Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones
Bennis, Mohamed (The University of Texas at Austin) | Mohamed, Tarek S. (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Merletti, German (bp) | Gelvez, Camilo (bp)
Abstract Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.
- South America (0.93)
- Europe > Norway (0.66)
- North America > United States > Texas > Travis County > Austin (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
In-Reservoir Mixing Dynamics Over Geologic Time of Separate Gas and Oil Charges in Well-Connected Reservoirs
Mohamed, Tarek S. (University of Texas at Austin) | Kristensen, Morten (SLB) | Pan, Shu (SLB) | Wang, Kang (SLB) | Betancourt, Soraya S. (SLB) | Torres-Verdín, Carlos (University of Texas at Austin) | Mullins, Oliver C. (SLB)
Abstract Many reservoirs experience separate gas and oil charges that can lead to a variety of different outcomes of fluid type and distribution. There has been fundamental uncertainty even as to which charge fluid can arrive first, let alone what fluid dynamic processes can result over geologic time. For high-pressure basins such as the Gulf of Mexico, this mixture can lead to increased solution gas, large GOR gradients and sometimes cause formation of viscous oil and tar at the oil-water contact, impacting aquifer support. In some reservoirs, the present-day outcome of oil and gas mixing over geologic time is clearly established by detailed chemical evaluation of reservoir fluids from many reservoir locations. Our objective is to understand the dynamics of the gas and oil mixing processes. Chemical measurements show that the extent of mixing includes thermodynamic equilibration in young reservoirs by 1) FHZ equation of state (EoS) asphaltene gradients and cubic EoS modeling of solution gas for reservoir fluids, 2) analysis of liquid-phase geochemical biomarkers, and 3) methane carbon isotope analysis. Specifically, in the common charge of primary biogenic gas and oil into reservoirs, methane isotope analysis is unequivocal. We employ reservoir simulation of a point gas charge into oil with various geometries and charge rates to establish parametric conditions which lead to excellent mixing vs those conditions that lead to large, disequilibrium gradients. The roles of compositional diffusion vs. momentum diffusion induced by forced convection are explored both in simulation and overall fluid mechanics analysis, which helps both to validate the results and extend the range of applicable parameters. Modeling results and simple fluid mechanics estimates also establish that there is no possibility that these reservoirs could have a gas charge followed by an oil charge; in the selected reservoirs, oil must have arrived first, followed by a biogenic gas charge. Seismic images of gas chimneys offer guidance regarding how the latter process can take place. Second, modeling results clearly establish a surprisingly wide range of charge conditions that can lead to excellent mixing and equilibration even for a point gas charge. Modeling results also show that for a very fast charge, results are consistent with those expected for CO2 injection and sequestration. The evaluation of geodynamic processes of separate biogenic gas and oil charges into reservoirs has rarely been accomplished. Even the result that biogenic gas charge must occur after oil charge challenges widely-held conventional thinking. In addition, the rapid and thorough mixing (less than 2 million years) of gas and oil charges is unexpected yet readily reproduced by reservoir simulation. The ability to connect CO2 sequestration to a wide range of reservoir studies is a novel way to constrain CCS modeling.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Middle East > Qatar (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.19)
- Geology > Rock Type > Sedimentary Rock (0.97)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.90)
- Geology > Geological Subdiscipline > Geochemistry (0.88)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
- (10 more...)
