Gas Liberated by Drilling
The gas that enters the mudstream as a direct consequence of drilling is termed liberated gas (Mercer and McAdams 1981) in order to distinguish it from produced gas, which enters the annulus out of rock formations exposed in the wellbore; from recycled gas, which is carried into the borehole by circulating mud; and from contaminant gas, which is introduced in the mud stream as a consequence of such actions as using an oil-base mud or adding diesel to a water-base system.
The total volume of gas available for liberation from any drilled increment of rock will be in proportion to (1) the volume of rock drilled, (2) the porosity of that rock, and (3) the gas saturation within that porosity ( Figure 1 , Drilling and rock parameters that determine the volume of liberated gas in the drilling mud for any unit of time).
The process of gas liberation as a consequence of drilling, however, will be neither instantaneous nor complete. Grinding action at the bit cannot expose all pores to the mud system. In addition, the hydrostatic pressure of mud at the bottom of the borehole will commonly be slightly greater than fluid pressure within the rock pores. Thus, much of the gas in exposed pores will be held in place in the cuttings.
Following the grinding action of the bit, further liberation of gases and liquids occurs throughout uphole travel as residual fluid pressure in the cuttings overcomes decreasing hydrostatic containment of the mud. It may continue at surface, as shown by bleeding cuttings. Gas confined within isolated pores, however, will remain in place during uphole travel unless increasing pressure differentials cause fractures to develop in the cuttings.
It is important to remember that the overall composition of the liberated gas that is sampled by the gas trap at surface will be related to — but not the same as — the gas originally in place in the formation, the gas retained within cuttings porosity, and the gas dissolved in pore water and oil. All will have been modified by phase and solubility changes that occurred with uphole temperature and pressure changes and, therefore, cannot be equated directly to conditions at depth.
Influx and Flushing
Fluid flow can occur between the mud system and borehole wall rock at any place along the uncased well annul us where differential pressure and formation permeability are adequate. Influx
occurs when hydrostatic pressure is low enough to permit formation fluids to enter the well bore; flushing
occurs under reciprocal conditions ( Figure 2 , Borehole and mud conditions affecting cuttings and mud gas before arrival at surface).
Consequently, the rate of influx or flushing across the wellbore interface depends principally on the interrelation of two factors — pressure and permeability. In holes where pressures are close to balance or permeabilities are insufficient to sustain a major flow, only minor movements of fluids can be expected across the borehole interface. If pressure differentials are high or permeabilities are great, large incursions of produced gas, oil, and water can enter the mud system ( Figure 3 , Influx and flushing in the wellbore), or conversely, mud and filtrate can enter and flush the formation.
Where high pore pressures cannot be released from impermeable lithologies like shale, the rock can fracture or spall causing caving, sloughing, or collapse of the borehole ( Figure 4 , Common causes of uphole modification of drilling mud. Factors include influx of produced gas from underbalanced permeable intervals and cavings from overpressured impermeable intervals). Overpressured zones may respond in this manner if adequate mud overbalance is not maintained.
Together, produced gases, fluid incursions, and cavings entering from the borehole wall can be added to mud circulating surfaceward in the well annul us. The admixture of fluid influxes and rock cavings can cause serious discrepancies in formation logging data and affect interpretations.
As we have indicated, produced gas, oil, and water incursions may influx at any point from the bottom of the borehole to the casing shoe of a previously set casing run. Influx may result from a small sustained mud underbalance; this will yield a low continuous feed to the background gas reading. Alternatively, influx may result from a major underbalancing event of short duration (e.g., lifting drillpipe during a connection or trip). This results in a single large gas "show" at surface occurring at a predictable lag time after the underbalancing event. These short-lived incursions into the wellbore and mud system are called connection gas or trip gas.
To control influxes and at the same time prevent formation flushing and damage, it is good drilling practice to maintain a mud density sufficiently high to slightly overbalance formation pressure. This is balanced drilling.
If overbalance is not adequate, large fluid incursions can occur when high pressure gas, oil, or water zones are penetrated. Since these fluids are less dense than drilling mud, their presence in the borehole will lower the hydrostatic pressure further and worsen "underbalance." Eventually, there can be an uncontrolled fluid flow into the borehole and an expulsion of drilling mud at surface.
Expulsion of mud up the borehole is called a well kick.
If a strong kick is not controlled by closing the blowout preventers, all of the mud will be expelled from the annulus and formation fluid will flow freely to the surface, possibly resulting in a fire or explosion. This is a blowout. Consequently, an important function of modern formation logging is to monitor mud gas level, mud density, mud flow into and out of the hole, and mud volume in the pit in order to have early detection and alarm in case of a well kick.
When a well is consistently overbalanced, fluid flow or flushing will occur from the borehole into the rock. To prevent deep invasion and damage to formations adjacent to the open borehole, clay solids are incorporated in drilling mud. These particles filter rapidly from flushing muds to form a thick impermeable filter cake on the borehole wall for all but the most permeable formations. When the latter condition is present, lost circulation can occur. Halting this type of influx may require the addition of very coarse and platy "lost circulation material" (LCM) to the drilling mud. Needless to say, this type of addition means that formation logging may, at times, have to take into account LCM contaminants put deliberately into the mud system at surface.
Below the face of the drill bit, flushing is continuous. Filter cake cannot form under the crushing action of bit teeth and the jetting action of high velocity mud. If a very permeable formation is drilled, flushing action may be so great that mud totally displaces all original formation fluids ahead of the bit ( Figure 3 ). When such permeable rock is drilled and carried to surface, the cuttings will contain only mud filtrate. All traces of formation gas and oil will be lost. This may obscure a potential reservoir.
Total flushing such as this seldom occurs except when permeable zones are extremely thin and confined by impermeable beds. Individually, such thin permeable zones rarely contain commercial quantities of gas and oil. If the permeable zone is thicker, then it is possible that the pore fluid flushed back into the rock may be cycled back into the borehole behind the bit and its zone of turbulence. The effect of this can be that the top of the permeable zone will, from its gas show, appear to be a few feet deeper than other evidence (e.g., ROP break, cuttings porosity) indicates ( Figure 3 ).
Sample Lag
As we have just described, the mixture of gas, oil, water, and cuttings in the circulating mud travels from bit to surface along the well annulus. Furthermore, experience shows that during this uphole journey some mixing and preferential settling will occur ( Figure 2 ). However, the viscosity and gel strength of modern drilling muds will maintain a reasonably good order of sample arrival at surface and hold together fluids and solids from a particular drill depth. These representative samples, then, can be projected back to their true drill depth and rock source if uphole transit time, or lag time, is known.
Lag time for both cuttings and fluids is generally determined by a two-step process: (1) the addition of a tracer into the downhole side of the mud circulating system, and (2) the detection of the tracer when it returns to surface on the uphole side ( Figure 5 , One calculation is necessary to compensate for the number of pump strokes required to pump the tracer down the inside of the drill pipe). Tracer material can be any substance, like gasoline or chopped-up rubber bands, that can be detected analytically or visually upon arrival at surface.
The tracer method of lagging is consistently more accurate than that of volumetric or flow calculations based upon pump displacement plus bit, collar, and pipe sizes. This latter arithmetic calculation method cannot readily account for unpredictable hole enlargements, overdrill beyond bit size, and changes in pump output efficiency. However, a combination of tracer lagging and mathematical lagging can give a fair indication of hole condition. If the calculated lag is significantly shorter than the tracer lag, wall sloughing or washout can probably be inferred ( Figure 6 , Determining borehole washout by comparing the difference between calculated lag time an dtracer-test lag time).
