Fullbore Formation MicroImager Research Articles

Extraction and characterization of faults and fractures from 3D VSP data in a carbonate reservoir: A workflow

We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.

Petrophysical Evaluation of a Severely Heterogeneous Carbonate Reservoir; Electrical Image Logs Usage in Porosity Estimation

Image logs have higher resolution than conventional logs and it makes them powerful tools for detailed reservoir characterization and modeling. Hence, thin beds, which are not detectable using conventional logs, can be characterized by image log data. The present study focuses on the Permian-Triassic carbonate reservoirs of Dalan and Kangan formations in one of the gas fields in southern Iran. In this study, the reservoir porosity was estimated using Fullbore Formation Microimager (FMI) image log. Then, the results were compared and validated with the core data. Porosity was estimated as 2-dimentional image by rescaling the FMI image log with Micro-Spherical Focused Log (MSFL). The image log-derived porosity was then compared with conventional logs-derived and core porosities. The image log-derived porosity is in good agreement with the core data. In this paper, a procedure was introduced which can be used to recognize very narrow pay layers (thickness in centimeters). This work is very important for identifying the proper perforation intervals in heterogeneous reservoirs.

Lower Es3 in Zhanhua Sag, Jiyang Depression: a case study for lithofacies classification in lacustrine mud shale

Oil and gas exploration in lacustrine mud shale has focused on laminated calcareous lithofacies rich in type I or type II1 organic matter, taking into account the mineralogy and bedding structure, and type and abundance of organic matter. Using the lower third member of the Shahejie Formation, Zhanhua Sag, Jiyang Depression as the target lithology, we applied core description, thin section observations, electron microscopy imaging, nuclear magnetic resonance, and fullbore formation microimager (FMI) to study the mud shale lithofacies and features. First, the lithofacies were classified by considering the bedding structure, lithology, and organic matter and then a lithofacies classification scheme of lacustrine mud shale was proposed. Second, we used optimal filtering of logging data to distinguish the lithologies. Because the fractals of logging data are good indicators of the bedding structure, gamma-ray radiation was used to optimize the structural identification. Total organic carbon content (TOC) and pyrolyzed hydrocarbons (S2) were calculated from the logging data, and the hydrogen index (HI) was obtained to identify the organic matter type of the different strata (HI vs Tmax). Finally, a method for shale lithofacies identification based on logging data is proposed for exploring mud shale reservoirs and sweet spots from continuous wellbore profiles.

Facies Development of Carbonate Rock and System Tract Influence Based on Fullbore Formation Microimager (FMI) and Well Log Analysis on Carbonate Reservoir Tuban Formation, North East Java Basin

The North East Java Basin is known to be one of the basins that consist of Miocene carbonate rocks, like the reef carbonate of Tuban Formation. It has the potential hydrocarbons that can be explored. Therefore, the FMI log analysis is very important to identify carbonate rocks of Tuban Formation to know facies and characteristics of that carbonate rocks. The method used descriptive and analysis process of FMI and Gamma Ray log to determine facies of the carbonate rock and the system tract. Based on the result of FMI log analysis, there are variations lithofasies include mudstone, wackestone, packstone, grainstone, floatstone, rudstone and claystone. A collection of rock associations can interpret the reef facies. It involves back reef facies, reef core facies, and fore reef facies. The changes of lithofasies and reef facies are caused by sea level fluctuations and subsidence resulting in the system tract. The system tracts generated in the research area include transgressive and highstand system tract.

