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Article

Recognition of Artificial Gases Formed during Drill-Bit Metamorphism Using Advanced Mud Gas

by
Janaina Andrade de Lima Leon
1,*,
Henrique Luiz de Barros Penteado
1,
Geoffrey S. Ellis
2,
Alexei Milkov
3,† and
João Graciano Mendonça Filho
4
1
Brazilian Petrol S/A—Petrobras, Rio de Janeiro 20031-912, Brazil
2
U.S. Geological Survey (USGS), Denver, CO 80225, USA
3
Department of Geology and Geological Engineering, Colorado School of Mines, Golden, CO 80401, USA
4
Department of Geological Sciences, Federal University of Rio de Janeiro, Rio de Janeiro 21941-916, Brazil
*
Author to whom correspondence should be addressed.
†
Deceased author.
Energies 2024, 17(17), 4383; https://doi.org/10.3390/en17174383
Submission received: 14 March 2024 / Revised: 6 July 2024 / Accepted: 19 July 2024 / Published: 2 September 2024
(This article belongs to the Topic Advances in Oil and Gas Wellbore Integrity)
Browse Figures
Figure 1
<p>Regional map of the Santos Basin, showing the location of wells that were drilled using advanced mud gas analysis.</p> "> Figure 2
<p>Generalized process of advanced mud gas extraction and analysis (modified from Ablard et al., 2012 [<a href="#B3-energies-17-04383" class="html-bibr">3</a>]). The schematic illustrates well drilling and mud circulation, positioning of mud extraction probes at the IN and OUT along the mudflow line, and subsequent analysis of the gas inside the mudlogging unit by gas chromatograph and mass spectrometer.</p> "> Figure 3
<p>Mud gas logs for well E3 are divided into four parts including formation tops, lithology, and gas ratios (Well-E3 a panel), ratios C<sub>2</sub>/C<sub>1</sub>, dryness, and ethene/(ethane+ethene) (Well-E3 b panel), gas chromatography (Well-E3 c panel), and normalized alkanes (Well-E3 d panel). See <a href="#energies-17-04383-t002" class="html-table">Table 2</a> for mnemonics of lithological types. Interval with drill-bit metamorphism marked with green arrow. From 5500 until the end of the well, changes were observed in the gas curves, mainly in the igneous rock interval caused by drill-bit metamorphism. In Well-E3 b, we observed an increase in the C<sub>2</sub>/C<sub>1</sub> curve and a decrease in dryness causing the inversion of these two curves. In Well-E3 c, an increase in C<sub>2</sub> is also observed, overlapping C<sub>1</sub> from 5500 m to the end of the well, and in Well-E3 d, the relative percentage of ethane is greater than that of methane depending on the increase in ethylene.</p> "> Figure 4
<p>Mud gas logs for well D3 are divided into four parts including formation tops, lithology, and gas ratios (Well-D3 a panel), ratios C<sub>2</sub>/C<sub>1</sub>, dryness, and ethene/(ethane+ethene) (Well-D3 b panel), and gas chromatography (Well-D3 c panel) and normalized alkanes (Well-D3 d panel). See <a href="#energies-17-04383-t002" class="html-table">Table 2</a> for mnemonics of lithological types.</p> "> Figure 5
<p>The panel is separated into three different wells. Well-B2 (c, d, and b), Well-C2 (c, d, and b), and Well-D5 (c, d, and b) are represented on all the graphs that identify the drill-bit metamorphism in wells B2, C2, and D5. For the three wells, the chromatographic distribution graphs of alkanes (Well-B2 c, Well-C2 c, and Well-D5 c), the concentration of normalized alkanes from C<sub>1</sub> to C<sub>5</sub> (Well-B2 d, Well-C2 d, and Well-D5 d), and ratios (Well-B2 b, Well-C2 b, and Well-D5 b) were evaluated. Comparison between the gas chromatography of wells B2 (Well-B2 c—without drill-bit metamorphism until 5918 m and with drill-bit metamorphism when started the igneous rock), well C2 (Well-C2 c—with drill-bit metamorphism in the interval below 5700 m after changing from PDC to impregnated drill), and well D5 (Well-D5 c—with drill-bit metamorphism throughout the well drilled with the impregnated drill). Interval with drill-bit metamorphism marked with green arrow.</p> "> Figure 6
<p>Correlations between the drilling parameters and the gas ratios that were used for the identification of DBM considering the groups of wells with and without DBM, separated by lithology (ROP x C<sub>2</sub>/C<sub>1</sub>, WOB x ethene/ethene+ethane, and RPM x dryness).</p> ">
Versions Notes

Abstract

:
Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the interface of the bit and rock due to the overheating of the bit. The heat generated by the drill when drilling into a rock formation promotes the generation of artificial hydrocarbon and non-hydrocarbon gas, changing the composition of the gas. The objective of this work is to recognize and evaluate artificial gases originating from DBM in wells targeting oil accumulations in pre-salt carbonates in the Santos Basin, Brazil. For the evaluation, chromatographic data from advanced mud gas equipment, drilling parameters, drill type, and lithology were used. The molar concentrations of gases and gas ratios (especially ethene/ethene+ethane and dryness) were analyzed, which identified the occurrence of DBM. DBM is most severe when wells penetrate igneous and carbonate rocks with diamond-impregnated drill bits. The rate of penetration, weight on bit, and rotation per minute were evaluated together with gas data but did not present good correlations to assist in identifying DBM. The depth intervals over which artificial gases formed during DBM are recognized should not be used to infer pay zones or predict the composition and properties of reservoir fluids because the gas composition is completely changed.

