FMI Log Research Articles

Petrophysical Properties Estimation by Using Well Log and Core Data Interpretation for Tertiary Reservoir in Ajeel Oil Field

Understanding the petrophysical properties of reservoirs is paramount for assessing their characteristics and estimating the potential of oil-bearing formations. This study focuses on the tertiary reservoir in the Ajeel oil field, renowned for its heterogeneous carbonate nature and diverse production formations, including Jeribe, Dhiban, and Euphrates. The formation of the tertiary reservoir is evaluated through a comprehensive analysis of petrophysical properties utilizing well log data from well AJ-25 and core analysis data (routine and special analysis). The study reveals significant insights into the petrophysical properties of the formations. The effective porosity values for the Jeribe, Dhiban, and Euphrates formations are determined as 15.41%, 4.65%, and 9.85%, respectively, with lithology predominantly consisting of dolomite rock interspersed with limestone slices and anhydrite nodules. A high Secondary Porosity Index (SPI) indicates fractures. Archie's Parameters, obtained from a Pickett Plot, yield cement coefficient (m=1.8), saturation exponent (n=1.9), and tortuosity factor (a=1.19). Water saturation levels for the Jeribe, Dhiban, and Euphrates formations are 33%, 86%, and 81%, respectively, with porosity and water saturation cutoff values determined as 10% and 60%, respectively. Net to Gross of Jeribe, Dhiban, and Euphrates formation are 0.706, 0.029, and 0.011, respectively. Jeribe Formation is identified as an oil-bearing zone. In contrast, the Dhiban and Euphrates formations are identified as water-bearing zones. To enhance the accuracy of petrophysical assessments, modern well logging techniques, such as the Formation Micro Scanner log (FMI log), are recommended to investigate fractures and their impact on field performance, as traditional logs may not adequately capture these features. Additionally, our comparative analysis highlights superior petrophysical properties of the Euphrates Formation compared to the Jeribe Formation. Therefore, prioritizing drilling and completion activities in the Euphrates Reservoir within the field, contingent upon its positioning relative to the oil-water contact level, is suggested for optimizing reservoir performance.

Multiscale fractures, stress and reservoir quality characterization: The Mississippian Meramec and Osage intervals, STACK play, Central Oklahoma

This study characterized in-situ stress-fields and multi-scale fractures in the low porosity and low permeability Mississippian-aged “Meramec and Osage” intervals in the Anadarko Basin of central Oklahoma. As the two reservoirs' productivity is influenced by fractures, understanding fracture nature, frequency and distribution is important for the development of these reservoirs. The study implemented an integrated approach to characterize in-situ stress-fields and related fractures utilizing 3D seismic data, cores, petrophysics, and formation micro-imaging logs. Density of fractures was interpreted from integrated analyses of seismic, petrophysical, core, and FMI log data. Fracture orientations were determined from the seismic and FMI log data. Detected fractures in the “Meramec” interval preferentially occur in pervasively calcite-cemented rock with low porosity. Because of the adverse effect of calcite cementation, fractures did not significantly improve reservoir quality within the “Meramec” interval. In contrast, detected fractures in the “Osage” interval added sufficient porosity and permeability to overcome negative cementation effects and improved the overall reservoir quality. This study revealed a rotation of the horizontal stress orientations from ancient stress regimes to the present-day in-situ stress regimes. The study demonstrated the application of integrated seismic and non-seismic data in fracture and stress-field characterization, improved our understanding of the effects of fractures on reservoir quality to reduce risks associated with exploring low-porosity/low-permeability mixed carbonate and siliciclastic reservoirs.

