Static Geological Model Research Articles

Integrated Geomodel Accuracy Enhancement Based on Embedded MPS Geological Modeling for Thin Interbedded Reservoirs

Continental delta deposits are characterized by strong heterogeneity in the lateral direction; meanwhile, reservoir development is challenged by rapid changes in rock properties. Thus, it is critical to use proper methods for fine characterization to confirm the distributions of thin interbedded reservoirs. The aim of this study was to propose a novel workflow for integrated research on the 3D geomodeling of thin interbedded reservoirs, using the Triassic T2a1 formation in the Tahe Oilfield B9 area of the Tarim Basin as a case study. The complicated representation of thin interbeds in a 3D geomodel was simulated using a multiscale joint controlling strategy, based on wells (Points), 2D geological cross-sections (Lines), and horizontal wells (Surfaces). The resistivity inversion results from the horizontal wells validated the proof of the plane distribution of the thin interbeds within the drilled area, and this quantitative statistic provided effective parameters and guidance for 3D interbed geomodeling. In this study, comprehensive 3D facies modeling was divided into 3D interbed geomodeling and 3D sedimentary facies modeling. An optimized interbed geomodel was picked out from multiple stochastic simulation realizations, and the drilled horizontal well data were used to constrain the simulation process, so the simulation results were more consistent with the real distribution of the thin interbed morphology. Classical two-point geostatistical methods, the multipoint simulation (MPS) geostatistical method, and the hierarchical mindset were integrated for the microfacies simulation. This procedure demonstrated a good ability to characterize thin interbed reservoirs in continental delta deposits. An MPS training image obtained from a high-resolution satellite photo was used to fix the issue of the relationships between the distributions and configurations of all microfacies within the spatial distribution. A 3D lithofacies interbed model was embedded into the 3D facies model. This comprehensive facies model served as a constraint condition in the property modeling process. A porosity model was simulated using separate stratigraphy and individual microfacies controls, as facies-controlled property modeling has been used as a prior foundation for field development planning in the Tahe Oilfield B9 case. The porosity model was then used as a basis for permeability modeling, and a water saturation model was created using the J function and all of the constraints from the other two property models. Finally, all the results were validated using dynamic production data from the Tahe Oilfield B9 wells, with good matching observed between the geological models. There was only a 0.92% difference in reservoir volume between the reservoir simulation results and the static geological model results using our solution.

How to estimate the 3D stress state for a deep geological repository

Abstract. When stresses yield a critical value, rock breaks or pre-existing faults are reactivated, generating pathways for fluid migration. Thus, the contemporary undisturbed stress state is a key parameter for assessing the stability of deep geological repositories and for quantifying whether stress changes induced by sub-surface constructions and storage of heat-generating waste lead to a critical state. The prediction of the contemporary 3D stress state is achieved with geomechanical–numerical models that are based on the static geological models. These are based on 3D seismic imaging and borehole data and describe the 3D structure and distribution of rock properties. Furthermore, pointwise measurements of the stress state are needed to fit the model to these data. The workshop is divided into three parts. Each part will have a short introduction to the specific topic, followed by dedicated hands-on exercise in small groups and discussions of the exercise outcome and its implications. 1. How do we formally describe the stress field? Here you will learn that the stress field is different from other physical field quantities such as temperature or displacement. The latter can be described with a scalar or a vector at a point. In contrast, the stress state at a point is described with the so-called Cauchy stress tensor that has nine components. We will give a quick tour through this concept, starting from very basic physics, and explain why the tensor is needed. In particular, you will learn in the exercises that stress cannot be measured directly with most methods but that strain is observed, from which stress is inferred.2. How do we actually measure stress? We present a range of methods that determine individual components of the stress state. In the exercise you will analyse borehole image logs to identify borehole breakouts and drilling-induced tensile fractures at the borehole wall. These are used to derive the orientation of the minimum and maximum horizontal stresses. Furthermore, we will present methods for the estimation of stress magnitudes. These are essential data for the calibration of a 3D geomechanical model. We will give a brief overview of different methods and in the exercise on the analysis of mini-hydraulic fracture tests as well as on the sleeve-fracturing and sleeve re-opening methods.3. From a viewpoint to a 3D description. If rock properties in the sub-surface were homogenous and isotropic and were to follow a simple linear behaviour between stress and strain, we could estimate the stress state analytically. However, this is not the case, and we will discuss three questions. a. How many pointwise stress data are needed to efficiently constrain a 3D model?b. How do I know whether a data point taken from less than a cubic metre is a good representation of a large rock volume, i.e. a whole lithological layer?c. How can we quantify the uncertainties of the model stress state, and what is the typical range? You will use a case study in northern Switzerland to explore these questions.