Comparison of Quantitative Analysis of Image Logs for Shale Volume and Net to Gross Calculation of a Thinly Laminated Reservoir between VNG-NERGE and LAGIA-EGYPT

This study focuses on one of the resistivity imaging tools owned by Schlumberger; Full-bore Formation Micro Imager (FMI). The objective of this paper is to analyze quantitative analysis that is carried out focusing on calculating the volume on clay volume and net-to-gross measurement. Clay volume in a thinly bedded interval was estimated based on the gamma ray log and one FMI trace (out of 192 traces).The gamma ray log data resolution is considerably lower than the FMI log to reflect accurate lithology changes in thinly bedded reservoirs. It has been found afterthought some calibrations and corrections on the FMI resistivity log, the new processed log is used for clay volume and net to gross calculation of the reservoir, indicating the potential of this log for analysis of thin beds. A comparison between VNG-NERGE, NORTH SEA WELL, NERWING and LAGIA-8, LAGIA, EGYPT indicates the calculation for shale volume at different intervals using FMI tools.

Application of fullbore formation microimager logging in the evaluation of anisotropic resistivity in a thin interbed reservoir

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.

Introduction of sealing fault in Asmari reservoir by using FMI and RFT in one of the Iranian naturally fractured oil fields

Historically, in Iran, the borehole imaging tools are acquired to locate major structural features, such as faults, fractures, and sedimentary environment interpretation. The well GS-314 was drilled to evaluate the Asmari formation. It was drilled with an 8.5-in, vertical hole. To get a better understanding of reservoir characteristics of the Asmari formation on the Gachsaran field, to fullbore formation microimager (FMI), repeat formation tester (RFT) and a full set of open hole logs are acquired. The main objective of running FMI was to determine fracture characteristics and locate high porous layers/streaks so that points for RFT survey could be chosen for better results. In this study, it indicated a possible sealing/non-permeable fault in the Asmari reservoir in GS-314 of the Gachsaran field. The RFT pressure data indicated a change of 100 psi in the oil gradients across the fault, indicating possible reservoir compartmentalization in the area around well GS-314. The FMI images indicated a dense layer of 1 m thickness with a dip very different from the bedding around 2173.6 m in the Asmari reservoir. It was interpreted as a sealing fault based on the dense appearance of its plane. In this work, we will show you that how by using a combination of FMI and RFT can interpret a sealing fault in one of the Iranian naturally fractured oil fields.

Estimation of density and fracture orientation in HTI media through azimuthal analysis of P-waves

In a medium with Horizontal Transverse Isotropy (HTI) associated with fractures, Normal Move Out (NMO) velocity varies ellipsoidally with the azimuth. The major axis of the ellipse indicates the direction of the fractures. Also, density is defined by the axial ratio. We are presenting a methodology to estimate fracture parameters based on the difference of NMO times measured in two orthogonal common midpoint seismic lines. The method was tested with synthetic data and then applied in seismic data of the La Luna Formation in the Tenerife Field, providing the orientation of the fractures as well as an estimated density. Results were validated by analysis of Fullbore Formation Microimager FMI logs acquired in wells in the vicinity of the Field.

Development of a Papua New Guinean onshore carbonate reservoir: A comparative borehole image (FMI) and petrographic evaluation

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.

Comparison of electrical image log with core in a fractured carbonate reservoir

Borehole image logs are kind of the modern logs which are frequently used to detect small-scale fractures intersecting well in fractured reservoirs. Electrical imaging tools like FMS (Formation MicroScanner) and FMI (Fullbore Formation MicroImager), electrically scan the borehole wall and deliver a pseudo-picture of the formation. Characteristics of fractures such as type, aperture and orientation can be determined by interpreting these logs.In this paper, we attempt to evaluate the ability of electrical image logs in detecting fractures and other geological features of a carbonate reservoir (Asmari) and explain the possible reasons of mismatch between the image log and core. To achieve this goal, we have compared the FMS of a well with the core. The results are verified with FMI and core data from seven nearby wells.Comparison of the FMS with the core revealed that FMS, as representative of electrical image logs, is robust in detecting open fracture and anhydrite; it is average in detecting bedding plane and flexural slip and is weak in detecting filled fracture, fault and compactional feature in carbonate reservoirs.