1. Introduction

Mud gas logging is the process of measuring the chemical composition, recognition of artificial gases, and concentrations of gases released from the returned drilling mud [1,2,3]. Mud gas logging helps recognize potential well safety issues (e.g., gas kicks), detect possible pay zones and the depths of petroleum–water contacts, predict the type and composition of reservoir fluid, and identify potential reservoir compartmentalization [4,5,6,7]. In general, mudlogging is a valuable evaluation technique that has evolved since the advent of rotary drilling in 1939 [8]. It provides continuous real-time information that can be used for drilling process optimization and detecting downhole drilling problems [9,10,11].
This technology, mud gas logging, has been used in the petroleum industry for decades [12,13,14] and has continuously and significantly improved over time [15,16]. Petroleum companies use advanced mud gas logging (AMG) to collect data during drilling, including measuring molecular compositions of gases and making real-time corrections to eliminate the effects of gas recycling and various drilling artifacts [3,7,17,18,19,20,21].
Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the drill bit and rock interface due to drill-bit overheating. The heat generated by the bit when drilling into rock formations promotes the generation of artificial gas, changing the gas composition and the drill cuttings that return to the surface [22,23,24,25,26]. Bowen and Aurousseau [27] first documented that the heat produced by the friction of drilling can significantly affect (fuse) cored rocks. Taylor [28] introduced the term “bit metamorphism” into the literature after describing severely altered cuttings commonly accompanied by the increase in gas volumes in wells from the German North Sea. DBM commonly occurs when drillers use impregnated drill bits or polycrystalline diamond compact (PDC) bits [29], together with drilling fluid containing oil-based mud. Because of these two factors, high temperature (from ~350 °C to 1200 °C) results from both in situ formation temperature and the friction of the bit with the rocks during rotary drilling [22,25,30,31]. Mud temperature is an important factor to be evaluated as it impacts both the generation of artificial gas and the stability of the well [32,33].
DBM generates carbon monoxide (CO) and alkenes (CnH2n, including ethene (C2H4), propene (C3H6), and butene (C4H8)) that are not present in the geological formations and natural petroleum fluids [24,25]. DBM also generates alkanes (methane (CH4 or C1) to pentanes (C5H12 or C5)), aromatics (benzene), hydrogen (H2), carbon dioxide (CO2), hydrogen sulfide (H2S), and carbonyl sulfide (COS), and these artificial compounds contaminate the indigenous compounds present in geological formations and reservoirs before drilling [24,26,34,35,36]. Artificial gases associated with DBM may be generated by Fischer–Tropsch reactions [37], pyrolysis of the oil-based mud during drilling, corrosion of the drill pipe, alteration of the gas already present in the drilled rock, and by a combination of these processes [23,36]. DBM increases the total gas amount and the concentrations of specific compounds changing gas ratios and affecting the isotopic composition of gases [23,24], all of which may lead to false identification of pay zones and incorrect interpretation of reservoir fluid types and properties [26].
According to Wenger [24] DBM can be observed in several ways including in cutting samples, in the composition and isotopic analysis of mud gases, and in the analysis of fluid-inclusion volatiles. In wells where DBM occurs, mud gas analysis shows that gases typically not found in natural gases such as alkenes, CO2, CO, and COS are generated during DBM.
When drilling a well, conventional mud gas or advanced mud gas analysis can be used to identify gas during drilling. Conventional mud gas uses a chromatograph and is unable to distinguish alkanes from alkenes as the retention times for alkanes and alkenes are very similar. Because advanced mud gas uses a mass spectrometer to identify drilling gas and the spectrometer differentiates gas based on molecular weight, alkanes can be easily distinguished from alkenes with this technique that is currently being used [38]. This differentiation is important for identifying DBM and therefore advanced mud gas will be used as the basis of this work.
Ref. [39] developed specific DBM research work by carrying out controlled experiments in the laboratory, using rock samples 0.5 m long. This experiment was able to simulate drilling conditions up to 5 km. In this experiment, the generation of alkanes, alkenes, CO, and H2 was observed through the extraction, analysis, and sampling of mud gas during drilling. The alkanes, alkenes, CO, and H2 that were generated during the experiment responded to a gradual increase in WOB or RPM generated through the cracking of the drilling fluid due to the increase in temperature at the cutter–rock interface.
As companies drill more wells in deep and hot reservoirs [40,41,42], which often have low permeability [43,44] and are characterized by low rates of penetration (ROP), the occurrences of DBM have become more common. Still, there are few published case studies that describe how to recognize artificial gases generated during DBM using advanced mudlogging data. Here, we discuss occurrences of DBM in wells that targeted oil accumulations in pre-salt carbonate reservoirs in the Santos Basin offshore Brazil [45]. Fifty wells were evaluated in the Santos Basin, targeting pre-salt carbonate reservoirs, and this is an academic innovation, as such a broad study had never been carried out with so many wells, totaling more than 66 km of well drilled using AMG for a study focused on identifying DBM. It was possible to carry out a robust analysis of the presence, absence, and intensity of DBM. We present a workflow to identify artificial gases formed during the DBM using advanced mud gas logging data and estimate the intensity of the DBM as a function of drill-bit types, penetrated lithologies, and drilling parameters. During the drilling of these wells, we did not have real-time isotopic data, nor a methodology to assist in the decontamination of artificial gases.