It is sound practice to have tracer tests start early in any drilling program. This permits the combined characteristics of mud pump, tophole, and circulating system to be accounted for, so that down-hole conditions can be evaluated as they develop during drilling. It is also sound practice to have tracer tests run on a systematic basis, such as at the beginning of each shift or at predetermined depth increments. It also is routine to run a tracer test when drilling is resumed after a trip.
The most commonly used tracer is calcium carbide, a manmade crystalline solid that reacts spontaneously with water to form acetylene gas:
CaC2 + 2H2O Ca(OH)2 + C2H2
Calcium Carbide + Water Calcium Hydroxide + Acetylene Gas
Procedurally, a small packet of calcium carbide is dropped into the top of the drillstring when the kelly is unscrewed from the pipe to make a connection. As drilling resumes, the material is forced down the drillpipe by circulating mud and then out into the borehole through the jets at the bit. Upon circulating back to surface in the mud, the acetylene gas generated is routinely detected by the mud logging gas detector. Because acetylene is not encountered as a natural product during drilling, its occurrence and detection characteristics, as we note farther on in this unit, cannot be easily confused with a true gas show.
A further consideration in lagging with calcium carbide should be the use of the same amount of tracer in each lag test; subsequent variations in response at the detector can be used to evaluate changing efficiency of the gas trap and sensitivity of the detector. This variation becomes important when gas show data are normalized so they can be compared with one another.
In practice, lag time established by the tracer method is expressed as the number of pump strokes required to move mud from the bit to surface. This is determined by counting the total number of pump strokes required for the tracer's round trip and then subtracting the calculated number of strokes needed to carry the calcium carbide down the inside of the drillstring to the bit. Because the inside diameter of the drillpipe can be accurately determined, very little error is introduced into lagging by this one calculation.
Use of pump, or lag, strokes provides automatic correction in lag time for varying pump speeds and for periods when pumps are turned off, as when making a connection. Sampling of a particular depth or event, in other words, can be predicated on a specific number of pump strokes after that depth is penetrated or that event, such as an ROP break, has occurred.
Lagging is a simple matter when two stroke counters monitoring the same pump are used. One counter is set as "pump tally"; the other is set "lag strokes" behind. When a depth is reached or an event occurs, the numbers on the tally counter are recorded. The sample of the depth or event is taken when the lag counter reaches the recorded number. The only additional step that needs to be made when two counters are used is to add a predetermined number of lag strokes for each few feet drilled. This, of course, is because transit time from bit to surface increases progressively as a hole is deepened.
Once verified lagging has been established, minor adjustments can be made between tracer runs, if deemed necessary, by comparing current lag stroke count with sample arrival from known bottomhole events. A sharp drilling break due to marked change in rock type is one usable event. Connection gas arrival can also be used if the gas is coming from the bottom of the hole and not from uphole influx.
Phase and Volume Changes During Uphole Travel
In traveling from hole bottom to surface, rock debris, natural fluids, and circulating mud experience great changes in temperature and pressure conditions. Mud temperature may decrease by as much as three degrees centigrade for each hundred meters of upward travel (1.65° F/100 ft). In a 3000 m well (about 10,000 ft) this change can exceed 90º C (165º F) It is possible that under this cooling effect, compounds that are gaseous or liquid at depth may change phases and liquefy or precipitate, respectively, with uphole travel.
Pressure changes during uphole travel are also extreme. Hydrostatic pressure in the borehole is a function of the mean density and vertical height of the fluid column:
Ph = f Dv K
where:
Ph = hydrostatic pressure, KPa or psi
f = fluid density, kg/m3 lb/gal
Dv = vertical depth, m ft
K = unit conversion 0.0098 0.0519
From this hydrostatic pressure equation it is apparent that pressure (Ph) will decrease proportionally with vertical depth (Dv) (i.e., pressure is halved if depth is halved). We also know from the gas laws that pressure and volume are inversely proportional. Thus, with each halving of depth in travel to surface the volume of gas will double.
The combined result of temperature and pressure change, as governed by the gas laws, is shown in Figure 7 ( Changes in volume of gas at surface as a consequence of changes in normal pressure and temperature conditions during uphole travel). It can be seen that even low porosity and low gas saturation in rock at depth can produce a very large gas show at surface. Careful monitoring is necessary to discriminate between gas influx or well kick due to underbalanced drilling and the arrival of a large volume of gas-aerated mud resulting from penetration of a gas-bearing zone. To be effective then, gas monitoring must include consideration of ROP and lithology factors (e.g., porosity and permeability).
Hydrocarbon Gases
Hydrocarbon compounds, by definition, include only those made up entirely of hydrogen and carbon. Hydrocarbon gases are the simplest compounds contained in petroleum. They consist almost wholly of individual or short chains of carbon atoms with hydrogen atoms attached to all remaining available bond positions ( Figure 8 , Classification of hydrocarbons: composition of common hydrocarbon gases). They are classified as alkane hydrocarbons.
The fundamental characteristic of all alkane hydrocarbons is that the carbon chains are saturated with hydrogen. Carbon chains may be straight, branched, or cyclic; these patterns form the basis for three series of alkanes ( Figure 9 and Figure 10
, General categories of saturated straight-chain, branched-chain and closed-chain hydrocarbons and unsaturated hydrocarbons).
In mud logging, we are mainly interested in the five lightest alkanes (C2-C4), all of which remain in the gas phase at nearly all ambient temperatures. Various heavier hydrocarbons compounds (C5, C6) ( Figure 9 , Figure 10 and Figure 11 ) also may be present in mud gases and gas shows if the ambient surface temperature is high enough to prevent them from condensing in the mud-logging vacuum system. These also may be plotted on mud logs.
Because hydrocarbons represent carbon in a reduced form, they are all combustible — they react with oxygen, producing carbon dioxide, water, and energy in the form of heat. The oxidation reaction can be expressed in the general form:
Descriptively stated, this means that the quantities of carbon, hydrogen, and oxygen consumed and carbon dioxide, water, and energy produced will depend upon the number of carbon atoms (x) and hydrogen atoms (y) in the hydrocarbon molecules that are oxidized. Consequently, if a mixture of hydrocarbons is burned in oxygen, the total energy produced will be directly related to the individual molecular types present and the relative concentrations of each in the mixture. In other words, the amounts of carbon and hydrogen present to be oxidized determine the energy produced. This energy and some specific combustion products form the basis for the two most common methods of detecting hydrocarbons in mud gas-catalytic combustion and flame ionization.
Gas Sampling
Once mud gas reaches surface a portion of it enters the sampling and analytical cycle. Here, additional variables (e.g., extraction efficiency, ambient conditions) come into play that can affect the final analytical results. The two principal mud gas collecting mechanisms used in conventional mud gas logging are the gas trap sampler and the steam still sampler. A third collecting apparatus, the cuttings gas sampler, is used to extract gas retained in the cuttings arriving at surface. Although cuttings gas is not obtained totally from the mud system, it is analyzed in the same manner as mud gas and often used in conjunction with it as part of a full formation logging program. As such, cuttings gas also can show up in Track Three or Four if the analysis is not part of a separate geochemical program.