Mechanostratigraphic control on carbonate fractured reservoir evaluation: a PNG case study

Interpretation of Schlumberger Fullbore Formation Microimager (FMI) logs in the Elk-1, Elk-2 and Triceratop-1 wells show that the limestone formation is heavily and heterogeneously fractured. As part of the Elk/Antelope gas field development, reservoir modelling using a dual porosity system is currently being conducted. The gas field discovered is believed to be flowing from a fractured carbonate reservoir and establishing fracture to bedding thickness relationship will assist in developing a dual porosity system. A key input into reservoir modelling and simulation is fracture density across the entire field. This study was aimed at understanding the relationship of bedding thickness to fracture density to facilitate fracture modelling and dynamic simulation.

Statistical correlation between geophysical logs and extracted core

The precise correlation of extracted core to geophysical borehole logs is often problematic in intervals in which no sufficiently large or distinctive features span the gap between the outer core surface and the borehole wall. This impairs our ability to use techniques that require accurate correlation as a prerequisite (e.g., to develop field-based, upscaling and downscaling relationships of porosity distributions at or below log resolution). We propose a new method for such situations in which we correlate a cascade of statistics of core features with those of image logs taken from the borehole wall. Each statistic is used individually to calculate a likelihood function of possible correlation locations. These results are combined using a joint-likelihood function, and with other prior information using Bayesian techniques, to bring all available information to apply to the final correlation solution. The technique is demonstrated with computerized tomography for a core section and image-log data extracted from a typical Middle Eastern carbonate reservoir. Using lithologic criteria alone, the correlation was constrained to a [Formula: see text] [Formula: see text] region, which constitutes prior information. Using the mean, variance, and geostatistical-range parameter, our method further constrains the correlation to [Formula: see text] [Formula: see text], only seven times larger than Fullbore Formation MicroImager resolution. Thus our method allows further interpretation to be based on correlation accuracies as small as [Formula: see text] [Formula: see text].

Physical rock properties in and around a conduit zone by well-logging in the Unzen Scientific Drilling Project, Japan

The objective of the Unzen Scientific Drilling Project (USDP) is not only to reveal the structure and eruption history of the Unzen volcano but also to clarify the ascent and degassing mechanisms of the magma conduit. Conduit drilling (USDP-4) was conducted in 2004, which targeted the magma conduit for the 1990-95 eruption. The total drilled length of USDP-4 was 1995.75 m. Geophysical well logging, including resistivity, gamma-ray, spontaneous potential, sonic-wave velocity, density, neutron porosity, and Fullbore Formation MicroImager (FMI), was conducted at each drilling stage. Variations in the physical properties of the rocks were revealed by the well-log data, which correlated with not only large-scale formation boundaries but also small-scale changes in lithology. Such variations were evident in the lava dike, pyroclastic rocks, and breccias over depth intervals ranging from 1 to 40 m. These data support previous models for structure of the lava conduit, in that they indicate the existence of alternating layers of high-resistivity and high P-wave velocity rocks corresponding to the lava dikes, in proximity to narrower zones exhibiting high porosity, low resistivity, and low P-wave velocity. These narrow, low-porosity zones are presumably higher in permeability than the adjacent rocks and may form preferential conduits for degassing during magma ascent.

Geostatistical characterization of Callovo–Oxfordian clay variability from high-resolution log data