2. Methodology

2.1. Overview

The dataset studied is available at the Brazilian regulatory agency “Brazilian National Agency for Petroleum, Natural Gas and Biofuels—ANP”. These data include the molecular composition of the mud gas and drilling parameters from 50 wells drilled between 2009 and 2020 by Petrobras in the Santos Basin (Figure 1). Mud gas analyses were performed during drilling by service providers using equipment for advanced mud gas analysis (Figure 2). Three service providers for advanced gas analysis were employed, but the names of wells (Table 1), the service providers, and the names of the equipment were coded for confidentiality reasons: MUDX with the GASX equipment (37 wells), MUDY with the GASY equipment (11 wells), and MUDZ with the GASZ equipment (two wells).
The evaluation to recognize the DBM in the wells started with the analysis of the gas ratio plots. Initially, several ratios were calculated along each well: C1/(C1 + C2 + C3 + i-C4 + n-C4 + i-C5 + n-C5), called dryness [46], C2/C1, C2/C3, C2C/C3, C3/n-C4, i-C4/i-C5, n-C4/n-C5, i-C4/n-C4, i-C5/n-C5, and ethene/(ethene+ethane) [24]. Then, these ratios were plotted in scatter plots as a function of depth so that it was possible to identify the patterns of variation of the gaseous compounds. We identified that C2/C3, C2/C1, ethene/(ethene+ethane), and dryness ratios were most relevant for the evaluation of DBM in the wells. For each well, evaluations were performed in the same manner using mud gas data, lithologies, and drill-bit types as displayed in three panels (Figure 3, Figure 4 and Figure 5). For Figure 3, Figure 4 and Figure 5, panel “a” represents the general graph of the well with the indication of lithologies, bit changes, formation tops, and gas ratios. The panel “b” shows the ratios C2/C1, dryness, and ethene/(ethene+ethane). Panel “c” shows concentrations (chromatography) of C1–C5 gases and benzene (DELTA data), and panel “d” shows the normalized alkanes.
We recognized artificial mud gases generated by DBM based on the following criteria:
✓
A gas chromatography response from a reservoir without DBM shows a normal distribution of the gaseous fractions (C1 > C2 > C3 > C4 > C5; [12,16]). However, in the presence of DBM, the chromatography order is reversed (C2 > C1 in the case of extreme metamorphism), or the values tend to be very close (C2 ≈ C1 in the case of moderate metamorphism).
✓
The concentrations of benzene tend to increase in the presence of DBM and may be higher than C5 depending on the intensity of the metamorphism.
✓
During the occurrence of DBM, the average values for C2 (ethane + ethene) normalized to the C1 to C5 range normally are higher than 20%, reaching very high values (up to 70%) in extreme cases.
✓
The ratio C2/C3 tends to present high dispersion in the presence of DBM and low dispersion when there is no DBM.
✓
The C2/C1 ratio tends to be greater than 0.2, with high dispersion and greater than dryness and ethene/(ethene+ethane) ratio values depending on the intensity of DBM.
✓
The ethene/(ethene+ethane) ratio is close to 1 in the presence of DBM and has lower values or is close to zero in the absence of DBM [24].
✓
Dryness tends to be close to 1 in intervals without DBM and close to 0 in intervals with DBM because DBM generates many wet (C2+) gases.

2.2. Tools and Data Source

The equipment for advanced mud gas analysis can analyze gases during well drilling and identify several compounds such as alkanes (methane (CH4 or C1), to octane (C8H18 or C8)), aromatics (benzene and toluene), and cycloalkanes (cyclohexane and methylcyclohexane). The analyses provide quantitative data for the lighter hydrocarbons (from C1 to pentanes, C5) and qualitative data for the heavier (C6+) hydrocarbons [3].
The wells that used GASX and GASY were analyzed with a mass spectrometer. With this equipment, it is possible to detect single-bonded ethane (C2H6) and double-bonded ethene (C2H4) through a channel with the presence of ethane and ethene (C2) together and another channel called “corrected C2—(C2C)” where only the presence of pure ethane is detected. Ethene concentrations were estimated indirectly by subtracting these channels (ethene = C2 − C2C) because the advanced gas analysis equipment did not have an ethylene analyzer available at the time the wells were drilled. The C2C channel is only presented when there are relatively high concentrations of C2C values (>200 ppm). All evaluation and interpretation of this work were performed considering C2C above 200 ppm.
In the advanced mud gas analysis, there are two gas extractors in the mudflow line [3]. One is positioned to measure mud gas in the drilling fluid injected into the well (IN) and the other one measures mud gas after complete circulation of the drilling fluid in the well (OUT; Figure 2). This facilitates extraction and quantification of the gas that is incorporated into the drilling fluid at the entrance of the well (IN) and the gas that is returning from the well (OUT). The calculated difference (“DELTA” data) between the measurements in the OUT and IN extractors (DELTA = OUT − IN) removes the effect of the recycled gas in the mud from the concentration measurements and only accounts for the gas that was released during drilling. The gas reading at the IN and OUT is a great advantage of the advanced gas analysis when compared to the conventional gas analysis.
The drilling fluid is heated (80 °C or 90 °C depending on the service provider) both at the inlet and at the outlet before being extracted. As a result, the gas dissolved in the fluid is released more easily and with greater efficiency because the increase in temperature leads to an increase in the solubility [43] (especially in the heavy fractions), which is another great advantage of advanced mud gas analysis [3].
During gas extraction, hydrocarbons tend to stick to the drilling fluid and are therefore difficult to extract, causing an extraction deficit in gas analysis. Advanced gas analysis equipment also has the limitation of keeping some parameters stable. This difficulty in stabilization also causes an extraction deficit in gas analysis. To compensate for these extraction difficulties at the end of well drilling, mudlogging companies normally calculate the Extraction Efficiency Correction (EEC) and apply that correction to the DELTA data from C1 to C5. This correction occurs by multiplying a different coefficient for each of the alkanes (C1, C2, C3, C4, and C5). When this coefficient is identified for each alkane, it will be applied throughout all depths of the well. This coefficient varies for each of the alkanes, being progressively larger from C1 to C5, according to the difficulty of extraction. This coefficient is used to compensate for both the extraction deficit, which is inherent to the equipment’s capacity, and for the characteristics of the drilling fluid. Each mudlogging company has its criteria for calculating the correction factor and they apply a unique value for each of the alkanes. The EEC factor can be recalculated for each compound at the end of each drilling phase or when the drilling fluid changes configuration. Extraction coefficients are not calculated for C6+ heavy hydrocarbons.