Gas Trap Sampler
The first separation step in continuous combustible gas logging is taken at the gas trap. The principal objective of this trap is to extract a relatively consistent gas sample from the mud for continuous analysis.
The typical gas trap is housed in a rectangular or cylindrical metal box installed in the flowline or ditch. In one style of gas trap ( Figure 1 and Figure 2 , Standard gas trap configurations), an internal impeller (1) draws mud into the trap through an upstream port, (2) agitates it to lower its viscosity and free the entrained gas, and (3) discharges it through a downstream port. In another common style ( Figure 3 , Schematic of baffle-type gas trap), returning mud is cascaded down a series of baffles so that gas is released. The former type provides more consistent sampling because it is less affected by varying mud return rates and viscosities.
In both types of gas trap, ambient air enters the trap above mud level and, with the freed gas, is drawn through a moisture trap and vacuum line to the mud-logging unit. Here the sample passes through filtration and further drying steps and is routed and metered to various gas detectors and analyzers ( Figure 4 , Schematic of mud gas flow system, from gas trap through analysis in the mud log unit).
Steam Still Sampler
A supplementary means of intermittent gas sampling that is sometimes used at the wellsite is the steam or vacuum mud still (
Figure 5 , Steam still with mud chamber atop heating unit). For this technique, a sample of drilling mud is caught by hand at the flow line and returned immediately to the logging unit. For gas extraction, the sample is placed in a flask, heated by steam discharge, and placed under vacuum in order to remove all volatilized hydrocarbons. Following cooling and drying, the extracted gas is analyzed by routine mud gas techniques.
Extraction efficiency is very high in the steam still technique; however, the procedure also is time-consuming and may require an additional operator to carry out repetitive analysis. Consequently, the mud still's principal use in most conventional logging programs is to add supplemental information to the evaluation of a specific drilled interval, such as an oil or gas show. It generally is not considered a replacement for the gas trap technique. Systematic use of the still while drilling, however, can provide a baseline for recognizing changes in gas trap efficiency and assisting in the normalization of analytical data from samples taken at the gas trap. The still probably provides the most representative mud gas sample because of its extraction efficiency; as such, it should be weighted heavily when mud gas compound ratios are used to interpret formation fluids at depth.
Cuttings Gas Sampler
The general method used to sample gases still retained within cuttings is to place the cuttings in a closed container, mechanically disaggregate the sample, and then draw off the liberated gas. The most common configuration for a cuttings gas sampler is a blender jar with a cap fitted with gas-sampling tubing ( Figure 6 , Cuttings blender, vacuum tubing and gas detector and Figure 7 , Schematic of cuttings gas analytical flow system).
Procedurally, about one cup of fresh cuttings is taken at the shale shaker, placed in the blender, covered with an equivalent amount of clean water, and blended for a specific number of seconds, generally up to two minutes. The shattering action of the blender blades physically breaks the cuttings down so that all pore walls are fractured and contained gases are liberated.
Once the gas is liberated and available for sampling, it can be processed in the manner of any gas batch sample. Typically, a measured amount of gas is drawn off by vacuum and analyzed. The type and completeness of the analysis (e.g., total combustible gas, individual compound types) will depend upon what uses and comparisons will be made with the analytical data.
Gases contained within cuttings are the most reliable mud-borne samples routinely available at surface to indicate original, if not complete, fluid content at depth. These may be very important in locating the top or bottom of show zones or in detecting first occurrences and trace components. Cuttings gas data can also have application in estimating changes in effective permeability and rock porosity when compared with mud gas data.
The principal limitation of cuttings gas sampling is that, characteristic of all intermittent or batch samples, it is not continuous. In general, it seldom represents sample density any closer than that used for lithologic descriptions. In addition, if an oil-base mud is used, or contaminants are present, these must be rinsed from the cuttings sample prior to blending. This can affect the validity of the analytical data.
Gas Detection and Measurement
Mud gas detection techniques generally are based on a single diagnostic chemical or physical property of a gas molecule. This means that not all gases can be detected by the same technique. This can be easily recognized if we remember, for example, that not all compounds are combustible, or fluoresce, or react with acid. Therefore, each detection technique used in mud logging has specific capabilities and limitations. The combinations of different techniques used by different logging companies generally reflect what their experience has shown to be an effective balance between detection level, reliability, and cost.
Hydrocarbons, as we noted, give off heat and reaction products when burned. The amount of each depends almost entirely on the specific hydrocarbon molecules present. By measuring one of these combustion products it is possible to approximate or quantify the nature of the original hydrocarbons. This approach is the basis for catalytic combustion and flame ionization detection used while logging for combustible gases.
Two other properties commonly used in mud gas detection are based on properties unrelated to combustion; these are thermal conductivity and infrared absorption. Because such properties do not rely on any oxidizing (or reducing) reactions, they are often used to monitor mud gas mixtures that also contain nonhydrocarbon gases; these include dangerous and undesirable gases like hydrogen sulfide and carbon dioxide.
Catalytic Combustion Detector (CCD)
The original mud logging gas detector, and one still widely used in conventional mud logging, is the catalytic combustion, or "hot wire," total gas detector. In this device, the filtered and dried gas sample is passed continuously, at a controlled flow rate, through a combustion chamber containing a heated platinum filament. Filament voltage is adequate to induce total combustion in that small portion of the gas stream that comes into contact with the catalytic platinum surface. In practice, as we discuss below, catalytic combustion detectors may be run in pairs, with the second unit set at a cooler, lower voltage so that combustion of methane does not occur. This produces a "petroleum vapors," "heavies," or, as referred to in this reference, wet gas detector.
An advantage of catalytic combustion is that a uniform, proportional reaction rate is maintained across a normal range of combustible gas concentrations in drilling mud (up to about the equivalent of 6% methane). This yields nearly linear signal response for most hydrocarbon/air mixtures coming from the gas trap and provides good sensitivity to extremely low gas concentrations.
Measurement of hydrocarbon gas content in a sample is obtained in the following manner in a catalytic combustion detector. The platinum filament forms one resistance arm of a Wheatstone bridge circuit in balance with three other arms ( Figure 1 , Schematic of a Wheatstone bridge used as a catalytic combustion detector). When catalytic combustion occurs, energy in the form of heat is liberated in proportion to the content of hydrocarbons (hydrogen and carbon atoms oxidized) in the sample. This, in turn, heats the platinum filament and increases its electrical resistance proportionately. The bridge circuit is unbalanced by this change in resistance and the resultant electrical potential across the bridge can be measured and calibrated in terms of combusted gas concentration.
In mud logging, output from the catalytic combustion detector typically is routed to one or more of three devices: integrator meter, strip chart, and integrator/digital recorder ( Figure 2 , Typical hydrocarbon detector with strip chart recorder. Instruments for monitoring lag time, position of bit, and mud pit volume are incorporated in this detector panel). Generally, the meter is used to monitor the continuous operation of the detector; needle limits are set to sound a signal if gas readings go significantly above background, providing an audible "gas show" alert. The strip chart becomes a continuous trace of gas concentration against sample time and provides a permanent visual record of detector response. It is also used to estimate periodic averages or pick the highest concentrations to be plotted on the formation log. The digital recorder has storage and printout capabilities that find most use in modern systems incorporating computer handling of data.
Let us look briefly at the catalytic combustion detector as a total gas detector. In this higher-voltage, "hotter" configuration, the detector is nondiscriminating. It will respond to all combustible gases, including gaseous hydrocarbons, rare appearances of naturally occurring hydrogen, and acetylene used as a lag-time tracer. Consequently, its single output will depend upon both the concentrations and the compositions of gases reacting at the catalytic "hot wire" surface.