Image Log Facies and Lost Circulation of the Dammam Formation in Rumaila Oil Field, Southern Iraq

One of the most useful logging tools for identifying losses and fractures is Formation Micro Imager. Drilling through the Dammam Formation is typically associated with substantial nonproductive time due to severe and often entire drilling fluid losses. The majority of remedy this problem require time for preparation, placement or setting. Combining between conventional well log and FMI log associated with drilling data, a special study of the shallow Dammam carbonate formation penetrate by wells is accomplished. For a better understanding of the loss mechanism, Image log study was highlighted to imagine the loss zones and as such adapt data to advance loss prevention or cure future scenario. Five images and conventional logs available data associated with drilling operation documents were applied to suggest best subsurface stratigraphic facies in order to knowledge sediment environment of Dammam Formation. Five image log facies were identified as representing the different environments within the different depths, large, fine vugs, carbonate layers, laminate interrupt and laminate. The stratigraphy succession reveals shallowing upward from deep water represented by laminate facies to more disturbed water signified by vuggy large facies. There are six internal picks zone according to GR log sign D90 at the top of Rus Formation, D80, D70, D65, D60, D50 and D40. It has been clear that nearly severe or complete losses events limit intensively in D60 and D65 based on logs interpretation analysis associated with drilling data.

In-situ stress analysis of Ahnet Basin, South western Algeria: A 1D geomechanical approach

This work aims to determine the present-day in-situ stress and pore pressure in the Ahnet Basin, Algeria, through a 1D geomechanical approach. We investigated the drilling-induced fracture (DIF) from FMI log data to ascertain the direction of maximum horizontal stress (SHmax) from the Ahnet Field. A mean orientation of N140° ( ± 10°) has been interpreted, which is NW-SE (N140°-N320°), with a local variation of ( ± 20°) compared to fields such as Illizi, Hassi Messaoud, and North Algeria, which can be explained by depth variation and intrinsic rock properties. A 1.05 psi/ft gradient of overburden stress (Sv) has been obtained from density. Pore pressure has been estimated from the sonic log by a normal compaction trend, indicates a hydrostatic regime from the surface to the top of the Silurian unit with an average pore pressure gradient of 0.43 psi/ft and an overpressure regime against the hot shale unit with a gradient of 0.58 psi/ft caused by the high in situ temperature in the study area and possible activity of the mega-shear zone. The poroelastic approach under transverse isotropic vertical conditions (VTI) has been used to calculate the minimum and maximum horizontal stress magnitudes. The outlines indicate a high-stress gradient close to 0.82 psi/ft, for Shmin calibrated with MDT stress points and 1.10 psi/ft for SHmax. The stress magnitudes results, suggest a present-day normal to strike-slip stress regime in the Ahnet Basin. Fault reactivation potential at two Silurian units has been inferred from the frictional theory analysis. The results indicate that increased pore pressure in hot shale formations due to by fluid injection and hydraulic fracturing causing shear slippage of the pre-existing faults, resulting in induced seismicity. Our study has contributed to the understanding of stress state origin in Ahnet Basin, the relationship between in situ temperature and pore pressure, and the fault stability analysis in such unconventional reservoir development.

Fracture Characteristics and Heat Accumulation of Jixianian Carbonate Reservoirs in the Rongcheng Geothermal Field, Xiong'an New Area

AbstractGeothermal energy plays an important role in urban construction of the Xiong'an New Area. Geothermal reservoir fracture distribution of the Mesoproterozoic Jixianian Wumishan Formation (Fm.) carbonate reservoir in the Rongcheng geothermal field are evaluated based on FMI log from Wells D19 and D21. The results show carbonate reservoir fracture density of Well D19 is 15.2/100 m, greater than that of Well D21 with a value of 9.2/100 m. Reservoir porosity and permeability of Well D19 are better than that of Well D21, and the water saturation is bimodally distributed. The movable fluid volume ratio (BVM) of Well D19 is 2% to 8% with some zones exceeding 20%, while the value of Well D21 is less than 4%. Therefore, reservoir fractures in Well D19 are more conducive to fluid flow. Reservoir fractures have a similar occurrence to normal faults, indicating that the tensile stress field controlled the formation of such fractures. Developed reservoir fractures provide a good channel for groundwater convection. The circulation of regional groundwater and the heat exchange between water and rock and the multiple heat accumulation patterns form a stable and high potential heat reservoir in the Rongcheng geothermal field.