Abstract Data quality of well logs and laboratory measurements is crucial for accurate petrophysical interpretations in formations with complex solid compositions, thin beds, and adverse geometrical conditions . In this paper, we introduce a new method to calibrate and verify the reliability of core data and well logs acquired in spatially complex rocks. The method is based on the numerical simulation of well logs to reproduce the effects of borehole environmental conditions and instrument physics on the measurements. Additionally, high-resolution (HR) core data combined with rock typing and multiwell measurement analysis techniques enable the construction of multilayer formation models. We document the successful application of the new core-well-log calibration method to two wells penetrating a clastic formation in the North Sea. While the numerically simulated well logs match the available borehole measurements in the first well, large measurement discrepancies were observed in the second well. Normalization of nuclear logs in the second well based on core data and numerically simulated well logs improved the assessment of bulk density and neutron porosity by 5% and 20%, respectively, while unnormalized nuclear logs overestimated formation porosity. Multiwell comparisons of well logs also confirmed that measurement accuracy was compromised. The problem with data quality was attributed to a probable inadequate tool calibration, although the log header did not indicate any notable issues. Additionally, numerical simulations of nuclear magnetic resonance (NMR) porosity logs indicated a prominent depth mismatch among well logs. The numerical simulation of well logs based on HR core data enables the detection of inconsistent, noisy, and inaccurate measurements, including cases of abnormal borehole environmental corrections causing biases in petrophysical interpretations.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.91)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Cardium Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Thompson Field (0.89)
- North America > United States > Texas > Fort Worth Basin > Katz Field (0.89)
- Information Technology > Mathematics of Computing (1.00)
- Information Technology > Data Science > Data Quality (1.00)
Abstract Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.
- Personal > Honors (1.00)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.67)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.32)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 826 > Mad Dog Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (5 more...)
Adaptive OCCAM’s inversion for the interpretation of borehole ultra-deep azimuthal resistivity measurements
Saputra, Wardana (The University of Texas at Austin) | Hou, Junsheng (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Davydycheva, Sofia (3D EM Modeling & Inversion JIP) | Druskin, Vladimir (3D EM Modeling & Inversion JIP)
Ultra-deep azimuthal resistivity (UDAR) logging technology has been around for the last two decades. However, the real-time inversion of deep-sensing borehole electromagnetic measurements is still an outstanding challenge to yield a reliable image of subsurface electrical resistivity. In this study, we develop a new procedure for adaptive 1D inversion of UDAR measurements that quantifies the uncertainty of results and implements various measures of data misfit to trigger local higher-dimensional inversions. We construct an augmented linear system for fast and stable OCCAM’s inversion that accounts for data and model weight matrices, as well as priors for adaptive inversion. We further verify the successful application of this adaptive inversion method on three resistivity models inspired by actual reservoir structures explored with commercial UDAR tool configurations.
- Geophysics > Electromagnetic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
Present-day distributions of reservoir fluid properties result from mixing of gas and oil charges, over geologic time. Fluid mixing outcomes are highly variable, covering the whole range of reservoir realizations from simple equilibrated to complex disequilibrium distributions. Fluid dynamic processes lead to current reservoir realizations and are affected by structural flow barriers or depositional stratigraphic barriers such as shale breaks. By understanding hydraulic connectivity implications on oil chemistry, we provide an effective method for the assessment of reservoir connectivity. We introduce a new way of modeling the implications of hydraulic connectivity on reservoir fluid geodynamic processes leading to present-day reservoir realizations. Reservoir simulations over geologic time are used to match complex fluid charges into the reservoir and we compare these results to many measurements of compositional distribution of reservoir fluids as a new way to test the geologic model of the reservoir. Understanding fluid dynamic and mixing processes leads to a reliable assessment of reservoir structures and connectivity profiles.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.95)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
New Iterative Resistivity Modeling Workflow Reduces Uncertainty in the Assessment of Water Saturation in Deeply Invaded Reservoirs
Merletti, German (BP) | Rabinovich, Michael (BP) | Al Hajri, Salim (BP) | Dawson, William (BP) | Farmer, Russell (ADNOC) | Ambia, Joaquin (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin)