Because heat of combustion and consequent detector response increase with higher concentrations and molecular weights of the hydrocarbons present (Table 1., below), the catalytic combustion detector sums this effect; thus the name total gas detector. Its response may, to a degree, be considered a "richness" indicator. That is to say, an increase in detector response may indicate an increase in gas concentration, an increase in gas molecular weight, or both.
Table 1. Minimum Ignition Temperatures for Various Gases
Gas | TemperatureoC | Ignition Voltage, volts |
Methane | 632 | 0.9 |
Ethane | 520 | 0.6 |
Propane | 481 | 0.45 |
Butane | 441 | 0.3 |
Hydrogen | 580* | 0.2 |
*In the presence of a platinum catalyst, hydrogen will react vigorously with oxygen at much lower temperatures.
As we noted, some conventional logging units may be equipped with a wet gas detector; this is a catalytic combustion detector similar to the total gas detector but operating at a lower bridge voltage and cooler filament temperature. At the lower temperature ( Figure 3 , Response of catalytic combustion (hot wire) detector to different concentrations of hydrocarbon gases. The maximum response of each gas represents the approximate concentration at which that gas reaches saturation with oxygen in air, and above which complete combustion cannot occur), the platinum does not provide sufficient energy to induce combustion of methane; ideally the filament will only detect the presence of heavier gas hydrocarbons like ethane, propane, butane, and isobutane. However, if the combustion effect of the heavier gases passing across the filament is large, surface temperatures may become adequate for some combustion of methane. This is one source of error in the low-temperature configuration.
You are reminded that neither type of detector can be calibrated to measure absolute gas concentrations in the gas/air mixture. This is because more than one hydrocarbon compound type generally is present. Consequently, for total combustible gas logging, catalytic combustion detectors are calibrated to a reference gas. This means that detector output is in units equivalent to the combustion of a specific concentration of a single gas.
The most commonly used calibration gas mixture for total combustible gas logging consists of one percent methane in air (i.e., equals 1% EMA). Using such a standard calibration gas, detector output is generally reported and plotted on the formation log as Total Combustible Hydrocarbons: % EMA or Wet Gas Hydrocarbons: % EMA ( Figure 4 , Total combustible gas track).
Some contractors report mud gas in total gas units. These units generally are specific to a particular type of detector design and calibration gas mixture. If total gas units are used on a mud log, it is advisable to have conversion information recorded on the log heading, (e.g., 100 total gas units = 2% EMA total combustible hydrocarbons). This may be essential when attempting to normalize and correlate responses with other mud logs and is the type of performance level that can be required through contractual specifications or confirmed at the prespud meeting.
Catalytic combustion detectors are not without their limitations. At high gas concentrations, in excess of 6% EMA, the catalytic combustion detector begins to lose linear response; at about 10% EMA, the mixture becomes saturated with hydrocarbon gas and has insufficient oxygen available to induce complete combustion (i.e., air is about 21% oxygen and two units of oxygen are needed to combust one unit of methane: CH4 + 202 CO2 + 2H2O). However, saturation can occur much below 10% total gas (i.e., propane: C3H8 + 5O2 3C02 + 4H20) because we are dealing with methane equivalents, not gas concentrations. Heavier gases require more oxygen per molecule of gas to burn completely ( Figure 3 ). Above 10% EMA concentrations it is necessary, therefore, to dilute the gas sample prior to introduction into the combustion chamber. Dilution results in a progressive loss of accuracy for each decrease in sample size. It is commonly accepted that valid response of a catalytic combustion detector is lost with the level of dilution necessary to accommodate a gas over 40% EMA.
Another limitation related to oversaturation can occur with a catalytic combustion detector operating in the lower temperature, wet gas configuration. An abundance of heavier hydrocarbons in the rich gas mixture may cause the detector to give a greater response than a total gas detector sensing the same mixture. Therefore, a negative difference in measurement between total gas and wet gas is given. A total being less than any of its parts is of course, impossible and is simply a reflection of a greater response to the abundance of larger molecules being selectively combusted as methane is ignored.
A more serious disadvantage of the catalytic combustion detector is that the effectiveness of the catalytic surface declines progressively over the lifetime of the filament; this decreases its sensitivity correspondingly. Twice daily recalibration of the detector and regular performance checks are recommended by many users to assure reliable performance. The response of the detector to acetylene lag gas returning uphole should also be used to check for declining sensitivity.
As a further limitation, the presence of certain "catalyst poisons," such as silicon compounds, hydrogen sulfide, or leaded gasoline used as a tracer, may even totally deactivate the detector in a matter of minutes. Because of this, many catalytic combustion detectors have scavenging systems, such as charcoal filters in the gas flow line, to remove deleterious gases. This should be remembered when using the mud gas flow line to supply other analytical equipment.
Flame Ionization Detector (FID)
Unlike catalytic combustion, the flame ionization detector requires complete combustion of the mud gas sample. This is assured at all concentrations by mixing a small amount of the continuous mud gas stream into a completely combusted hydrogen flame.
Detection depends upon a specific ionization process that takes place when compounds containing carbon-to-hydrogen (C-H) bonds burn in a high temperature flame. This process involves the formation of unstable negative alkyl (alkane functional groups) ions and positive hydrogen cations as an intermediate step in the combustion process:
2H2 + O2 2H2O
Hydrogen Flame
CH4 H+ + CH3
Methane Molecule Hydrogen cation Methyl Anion
Both the methyl (alkyl) anion and the hydrogen cation are violently unstable and under "open-air" circumstances would rapidly combust with oxygen to form the normal reaction products of carbon dioxide and water. However, in the flame ionization detector, a cylindrical anode surrounds the flame (
Figure 5 , General features of a flame ionization detector. Note the position of the anode probe/collector cylinder for gathering anions and the cathode probe for collecting cations. The electric potential between the two probes is a proportional measure of hydrocarbon combustion occurring in the detector flame). The methyl anion (-) is attracted to this anode (+) where it discharges an electron and becomes a neutral methyl radical. The radical then undergoes complete combustion. Similarly, the hydrogen cation (+) becomes neutralized by gaining an electron at the grounded combustion chamber cathode (-) wall before combusting further. When the anode and cathode are held at the correct electrical potential, all ions produced are captured within the detector. This ion flow completes an electrical circuit and appears as a current flow that is measured by a sensitive meter device ( Figure 6 , Schematic of basic flame ionization detector circuitry). The current flow is directly proportional to the volume and types of hydrocarbons in the sample. The output of the detector is amplified to produce a signal that is sent to a meter, plotter, or integrator/recorder in the same manner as for the catalytic combustion detector.
The flame ionization detector, as implied above, responds both to the concentration of hydrocarbons present and to the number of breakable carbon-hydrogen bonds within them. In other words, flame ionization detector response is a richness indicator much like that of the catalytic combustion detector because it sums both concentration and composition. For this reason, its output is also standardized to, and expressed in, % EMA.
The flame ionization detector yields more uniform and linear richness readings and is less subject to progressive loss of sensitivity than the catalytic combustion detector. It also has greater sensitivity to very low concentrations. In addition, it will not respond to the presence of hydrogen gas in the mud stream. However, it is the less rugged of the two detector types and is more susceptible to malfunctions under normal wellsite conditions. Daily or more frequent calibrations with a gas standard are recommended to compensate for electronic baseline drift.
