Borehole Formation Microresistivity Imaging (FMI)

Basic Concept

Formation microresistivity imaging (FMI) is a borehole-logging technique that uses measured electrical properties to produce two-dimensional “images” of the formations intersected by a borehole. FMI logs show the variations in electrical resistivity of the borehole wall with a high-enough resolution to allow for analysis comparable to that of core images.

Unlike other borehole methods that estimate bulk formation properties, the principle information within FMI logs is structural. As such, FMI logs reference only the geometrical arrangement of earth materials due to sedimentary and tectonic forces (Chen and others, 1987). Thus, FMI data aid the identification, characterization, and/or interpretation of subsurface features based on the visual assessment of microresistivity images.

Theory

Formation microresistivity imaging (FMI) techniques involve the same basic principles as those used in conventional borehole resistivity methods. However, FMI tools do not explicitly employ current- and potential-electrode pairs. Instead, FMI tools contain multiple, millimeter-scale button electrodes arranged on electrically conductive pads that laterally expand to contact the borehole wall. While logging, which occurs in the upward direction, a voltage is applied between the button-electrodes and a return electrode that occupies the upper section of the probe.

In so doing, electrical current is initiated at each button electrode and focused into a cylinder with a cross-sectional area equal to that of the button. Though some current may flow parallel to the borehole through electrically conductive mud, most of the current penetrates the formation beyond the borehole anulus. As the current flows away from the focusing pad, it diffuses into a volume within the formation before reaching the return electrode (Safinya and others, 1991).

The magnitude of current that originates from a button electrode is related to formation conductivity (or its inverse, resistivity) along the length of its path of travel. Specifically, current is proportional to the conductance of its travel path, which, itself, is proportional to conductivity along the path multiplied by its cross-sectional area. Thus, high-magnitude current represents conductive formations and/or diffuse current lines, whereas low-magnitude current represents resistive formations and/or dense current lines (Safinya and others, 1991).

Each button-electrode current consists of a high-resolution and low-resolution component, which correspond, respectively to a small, focused volume and a diffused (i.e., background) measurement. The variations of microresistivity observed in the data are most significantly influenced by the high-resolution component and, as such, are representative of it. Thus, each button electrode examines a small, fixed-width volume of rock in the vicinity of the borehole wall as the tool travels the length of the borehole.

Measuring tool orientation (borehole deviation logging) with depth and resistivity allows FMI logs to be displayed with respect to depth and azimuth. Data are often presented as variable-intensity plots that show microresistivity variations via a color scale and allow qualitative-data analysis. Because an FMI log is the projection of a cylindrical-borehole surface onto a two-dimensional plane, quasi-planar features appear as sinusoids. Additional small-scale structures can be identified based on similarly derived characteristic patterns (Chen and others, 1987).

The spatial resolution of FMI data is determined by the button-electrode diameter(s). As such, hairline features may be detected if they have sufficient resistivity contrast and are separated by at least the electrode diameter. Typically, the high-resolution component has a very sallow (i.e., less than 3 cm) radius of investigation into the formation. This distance is reduced with a decrease in bed thickness and/or conductivity and an increase in borehole rugosity and/or spatial density of voids (Bourke and others, 1989).

Applications

The relative microresistivity variations provided by formation microresistivity imaging (FMI) can be related to variations in pore geometry/-chemistry and/or interactions occurring at the pore boundaries. As such, variations on the microresistivity images are often in response to changes in porosity, fluid type, grainsize, mineralogy, and/or cementation (Bourke and others, 1989). Thus, if exhibited at the appropriate scale (i.e., greater than the tool resolution), sedimentary structures and structural features are often easily identifiable in FMI logs.

The azimuthally oriented sinusoids displayed in FMI logs can aid the determination of feature orientation (e.g., bedding plane strike and dip). The trough inflection point indicates dip direction, and dip angle is calculated by normalizing the amplitude to the borehole diameter (Chen and others, 1987). Additionally, unlike fracture density and spacing, fracture porosity is analyzed qualitatively. Open, fluid-filled fractures will appear darker (i.e., are less resistive) than closed fractures containing little to no fluid (Bourke and others, 1989).

