Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.
High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.
Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.
Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
Image processing of high-resolution 3D images to create digital representation of pore microstructures for image-based rock physics simulations remains a highly subjective enterprise, despite the seemly precision associated with improving imaging resolutions and intensive parallel computations. The decisions on how to identify pore space, both macro- and micropores, and various mineral components remain very much dependent upon user choices and biases. This study demonstrates how uncertainty can be quantified for a highly subjective segmentation process. A set of shaly sand samples with significant amounts of authigenic chlorite/smectite that lines larger pores was tested to identify uncertainty quantification (UQ) requirements associated with image-processing steps, segmentation in particular. Much of the porosity in these coarse-grain samples is associated with subresolution micropores that complicates their assignment in any pore-grain segmentation strategy. Two segmentation strategies, a binary segmentation with a linear-threshold and a machine-learning (ML) approach to two-phase segmentation, are employed with different UQ parameter space. The contribution of resolvable macropores in these samples, and their spatial distributions with regard to pore-lining clay mineral with unresolvable microporosity, are iteratively studied over the defined UQ parameter space, and cross-validated by independent NMR and MICP measurements. The pore structure extracted from these different iterations was the basis of simulations for basic petrophysical properties. Upon cross-validation of simulated results with measured core properties, a UQ framework is proposed to assess the differences between the different measurements from three angles: sampling, numerical and physical.
Merza Media, Adeyosfi (Schlumberger) | Muhajir, Muhajir (Pertamina Hulu Energi Tuban East Java) | M. Wahdanadi, Haidar (Joint Operating Body Pertamina Petrochina East Java) | Agus Heru, Purwanto (Joint Operating Body Pertamina Petrochina East Java) | Anugrah, Pradana (Schlumberger) | Dedi, Juandi (Schlumberger)
Most of sedimentary basins in Indonesia contain productive carbonate reservoirs. Geologically, the reservoirs are mostly part of a reef complex and carbonate platform, with basinal areas situated mainly in the back arc of the archipelago. Many of the productive carbonate reservoirs have dual porosity systems with widely varying proportions of primary and secondary porosity. Carbonates of the Tuban formation in Platinum field represent two carbonate buildups identified with similar effective porosity but different productivity. This paper describes a method for characterizing secondary porosity distribution at the wellbore and field scales to address the productivity difference between the northern and southern carbonate buildups in this field.
To resolve the challenges in characterizing secondary porosity in a carbonate formation, an integrated workflow was developed that consists of combination of quantitative and textural analysis based on borehole images at the single-wellbore scale and the seismic inversion result to control lateral distribution at the field scale. Analysis based on borehole image log provides high-resolution porosity characterization based on its size, interconnectivity, and type. The result of the single-wellbore analysis will be distributed at the field scale with control of a seismic attribute such as acoustic impedance (AI). Acoustic impedance is built with stochastic seismic inversion to provide a higher-resolution result compared to the deterministic seismic inversion method.
The result of the analysis based on borehole images at the single-wellbore scale shows most of the northern carbonate buildup wells demonstrate high development of porosity from interconnected vugs, leading to a relatively high permeability interval. In contrast, the southern carbonate buildup wells demonstrated low secondary porosity development. Low secondary porosity development is related to cemented zones and the predominance of claystone facies in a well. Later, the result of the single-wellbore scale analysis was distributed at the field scale with seismic attribute control such as AI. The Platinum field shows a negative correlation between AI and porosity with a value of -0.769; hence, the acoustic impedance from stochastic seismic inversion can be used to control the porosity distribution. The secondary porosity model shows a distinct difference between the northern and the southern carbonate buildups. The northern carbonate buildup has higher average secondary porosity compared to the southern carbonate buildup. The result was confirmed with production data; the northern carbonate buildup has higher productivity compared to the southern carbonate buildup.
This integrated workflow provides a comprehensive and high-resolution analysis of secondary porosity distribution at the single-wellbore scale and the field scale. Thus, this workflow can reduce uncertainty during reservoir characterization, well placement, and production planning.