Thermal Conductivity Detector (TCD)
The thermal conductivity detector may be thought of as a catalytic combustion, or "hot wire," detector operating in reverse ( Figure 1 ). This detector consists of a similar Wheatstone bridge circuit, but by using either a tungsten filament or a very low filament voltage, combustion is prevented. In this case, filament temperature and bridge potential will depend on the ability of the mud gas sample to cool the filament as it passes over the heated metal surface. (This cooling effect is also present in the catalytic combustion detector but is very small compared to heat of reaction; it is effectively adjusted out for low gas concentrations when the instrument is set for "zero" gas.)
Thermal conductivity, that is cooling effectiveness, of a particular gaseous compound depends upon the molecular kinetic energy of the gas. This property depends inversely upon the molecular weight of the gas ( Figure 7 , Properties of mud gases, particularly as related to thermal conductivity detectors). Stated another way — the lighter the gas, the more kinetic energy present and the greater the cooling capacity. Methane, having a lower molecular weight than air, for example, will have a substantially greater cooling effect. Therefore, in a pure methane-air mixture, like a standard, the higher the methane content the greater the "positive" (or cooling) response on the detector. This effect is linear with methane concentration and may be so calibrated in % EMA. The fact that linearity extends to 100% concentration makes it a good detector to supplement catalytic combustion detection for high methane concentrations.
As might be anticipated, the thermal conductivity detector responds poorly to heavier hydrocarbon and noncombustible gases. These may even give a "negative" response when their cooling is less effective on the heated filament than pure air or other carrier gas. Conversely, low molecular weight hydrogen and even non-combustible helium have a thermal conductivity response greater than methane. In overall performance, the thermal conductivity detector is the least sensitive of those discussed to this point.
Obviously, the thermal conductivity detector, while ideal for detecting concentrations of a single gas and carrier gas mixture, is too unpredictable in response to be used routinely as the sole detector on the mud gas mixtures coming from the gas trap. As suggested above, this technique finds a common mud-logging use in the detection of very high concentrations of methane; it also is used in the detection of noncombustible gases like carbon dioxide after they have passed through purifying steps.
Infrared Absorption Detector (IRAD)
One additional instrument, the infrared absorption detector, may be used in mud gas logging ( Figure 8 , Schematic of a modern infrared analyzer. The basic concept is to alternate infrared energy of a predetermined wavelength through parallel optical cells (sample cell and comparison cell) and detect the change caused by the sample). The IRAD has been applied recently to hydrocarbon detection, with limited success. The principle of the measurement, whether for detecting hydrocarbon or other compound types, depends upon the fact that any one type of chemical bond within a compound will absorb infrared energy of one particular wavelength. If a gas sample is irradiated with that specific wavelength of infrared energy, the energy should be absorbed in proportion to the number of those bonds present, and, therefore, be a method of detection and measurement.
In practice this does not work accurately for hydrocarbons; all C-C bonds are similar but not identical. The same is true of all C-H bonds. For this reason, there are not two discrete peaks of infrared absorption for hydrocarbons but continuous bands of overlapping absorption wavelengths. These bands do not allow precise determination of hydrocarbon concentrations.
The most effective use of infrared absorption in mud gas logging is for the detection of single gases, specifically carbon dioxide. This is followed by determining concentrations of single pure hydrocarbon compounds after separation by chromatography. When applied to hydrocarbon mixtures it is less effective in estimating total hydrocarbons (% EMA) and light/ heavy ratios than dual voltage catalytic combustion detector systems. Because it responds to nonhydrocarbon gases as well, it is seldom used to replace combustion detectors.
Gas Compound Separation
Gas chromatography is the principal separation method used in mud logging. Infrared absorption, when narrowed to a specific wavelength, also can be used in mud logging to discriminate among and monitor the presence of a few selected individual compound types; most common, as we have said, is carbon dioxide.
Gas Chromatography (GC)
Chromatography is a separation method in which a complex mixture is passed through a medium that retards individual compound types at different rates ( Figure 1 , Basis of gas chromatography). The retardation or retention rate depends upon the specific chemical and physical character of each compound type relative to the medium. Procedurally, the mixture passes along a conduit in a mobile (gas or liquid) state. Identical compounds in the mixture are retarded at the same rate by the fixed-state medium, become grouped together as waves, and ultimately exit the conduit at the same time as a surge. A detector sensitive to that compound makes an accurate measurement of the quantity in the surge.
A variety of chromatographic procedures are available, but the technique commonly used in mud logging is, as we stated, gas chromatography. In this, the compounds to be separated are carried in a gas phase through tubing in which separation occurs. The tubing, or "chromatographic column," can have an exceedingly small internal diameter that is coated with a retarding liquid or can be of larger diameter and packed with porous material soaked with retarding liquid.
The choice of the carrier gas that moves the sample through the chromatographic column is determined by the compounds to be separated, plus the type of detector to be used. If feasible, a carrier gas is chosen to which the detector is insensitive.
In gas chromatography, the column is heated and maintained at a constant temperature. Heating the column speeds up the elution time, thereby allowing a greater number of chromatograms to be obtained during a fixed interval of time, while maintaining the column at a constant temperature "fixes" retention time so that it does not vary between samples. Consequently, component identification remains a direct function of analytical time. Maintenance of constant temperature is essential when the analytical instrument uses an integrator/recorder for data output and compound identification.
In practice, mud-logging gas chromatography encompasses four sequential steps: (1) sample collection, (2) sample injection, (3) chromatographic separation, and (4) compound detection. These are carried out with the sample flow loop, batch sampler, separation columns, and detector.
Sample Flow Loop-This unit collects the mud gas sample. Collection is done by splitting off a portion of the gas coming from the gas trap in the mud gas vacuum system. The diverted portion is passed at a controlled rate and pressure into a continuously refreshed flow loop.
Batch Sampler- This unit isolates the gas sample to be analyzed and triggers the separation phase. Periodically the sampler takes a representative gas sample from the sample flow loop and "injects" it into the chromatographic column to start the analysis. This sampling and injection step is repeated every few minutes as each full analytical cycle is completed.
Separation Columns- This assemblage is the heart of the gas chromatograph. For efficiency, most mud-logging gas chromatographs contain two columns. This permits one column to perform a separation while the other is being backflushed, cleansed, and prepared for its next separation cycle. Two columns also permit two different separations or analyses to be performed alternately.
Detector- After chromatographic separation, the components of interest pass to a suitable detector in predictable order. Each component arrives as a nearly pure sample and may be both identified by its sequence or time of arrival, and quantified by its detector response. Catalytic combustion or flame ionization detectors are commonly used when only the presence and concentration of hydrocarbons are being determined. Thermal conductivity or infrared detectors have more general applications although, as discussed in the text, they are less sensitive in many situations.
An example of two columns set up to make different separations for analysis is offered in Figure 2 (Schematic of a gas chromatograph set up for two-column operation). It is common to make alternating analysis of (1) the lightest combustible gases, hydrogen and methane, by separating them with one column and (2) the combustible gases, methane (plus hydrogen), ethane, propane, isobutane, and butane, by separating them with the other ( Figure 3 , Separation of hydrogen and methane;
Figure 4 , Separation of light hydrocarbon gases (note effect of nitrogen carrier gas);
Figure 5 , Separation of light hydrocarbon gases (note effect of helium carrier gas);and Figure 6 , Separation of light hydrogen gases (note effect of hydrogen sulfide)).