Because only electrical properties are considered in FMI data, log interpretation is improved with supplementary data (e.g., local lithology, structures, and/or features). Additionally, factors such as borehole deviation, true vs magnetic north, and borehole diameter can affect feature orientation and should be corrected when appropriate. Especially when appropriate corrections are implemented and additional borehole/site information is considered, FMI logs provide physical measurements of the borehole wall that can aid in the following applications:

Assisting sedimentological interpretation
Determining the boundaries and thickness of depositional sequence and formations
Identifying sedimentary structures, structural features, and lithofacies
Determining the geometry and density of fractures and faults
Determining the presence of permeability paths and potentially impermeable barriers
Distinguishing natural from anthropogenic fractures
Planning well completion, perforation, fracturing, or drilling locations

Examples/Case studies

Evans, D.J., Kingdon, A., Hough, E., Reynolds, W., and Heitmann, N., 2012, First account of resistivity borehole micro-imaging (FMI) to assess the sedimentology and structure of the Preesall Halite, NW England: implications for gas storage and wider applications in CCS caprock assessment: Journal of the Geological Society, v. 169, no. 5, p. 587-592, doi:10.1144/0016-76492011-143.

Abstract: UK future energy infrastructure will include solution-mined salt caverns in bedded halite deposits providing short to medium term, fast-cycle underground gas storage volumes. Assessing the stratigraphy, sedimentology and structure of halite beds is essential for understanding and developing gas storage caverns. This paper highlights perhaps the first application of Schlumberger’s FMITM resistivity borehole imaging tool to characterize and provide a detailed understanding of bedded halites. Widely used in the hydrocarbons industry for over 20 years the potential value of such tools has yet to be fully recognized in the solution mining industry and is applied to the Triassic Preesall Halite in NW England with promising results. There may be wider applications in, for example, CCS caprock assessment.

Geng, X., Lin, C., Wu, B., and Li, H., 2016, Paleokarst system based on FMI facies analysis: a case study in the Yingshan Formation at the Tazhong uplift in the Tarim Basin, Northwest China: Arabian Journal of Geosciences, v. 9, doi:10.1007/s12517-016-2634-0.

Abstract: FMI (Formation Micro-Scanner image) is a widely used technique to analyze reservoir properties with the advantages of being high resolution and providing a visible and quantifiable image. In this study, eleven FMI facies are classified based on integrating borehole images, cores, thin sections, and well logs. The facies include such reservoirs as caves and tectonic fractures, sedimentary interbeds, such as high-resistivity facies, and two facies of fractures and holes. In addition to the description of karst systems in the borehole images, anomalies in the GR (gamma ray) well log curve may complement the results from the FMI images. The GR curve shows that the composite facies of fractures and holes could be an effective reservoir instead of caves with high GR values because the holes filled with oil and gas are connected by fractures. Two suites of karst systems formed in the SQ4, while small scale caves and holes formed in the SQ3 because of their lithological and structural locations. The results of this study demonstrate that unconformities and tectonic geomorphology control the differences between the paleokarst systems.

Mancini, E.A., Epsman, M.L., and Stief, D.D., 1997, Characterization and Evaluation of the Upper Jurassic Frisco City Sandstone Reservoir in Southwestern Alabama Utilizing Fullbore Formation MicroImager Technology: Gulf Coast Association of Geological Societies Transactions, v. 47, p. 329-335, doi:

Abstract: The upper Jurassic Frisco City Sandstone is a prolific oil reservoir in southwestern Alabama. To date, there is no consensus as to the reservoir depositional model for this sandstone. Interpretations include marine, braid delta-front deposits, braided stream deposits associated with alluvial fans, strandplain and beach deposits associated with shoal-water braid deltas, and tidal channel and ebb and braid delta deposits. In utilizing a fullbore Formation MicroImager (FMI) well logs in conjunction with a core study, the interpretation of the depositional environments of the Frisco City Sand were determined to be braid-delta, ebb-delta, tidal channel and strandplain. The FMI log provided paleocurrent direction and sandstone orientation data that are not attainable from core studies. The FMI log is also useful in deciphering reservoir quality and reservoir grade sandstone. Not only is the FMI log beneficial in defining the porous and permeable sandstone intervals, it can also be utilized in identifying anisotropic features that could be barriers to flow. Reservoir characterization and evaluation are enhanced through the use of the FMI well log.

Parra, J., Hackert, C., Richardson, E., and Clayton, N., 2007, Analyses of Porosity And Permeability Variations Captured By Cross-well Seismic Measurements And Geophysical Well Logs At Port Mayaca Aquifer, South Florida, in Proceedings, SEG Annual Meeting: San Antonio, Texas, Society of Exploration Geophysicists, 5 p.