2.3. Data Preparation and Processing

Initially, compositional data from advanced mud gas analysis were collected for each of the 50 wells. All data were cataloged, organized, and evaluated for quality. Gas data with zero values, values greater than one million, values consecutively repeated, fractionated values, and the data acquired before the start of the mud return were excluded. Data in which the unit of measurement was not parts per million (ppm), such as a unit of total gas, a unit of heavy gas, and percentage data, were also disregarded. At the end of this process, all invalid and spurious data were removed. For each of the 50 wells, the drilling data (type of bit used and bit change depths), type of drilling fluid, the tops of lithostratigraphic formations, lithologies, the final and initial depths of advanced mud-gas analysis, the identification of the company providing the advanced gas analysis service, and drilling parameters (rate of penetration—ROP, weight on bit—WOB, and rotations per minute—RPM) were recorded.
After organizing these data, several gas ratios were calculated. Then, these ratios were plotted versus measured depth MD (m) for each well to identify the variation patterns of the gaseous compounds. The top of each lithostratigraphic unit and the depth of each bit change were marked on these plots. In addition, plots of gas concentrations (C1, C2, C2c, C3, i-C4, n-C4, i-C5, n-C5, and benzene, using DELTA data versus depth MD (m)) and plots of drilling parameters (ROP, WOB, and RPM versus depth MD (m)), were prepared.
During the drilling of the wells, geological information such as rock samples, gas samples, well logs, and drilling parameters were used to identify the lithostratigraphic formations of the wells. This information was recorded in a document called a geological monitoring profile, from which the top and bottom information of the lithostratigraphic formation used in this work were taken. According to [47], the Santos Basin comprises the following lithostratigraphic formations: Marambaia (Paleocene sandstones, siltstones, and shales), Juréia (Late Cretaceous siltstones, shales, and diamictites), Itajaí-Açu (Late Cretaceous siltstones, shale, and diamictites), Itanhaém (Albian/Cenomanian dark laminated shales and calcilutites), Guarujá (Albian shales, calcilutites, calcirrudites, and calcarenites), Ariri (Neoaptian halite and anhydrite), Barra Velha (Aptian stromatolitic limestones and microbial laminites), Itapema (Neobarremian and Eoaptian calcirrudites and shales), Piçarras (Barremian conglomerates and polymictic sandstones), and Camboriú (Early Cretaceous basalts and diabase) Formations.
In all wells, the top and bottom of each lithostratigraphic formation were identified, and the results of this survey are compiled in Table 1. Some wells penetrated igneous rocks with different thicknesses interspersed with siliciclastic and carbonate rocks. Seven wells penetrated the Camboriú Formation, which is the economic basement of the Santos Basin.
The predominant lithologies were identified for each lithostratigraphic unit (Table 2). The “siliciclastic” lithology group includes all sedimentary lithologies from the Marambaia, Juréia, Itajaí-Açu, and Itanhaém formations. The “carbonate platform” group includes all lithologies of the Guarujá Formation, whereas the “salt” group includes all lithologies of the Ariri Formation. The “limestone” group includes the Barra Velha, Itapema, and Piçarras formations. All other lithologies with low porosity were included in the “calcilutite” group.
For some wells that crossed igneous rocks, it was not possible to identify the rock type in detail, and therefore the rocks were classified only as “igneous”. In the “diabase” group, igneous rocks that have been identified as diabase or basalt are included. Finally, two groups were created in which the carbonate lithologies are interspersed with igneous or fine low-porosity lithologies. These intercalations of carbonates with igneous or fine rocks are layers with thicknesses <10 m. Thus, the groups “limestone/igneous” and “limestone/calcilutite” were created. These two last groups were created because these thin lithologies are difficult to visually recognize on the lithology profiles of the wells, but they can affect the gas response.