Mudstone (shale) reservoir evaluation and efficient development poses a significant challenge due to the heterogeneous nature of these complex formations. Organic-rich shales are characterized by intricate mineralogy, ultra-low nanoporosity, and nano-darcy permeability making these tight source/reservoir rocks challenging in obtaining economically viable hydrocarbons. Consequently, characterizing and quantifying minerology and intra-/interparticle (non)organic-hosted porosity at the pore-scale, and up-scaling it to the core-scale remains a significant focus of evaluating reservoir quality in shale plays.
Current advances in correlative multi-scale and multi-modal 2D/3D imaging of nanoporous geomaterials, such as shales, provide a tremendous opportunity to characterize and represent these rocks over multiple length scales – from core-to pore-scale. Subsequently, these image datasets can be then used for advanced image analysis and digital rock modeling to reconstruct 2D/3D models used to analyze their petrophysical properties.
In this study, the Mancos Shale from the Uinta Basin – one of the most promising shale plays in the United States (
Structural dip is the term used in borehole image and dipmeter interpretation to indicate the "tectonic" tilting in the vicinity of the wellbore. Structural dip, by definition, is the formation dip component that is caused by tectonic deformation such as folding, faulting, uplift and others.
Knowledge of the structural dip in the vicinity of the borehole is essential for several applications, including field structural modeling, well placement, geosteering of the lateral sections, and seismic data processing.
Traditionally, structural dip is computed from borehole image data using laminated shale dip based on the assumption that the laminated shale was deposited out of suspension and that the lamination was originally deposited as horizontal beds. This means that any tilting observed in laminated shale with "coherent" lamination is caused by tectonic tilting; hence, it can be used to compute the structural dip. There is nearly a consensus in the industry around this assumption, and the laminated shale dip is widely used to compute structural dip.
There are several geological settings under which laminated shale can form. Those are mostly subaqueous setting such as marine and lacustrine settings. Drilling through rocks deposited in such settings normally encounters sequences of laminated shale from which structural dip can be computed. However, rock formations deposited in subaerial environments often lacks settings under which laminated shale forms. Such environments are often dominated by sandstone lithologies deposited in high- energy settings this rich in sedimentary structures such as crossbedding. Due to absence of laminated shale sequences, computation of structural dip using the traditional approach is not possible.
This paper explains a technique that can be used to estimate structural dip from cross bedding on borehole images. It uses the geometrical relationship between the crossbedding surfaces and the lower set boundary of the corresponding crossbedding set. The line of intersection between these two surfaces is assumed to be horizontal at the time of deposition. Measuring multiple lines of intersections, plotting them on a stereonet, and fitting a great circle to them helps estimate the structural dip within the analyzed interval. The best- fitting great circle of these lines is believed to be a reasonable estimation of the structural dip.
This approach has been tested on few image log datasets with cross bedded sandstone facies and proved to be very close to the actual structural dip computation obtained from the shale facies in the same depositional sequence. This paper will illustrate some interpreted image log supporting this technique.
Guan, Lijun (CNOOC Shenzhen) | Wang, Xiannan (CNOOC Shenzhen) | Xiao, Dong (CNOOC Shenzhen) | Shim, Yen Han (Schlumberger) | Maggs, David (Schlumberger) | Maeso, Carlos (Schlumberger) | Legendre, Fabienne (Schlumberger) | Leech, Richard (Schlumberger) | Qu, Chang Wei (Schlumberger)
During field testing of a logging-while-drilling (LWD) laterolog resistivity and imaging tool, formation resistivity differences were observed between the new laterolog and standard propagation resistivity. This paper compares the resistivity measurement acquired in the same borehole using different tools in both sand and shale formations. In addition, the high-resolution images acquired by the new tool are used for a detailed geolgical analysis of the sequence.