Abstract: High-resolution seismic reflection between wells provides images of the subsurface about one order of magnitude greater than surface seismic reflection. Cross-well seismic images outline the zones of high matrix porosity and permeability that are associated with high water production at the Port Mayaca test site. The top of the Floridan Aquifer System (FAS) and the lower boundary of the intermediate confining unit (the basal Hawthorn) are delineated with an impedance image. Impedance, porosity, and permeability images capture the variation of the aquifer matrix in the interwell region. In particular, the impedance image provides the stiff and soft zones of the aquifer. The stiff zones contain conduits, which may not be connected, that are associated with secondary porosity features such as pore/vugs/fractures near the wells. The soft zones of low impedance are associated with high water production. Furthermore, the impedance and porosity images, combined with the Fullbore Formation Micro Imager (FMI) resistivity image logs, provide information that can explain the development of conduits in the stiff intervals. The permeability image gives a good visualization of low and high matrix permeability distribution intervals, and the FMI image data provides information on the secondary porosity distribution at the borehole scale that cannot be detected with any other log. In particular, the FMI image logs show a sequence of dark (conductive) and white (resistive) bands. This suggests that the conductive bands are porous and saturated with brackish water. Some of the resistive bands may be connected between wells, but the dark zones embedded in the white bands likely are not. Zones characterized by these sequences are intervals with low water production.

Rajabi, M., Sherkati, S., Bohloli, B., and Tingay, M., 2010, Subsurface fracture analysis and determination of in-situ stress direction using FMI logs: An example from the Santonian carbonates (Ilam Formation) in the Abadan Plain, Iran: Tectonophysics, v. 492, no. 1-4, p. 192-200, doi:10.1016/j.tecto.2010.06.014.

Abstract: The relationship between the present-day stress field and natural fractures can have significant implications for subsurface fluid flow. In particular, fractures that are aligned in orientations favourable for reactivation by either shear or tensile failure in the in-situ stress field often exhibit higher hydraulic conductivities. The Ilam Formation of southwestern Iran is an important hydrocarbon reservoir containing numerous natural fractures. However, little is known about the state of stress in this region, or any of Iran's petroleum provinces. We conducted analysis of the present-day maximum horizontal stress orientation and the density, orientation and hydraulic conductivity of natural fractures in the Ilam carbonates using high resolution Formation Micro Imager resistivity logs in two wells. A total of 51 breakouts with an overall length of 215 m were observed in the two wells, indicating a maximum horizontal stress orientation of 68°N (± 7.6°) in well A and 58°N (± 6.3°) in well B. Furthermore, the wellbore-derived stress orientations determined herein are consistent with those inferred from nearby earthquake focal mechanism solutions, indicating that stresses in the sedimentary cover are linked to the resistance forces generated by Arabia–Eurasia collision. Furthermore, the correlation between stress orientations estimated from earthquake focal mechanism solutions and breakouts indicates that focal mechanism solution data, which is often considered to be unreliable for stress field analysis near transform margins, may provide reliable information on the stress orientation near continental collision zones. The image log data also reveals three sets of open, and presumably hydraulically conductive, fractures with strikes of (i) 160–170°N, (ii) 110–140°N and (iii) 070–080°N. Fracture set (iii) is consistent with being formed and open in the present-day stress field. However, fracture sets (i) and (ii) strike at a high angle to the present-day maximum horizontal stress, and are interpreted herein to be the result of either pre- or syn-folding related forces. The observation that different sets of open fractures in the field can be either sensitive or insensitive to the present-day stress is critical for improving hydrocarbon recovery.

Tominaga, M., 2013, “Imaging” the cross section of oceanic lithosphere: The development and future of electrical microresistivity logging through scientific ocean drilling: Tectonophysics, v. 608, p. 84-96, doi:10.1016/j.tecto.2013.06.018.

Abstract: A detailed understanding of the architecture of volcanic and magmatic lithologies present within the oceanic lithosphere is essential to advance our knowledge of the geodynamics of spreading ridges and subduction zones. Undertaking sub-meter scale observations of oceanic lithosphere is challenging, primarily because of the difficulty in direct continuous sampling (e.g., by scientific ocean drilling) and the limited resolution of the majority of geophysical remote sensing methods. Downhole logging data from drillholes through basement formations, when integrated with recovered core and geophysical remote sensing data, can provide new insights into crustal accretion processes, lithosphere hydrogeology and associated alteration processes, and variations in the physical properties of the oceanic lithosphere over time. Here, we introduce an alternative approach to determine the formation architecture and lithofacies of the oceanic sub-basement by using logging data, particularly utilizing downhole microresistivity imagery (e.g. Formation MicroScanner (FMS) imagery), which has the potential to become a key tool in deciphering the high-resolution internal architecture of the intact upper ocean crust. A novel ocean crust lithostratigraphy model based on meticulously deciphered lava morphology determined by in situ FMS electrofacies analysis of holes drilled during Ocean Drilling Program legs (1) advances our understanding of ocean crust formation and accretionary processes over both time and space; and (2) allows the linking of local igneous histories deciphered from the drillholes to the regional magmatic and tectonic histories. Furthermore, microresistivity imagery can potentially allow the investigation of (i) magmatic lithology and architecture in the lower ocean crust and upper mantle; and, (ii) void space abundances in crustal material and the determination of complex lithology-dependent void geometries.