The aim of this paper is to outline a methodology to transform depth intervals into geological time intervals and thus to estimate duration; for example the duration of biostratigraphical units or of hiatuses. The latter point is particularly important because a continuous time recording is often assumed in geological modelling. Andra (National Radioactive Waste Management Agency) has conducted studies in its Meuse/Haute-Marne Underground Research Laboratory located at a depth of about 490 m in a 155-million-year-old argillaceous rock: the Callovo–Oxfordian argillite. The study of the variations of that clay layer can be conducted by the analysis of logs and particularly high-resolution logs. Working in a geochronological system helps to understand the physical properties of rocks and to make very precise well-to-well correlations. To transform the present coordinates, a high-resolution tool is necessary: the FMI ® (Fullbore Formation MicroImager, Schlumberger). First, well-to-well correlations are established between seven wells at different scales. Relative variations of the sedimentation rate are observed locally. Second, FMI ® data are studied in detail to extract as much information as possible. For example, the analysis of FMI ® images reveals a clear carbonate-clay interbedding which displays cycles. Third, geostatistical tools are used to study these cycles. The variographic analysis of conventional log data shows one-metre cycles. With FMI ® data, smaller periods can be detected. Variogram modelling and factorial kriging analysis suggest that three spatial periods exist. They vary vertically in the boreholes but cycle ratios are stable and similar to orbital cycle ratios (Milankovitch cycles). The three periods correspond to eccentricity, obliquity and precession. Since the duration of these orbital cycles is known, depth intervals can be converted into time intervals (duration) and thus give real sedimentation rates and a quantification of hiatus duration.

Outcrop and behind-outcrop characterization of a late Miocene slope fan system, Mt. Messenger Formation, New Zealand

The late Miocene Mt. Messenger Formation of Taranaki, New Zealand, consists mainly of well-sorted, very fine to fine-grained thin-bedded sandstone and siltstone deposited in middle- and upper-bathyal water depths. Lithofacies are dominated by turbidite beds, comprising planar-laminated and climbing-ripple-laminated sandstone and massive siltstone. These strata were studied in a 200 m-thick, 4 km-long coastal outcrop section and in two, behind-outcrop boreholes from which Fullbore Formation Micro Imager (FMI) and Platform Express logs and core were obtained. The boreholes were 47 and 105 m deep and were drilled about 100 m behind the cliff outcrop about 150 m apart. In addition, a high-resolution seismic reflection line was shot adjacent to the coastal cliff and was tied to the updip outcrop exposures. The outcrop section displays abundant erosional cutout of beds by scour or channels that considerably limit lateral bed continuity. At a smaller scale, bed continuity is also interrupted by bioturbation structures. We interpret the outcrop section as a series of vertically stacked or shingled slope fan or channel-levee/overbank complex deposits, comparable to Mutti type III fans. Comparison of behind-outcrop dipmeter, seismic reflection profiles, and FMI data with outcrop data indicates that three main channel-levee/overbank depositional units are present. Siltstone and alternating thin-bedded sandstone and siltstone that display an upward decrease in dip magnitude and variable dip orientation on dipmeter logs are interpreted as channel fill deposits. Vertically stacked, interleaved packages of thin-bedded, typically planar-laminated sandstone (Bouma Tb divisions), climbing-ripple-laminated sandstone (Tc), and siltstone (Te) with complex upward-decreasing dipmeter patterns are interpreted as proximal channel-levee and overbank deposits. Laterally extensive interbedded Tb and Tc sandstone and Te siltstone lithofacies with low-angle dips and little variability on dipmeter logs are interpreted as distal channel-levee and overbank deposits. These three depositional settings are important to distinguish, as each exhibits different fluid-flow behaviors in an analog reservoir. Comparison of the outcrops with typical subsurface data sets as used by petroleum geologists (logs, core, seismic reflection) has provided criteria for distinguishing subtle stratigraphic features that can influence production from a subsurface reservoir analog.

Rock types and permeability prediction from dipmeter and image logs: Shuaiba reservoir (Aptian), Abu Dhabi