Abstract A new iterative modeling workflow has been designed to reduce the uncertainty of water saturation (Sw) calculations in the tight Barik sandstone in the Sultanate of Oman. Results from this case study indicate that Sw can be overestimated by up to 20 s.u. if the as-acquired deep resistivity is used in volumetric calculations. Overbalanced drilling causes deep invasion of water-based mud (WBM) filtrate into porous and permeable rocks, leading to the radial displacement of in-situ saturating fluids away from the wellbore. In low-porosity reservoirs drilled with WBM, the inability of the filtration process to quickly build impermeable mudcake translates into long radial transition zones. Under certain reservoir and drilling conditions, deep resistivity logs cannot reliably measure true formation resistivity and are, therefore, unable to provide an accurate assessment of hydrocarbon saturation. The effect of mud-filtrate invasion on resistivity logs has been extensively documented. Processing techniques use resistivity inversion and tool-specific forward modeling to provide uninvaded formation resistivity logs, which are much better suited for in-place resource volume assessment. However, sensitivity analysis shows that the accuracy of invasion-corrected logs dramatically decreases as the depth of invasion increases, whereby the inversion process needs to be further constrained. The new workflow is designed to reduce the non-uniqueness of true formation resistivity models so that they honor multiple and independent petrophysical data. The inversion routine utilizes a Bayesian algorithm coupled with Markov-Chain Monte Carlo (MCMC) sampling. Inversion results are iteratively modified based on two rock property models : one derived from rock-core data (helium expansion porosity and Dean-Stark saturations) and the other using an equivalent log interpretation of thick reservoir intervals from oil-based mud (OBM) wells. Simulated borehole resistivity is compared to field logs after each validation loop against rock property models. The new inversion-based workflow is extensively tested in the unconventional tight Barik Formation across water-free hydrocarbon and perched water intervals, and inversion-derived Sw models are independently validated by capillary-pressure-derived saturation-height models and fluid inflow rate from production logs.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Oman > Central Oman (0.24)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.35)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Miqrat Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Buah Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Barik Formation (0.99)
- (7 more...)
Abstract We develop and successfully verify a reliable method that matches the fieldwide oil and gas production from all horizontal hydrofractured wells in the Eagle Ford Shale and calculate the play-wide Estimated Ultimate Recovery (EUR). Unlike purely empirical industry-standard forecasting methods, our approach relies on the physics of hydrocarbon flow in a hydrofractured shale geometry and captures the probabilistic uncertainty of shale geology and well productivity. For this study, the Eagle Ford play is divided into 24 spatiotemporal well cohorts based on shale geology, fluid composition, and completion date. For each well cohort, we fit the distribution of annual production via Generalized Extreme Value statistics. Expected values are then used to construct historical well prototypes. Next, we extrapolate these well prototypes for up to two more decades, using a physical scaling method that accounts for variations in fluid composition across the Eagle Ford Shale. The resulting well prototypes provide robust history matches and predictions of total field production. Finally, to estimate the play-wide EUR, we calculate the well infill potentials for each subregion of Eagle Ford, then we assign the well prototype to each of the potential wells. Based on fluid composition and shale geology, we first mapped all Eagle Ford wells into eight spatial cohorts. To capture the advancement of completion technologies over time, we further divided the well cohorts into three completion date intervals. The total 25,707 existing wells in the Eagle Ford will ultimately yield 2.53 Gbbl of crude oil, 2.79 Gbbl of natural gas liquid (NGL), and 25.67 Tscf of natural gas by 2035. We found that there are 50,115 potential wells that can be drilled across 18,665 sq. mi of Eagle Ford play. With future drilling programs, there will be additional 8.60 Gbbl of crude oil, 2.42 Gbbl of NGL, and 63.7 Tscf of natural gas by 2065. To our knowledge, this project is the first successful attempt to evaluate the play-wide ultimate recovery of the Eagle Ford shale combining physical scaling, generalized extreme value statistics, play geology, and realistic future drilling programs. We also develop a new reserve-assessment method in shales that considers not only the geology of the shale play geology, but also the production dynamics with uncertainty quantifications. In our opinion, this hybrid, data-driven, and physics-based approach is the future of production forecasting and reserves estimation in all shale plays which also provides an objective way of avoiding estimates that are unrealistically low or high.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.96)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (38 more...)
