GasIDcan be used qualitatively identify the presence of gas zones in shaly sand zones.

In a first example,FIG. 7represents a logged interval320of a formation242of shaly sand with a known gas zone. The logged interval320shows measurements obtained from approximately 12050-12250 feet, and includes conventional log data322showing measurements for resistivity, neutron, and density porosity in a petrophysical analysis of the zone. Alongside the conventional log data322are qualitative curves324. These qualitative curves324include a conventional sigma curve326, a counts curve328, and a gas detection measurement GasIDdiagnostic curve330. The uppermost ordinate of the qualitative curves324represents sigma values associated with the sigma curve326and the lowermost ordinate represents total counts associated with the counts curve328. The gas detection measurement GasIDdiagnostic curve330is unitless and normalized, and thus is shown alongside the sigma curve326and the counts curve328.

As apparent in the logged interval320, the zone between about 12050 and 12150 feet could simply be a low porosity and/or gas sand interval. The neutron openhole porosity data of the conventional log data322shows this interval to be a tight zone. On the other hand, the density openhole data of the conventional log data322indicates a higher porosity zone. The sigma curve326appears to show a decreased response in this zone and indicates that hydrocarbons are likely to be present. The porosity and sigma values are reduced by the formation242hydrocarbon/matrix responses. However, the gas detection measurement GasIDdiagnostic curve330clearly, and correctly, indicates a gas zone at 12050-12150 feet. A change in the gas detection measurement GasIDcurve330of over two divisions through this interval strongly confirms that this zone of the formation242is a gas sand. The variation in the gas detection measurement GasIDdiagnostic curve330also suggests a gas density effect (e.g., possibly a difference in the interval pressure). Thus, combining the conventional log data322with adjacent formation242gas detection measurement GasIDresponses may also provide an estimate of the interval pressure.

Likewise, in the zone below the 12150 foot interval, a possible gas formation interval is indicated by the openhole neutron-density response of the conventional log data322. However, the gas detection measurement GasIDdiagnostic curve330suggests otherwise. The gas detection measurement GasIDdiagnostic curve330through this zone shows only negligible change. Therefore, the gas detection measurement GasIDdiagnostic curve330may be understood to identify, correctly, the absence of a gas zone in the zone below 12150 feet. In addition, it may be noted that the sigma curve326suggests a liquid hydrocarbon response in the zone below 12150 feet.

In another example, shown inFIG. 8, a logged interval350of a formation242provides data for an interval between 14100 feet and 14250 feet.FIG. 8also illustrates conventional log data352and qualitative diagnostic curves354. The conventional log data352includes, for example, resistivity, density, and neutron log data. The qualitative diagnostic curves354include a sigma curve356, a counts curve358, and a gas detection measurement GasIDcurve360. The uppermost ordinate of the qualitative curves354represents sigma values associated with the sigma curve356and the lowermost ordinate represents total counts associated with the counts curve358. The gas detection measurement GasIDdiagnostic curve360is unitless and normalized, and thus is shown alongside the sigma curve356and the counts curve358.

As illustrated in the logged interval350ofFIG. 8, the gas detection measurement GasIDdiagnostic curve360shows a moderate response at several known gas sand intervals between 14146-14172 feet, but has little or no response in the lower zones. The gas in the formation242causes the gas detection measurement GasIDdiagnostic curve360to increase over one division. The change in the gas detection measurement GasIDdiagnostic curve360suggests a liquid hydrocarbon below 14176 in probable water below 14222 feet (the gas detection measurement GasIDdiagnostic curve360response is negligible over these lower intervals). The qualitative indications by the gas detection measurement GasIDdiagnostic curve360confirms that the gas detection measurement GasIDis not affected by the presence of liquids in the formation, but rather discretely identifies gas in the same depositional environment. The representation of the logged interval350inFIG. 8also suggests at least a qualitative response to pressure and/or density of the hydrocarbons present in the formation242.

Here, it should also be noted that the data obtained using conventional pulse neutron capture (PNC) logging measurements can be extended to the estimation of the gas pressure of the reservoir. Gas pressure is directly related to the hydrogen index volume in the matrix of the formation242. With an estimate of the elemental volumes of the materials present in the formation242(e.g., rock matrix, shale, water, and gas), the sigma response can be correlated to hydrogen index using any suitable functional form. Accordingly, the sigma response can be correlated to the gas pressure using nuclear modeling (e.g., SNUPAR nuclear modeling). As noted above, the PNC shaly sand interruption technique used to determine water saturation provides estimates of this same information, if specific elemental data is not available from other sources such as openhole logs and core analysis.

To provide one brief example, wireline PNC data has been used to determine gas pressure. In particular, gas zones were detected in a shaly-sand interval with an average sigma of 17.7 cu. The water saturation was calculated to be about 35% in the interval. Based on the volumetric constitutions in this zone, the model indicated a hydrogen index of about 25, which translates to a gas pressure of about 7000 psia. The measured bottomhole pressure was 7040 psia. That is, the techniques of the present disclosure enable a fairly accurate estimation of the gas pressure in shaly sand zones. In addition, the same measurements can be used to estimate the density of a liquid within the formation242matrix using a similar approach. In particular, the water and oil saturation can be analyzed from the petrophysical and PNC-type data, and the oil density collated with the hydrogen index estimate.

Technical affects of the present disclosure include the identification of gas in difficult areas for gas zone identification, such as layer sand/shale environments and other similar materials (e.g., shale, sandstone, dolomite, and/or carbonate). In such environments, the presence of gas is believed to reduce the sigma and porosity values conventionally measured by PNC-type tools. However, the porosity can be decreased by inter-granular calcite cementation and/or shale content which appear to be similar in log response to a gas zone. As such, the gas detection measurement GasIDformula can enable, among other things, distinguishing gas-filled formations from low-porosity formations in highly laminated, shaly sand environments. The gas detection measurement GasIDcan also be used with any PNC-type data set in real time or can be used to reprocess data in a playback mode to identify potential gas zones. Moreover, the gas detection measurement GasIDcan provide a qualitative indication of the gas density and pressure environment when combined with other conventional log data.