The Shuaiba Formation is a complex carbonate reservoir characterized by small-scale geological heterogeneity primarily related to rudist macrofauna. The textural heterogeneity corresponds to extreme permeability variation that is the controlling factor in reservoir production. Because of the large vertical resolution contrast between cores (actual scale) and conventional logs (averaged responses over a few feet), extrapolation of small-scale heterogeneity into uncored wells using a traditional approach is unreliable. High-resolution log data, like dipmeters and image logs, are required to characterize small-scale heterogeneity that is essential to a good three-dimensional (3-D) geological model that predicts true reservoir behavior. Our study illustrates an approach to improve the reservoir characterization of the Shuaiba by quantifying small-scale heterogeneity using dipmeter and image logs. A methodology is proposed to use the existing high-resolution (High-resolution Dipmeter Tool [HDT], Stratigraphic High-resolution Dipmeter Tool [SHDT], and Formation MicroScanner [FMS]) and conventional log data to characterize and extrapolate geological heterogeneity. Texture and neural network analyses, derived from microresistivity variations and a multiregression approach, have been used in two wells to demonstrate the methodology. Both rock types and permeability are estimated for extrapolation into uncored wells. Although differences between the conductivity of conductive and resistive areas when normalized for background conductivity are an indirect measure of permeability for HDT and SHDT, the connectivity coefficient of conductive anomalies derived from textural analysis is related to permeability in the case of FMS. Reservoir rock types (RRT) obtained from the methodology correlate well with RRTs derived from the integration of core, special core analysis (SCAL), and conventional log data in two test wells. Permeability estimations, including small-scale extreme variations from less than 1 md in tight mudstones to greater than 1 d in caprinid rudstones, are in good agreement with the core plug permeability measurements after a simple calibration. In one example, permeability trends in rudist RRTs, which are not discernible using core plugs and minipermeameter data, are clearly resolved using SHDT data. The degree of correlation between estimated and core permeabilities is greater with increased vertical resolution of the tool (HDT, lowest; FMS, highest). Distinct RRTs resulting from small-scale geological heterogeneity can be classified and permeability can be estimated with a high degree of confidence, providing a better pathway of extrapolating from core data to conventional logs for 3-D modeling. The methodology has potential application to other carbonate and siliciclastic reservoirs with appropriate calibration and scaling. Underused HDT, SHDT, FMS, and Fullbore Formation MicroImager (FMI) databases are available in many other areas that could be analyzed. An order of magnitude improvement in the ability to characterize small-scale heterogeneity has significant implications for future coring, logging programs, and reservoir characterization efforts. Duffy Russell is a senior carbonate geologist at Saudi Aramco in the Reservoir Characterization Department, Southern Fields Characterization Division. He received B.S. and M.S. degrees in geology from North Carolina State University in 1976 and Duke University in 1979 and a Ph.D. in geology from the University of Aberdeen in 2001. He started his career as a geophysicist with Amoco Production Company in 1979 and has worked nearly 21 years as a geologist for Mobil Oil Corporation and ExxonMobil, specializing in carbonate reservoir characterization.Mahmoud Akbar is a principal geologist for Schlumberger working Iran, Qatar, the United Arab Emirates, Oman, and Yemen. He started his professional career with Schlumberger Wireline and Testing in 1985 in Pakistan. He received B.Sc. (1983) and M.Sc. (1985) degrees in applied geology from the University of Punjab, Pakistan. He has carried out research in the Lower Himalayas on factors controlling fractures and their effect on rock strength. Badarinadh Vissapragada is a senior petrophysicist with Schlumberger Data and Consulting Services, Abu Dhabi, United Arab Emirates. He did his postgraduate study in geophysics at Andhra University, Waltair, India. He has more than 19 years of petrophysics experience in India and Middle East reservoirs from fieldwide petrophysical studies and reservoir characterization. His special interests are reservoir rock typing, permeability, and fracture detection. Gordon Walkden is head of the Department of Geology and Petroleum Geology at the University of Aberdeen, Scotland. After receiving a degree from Quintin School in London, he obtained his Ph.D. in carbonate sedimentology from Manchester University, United Kingdom, in 1970. Gordon was appointed senior lecturer in 1988 and became department head in 1993. He has extensive field experience and supervision of research projects in Britain, Europe, North America, and the Middle East.