3. Results and Discussion

Among 50 wells that penetrated the pre-salt section in the Santos Basin, 33 wells had clear evidence of DBM in some parts of the wells. Figure 3 represents an evaluation model of the well E3, showing the presence of DBM (based on all the criteria) in the section below 5500 m up to 5800 m (e.g., C2 > C1 in ppm, with C2 normalized > 20%). In the Well-E3 b panel, we observe between 5500 and 5800 m the inversion of the curves and dispersion of the ratios within the limestone/igneous lithological group (pre-salt carbonate rocks with thin (centimeters to <10 m) intercalations of igneous rocks). The limestone and igneous intercalations make it difficult to advance the drilling, promoting more friction and thus generating artificial gas, even before drilling the thick package of igneous rock at the end of the well. The normalized alkane chart values were calculated by normalizing the advanced gas analysis ranges of each well from C1 to C5 in percentage terms.
Figure 3 and Figure 4 show a typical DBM signature in the Ariri Formation (salt) section. This formation has low porosity and permeability, causing the gas background to be normally below 100 ppm. Sometimes, methane and ethane are present in higher concentrations during salt drilling, while the other hydrocarbons have low concentrations. This characteristic of the formation (all alkanes are below 100 ppm) can generate a false DBM signature that is possibly an artifact of the low gas concentration (<100 ppm).
Similar low gas anomalies also sometimes occur in siliciclastic rocks drilled in the post-salt interval. In Figure 4, these low concentration values (<100 ppm) associated with the inversion of the dryness curve and dispersion of the gas ratios occur both in the post-salt interval (Itajaí-Açu Formation) and at the top of the Ariri Formation. The inversion of the C2/C1 and dryness curves and a larger dispersion of the C2/C3 and C2/C1 ratios are observed below 3100 m just when the gaseous anomaly decreases.

3.1. Influence of Drill-Bit Type and Lithologies on DBM

At Petrobras, well drilling is carried out with different bits depending on the objective and drilled interval. Until the present work, a broad study had not been carried out correlating the intensity of the DBM with the drills used to drill wells in the pre-salt section.
We found that different types of drill bits and lithology influence the presence and severity of DBM. Therefore, wells were separated according to the type of drill bit that was more common (PDC bits, diamond-impregnated bits, and tricone bits) and according to the main lithologies (igneous, pre-salt carbonate, salt, and post-salt).
Different intensities of DBM were observed during the drilling of pre-salt carbonate rocks with different bit types. Figure 5 shows a comparison between the chromatography of three wells with different amounts of artificial DBM-generated gases in the pre-salt interval.
The well B2 (Figure 5, Well-B2 c) was drilled with a PDC bit in the Barra Velha Formation (limestones). Based on the normal chromatographic distribution of C1 > C2 > C3 > C4 > C5, C2 normalized = 10%, low dispersion (C2/C1 and C2/C3), dryness close to 1, and low values of benzene, in this case, the PDC bit did not generate artificial gases until the depth of 5918 m. The drill bit started to drill the igneous rock (5918 m until 5933 m), and all the criteria for identifying DBM were observed (e.g., C2 > C1 in ppm with C2 normalized = 46.8% range average 5918/5933).
In well C2 (Figure 5, Well-C2 c), the mud gas data were acquired starting a few meters below the top of the Barra Velha Formation and drilled with a PDC drill bit to a depth of ~5700 m without DBM. Then, the PDC bit was changed to a diamond-impregnated bit. After changing the bit (5700 m until 5765 m), all the criteria were observed, suggesting the occurrence of DBM (e.g., C2 > C1 in ppm with C2 normalized = 47.9% range average 5700/5765).
The well D5 (Figure 5, Well-D5 c) was drilled with an impregnated drill bit from the top of the Barra Velha Formation to the end of the well. This drill bit generated moderate DBM in the section below the depth of 4965 m until 5180 m (based on all the criteria, e.g., C2 = C1 in ppm with C2 normalized = 39.6% range average 4965/5180) in the pre-salt carbonate and generated extreme metamorphism in the igneous rock interval 5180 m until 5505 m (e.g., C2 normalized = 51.3% range average 5180/5505). The extreme DBM response was recognized by observing the inversion of the chromatographic curves (C2 > C1) and significant concentrations of benzene (benzene > C5).
As a result of the integrated evaluation of the drill bits, lithologies, and the responses of gas ratios, we found that only the PDC and impregnated drill bits resulted in DBM. Artificial gases generated by DBM were observed in 92% of the cases in which an impregnated bit was used to drill igneous rocks. DBM also often occurs when the PDC drill bit cuts through an igneous rock (73%). As for the pre-salt carbonates, the impregnated drill bit caused DBM in 71% of the cases and the PDC drill bit caused DBM much less often (24% of cases).
The occurrences of DBM and associated artificial gases in the salt section are rare. The gas background is normally low (<100 ppm) when the salt section is drilled because of its relative ease for drilling, given its characteristic behavior as a seal rock, and a lack of indigenous gases. For the 50 wells that were evaluated, only PDC or tricone bits were used to drill the Ariri Formation. DBM was observed in only 8% of cases when the PDC was used to drill the salt, normally associated with anhydrite drilling.
Igneous rocks were penetrated in 23 wells with impregnated or PDC bits. We observed that the intensity of DBM was much higher in the igneous rocks than in sedimentary rocks. DBM in the igneous rocks generated abundant artificial gases (both alkanes and alkenes), with strong inversions of the dryness and ethene/(ethene+ethane) curves, high values, and high dispersion of C2/C1, inversion of normal chromatography C2 > C1, C2/C3 dispersion, and the concentrations of benzene exceeding the concentrations of C4 and C5 (Figure 3). Rocks that have a high degree of cohesion and low permeability, such as igneous rocks and silicified carbonate rocks, for example, may have a high generation of artificial gas since the drill will have greater difficulty drilling these rocks. Rocks with a high degree of resistance associated with small grain sizes can also influence drilling. The smaller the grain, the more cohesive the rock and the more difficult it is to drill.
We have not observed DBM when the tricone drilling bits were used for drilling. In all cases observed, the presence of DBM impacts the gas data, compromising the interpretation. Knowledge about the types of drill bits associated with DBM is quite applicable during the drilling operation so that well projects can plan and avoid using drill bits that produce more DBM in the intervals of interest or the objective of the well. Therefore with this knowledge, the evaluation of advanced gas analysis during drilling can be conducted with the best possible reliability.