Maximising gas production from late-life assets: a case study from the Snapper Field, Gippsland Basin

Discovered in 1968 and developed in 1981, the Snapper Field has supplied oil and gas to Australia’s eastern seaboard for over 40 years. The field consists of a broad northeast–southwest trending faulted anticline within the Eocene and Paleocene sands of the Latrobe Group. Reserves in 2023 are within the shallowest reservoir interval – the N-1 – which had an original gas in place of approximately 3.8 Tcf. Pressure and wireline log data acquired during exploration and development suggested that the Snapper Field was horizontally and vertically well connected, and it was expected that individual intervals within the N-1 reservoir would water-out sequentially from the bottom to the top of the reservoir during production. As a result, the risk of water over-running gas, and bypassed gas was considered to be low. Production and logging results in 2017 proved otherwise, prompting a period of renewed study from 2019 to 2022. This paper focusses on the culmination of this work effort: construction of a new static geological model and dynamic simulation model, which was built upon and expanded previous models completed prior to 2019. The insights from this study have demonstrated the importance of ongoing and regular reservoir surveillance and the significant value that the construction of new static and dynamic models can add to late-life oil and gas fields. This study showed a later end of field life than previous estimates and an increase in reserves by up to ~20% through the optimisation of future work-over programs. The Snapper Field is owned by ExxonMobil (50%) and Woodside Energy (50%) and is operated by ExxonMobil.

Economic and operational investigation of CO2 sequestration through enhanced oil recovery in unconventional reservoirs in Colorado, USA

The ongoing CCUS commercial projects are highly relied on the support of government incentives due to massive capital investment. This study analyzes the economics of carbon capture utilization and sequestration (CCUS) projects, shows a state-wide CCUS deployment exercise, followed by simulation results of enhanced oil recovery (EOR) based CO2 storage in unconventional reservoirs. The comprehensive economic analysis of capture, transportation, sequestration costs, enhanced 45Q tax credits, and EOR revenue implies the practicality of CO2-EOR to offset the high CCUS costs. With the economics understanding, we study the top CO2 sources, existing CO2 pipelines, and sequestration sinks in the state of Colorado, USA. This paper next presents results from EOR simulation in one section of the unconventional Denver-Julesburg (DJ) Basin Niobrara and Codell reservoirs. The simulation model is based on a geological static model, incorporated with hydraulic fracture stimulation, history matched to production, and calibrated to the microseismic and time-lapse surface seismic data. The CO2-EOR simulation results show that oil production can be increased and more CO2 stored with: a longer primary production period; the presence of a shut-in period; higher injection rates; and multi-well injectors. The modeling results show that about 7–10 Mscf of CO2 will be stored when recovering 1 stb of EOR oil. By adding the enhanced oil revenue and the carbon credits together, it is estimated that the most economic case can generate $13 MM when oil price is assumed to be $80/stb, and the EOR oil revenue is 3.4 times greater than that generated from 45Q incentives. It corresponds to the scenario that a five-year primary production is followed by CO2 injection into four wells with the sequence of injection (4 MMscf/day for 6 months), shut-in (6 months) and production (12 months). The best practices in this study will provide valuable insights for similar CCUS projects in other unconventional fields. Furthermore, this study defines a term named “Carbon Neutrality Index (CNI)” by comparing the amount of CO2 stored with that burned by EOR oil. The CNI value of 0 indicates the enhanced oil is carbon neutral; a negative CNI value implies there is a net reduction in carbon emission. The 4-year huff-n-puff (HnP) simulation leads to a positive CNI value, indicating that the EOR oil generated in this process is not carbon neutral yet.