As another example, the first, or primary, column can make a rapid separation of gases to be analyzed from those to be discarded ( Figure 7 , Schematic of gas chromatograph set up for dual-column operation). In this dual-column case, components for which the column was designed, like gaseous hydrocarbons, pass rapidly through the primary column and pass out of the system. Undesirable gases, like hydrogen sulfide, which may damage a detector, or light liquid hydrocarbons, which might contaminate a sensitive column, progress more slowly through the primary column and never reach its exit during this cycle. They are back-flushed and exhausted from the primary column after the separated gases pass into the other, secondary column to complete the full analytical cycle.
In each of these examples, separated components arrive as nearly pure samples that may be both identified by their sequence of arrival and quantified by their detector response. Catalytic combustion or flame ionization detectors are commonly used when only the presence and concentration of hydrocarbons are being determined. Thermal conductivity or infrared detectors have more general applications, although, as we have discussed, they are less sensitive in many situations.
Measurement of individual compounds is intermittent. This is because we are no longer looking at continuous monitoring of the same material, as is the case with total combustible gas analysis. Although a gas chromatograph detector may be providing output almost continuously, it is measuring values for different compounds as they occurred in batch samples taken every few minutes. Therefore, data, whether presented on a meter, a chart, or a digital record are values for a number of individual compounds, with only one value per compound for each analytical cycle. These can be averaged or plotted as points on the formation log, as with continuous total gas measurements.
Chromatographic systems are calibrated in the same manner as simple detector systems — by the use of a standard. In this case, however, the standard contains all of the compounds being measured, and in known amounts. For hydrocarbons, a typical standard consists of one percent of each of the five gases, methane, ethane, propane, butane, and isobutane, mixed with ninety-five percent nitrogen. When a standard is run, the response given by the detector for each compound is recorded and used to calibrate other percentage values for the individual compounds. Some operators require a three-point calibration; when this is carried out, two standards plus air are used.
A calibration cycle should be run at least once a day and also when sensitivity loss or drift is suggested by comparison of chromatographic data with total mud gas or lag gas readings. Care should also be taken in the use of the standard to assure that storage temperature has been high enough to keep all components in a mixed, gaseous phase.
Infrared Absorption Discriminator
In certain situations, it is not necessary to physically separate an individual compound type from a mud gas mixture in order to measure the quantity present. Some detectors can be made so specific that they become, in effect, compound separators. The current principal use of the infrared absorption detector is in such a configuration — the energy source is set for a single chemical bond. That makes it both a detector and a separator, or discriminator; the measurement of carbon dioxide concentration in mud gas samples, as we have said, is a common application.
Calibration of an infrared unit is generally by the use of two gases, one containing no gas to which the discriminator is sensitive — a "zero" gas, and one with a known amount of detectable gas — a "standard" gas. These two provide the baseline and reaction factors needed to set response values. Commonly a meter is used for continuous monitoring and a recorder to provide a permanent record. Output also can be linked to alarm systems and to on-site computer storage systems.
Gas Plots
Two general types of hydrocarbon gas plots appear on the formation mud log. One is the continuous summary type, which is typified by the total combustible gas plot shown on Track Three ( Figure 1 , Total combustible gas track). The other is the intermittent, individual-compound type, which contrasts values from batch sampling; these are found on Track Four of our example ( Figure 2 , Gas Composition track).
Each type has a variety of uses. The continuous plot, for example, provides a gas background level against which to plot shows, trip gas, connection gas, and feed-in from declining mud overbalance responses. The detailed plot, on the other hand, gives insight into changes in hydrocarbon character, such as an increase in propane and butane, which might be associated with an oil show or changing reservoir conditions.
In nearly all cases, however, the points plotted on Tracks Three and Four are representative values; because of vertical scale it is generally impractical, if not impossible to plot all analytical results on the formation log. Presentation and use of gas data generally dictate how the data will be plotted.
Presentation of Gas Data
As is true for the ROP data in Track One, of the formation mud log, all changes in gas volume or composition are plotted horizontally on Tracks Three and Four. In the case of gases, convention dictates that an increase in volume or relative concentration is plotted to the right. This means that factors which, for example, usually reflect increasing porosity on a ROP curve, will be depicted in the opposite direction on the total gas curve. A mirror image presentation then is established on opposite sides of a formation log, much as on many wire line logs.
As with Track One, horizontal scales can be either linear, logarithmic, or proportioned nonlinear. Current practice favors the latter two scales. These can show wide-ranging gas readings, which are common to mud gas logging, without requiring scale changes; at the same time they can show small variations at low concentrations, which also have significance in mud logging. Units selected for the horizontal scale of total combustible gas may be in % EMA or in arbitrary units that are equated to % EMA (e.g., 100 units = 2% EMA). These same units, plus parts per million (ppm), may be used for detailed hydrocarbon gas analysis data carried in Track Four.
When a comparative plot is used, as to depict gas wetness (% not methane), percentages of individual hydrocarbon gases within the analyzed sample are generally plotted on a linear scale. This type of plot shows relative changes in composition but gives no indication of quantity (i.e., combined gas measurements always equal 100%).
Data plots may be in bar graph or continuous curve format similar to ROP. In most cases, the same format will be used for Tracks One, Three, and Four of a single log so that visual comparisons and correlations are easily made.
Because most data points on a gas plot can represent a number of repeated analyses or a period of time of continuous analysis, the significance of a plotted point will vary depending upon the system used to select the plotted value. In some cases, the average or the mode for the number of analyses or length of period is plotted. In others, the highest reading within the same increment is plotted. For some plots, as connection gas, the value plotted may be the total reading or it may be only the value above background. The operator normally designates which values are to be plotted in light of their use and their compatibility with other formation logs from the area.
Characteristics of Gas Data
As gas data are compiled on the formation log during the drilling life of a well, a number of recurrent features become apparent ( Figure 1 , Total combustible gas plot from chart recorder with diagnostic features noted). Many, such as connection gas, lag gas, and down-time gas, result from drill-rig operations; others, such as background gas, are related to downhole changes in lithology.
Once the influences of relatively predictable factors on mud gas data are recognized, then identification and evaluation of unpredictable variables are practical. The two most significant anomalies are:
Gas Show — Any unexpected or anomalous increase in mud gas content. It may result from liberated gas, produced gas, recirculated gas, or mud contaminants. A "true" gas show is from liberated gas coming off bottom.
Increased Feed-In — Progressive increase in the amount of connection gas, down-time gas, or produced gas arriving at surface. This condition probably indicates a declining mud overbalance relative to a permeable open-hole zone.
Repetitive features that may be recognized and annotated on total combustible gas charts
· "True" Zero Gas or Air — The minimum reading obtained when only air is passing through the mud gas detector.
Zero Gas or Circulating Background Gas — The amount of gas present in a circulating mud system while the drillstring is off bottom, rotating, and undergoing no vertical movement.
Background Gas — The relatively consistent mud gas value measured while drilling through any uniform lithology at a uniform rate. The points plotted on the total combustible gas track can approximate this value if an average or mode is plotted.
"True" background gas values have a zero gas factor subtracted from the average or mode used.
Total Gas — The maximum reading during an interval, or the total reading at any one time. Individual points plotted on the total combustible gas track can be these values if no averaging is used for each interval. Total gas includes background gas and any other hydrocarbon gas present.