3.2. Influence of Drilling Parameters on DBM

Drilling parameters, such as ROP, were evaluated to understand how or if they influence the DBM. Of the 50 wells evaluated, 13 showed DBM in the entire section drilled in the pre-salt section and 15 wells did not show DBM in any drilled interval. These 28 wells were separated into 2 groups of “wells with DBM and wells without DBM”, and the correlations between the drilling parameters ROP, WOB, RPM, and the DBM proxies C2/C1, dryness, and ethene/ethene+ethane were evaluated.
According to information on the influence of lithology on the DBM, for each group of wells, the lithologies were grouped as follows: igneous rock, limestone, calcilutite, post-salt sedimentary rock, and salt.
For the two groups of wells, the following plots were made: ROP versus C2/C1, ROP versus ethene/ethene+ethane, ROP versus dryness, WOB versus C2/C1, WOB versus ethene/ethene+ethane, WOB versus dryness, RPM versus C2/C1, RPM versus ethene/ethene+ethane, and RPM versus dryness. Figure 6 shows some of the correlations that were evaluated for the two groups of wells (ROP versus C2/C1, WOB versus ethene/ethene+ethane, and RPM versus dryness) and the respective R2 values separated by lithology. All correlations in both groups had R2 < 0.4, indicating little to no influence of drilling parameters on DBM generation or low linear correlation between drilling parameters (ROP, WOB, and RPM) and the DBM (C2/C1, dryness, and ethene/ethene+ethane).

4. Conclusions

DBM was recognized using advanced mud gas data in numerous wells drilled in the Santos Basin. DBM was most common and intense when igneous rocks and pre-salt carbonate rocks were drilled with impregnated bits. PDC bits also often result in DBM, especially when used to drill through igneous rocks.
As a result of the integrated evaluation of the drill bits, lithologies, and the responses of gas ratios, we found that only the PDC and impregnated drill bits resulted in DBM. Artificial gases generated by DBM were observed in 92% of the cases in which an impregnated bit was used to drill igneous rocks. DBM also often occurs when the PDC drill bit cuts through an igneous rock (73%). As for the pre-salt carbonates, the impregnated drill bit caused DBM in 71% of the cases and the PDC drill bit caused DBM much less often (24% of cases).
When drilling with impregnated or PDC bit, it is necessary to carefully evaluate for the presence of DBM. The identification of DBM during the drilling of exploration wells is essential. DBM generates artificial gases and changes the chromatography, gas dryness, and other gas ratios, which can potentially lead to incorrect interpretations of the origin and maturity of hydrocarbon gases.
We did not find discernable relationships between drilling parameters and the geomechanical properties that indicate DBM. The presence or absence of DBM is more correlated with the type of lithology and drill-bit properties.
For the 50 wells in this work (wells drilled between 2009 and 2020), the intervals where artificial gas was generated by DBM should not be used to interpret the composition of gases in the reservoir. As of yet, no methodology has been developed to decontaminate or separate gas components generated by DBM from indigenous gases coming from reservoir rocks. The application of analysis tools like machine learning or artificial intelligence may aid in this effort. New technologies are advancing, and it may be possible for companies providing AMG services to apply a methodology based on algorithms to decontaminate DBM.

Author Contributions

Conceptualization, J.A.d.L.L. and H.L.d.B.P.; Methodology, H.L.d.B.P., G.S.E. and J.G.M.F.; Formal analysis, J.A.d.L.L.; Investigation, J.A.d.L.L.; Data curation, J.A.d.L.L.; Writing—original draft preparation, J.A.d.L.L.; Writing—review and editing, H.L.d.B.P., G.S.E., A.M. and J.G.M.F.; Visualization, A.M.; Supervision, H.L.d.B.P., G.S.E. and J.G.M.F. All authors have read and agreed to the published version of the manuscript.

Funding

The authors J.A.d.L.L. and H.L.d.B.P. are employees of the company Brazilian Petrol S/A–Petrobras, which acquired all the data that were analyzed in this manuscript. This paper was part of J.A.d.L.L.’s Ph. and was funded by Brazilian Petrol S/A-Petrobras.