Fracture permeability estimation utilizing conventional well logs and flow zone indicator

Characteristics of the natural open fractures on the oil and gas reservoirs is crucial in drilling and production planning. Direct methods of fractures studies such as core analysis and image log interpretation are usually not performed in all drilled wells in a field. Therefore, in absence of these data, the indirect methods can play an important role. In this study, an integrated algorithm is introduced to identify the fractures and estimate its permeability employing conventional well logs. First, open fractures were identified and their properties including density, aperture, porosity and permeability were estimated using FMI log. Subsequently, the fracture index log (FR_Index) was estimated utilizing conventional logs including density, micro-resistivity, sonic (compressional, shear and stoneley slownesses), and caliper logs. After that, the fracture index permeability was estimated by improving the FZI permeability equation. The coherence coefficient between two estimated fracture permeability logs is 0.66. A good correlation is observed on the high permeability zones, but the lower correlation on the low permeability zones. It is notified that, in the high fracture permeability zones, the conventional logs are heavily impacted by fracture permeability. However, due to lower vertical resolution of conventional logs compared with the image logs, the conventional logs are less influenced by less dense fracture zones. However, this algorithm can be used with acceptable accuracy in all uncored and image log wells.

Identification of fractured-basement reservoir based on integration of FMI Log and seismic attributes in hydrocarbon field “I”, Barito Basin, South Kalimantan

As basement has very small matrix porosity, secondary porosity is needed to store hydrocarbon within the basement. Fracture is a secondary porosity, yet not all fracture can be a good secondary porosity. Open fractures have capability to store hydrocabon, also have important roles in productivity and quality of the pre-tertiary basement reservoir. This study is aimed to identify open fractures using FMI log and seismic attributes in the Field “I”, Barito Basin. Interpreted image log (FMI) on two wells gives the azimuth and dip orientation of open fractures are ENE –WSW, NNW-SSE and WNW-ESE and also the horizontal stress orientation. The stress orientation from image log combined with leak-off test (LOT) data and density log used to identify stress fields. Azimuth and dip orientation of the open fracture from FMI log is the input of the stereonet, as an orientation filter for ant-tracking. Ant-track attribute is based on ant-colony optimization algorithm that captures only continuous features and used as edge enhancement methods for fracture-sensitive attributes. Variance is a fracture-sensitive attribute that applied as input data for ant-track algorithm. The results of ant-track map are well correlated and confirmed by image log analysis. Also, by applying ant-track attribute to the fracture-sensitive attributes succesfully able to identify faults and fractures with better resolution and visualization than only using the fracture-sensitive attribute itself, so it makes easier to interpret and get the information.

Geomechanical analysis on casing deformation in Longmaxi shale formation

Abstract Casing deformation is the most significant problem while developing Longmaxi shale gas formation in Sichuan Basin, southwest China. In one of the operating acreages with 72 horizontal wells, 38 wells encountered casing deformation problems after several stages of hydraulic fracturing treatments. Tremendous lateral lengths were affected, among which some of them were treated with diversion technology during fracturing and some others were simply abandoned. Previous research explores this problem from perspectives of cementing, casing strength and etc. However, after combining all the data, we found that it is likely due to formation slip. In this research, we summarized all the casing deformation positions happened in the area of interest. We then project these positions into the ant-tracking plot. It is found that most of the deformed positions correspond to the fault positions in the ant-tracking plot. Further, we run caliper logs for some of the wells. From the images of the deformed positions, it can be inferred that the casing deformation is due to the formation shear. Based on what we found, we set up a model for fault slip potential. This model is based on Mohr-Coulomb (MC) failure criteria. We use this model to analyze the natural fractures observed from an FMI log. It is found that the increase of pore pressure from hydraulic fracturing jobs can cause natural fractures to slip. However, it cannot cause beddings to slip, which some of the previous research has suggested. The data and analysis in this research confirm that casing deformation in Longmaxi shale formation is caused by fault slip. Other reasons, like voids in cement bond, lithological layers, are not detrimental to this problem. In the end, we presented a method for continuing treatment when casing deformation happens. This method has been utilized in field, and significant downtime is reduced.