Geologic controls on the genesis of the Arctic permafrost and sub-permafrost methane hydrate-bearing system in the Beaufort–Mackenzie Delta

The Canadian Mackenzie Delta exhibits a high volume of proven sub-permafrost gas hydrates that naturally trap a significant amount of deep-sourced thermogenic methane (CH4) at the Mallik site. The present study aims to validate the proposed Arctic sub-permafrost gas hydrate formation mechanism, implying that CH4-rich fluids were vertically transported from deep overpressurized zones via geologic fault systems and formed the present-day observed GH deposit since the Late Pleistocene. Given this hypothesis, the coastal permafrost began to form since the early Pleistocene sea-level retreat, steadily increasing in thickness until 1 Million years (Ma) ago. Data from well logs and 2D seismic profiles were digitized to establish the first field-scale static geologic 3D model of the Mallik site, and to comprehensively study the genesis of the permafrost and its associated GH system. The implemented 3D model considers the spatially heterogeneously distributed hydraulic properties of the individual lithologies at the Mallik site. Simulations using a proven thermo-hydro-chemical numerical framework were employed to gain insights into the hydrogeologic role of the regional fault systems in view of the CH4-rich fluid migration and the geologic controls on the spatial extent of the sub-permafrost GH accumulations during the past 1 Ma. For >87% of the Mallik well sections, the predicted permafrost thickness deviates from the observations by less than 0.8%, which validates the general model implementation. The simulated ice-bearing permafrost and GH interval thicknesses as well as sub-permafrost temperature profiles are consistent with the respective field observations, confirming our introduced hypothesis. The spatial distribution of GHs is a result of the comprehensive interaction between various processes, including the source-gas generation rate, subsurface temperature, and the hydraulic properties of the structural geologic features. Overall, the good agreement between simulations and observations demonstrates that the present study provides a valid representation of the geologic controls driving the complex permafrost-GH system. The model’s applicability for the prediction of GH deposits in permafrost settings in terms of their thicknesses and saturations can provide relevant contributions to future GH exploration and exploitation.

Basin modeling constrains source rock position and dimension in the Burano-Bolognano petroleum system (Central Italy)

A two-dimensional basin and petroleum system modeling approach was applied to the Burano-Bolognano petroleum system (Central Italy) to constrain some factors (position, lateral extension and maturity of the source rock, the role of fractures and faults in hydrocarbon migration) which influenced its structural evolution and the related migration pathways. The petroleum system extends from the Majella Mountain to the northern Cigno, Vallecupa, Bonanno oil fields, intensively explored during the past century. Some features, such as the location and extension of the source rock and its maturity, and hydrocarbon pathways, are still undefined. Thus, we developed a 3D geological static model of the Cenozoic carbonate succession and then, we performed basin modeling along a 2D geological section, integrating the petrophysical properties of rocks measured in laboratory. Our results prove that the Burano source rock reached a low-middle maturity, and the best representation of the actual hydrocarbon occurrences is reached when the source rock is at north of the Majella Mountain with a minimum extension of 3 km. For the BBPS a strong lateral migration and a gradual oil biodegradation towards the Majella area must be considered. Moreover, modeling results highlight a minor control of the faults on the migration in this area. This basin modeling is relevance for investigations in similar settings since carbonate-ramp reservoir studies are usually very challenging to be correctly modeled due to their high heterogeneities.