Data Availability Statement

The dataset studied is public and can be requested. It is currently available at the Brazilian regulatory agency “Brazilian National Agency for Petroleum, Natural Gas and Biofuels—ANP”. Interested parties should contact the ANP “Technical Data Superintendence” (SDT) via email at [email protected].

Acknowledgments

We are grateful to Petrobras for supporting and providing fundamental data and materials for the development and execution of this work. We thank the U.S. Geological Survey Program and the Department of Geology and Geological Engineering, Colorado School of Mines, for supporting and stimulating this type of research. We express our gratitude to Alexei Milkov (in memoriam) for accepting to be part of this research, for his guidance, and for his great commitment to helping us. Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the U.S. Government.

Conflicts of Interest

The authors J.A.d.L.L. and H.L.d.B.P. are employees of the company Brazilian Petrol S/A–Petrobras. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. Regional map of the Santos Basin, showing the location of wells that were drilled using advanced mud gas analysis.
Figure 1. Regional map of the Santos Basin, showing the location of wells that were drilled using advanced mud gas analysis.
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Figure 2. Generalized process of advanced mud gas extraction and analysis (modified from Ablard et al., 2012 [3]). The schematic illustrates well drilling and mud circulation, positioning of mud extraction probes at the IN and OUT along the mudflow line, and subsequent analysis of the gas inside the mudlogging unit by gas chromatograph and mass spectrometer.
Figure 2. Generalized process of advanced mud gas extraction and analysis (modified from Ablard et al., 2012 [3]). The schematic illustrates well drilling and mud circulation, positioning of mud extraction probes at the IN and OUT along the mudflow line, and subsequent analysis of the gas inside the mudlogging unit by gas chromatograph and mass spectrometer.
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Figure 3. Mud gas logs for well E3 are divided into four parts including formation tops, lithology, and gas ratios (Well-E3 a panel), ratios C2/C1, dryness, and ethene/(ethane+ethene) (Well-E3 b panel), gas chromatography (Well-E3 c panel), and normalized alkanes (Well-E3 d panel). See Table 2 for mnemonics of lithological types. Interval with drill-bit metamorphism marked with green arrow. From 5500 until the end of the well, changes were observed in the gas curves, mainly in the igneous rock interval caused by drill-bit metamorphism. In Well-E3 b, we observed an increase in the C2/C1 curve and a decrease in dryness causing the inversion of these two curves. In Well-E3 c, an increase in C2 is also observed, overlapping C1 from 5500 m to the end of the well, and in Well-E3 d, the relative percentage of ethane is greater than that of methane depending on the increase in ethylene.
Figure 3. Mud gas logs for well E3 are divided into four parts including formation tops, lithology, and gas ratios (Well-E3 a panel), ratios C2/C1, dryness, and ethene/(ethane+ethene) (Well-E3 b panel), gas chromatography (Well-E3 c panel), and normalized alkanes (Well-E3 d panel). See Table 2 for mnemonics of lithological types. Interval with drill-bit metamorphism marked with green arrow. From 5500 until the end of the well, changes were observed in the gas curves, mainly in the igneous rock interval caused by drill-bit metamorphism. In Well-E3 b, we observed an increase in the C2/C1 curve and a decrease in dryness causing the inversion of these two curves. In Well-E3 c, an increase in C2 is also observed, overlapping C1 from 5500 m to the end of the well, and in Well-E3 d, the relative percentage of ethane is greater than that of methane depending on the increase in ethylene.
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Figure 4. Mud gas logs for well D3 are divided into four parts including formation tops, lithology, and gas ratios (Well-D3 a panel), ratios C2/C1, dryness, and ethene/(ethane+ethene) (Well-D3 b panel), and gas chromatography (Well-D3 c panel) and normalized alkanes (Well-D3 d panel). See Table 2 for mnemonics of lithological types.
Figure 4. Mud gas logs for well D3 are divided into four parts including formation tops, lithology, and gas ratios (Well-D3 a panel), ratios C2/C1, dryness, and ethene/(ethane+ethene) (Well-D3 b panel), and gas chromatography (Well-D3 c panel) and normalized alkanes (Well-D3 d panel). See Table 2 for mnemonics of lithological types.
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Figure 5. The panel is separated into three different wells. Well-B2 (c, d, and b), Well-C2 (c, d, and b), and Well-D5 (c, d, and b) are represented on all the graphs that identify the drill-bit metamorphism in wells B2, C2, and D5. For the three wells, the chromatographic distribution graphs of alkanes (Well-B2 c, Well-C2 c, and Well-D5 c), the concentration of normalized alkanes from C1 to C5 (Well-B2 d, Well-C2 d, and Well-D5 d), and ratios (Well-B2 b, Well-C2 b, and Well-D5 b) were evaluated. Comparison between the gas chromatography of wells B2 (Well-B2 c—without drill-bit metamorphism until 5918 m and with drill-bit metamorphism when started the igneous rock), well C2 (Well-C2 c—with drill-bit metamorphism in the interval below 5700 m after changing from PDC to impregnated drill), and well D5 (Well-D5 c—with drill-bit metamorphism throughout the well drilled with the impregnated drill). Interval with drill-bit metamorphism marked with green arrow.