Characterization of Basement Fracture Reservoir In Field ‘X’, South Sumatera Basin, Based On The Analysis of Core And FMI Log

Basement reservoir is a reservoir that is located in the basement rock, comprised of either igneous rock or metamorphic rock that has secondary porosity, resulting in its capability to store oil and gas. The research was conducted at field 'X' that is located at South Sumatra basin and it is a part of Jambi Sub-Basin. The study was focused on discussing hydrocarbon potential in Fields 'X', particularly at the basement metamorphic rock. The study was conducted at two wells in the field. The secondary porosity system of the basement is fracture porosity. Fracture analysis as secondary porosity system was performed on two wells, HA-1 and HA-2, by using FMI log interpretation. Based on the analysis of fracture on HA-1 well, the trend of fracture system is Northeast - Southwest (NE-SW) with a fracture porosity of 1.49%. On a different note, the trend of fracture system on HA-2 wells is East Northeast - West Southwest (ENE-WSW) with a fracture porosity of 0.888%. The effect of rock properties itself has little influence on the number of fractures as opposed to the effect of surrounding tectonic forces. The fractures are controlled by geological structures following Jambi pattern that has an orientation of Northeast - Southwest (NE-SW). Although the fracture porosity is relatively small, it is enough to storing hydrocarbons in economical quantity.

Application of time-lapse multi-component seismic inversion to characterize pressure and stimulation in the Niobrara and Codell Reservoirs, Wattenberg Field, Colorado

The Wattenberg field is the fourth-largest oil and ninth largest gas field in the United States (EIA, 2015). A multi-component time-lapse seismic study has been conducted by RCP and Anadarko Petroleum Corporation in the Wattenberg field. This study includes an integrated dataset with seismic, microseismic, FMI log interpretations, and completion information. As part of a horizontal drilling programme, the Niobrara and Codell formations were targeted. P-wave seismic and S-wave seismic were analysed as part of the time-lapse study before and after the completion of 11 horizontal wells in the study area. Time-lapse P-wave pre-stack inversion was able to identify pressure compartments in the different reservoir intervals that were able to be distinguished by the pre-stack data. The inverted P-impedance percentage difference volume allows for identification of pressurized zones and whether the faults are acting as seals or conduits for the hydrocarbons. S-wave data provides a subset of the pressure compartmentalization that encompasses the stimulated reservoir volume. Time-lapse post-stack inversions of the shear wave datasets provide insight into how the shear impedance is affected by hydraulic fracturing through the work of time-lapse shear wave splitting. The inversions show an increase in fast shear wave velocity and a decrease in slow shear velocity after stimulation. The sensitivity of both the fast and slow shear seismic to stimulation correlates with the net pressure trends at each stage as well as base map microseismic patterns. The stimulated volume for the Niobrara and Codell reservoir intervals are now more accurately defined. Timelapse shear wave splitting is able to define the stimulated rock volume and reveal areas that are not being accessed by the wells currently drilled. These areas are now detected within the Wishbone section, and may be candidates for future re-completion.

Drilling fluid loss control via implementing the FMI and DSI logs to protect environment

Implementing the drilling fluids in drilling operations is of paramount importance owing to the variety of applications and benefits they provide. Materials added to drilling fluid could cause numerous environmental problems in soil and water resources, and these problems are more pronounced in offshore as compared to land fields. Heavy metals such as mercury, barium, arsenic, lead, and nickel exist in drilling fluid, which bring detrimental damages to the environment. Moreover, heavy metals exist in oil-based muds due to presence of oil where their nickel and vanadium are much greater than other heavy metals. Additive materials and heavy metals existing in drilling fluid could pose irreparable environmental damage if fluid loss into the formation occurs. Regarding to the fact that drilling fluid loss occurs via the open fractures in the wellbore, the main aim of this study is to evaluation of wellbore fractures via implementing the FMI log and fracturing pressure using the slowness of compressional and shear waves. A total of 61 fractures in Dalan formation and 72 fractures in Kangan formation are interpreted and fracturing pressure for these formations, ranges between 8400 and 9450 psi. Implementing the results obtained from this study, drilling fluid loss into the formation and subsequent environmental damage could be prohibited via controlling the pumping pressure and density variation of drilling fluid in accordance with the formation fracturing pressure.