The high-resolution images acquired by the tool are used to determine the sedimentary environments in this complex fan delta sequence. A wide range of facies types can be identified on the images and correlated to available core with detailed examples shown of the key reservoir facies (distibutary channels and mouth bars). The images also provide valuable structural, depositional trend and insitu stress information for this well.
The laterolog resistivities were higher in the shales and lower in the sands than the propagation resistivity values. The data was acquired while drilling in a water-based mud, sub-vertical exploration well in the South China Sea. While the main objective of the data acquisition in the siliciclastic formations was high-definition resistivity borehole images for detailed geological description, the radial laterolog resistivity response was also of interest. An advanced wireline multi-frequency dielectric measurement was also acquired, and its response was used for comparison and validation.
In this paper, we associate the differences in resistivity response for varying formation properties to the tool physics, vertical resolution, depth of investigation, and time after bit between the measurements. In the sands, a resistivity inversion was applied to correct the logs for invasion effects and forward modeling used to resolve the resolution differences. The inverted formation resistivity from the LWD laterolog matches the deeper reading LWD propagation resistivity. The shale response was initially found to be more difficult to explain. It is commonly and historically accepted that due to resistivity anisotropy laterolog reads higher than propagation resistivity in low angle wells with laminated formations. Advanced forward modeling was used to investigate the laminations observed on the high-definition images and high-resolution laterolog resistivity curves. Although a model could be created to match both sets of resistivity measurements, the level of anisotropy required was considerably higher than expected, and supplementary information was required to validate the model. The wireline multi-frequency dielectric measurements provided the additional information required to confirm the anisotropy contrast observed by the resistivity modeling and confirm the LWD tool responses.
This paper will compare the tool responses, and to determine the correct sand and shale resistivity. It will show how by combining different measurements, additional insight can be obtained into the nature of the formation and its properties.
Sazali, Wan Muhammad Luqman (Petronas Research Sdn. Bhd.) | Md Shah, Sahriza Salwani (Petronas Research Sdn. Bhd.) | Kashim, M. Zuhaili (Petronas Research Sdn. Bhd.) | Kantaatmadja, Budi Priyatna (Petronas Research Sdn. Bhd.) | Knuefing, Lydia (Australian National University) | Young, Benjamin (Thermo Fisher Scientific)
PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.
Carbonate reservoirs are often comprised of a heterogeneous pore system within a matrix of variably distributed minerals including anhydrite, dolomite, and calcite. When describing carbonate thin sections, it is routine to assign relative abundance levels to each of these components, which are qualitative to semi-quantitative (e.g. point-counting) and vary greatly depending on the petrographer. Over the past few decades, image analysis has gained wide use among petrographers, however, thin section characterization using this technique has been primarily limited to the pore space due to the difficulty associated with optical recognition beyond the blue-dyed epoxy associated with the pores. Here, we present a new method of computerized object-based image segmentation (Quantitative Digital Petrography: QDP) that relies on a predefined rule set to enable rapid, automated thin section quantification with only minor human interaction. We have developed a novel work flow that automatically isolates the sample on a high-resolution (i.e. <1μm/pixel) scanned thin section, segments the image, and assigns those segments to predefined categories – e.g., pores, cement, grains, etc. Using this technique, statistically relevant numbers of thin sections can be rapidly processed and quality controlled, thereby allowing quantitative data such as MICP, wettability, and surveillance data to be integrated with the petrographic observations for a more complete description of the carbonate rock. Our technique can also incorporate multiple layers, such as cross-polarization, Back Scatter Electron (BSE) imaging, and elemental maps, which allow additional information to be easily integrated with results from QDP. The QDP approach is a significant improvement over previous digital image analysis methods because it 1) does not require binarization, 2) eliminates the subjectivity in assessing abundance levels, 3) requires less hands-on time for the petrographer, and 4) provides a much fuller dataset that can be incorporated across an entire well or field to better address common challenges associated with carbonate reservoir characterization, such as understanding pore type and cement abundance, pore connectivity, grain distribution, and reservoir flow characteristics.