Mud Gas Isotope Logging (MGIL)

1.??? Introduction

Mud Gas Isotope Logging (MGIL) primarily aims to assess the reservoir extent and identify any reservoir communication with other formations. It is a gas fingerprinting technique based on isotopic analyses of the gases in outflowing mud. It employs Mass Spectrometry (MS) as the underlying principle because Gas Collector (GC) cannot produce accurate results. GC lacks in the following aspects,

1.???? GC analysis gives amounts of methane, ethane, and propane (paraffins) but aromatics and naphthenes are not analyzed explicitly

2.???? It gives a false positive, where high gas conc. occurs due to changes in drilling parameters

3.???? It gives a false negative, where gas conc. is suppressed due to overbalanced drilling

4.???? Typical GC cycles of 3–6 minutes may lead to thin zones being missed at high ROP

5.???? It does not measure a wide range of Carbon species therefore making it impossible to distinguish free-phase compounds from the ones that are dissolved in an aqueous pore fluid system

The isotopic ratio of carbon in the gases is independent of gas concentration. This fact overcomes the disadvantageous principle of GC being based on gas concentration. It is advantageous in the following ways,

1.???? Due to little isotopic fractionation during sampling, the carbon isotopic ratio can be used to distinguish the sampled gas from biogenic gas and other unassociated gases

2.???? It helps to identify HC accumulations as they can be identified as ‘heavy carbon’ deviation from the background gas isotropic trend

3.???? It enables to distinguish in-situ HC gases from those that are migrated from deeper or more mature sources by attributing the background isotropic trend of methane in shale to in-site generation of gas

4.???? It helps to establish reservoir compartments that can either be separated by static boundary or dynamic boundary

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2.??? Workflow of MGIL

The gas sample collected from outflowing mud is first analyzed by GC to infer the sample size and type of isotopic technique to be employed. The isotopic ratios are then determined by Gas Chromatographer – isotope ratio mass spectrometer (GC–irms), as shown in Fig a. HCs contain two natural stable isotopes of carbon viz. 13C (Heavy) and 12C (Light). The ratio of these two isotopes depends on the HC type and its origin.

3.??? Gas type interpretation from MGIL data

The three major types of gas in the sedimentary basin are biogenic gas, thermogenic gas, and mixed gas, as shown in Fig b.

3.1.??????? Biogenic Gas

It is produced by the shallow subsurface metabolism of microorganisms. It is characterized by the dominance of isotopically light methane and scarcity of higher HCs. For a single-sourced accumulation, methane isotopic value of -60‰ or below indicates biogenic gas (Fig c). Microbes prefer to consume lighter 12C – carbon isotopes of the organic nutrient. Generally, Biogenic gas is found in shallow subsurface; 1m to a maximum of 2000m.

3.2.??????? Thermogenic Gas

It is produced from kerogen as a result of heating due to burial. It is characterized by the dominance of heavier carbon isotopic values and the fraction of heavier HC is very high. It has a carbon isotopic ratio of methane that is less negative than biogenic and ranges from -20‰ to -60‰ (Fig c), and the heavy HC is more than 50% relative to total HC. A heavier C-isotopic ratio (High thermal maturity) is indicative of generation in the gas window or generation from coal. In contrast, a Lighter C-isotopic ratio (Low thermal maturity) is indicative of generation in an oil window from a marine source. Thermogenic gas with low thermal maturity can be confused with Biogenic gas. Taking into account ethane, and propane in addition to methane can help us differentiate the source.

3.3.??????? Mixed Gas

Gases in the subsurface get partially mixed. Biogenic gas in deeper sediments retained as a result of rapid burial followed by rapid seal development may get partially mixed with thermogenic gas. Similarly, thermogenic gas may migrate to shallow zones and get mixed with biogenic gas.

4.??? Shows Identification

MGIL assists in verifying mud gas shows and pointing out missed or bypassed pay zones. The principle is, that economic Oil and Gas concentrations are cooked in deeper kitchens and are migrated later into the reservoir, whereas background gases are mostly indigenous. This causes the isotopic composition of the two gas types to differ. Significant isotopic shift indicates migrated or economic concentrations whereas feeble or no isotopic shift is attributed to changes in drilling parameters.