Figure 5. The panel is separated into three different wells. Well-B2 (c, d, and b), Well-C2 (c, d, and b), and Well-D5 (c, d, and b) are represented on all the graphs that identify the drill-bit metamorphism in wells B2, C2, and D5. For the three wells, the chromatographic distribution graphs of alkanes (Well-B2 c, Well-C2 c, and Well-D5 c), the concentration of normalized alkanes from C1 to C5 (Well-B2 d, Well-C2 d, and Well-D5 d), and ratios (Well-B2 b, Well-C2 b, and Well-D5 b) were evaluated. Comparison between the gas chromatography of wells B2 (Well-B2 c—without drill-bit metamorphism until 5918 m and with drill-bit metamorphism when started the igneous rock), well C2 (Well-C2 c—with drill-bit metamorphism in the interval below 5700 m after changing from PDC to impregnated drill), and well D5 (Well-D5 c—with drill-bit metamorphism throughout the well drilled with the impregnated drill). Interval with drill-bit metamorphism marked with green arrow.
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Figure 6. Correlations between the drilling parameters and the gas ratios that were used for the identification of DBM considering the groups of wells with and without DBM, separated by lithology (ROP x C2/C1, WOB x ethene/ethene+ethane, and RPM x dryness).
Figure 6. Correlations between the drilling parameters and the gas ratios that were used for the identification of DBM considering the groups of wells with and without DBM, separated by lithology (ROP x C2/C1, WOB x ethene/ethene+ethane, and RPM x dryness).
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Table 1. Survey of wells and lithostratigraphic units for which advanced gas analysis was performed. Lithostratigraphic units color coding: post-salt in green, evaporites in purple, pre-salt in blue and orange colors, and the economic basement of the basin in red. Blank cells indicate the absence of formation in the well or interval in which advanced mud gas analysis was not acquired. The letters IGN in the cells indicate the presence of igneous rock.
Table 1. Survey of wells and lithostratigraphic units for which advanced gas analysis was performed. Lithostratigraphic units color coding: post-salt in green, evaporites in purple, pre-salt in blue and orange colors, and the economic basement of the basin in red. Blank cells indicate the absence of formation in the well or interval in which advanced mud gas analysis was not acquired. The letters IGN in the cells indicate the presence of igneous rock.
Advanced Gas Analysis Data
WellsFormation
MarambaiaJuréiaItajaí-AçuItanhaémGuarujáAririBarra VelhaItapemaPiçarrasCamboriú
D3 x xx IGNx IGN
E3 xxxxx IGN
F4 xxxxx x
H1x xx x
H4 xxxxxx
I3 xx xx
I4 xxx IGNx IGNx
J1x xxxxx IGN
J2 xx
J3 x
A3 x IGNx
A4 xxxx IGN
B1 xxxx
B2 xx IGN
B5 xx
D4 xxxxx
D5 x IGNx IGNx
E1 xx IGNx
E2 x IGNx IGN
E4 xxxx
F1 xxx
F2 xxx
F3 xx IGNx
F5 xx IGN
G1 xx IGN
G2 xx
G4 xx
G5 xxxx IGN
H2 xx
H3 xxx
H5 xxxxx
I1 xxxx
I2 xx
I5 x
J5 xx
A1 x IGN
A2 x IGNx x
A5 xx x
B4 xx
C1 xxx
C2 xx
C3 xxx
C4 xxx
C5 xx
D1 xx x
D2 x
G3 x IGNx
J4 x IGN
E5 x
B3 x
Table 2. Lithology groups were used in the evaluation charts. The table includes the lithologies, groups, mnemonics, and the color used in each lithology group.
Table 2. Lithology groups were used in the evaluation charts. The table includes the lithologies, groups, mnemonics, and the color used in each lithology group.
Type of LithologyMnemonicColor
LithologyGroup Name
Sedimentary after saltSiliciclasticSILICI
Post-salt carbonate platformCarbonate platformCARB PLAT
Salt – Halite and soluble saltSaltSALT
Pre-salt carbonateLimestoneLIME
Shale, siltite, mudstone, laminiteCalcilutiteCALCI
Unidentified igneousUnidentified igneousIGN
Diabase/BasaltDiabaseDIABA OR BASA
Carbonate pre-salt intercalated with igneousLimestone/IgneousLIME/IGN
Pre-salt carbonate intercalated with calcilutiteLimestone/CalcilutiteLIME/CALCI
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Leon, J.A.d.L.; Penteado, H.L.d.B.; Ellis, G.S.; Milkov, A.; Filho, J.G.M. Recognition of Artificial Gases Formed during Drill-Bit Metamorphism Using Advanced Mud Gas. Energies 2024, 17, 4383. https://doi.org/10.3390/en17174383

AMA Style

Leon JAdL, Penteado HLdB, Ellis GS, Milkov A, Filho JGM. Recognition of Artificial Gases Formed during Drill-Bit Metamorphism Using Advanced Mud Gas. Energies. 2024; 17(17):4383. https://doi.org/10.3390/en17174383

Chicago/Turabian Style

Leon, Janaina Andrade de Lima, Henrique Luiz de Barros Penteado, Geoffrey S. Ellis, Alexei Milkov, and João Graciano Mendonça Filho. 2024. "Recognition of Artificial Gases Formed during Drill-Bit Metamorphism Using Advanced Mud Gas" Energies 17, no. 17: 4383. https://doi.org/10.3390/en17174383

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