Connection Gas — The increase in mud gas above background level that occurs as a consequence of making a drillpipe connection. When the mud-circulating system is shut down to make a connection, gas influxing at depth will accumulate in the mud; this connection gas surge will arrive and be monitored at surface when circulated up after drilling resumes.
Generally a background gas value is subtracted from a connection gas measurement so that connection gas is plotted at this lesser value rather than at total reading. Connection gas should arrive one lag time interval after the connection is made if it is coming off bottom.
Survey Gas — The increase of mud gas above background level that results from influx when mud circulation stops during a directional survey.
Down-Time Gas — Any gas that influxes during a period in which circulation has been stopped. (Connection gas and survey gas are two specific types of down-time gas.)
Trip Gas — The increase of mud gas due to the effects of swabbing and no mud circulation (as with connection gas), which occurs while drillpipe is being pulled up the hole. Trip gas may occur from either a short trip (e.g., pulling up into the casing) or from a full trip to surface.
Kelly-Cut or Top-Trip Gas — The added gas response measured as a consequence of a slug of air entering the mud system when a connection is made or a trip to bottom is completed. The incorporated air tends to aerate a small interval of mud and thereby make it more able to entrain gas during its round trip and to break out as the aerated mud expands on return to the surface. A kelly cut should arrive one full mud circulation period after a connection.
Top Connection Gas — An increase in sampled gas that is the result of a temporary accumulation of gas near the bell nipple when the mud system is shut down. This at-surface condition will vary with the configuration of the mud discharge line and the gas-sampling system. It may be avoided by circulating mud past the gas trap before resuming gas analysis after a connection.
Lag Gas — Any artificially introduced gas used to determine mud circulation rate or lag time. Acetylene is a common lag gas; light hydrocarbons like gasoline may also be dumped in the mud system for lagging.
Note: When gasoline is used, it should be white or unleaded to avoid lead damage to detector filaments.
Uses of Gas Data
The two broad uses of mud gas data in formation logging are:
Correlation — recognition of similarities with other logs and wells.
Evaluation — recognition of anomalies in the well being drilled.
In correlation, we are looking for interwell hydrocarbon and rock related data, as in characteristic background gas levels or in drilling breaks caused by anticipated lithologic changes. In evaluation, we are looking for variations in related rock and hydrocarbon data, such as increases in porosity denoted by increases in gas content, or as changes across a reservoir denoted by changes in gas composition.
In the remainder of this section, we generally consider mud gas and cuttings gas data relative to these two aspects as they are reflected in the continuous summary plot of Track Three and the intermittent component plot of Track Four. In the following discussion, remember that correlation and evaluation are, to a degree, end members in the use of gas data and each finds use in the interpretive region between them.
Correlation
Pattern correlation is perhaps the first or most obvious correlative use of mud gas plots as they are developing in a drilling well. The total combustible gas plot combined with the ROP or lithology curve can often be used visually for direct formation correlation with mud gas and wireline logs from adjoining wells. This type of pattern correlation permits bottomhole stratigraphy to be tracked as drilling progresses.
Total mud gas plots will also show a general correlation with wireline porosity logs, and can be used for interfield correlations while drilling is still in progress.
Total cuttings gas plots will closely correlate with SP logs where both are responding to changes in permeability. However, each has some response unrelated to permeability. Thus, a change in pore water salinity can alter and possibly invert SP response without effecting a change in cuttings gas concentration. Conversely, the presence of a low-gravity immobile oil can cause a sharp increase in cuttings gas. The response of the SP log to this occurrence will be small unless oil saturation is very high or the oil is so viscous and immobile that it causes a major permeability reduction.
Very usable correlations occur between total mud gas and shallow and deep resistivity and conductivity logs. Almost all porous rocks contain saline waters with dissolved gases, predominantly methane. Consequently, gas content and water content can closely track each other and porosity. Therefore, the mud gas total combustible hydrocarbon curve will generally correlate well with both shallow and deep conductivity logs and will be a reciprocal of the resistivity curve.
An approximate one-to-one correlation may not always occur between these logs and this also can be useful. When a zone of high hydrocarbon saturation is encountered, the gas curve will most probably increase with the increasing gas saturation. However, this need not be the case. If the mudcake has not built up effectively, mud flushing during drilling may result in the displacement of all hydrocarbons and a "negative gas show" at surface. In this situation, shallow conductivity logging will commonly see only the flushed zone around the borehole. Primarily sensing the mud filtrate, it will remain unaffected by the more distant, true gas saturation and give an unrelated response.
Deep conductivity logging, however, will respond primarily to the original, undisturbed hydrocarbon saturation and be unaffected by permeability and gas and oil mobility. Comparing the three curves can provide a quick-look evaluation of saturation and mobility.
Evaluation
As
presented at the beginning of this section, anomalies within a well are best recognized and evaluated after operational and lithologic variables are considered. Determining the validity of a gas show on the total combustible gas plot, for example, requires a number of adjustments. Specifically, the data should first be corrected for background influences and then normalized with respect to operational influences such as rate of penetration, bit diameter, rate of mud circulation, and gas trap extraction efficiency.
Background is generally established by inspection using the total combustible gas plot ( Figure 1 , Total combustible gas plot from chart recorder with diagnostic features noted). Based on the differences between zero gas points and running or visual averages of background gas, a true background is calculated for the depth at which the show occurred. This true background value is then subtracted from the show value to provide a "rough" quantification of the anomaly. The anomaly is now ready for normalization to give it a "reference" value for classification and comparison with other anomalies in the well or in nearby wells.
Normalization is necessary to remove operational influences that cannot be fully annotated on the gas log and thereby be interpreted out. Let us assume, as an example, that we drill into a porous and permeable zone. Such a zone will be physically weaker than the uphole section and we will recognize it by an increase in ROP, that is, a drilling break. If, after the appropriate lag time, we see an increase in total combustible hydrocarbon readings we might take this as a sign that the interpreted high-porosity zone is filled with gas and oil.
This need not be the case ( Figure 2 , Effect of change in ROP on mud gas detector response). An increase in gas will result, in part, simply from the higher ROP and greater pore volume drilled. We are crushing a larger volume of rock and liberating more gas within any increment of time.
An opposite effect will be seen when bit diameter is reduced, as at a casing point. A smaller volume of rock is crushed for each increment drilled following the bit-size change and, as a consequence, all gas shows will be reduced in magnitude to some degree below the casing point. Similarly, if mud flow rate is increased at any point, then the volume of formation fluid released during a show below that point will be mixed with a larger volume of drilling fluid. Consequently, the gas show will be more dispersed and give the appearance of being smaller than a comparable show occurring before the flow rate increase.
Some wellsite geologists are willing to accept these effects and work with raw data when evaluating a show. If operational variables have remained fairly consistent throughout the show interval, then a rough correction only for background may give a fair indication of the magnitude of the show.
This magnitude, however, will not necessarily be directly comparable to previous uphole or later downhole anomalies drilled under different conditions. Therefore, an increasing number of geologists prefer to work with normalized data. Normalizing can be done either by the geologist or as part of the mud-logging service.