Reservoir architecture of deep marine slope channel, Scarab field, offshore Nile Delta, Egypt: Application of reservoir characterization

Scarab field is an analog for the deep marine slope channels in Nile Delta of Egypt. It is one of the Pliocene reservoirs in West delta deep marine concession. Channel-1 and channel-2 are considered as main channels of Scarab field. FMI log is used for facies classification and description of the channel subsequences. Core data analysis is integrated with FMI to confirm the lithologic response and used as well for describing the reservoir with high resolution. A detailed description of four wells penetrated through both channels lead to define channel sequences. Some of these sequences are widely extended within the field under study exhibiting a good correlation between the wells. Other sequences were of local distribution. Lithologic sequences are characterized mainly by fining upward in Vshale logs. The repetition of these sequences reflects the stacking pattern and high heterogeneity of the sandstone reservoir. It also refers to the sea level fluctuation which has a direct influence to the facies change. In terms of integration of the previously described sequences with a high resolution seismic data a depositional model has been established. The model defines different stages of the channel using Scarab-2 well as an ideal analog.

Quantitative geophysical pore‐type characterization and its geological implication in carbonate reservoirs

ABSTRACTThis paper discusses and addresses two questions in carbonate reservoir characterization: how to characterize pore‐type distribution quantitatively from well observations and seismic data based on geologic understanding of the reservoir and what geological implications stand behind the pore‐type distribution in carbonate reservoirs. To answer these questions, three geophysical pore types (reference pores, stiff pores and cracks) are defined to represent the average elastic effective properties of complex pore structures. The variability of elastic properties in carbonates can be quantified using a rock physics scheme associated with different volume fractions of geophysical pore types. We also explore the likely geological processes in carbonates based on the proposed rock physics template. The pore‐type inversion result from well log data fits well with the pore geometry revealed by a FMI log and core information. Furthermore, the S‐wave prediction based on the pore‐type inversion result also shows better agreement than the Greensberg‐Castagna relationship, suggesting the potential of this rock physics scheme to characterize the porosity heterogeneity in carbonate reservoirs. We also apply an inversion technique to quantitatively map the geophysical pore‐type distribution from a 2D seismic data set in a carbonate reservoir offshore Brazil. The spatial distributions of the geophysical pore type contain clues about the geological history that overprinted these rocks. Therefore, we analyse how the likely geological processes redistribute pore space of the reservoir rock from the initial depositional porosity and in turn how they impact the reservoir quality.

A new calculating method for carbonate reservoir geological reserves

According to the results of FMI log interpretation and the water cut trend of low permeable carbonate reservoirs, the model of the fluid distribution in the fracture-cavity pore was derived. Based on the material balance principle, assuming the original water contribution to production as constant water influx, a new calculating method for the low permeable carbonate reservoir geological reserves was presented. This method estimated the impact of origin aquifer to the geological reserves. The calculating results of example indicate that comparing to numerical simulation, this new method is high accuracy and easy to use.

Characterization of fractured basement reservoir using statistical and fractal methods

This study presents a characterization of fractured basement reservoir by using statistical and fractal methods with outcrop data, seismic data, as well as FMI log data. In the statistical method, fracture intensity and length have been calculated from various outcrop data. The optimum statistical distribution functions of fracture length for outcrops have been identified with the use of discriminant equation derived from Crofton’s theory. The Fisher distribution constant, representing the fracture orientation, has been computed from FMI log data. With the statistical values and distribution functions, a 3D fracture network system has been generated. The result shows that there is no distinction in orientation of the fracture network system, and it excellently matches with the outcrop data. In the fractal method, fractal dimensions of fracture length and strike for the seismic fracture network in areal distribution were calculated; a greater value in fractal dimension means that the fracture network system has intensive fractal characteristics. Meanwhile, vertical distribution and dip angle of the fracture system have been evaluated from FMI log data. The resulting 3D fracture system presents that the overall strike and distribution of the fracture system are excellently matched with those of seismic data.

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.