The type of petroleum in the reservoir is indicated by heavier HCs in the show. Oil is attributed to a higher abundance of C3+ components. Wet gas is attributed to ethane dominance.

MGIL, however, cannot distinguish the saturation in highly permeable reservoirs from residual saturation or low saturation of migratory pathways. Thus, the ability to produce cannot be evaluated by MGIL and requires traditional wireline logging or production testing.

5.??? Background Isotopic Trends

Background gas in shallow depths can be attributed to immature sediments with bacterial gas formation while in deeper sections, it could be due to the generation of heavier methane gas by thermogenic cracking of in-situ kerogen. Background Isotopic trend is identified as a series of compositional isotopic data following a uniform trend with depth (Fig d). It is characterized by low total HC gas and light carbon isotopic ratios relative to HC shows. With increasing depth, methane becomes isotopically heavier while some trends show nearly constant carbon isotopic composition.

In pay zones, diffusion of dissolved light HCs shifts the background value to a heavier value. The false positives may be due to inefficient degassing of mud which causes the gas from earlier penetrated zones to smear through deeper sections.

6.??? Reservoir compartmentalization

Reservoir compartmentalization refers to the segregation of the HC accumulation into distinct fluid or pressure compartments. It occurs when the HC migration is hindered across reservoir boundaries. These boundaries are the result of various fluid dynamics and geological factors. The boundaries separating the compartments can be a static boundary, that completely withholds HC accumulation over a geological time or it can be a dynamic boundary, that reduces the HC flow to infinitesimally slow rates.

A study of MGIL data carried out in the Horn Mountain field with numerous wells penetrating particular reservoir sand reveals the static and dynamic reservoir compartmentalization.

For sand bisected by a fault (static boundary) as shown in the structure map (Fig e), the part of the sand that is in the upthrown block (southern block) at shallow levels has the isotopic shift signatures of biogenic to mixed gas while the same sand in the downthrown block (northern block) at deeper levels shows a significant shift from the background trend indicating a thermogenic charge. Multiple wells drilled in the downthrown northern block show similar isotopic signatures of thermogenic gas indicating uniform communication within the downthrown block. Also, a linear down-trending slope is attributed to vertical HC stratification resulting from density or gravity (Fig f). Wells drilled in the upthrown southern block mostly show similar isotopic signatures of biogenic to mixed nature but few wells showed anomalous heavier isotopic values (Fig f). Plotting these anomalous wells on the structure map, it was found that these wells lie in the Southeast part of the block which is separated from the southwest part of the block by a fault.

HC-bearing sands can be homogeneous with well-established communication and are indicated by cluster without any vertical trend while stratified sands in which HC are vertically layered and communication is restricted are indicated by vertically trending cluster (Fig f). HC stratification can be due to the inherent/geochemical properties of HC itself or it can be due to the geological properties of the sand or a combination of the two.

Discussion

The inexpensive MGIL technique delivers a geochemical perspective on the HC-charged zones providing a detailed petroleum system evaluation analysis. It helps to distinguish the economic zones from unproductive zones and provides insight into the segregation of HC across static or dynamic boundaries in a particular sand or pay zone. It maximizes the information from each well and constructively assists in framing precise exploration and production prognosis.

References

Leroy Ellis, Tom Berkman, Steve Uchytil, Leon Dzou, Integration of mud gas isotope logging (MGIL) with field appraisal at Horn Mountain Field, deepwater Gulf of Mexico, Journal of Petroleum Science and Engineering, Volume 58, Issues 3–4, 2007, Pages 443-463, ISSN 0920-4105

Ellis, L. & Brown, A. & Schoell, Martin & Uchytil, Steven. (2003). Mud gas isotope logging (MGIL) assists in oil and gas drilling operations. Oil and Gas Journal. 101. 32-41.

Jolley, S. & Fisher, Quentin & Ainsworth, R.B.. (2010). Reservoir compartmentalization: An introduction. Geological Society of London Special Publications. 347. 1-8. 10.1144/SP347.1.

Mud Gas Composition and Isotope Analysis by Stratum Reservoir team