Normalization is generally carried out by using the following mathematical scheme:
where:
Gn = "normalized" ditch total hydrocarbons, % EMA
Go = observed ditch total hydrocarbons, % EMA
Qo = observed drilling fluid pump output, m3/s
Qn = "normal" drilling fluid pump output, m3/s
Sn = "normal" drill bit diameter, m
Bo = actual drill bit diameter, m
Rn = "normal" ROP, m/s
Ro = observed ROP, m/s
Fen = "normal" extraction efficiency factor, dimensionless
Feo = observed extraction efficiency factor, dimensionless
The concept is simpler than the formula appears to indicate. Basically, if mud flow rate increases or bit size or ROP decreases, normalizing must have a positive effect on gas values to compensate for greater gas dilution and lesser ground-up rock. The opposite is true, of course, under inverse drilling changes.
The "extraction efficiency factor" in the formula above is a correction factor used to attempt to remove the effect of variations in gas trap efficiencies resulting from changes in such conditions as mud flow characteristics, mud chemistry, and ambient temperature. Its direction and magnitude can be approximated by comparing the results of cuttings gas values with mud gas values. It can also be estimated as the hole is drilled by monitoring changes in gas detector response to comparable amounts of acetylene lag gas.
When comparing a number of shows, "normal" values may be arbitrarily selected, but should remain the same throughout the normalization program for all shows and wells involved. It is recommended that normal values be chosen that are typical of those encountered when drilling the particular stratigraphic section under evaluation. If this is done, the eventual normalized gas magnitudes will not vary far from their observed values. In this way, they will be more readily understood and accepted by personnel already working in the district but who may be unfamiliar with normalizing techniques.
Another method of normalizing data that is commonly used when hydrocarbon data are evaluated is to make comparisons or ratios between the concentrations of specific hydrocarbon compounds within one sample — that is, measured during one single gas analysis. This normalizing process equates all values within one batch sample to 100%. The resulting ratios that can be established between compounds are independent of the total concentration measured and, therefore, relatively free of sampling and similar variables.
An easy way to visualize this normalizing effect is to imagine diluting a gas sample with different volumes of air or dissipating it into different volumes of mud. Although the absolute concentrations of hydrocarbon gas will drop proportionately to the dispersion, and thereby give a lower total reading, indicating greater dilution or dissipation, the relative concentrations, or ratios, between hydrocarbon compounds within each sample will remain the same. All compounds, in other words, are dispersed by the same amount.
Ratio normalization finds most use in evaluation of mud gas and cuttings gas data from chromatographic analysis. The hydrocarbon ratios obtainable from detailed analysis can provide important clues to the composition of formation fluids giving the show.
Because hydrocarbons have common origins in carbonaceous matter and are relatively soluble in each other, we should expect the liberated gas in a gas show to be of the same origin as the range of hydrocarbons in the show interval as well as reflective of their nature. Experience has shown this to be true; in particular, different hydrocarbon ratios in mud gas and cuttings gas can strongly reflect different compositions of companion fluids at depth ( Figure 3 , Show evaluation scheme using mud-gas compound ratios to interpret show potential).
Mud-logging companies have a variety of methods for interpreting and plotting show and probable reservoir relationships. Several rule-of-thumb guides are applied in most interpretations and evaluations:
Where gas ratios favor the lighter components — methane and ethane — reservoir lithologies are most apt to contain a light fluid — gas and/or condensate.
Where gas ratios favor the heavier gases — propane and butanes — reservoir lithologies are more apt to contain heavier fluid — crude oil.
At either extreme — all methane (dry gas) or predominantly butanes (very wet gas) — reservoir lithologies are probably going to have unfavorable petroleum characteristics. The former implies an immature, possibly biogenic gas, probably of low volume, or simply a water reservoir with dissolved methane. The latter suggests either heavy immature oil or residual oil from which all of the light, more mobile components have migrated.
Where data are adequate, comparison of gas ratios can be used also to evaluate down hole changes between shows. They may also be used as drilling progresses to give early insight as to changes occurring between wells (e.g., oil-water contact versus gas cap).
Naturally, we must assume that the better the data, the better the interpretation. Steam-still and cuttings-gas extractors generally provide better gas samples for the above types of interpretation than the gas trap at the mud tank.
The principal limitation of ratio normalizing for show evaluation is the fact that analytical data for individual hydrocarbon components must be available. Because these come mostly from intermittent or batch analyses, a reliable number may not exist for each show, particularly if sampling frequency is the same for cuttings gas as for lithologic description (e.g., the ten- to thirty-foot range). For this reason, it is good practice to require short-interval cuttings and mud sampling throughout a show, with cuttings and mud gas extraction and detailed analyses run as rapidly as possible.
Exercise 1.
Contrast the following:
a. liberated gas versus produced gas
b. influx versus flushing
c. lag time versus lag strokes
d. hydrocarbon gas versus nonhydrocarbon gas
e. mud gas versus cuttings gas
f. Catalytic combustion detection versus thermal conductivity detection
g. dry gas versus wet gas
h. % EMA vs ppm
i. connection gas versus lag gas
j. gas show versus gas feed-in
Solution 1:
a. The first is liberated by the bit, the second influxes from uphole.
b. The first is formation fluids entering the hole (or mud), generally from mud under-balance; the second is the result of mud fluids entering the drilled formation, generally from mud overbalance.
c. Lag time is that taken for cuttings to come up the annulus; lag strokes are the pump strokes required to bring cuttings to surface. (Chronologic time can be highly variable due to noncirculation, e.g., during connections, but pump strokes will remain relatively constant for mud return to surface.)
d. Hydrocarbon gases consist of molecules containing atoms of hydrogen and carbon only; any gas containing any other atom is a nonhydrocarbon gas, even if it also contains hydrogen and carbon.
e. Mud gases are extracted from mud; cuttings gases from cuttings.
f. Catalytic combustion detection depends upon the heating effect of combustible gas on a heated wire; thermal conductivity detection is dependent upon the cooling effect of any gas on a heated wire.
g. Dry gas is relatively pure methane gas; wet is methane gas mixed with ethane, propane, and butane.
h. % EMA is the gas measurement relative to response equivalent to that given by a known concentration of methane; ppm is the gas volume of individual gas related to entire gas sample.
i. Connection gas is formation gas entering the mud system at depth while a connection is made; lag gas is contaminant gas introduced at surface to measure mud system circulation cycle.
j. A gas show is a relatively short-term influx of gas (its appearance should signify penetration of a gas-bearing horizon); gas feed-in connotes a long-term influx of gas (commonly due to inadequate mud overbalance).
Exercise 2.
Explain why lag strokes determined by tracer test and mathematical calculation need not agree, as well as what application the difference between the two can have.
Solution 2:
The tracer test is an accurate physical measurement of the number of pump strokes required for mud to make one complete circulation down the drill pipe and up the annulus.
Calculated lag is the theoretical number of strokes required to move a theoretical volume of mud through the same system. The latter cannot take fully into account hole-size variations, pump efficiency, and similar variables.
The difference between the lag strokes (volume of mud) determined by the two methods can be used to evaluate hole conditions and some equipment efficiencies.
Exercise 3.
a. Why is total combustible mud gas measured in % EMA for the formation log instead of ppm or some similar, more precise method?
b. Why is mud gas analyzed by gas chromatography not a continuous measurement of gas composition?
Solution 3:
a. Each individual hydrocarbon gas (methane, ethane, etc.) gives off a different response to commonly used detectors. No discrimination can be made because changes in both concentration and composition produce changes in response.
b. Gas chromatography requires time to separate one sample into its individual components. No separation would be achieved with continuous sample injection.
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