Wang, F., Bian, H., Gao, X., and Pan, B., 2016, Application of fullbore formation microimager logging in the evaluation of anisotropic resistivity in a thin interbed reservoir: Journal of Geophysics and Engineering, v. 13, no. 4, p. 454-461, doi:10.1088/1742-2132/13/4/454.

Abstract: Oil and gas reserves in sand-shale thin interbeds are extensive, but it is a challenge to achieve satisfactory precision in the identification of these interbeds using traditional logging data. Phasor induction and three-component induction logging are appropriate tools for the identification of sand-shale interbeds. Unfortunately, phasor induction data are expensive and three-component induction logging is rarely used in major domestic oil fields. As a result, evaluation of sand-shale thin interbeds heavily depends on a traditional logging suite, general image logging, array lateral logging and array induction logging, and so on. In this paper, we investigate the sand-shale thin interbed region in the northern part of the Sulige field. We propose a comprehensive method of anisotropic evaluation which is based on the combination of wellbore microresistivity image logging (fullbore formation microimage (FMI)) and high-resolution array induction logging (HRLA), where HRLA can be used instead of a traditional logging suite or high-resolution array lateral logging. The proposed method works well in the evaluation of thin interbeds in the northern part of the Sulige field. In this paper, the combination of FMI and deep resistivity of HRLA is used. It should be noted that it is possible to use deep resistivity of conventional laterolog or array induction log instead of HRLA.

Wilson, M.E.J., Lewis, D., Yogi, O., Holland, D., Hombo, L., and Goldberg, A., 2013, Development of a Papua New Guinean onshore carbonate reservoir: A comparative borehole image (FMI) and petrographic evaluation: Marine and Petroleum Geology, v. 44, p. 164-195, doi:10.1016/j.marpetgeo.2013.02.018.

Abstract: The depositional and diagenetic controls on carbonate platform evolution are notoriously heterogeneous and difficult to determine from standard subsurface wireline logging techniques. Here, a combined borehole image (FMI – Fullbore Formation MicroImager) and petrographic study allowed evaluation of depositional and diagenetic trends across an Australasian subsurface buildup that is a major recent gas discovery. The Elk and Antelope gas fields are hosted in Tertiary reefal, platformal and associated deep water carbonates in the present day foothills region of the Fold and Thrust Belt in the Gulf Province of Papua New Guinea. A full suite of FMI logs (>2800 m), and 292 thin sections (mainly from sidewall cores and cuttings) from both platform flank and shallow water deposits were evaluated during this study. Despite the obvious scale differences between the datasets there was some correlation between the independent petrography and FMI studies for: a) picking major facies boundaries, and b) interpretation of depositional environments, the latter particularly for slope and deep water deposits. However, thin section petrography proved critical in understanding primary depositional textures and secondary alteration features through the shallow-water carbonates where complex diagenetic overprinting had strongly impacted original fabric, and/or in regions affected by “gas smearing”. The petrographic study allowed more detailed examination of diagenesis and its impact on rock fabric (which links to the FMI textures). Component analysis and depositional textures identified in thin section are good indicators of original depositional environment. Full FMI coverage allowed textural definition on a dm/m scale, identification and characterisation of vertical changes, and likely large-scale variations in depositional environments and sequences. It was clear from combining the results of the two studies that diagenesis as well as depositional fabric had a strong impact on resultant FMI facies. The diagenetic overprinting would have been difficult to extract from the FMI data without the benefit of the petrographic work. This study shows the merits of selective petrographic analysis to calibrate the quality of facies interpretation from FMI images, and proved critical for enhancing and in places revising initial FMI interpretations.

References

Bourke, L., Trouiller, P., Fett, T., Grace, M., Luthi, S., Serra, O., and Standen, E., 1989, Using Formation MicroScanner Images: The Technical Review, v. 37, no. 1, p. 16-40.

Chen, M.Y., Dahan, C.A., Ekstrom, M.P., Lloyd, P.M., and Rossi, D.J., 1987, Formation Imaging With Microelectrical Scanning Arrays: The Log Analyst, v. 28, no. 3, p 294-306.

Safinya, K.A., Le Lan, P., Villegas, M., and Cheung, P.S., 1991, Improved Formation Imaging With Extended Microelectrical Arrays, in Proceedings, SPE Annual Technical Conference and Exhibition: Dallas, Texas, Society of Petroleum Engineers, p. 653-664, doi:10.2118/22726-MS.