Limits of 3D Detectability and Resolution of LWD Deep-Sensing Borehole Electromagnetic Measurements Acquired in the Norwegian Continental Shelf
Jahani, Nazanin (NORCE Norwegian Research Centre, Bergen, Norway) | Torres-Verdín, Carlos (The University of Texas at Austin) | Hou, Junsheng (The University of Texas at Austin) | Tveranger, Jan (NORCE Norwegian Research Centre, Bergen, Norway)
ABSTRACT The Grane Field in the central North Sea contains numerous sandstone injectites embedded in shale formations and located above the main sandstone reservoir. Because seismic measurements cannot detect 3D small-scale sandstone injectites, they can be misinterpreted during pre-drilling planning, resulting in mud loss circulation when approaching shallow and unstable background shale. Inversion of deep-sensing electromagnetic (EM) borehole measurements provides a resistivity image of formations surrounding the wellbore, which can be used to detect and appraise 3D small-scale sandstone injectites up to a certain radial distance from the wellbore. Borehole EM measurements, however, have limited spatial resolution, potentially resulting in incorrect inversion-based geological interpretations and fatal geosteering decisions when sandstone injectites are located beyond their detection range. Our primary objective is to (1) quantify the spatial resolution of single small-scale sandstone injectites for a commercially available tri-axial deep-sensing borehole EM instrument operating in the Grane Field in terms of (a) measurement acquisition parameters, (b) distance between the well trajectory and targeted injectites, and (2) identify which components of the measured EM tensor can be used to resolve 3D injectites and correlate them to inversion uncertainty. We constructed several 3D synthetic models stemming from actual formations in the Grane Field, including single 30ft (9 m)-tick sandstone injectites overlying 196 ft (60 m)-tick sandstone reservoirs, at varying radial distances from the well trajectory, and varying measurement acquisition parameters. A finite-volume method was used to numerically solve Maxwell's equations for 3D heterogeneous rock formations. Measurement noise was assumed zero-mean 2% Gaussian. There are several factors that govern measurement resolution and distance to which borehole EM measurements can accurately resolve 3D sandstone injectites, such as resistivity contrast with the background formation, measurement noise, frequency of operation, and distance between transmitter and receivers. INTRODUCTION Sandstone injectites are intrusions formed during the remobilization of injected sandstone, which form a complex network and can be found hundreds of meters above the main sandstone reservoir (Hurst et al., 2011). This structure increases the flow of hydrocarbons between reservoirs and makes it attractive for hydrocarbon exploration and production. However, drilling into sandstone injectites may result in mud loss if they are embedded in shallow and unstable shale. The Grane Field, located on the west coast of Norway, contains the Heimdal Formation, a sandstone reservoir that produces oil, and the seal of Lista Formation shales. There is an illustration inspired by the Heimdal formation and its overlying shale with sandstone injectites in both Figure 1 and Figure 2. From the sandstone Heimdal formation, sandstone injectites extend into the overlying Lista formation. Sandstone injectites serve as oil reservoirs, but most of them are below seismic resolution. Bradaric et al. (2022) studied the seismic signature of small-scale sandstone injectites above massive sandstone units. They concluded that densely-spaced injectites with a high thickness (50 ft or 15 m) can improve their resolution and detection. Although seismic data from the Grane Field show irregularities, it is not possible to define the geometry of sandstone injectites based on seismic data alone. Sandstone injectites may be mistaken for main reservoirs when placing wells in real time, hence it is important to detect them, and define their geometry, spatial distribution, electrical conductivity, and distance from the well trajectory while placing the well.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Europe > Norway > North Sea > Heimdal Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 069 > Block 25/11 > Grane Field > Heimdal Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Shetland Group > Lista Formation (0.99)