Fracture systematics in and around well WD-1, kakkonda geothermal field, japan

Interpretation of FMI (Schlumbergers Fullbore Formation MicroImager) logs from well WD-1 and observation of spot cores from well WD-1 in the Kakkonda geothermal field have provided important clues about the nature and configuration of the fracture networks controlling circulation of high-temperature hydrothermal fluid. The fractures comprise four groups: (1) fractures striking NW, (2) high-angle fractures striking NE to E, (3) low-angle fractures striking N, and (4) low-angle fractures striking E. Most permeable fractures in the shallow (<1500 m depth) and deep reservoirs are of group 3, and likely reflect reverse faulting in the modern stress field. Low-angle, group 4 fractures are also permeable, and may have formed in the stress field that existed prior to 0.2±0.1 Ma. Distributions and densities of fractures are comparable in the shallow and deep reservoirs; the temperature difference between the reservoirs is independent of these variables.

The integration of electrical image logs with core data for improved sedimentological interpretation

Abstract Electrical borehole images allow the direct integration of sub-surface well-log data with core data on a detailed visual level. For sedimentary interpretation, electrical borehole images are primarily used to obtain bedding orientations and to confirm core-derived sedimentology. The aims of this paper are two-fold: firstly, to discuss how the sedimentological information provided by electrical borehole image logs is integrated with that obtained from other wireline logs and from cores; and secondly, to show that despite the need to integrate these data electrical borehole images can provide the geologist with unique sedimentological information which can not be obtained from either the cores or the other wireline logs. In a case study from the Oseberg Syd oil and gas field, a Fullbore Formation MicroImager (FMI Mark of Schlumberger) log through a complex interval of shallow marine sediments has been investigated. The interpretation of the FMI log led to the acquisition of very detailed orientation data related to the attitudes of sedimentary bedding surfaces. When these data were integrated with the sedimentary facies, identified from core description, they proved fundamental for understanding the activity of different shallow marine palaeocurrents during sediment deposition.

Characterization and Evaluation of the Upper Jurassic Frisco City Sandstone Reservoir in Southwestern Alabama Utilizing Fullbore Formation MicroImager Technology : ABSTRACT

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.

A Fracture-Orientation Comparison Between Core-Based and Borehole-Imaging Techniques: Paleomagnetic, Electronic Multishot, and FMI: ABSTRACT

Accurate orientation of fractures is crucial to enhanced productivity in low-permeability fractured reservoirs. This study presents results of a rare instance in which three widely different fracture-orientation techniques could be directly compared for orientation accuracy. In a fracture-orientation study of Pardonet/Baldonnel (Upper Triassic) carbonates from the Gwillim field, British Columbia, a 50[degrees] to 60[degrees] fracture-orientation discrepancy was observed in two consecutive core runs oriented by [open quotes]electronic multishot[close quotes] (an electronic version of the conventional [open quote]multishot[close quotes] core- orientation technique) versus Schlumberger's Fullbore Formation MicroImager (FMI). To resolve this discrepancy, the paleomagnetic core-orientation technique was employed as a third fracture-orientation method. The paleomagnetically-determined fracture orientations agreed within 5[degrees] with FMI, and confirmed a systematic error in the electronic multishot orientations of 46[degrees] in Core 1 and 60[degrees] in Core 2. Superimposed on the systematic error was a second-order, oscillatory [open quotes]torsion error[close quotes] of [+-]10[degrees], which probably reflects acquisition of electronic multishot data within a rotating drillstring (unlike conventional multishot where coring is stopped before each [open quotes]shot[close quotes]). The paleomagnetic and FMI data reveal that natural and induced fractures have different orientations at this well location in the Gwillim field. Natural fractures dip 72[degrees] toward N 45[degrees] E,more » nearly orthogonal to bedding which dips 15[degrees] toward S 45[degrees] W. In contrast, induced petal fractures strike N 10[degrees] E, at a 55[degrees] angle to the strike of natural fractures and bedding.« less