Application of Temperature Fall-Off Interpretation Method in Superheavy Oil or Oil Sand SAGD Process

SAGD technology has been successfully and widely applied in the development of superheavy oil and oil sand projects. Before normal SAGD process, some preheating ways are often needed to realize interwell hydraulic connection, and this means that determining reasonable SAGD conversion timing from the preheating stage is an essential precondition for good performance. Previous numerical simulations or qualitative analysis of temperature fall-off data are often adopted in the industry, but they have deficiencies in terms of dependent on static geological model or insufficient data utilization. Therefore, on the basis of the temperature and pressure monitoring process comparison in China’s superheavy oil and Canada’s oil sand projects, this paper proposed a temperature fall-off interpretation model to obtain thermal diffusivity and preheating radius at different measurement points along the horizontal section by combining an unsteady thermal conduction model under constant heating power of wellbores in the radial coordinate system and approximately unsteady thermal conduction model with constant wellbore temperature and Fourier’s law of thermal conduction. Besides, the duration time, interpretation method, and application flow chart of temperature fall-off test were presented. Then, it was validated to successfully determine the timing of SAGD conversion from the preheating stage by an example combining with tracking numerical simulation, temperature inflection point analysis, and index analysis during the partial-SAGD and initial SAGD stages. The findings of this study can help determine the SAGD conversion timing from the preheating stage simpler and faster especially for the case of long horizontal well section deployed with more temperature measurement points.

Integrating the Geology, Seismic Attributes, and Production of Reservoirs to Adjust Interwell Areas

Abstract —Dynamic models of the seismic, geological, and flow characteristics of a reservoir are the main tool used to evaluate the potential of drilling new infill wells. Static geological models are mainly based on borehole data combined with dynamic analyses of production dynamics. They are used to determine the redevelopment of and adjustments to new drilling locations; however, such models rarely incorporate seismic data. Consequently, it is difficult to control the changes in geological models between wells, which results in the configuration of well positions and predicted results being less than ideal. To improve the development of adjusted areas in terms of their remaining oil contents, we developed a new integrated analysis that combines static sediment modelling, including microfacies analysis (among other reservoir and seismic properties), with production behaviours. Here, we illustrate this new process by (1) establishing favourable areas for static geological analysis; (2) studying well recompletion potential and the condition of non-producing wells; (3) conducting interwell analyses with seismic and sedimentary data; (4) identifying potential sites constrained by seismic and geological studies, as well as initial oilfield production; (5) providing suggestions in a new well development plan.

Assessing the Geothermal Resource Potential of an Active Oil Field by Integrating a 3D Geological Model With the Hydro-Thermal Coupled Simulation

Assessment of available geothermal resources in the deep oil field is important to the synergy exploitation of oil and geothermal resources. A revised volumetric approach is proposed in this work for evaluating deep geothermal potential in an active oil field by integrating a 3D geological model into a hydrothermal (HT)-coupled numerical model. Based on the analysis of the geological data and geothermal conditions, a 3D geological model is established with respect to the study area, which is discretized into grids or elements represented in the geological model. An HT-coupled numerical model was applied based on the static geological model to approximate the natural-state model of the geothermal reservoir, where the thermal distribution information can be extracted. Then the geothermal resource in each small grid element is calculated using a volumetric method, and the overall geothermal resource of the reservoirs can be obtained by making an integration over each element of the geological model. A further parametric study is carried out to investigate the influence of oil and gas saturations on the overall heat resources. The 3D geological model can provide detailed information on the reservoir volume, while the HT natural-state numerical model addressed the temperature distribution in the reservoir by taking into account complex geological structures and contrast heterogeneity. Therefore, integrating the 3D geological modeling and HT numerical model into the geothermal resource assessment improved its accuracy and helped to identify the distribution map of the available geothermal resources, which indicate optimal locations for further development and utilization of the geothermal resources. The Caofeidian new town Jidong oil field serves as an example to depict the calculation workflow. The simulation results demonstrate in the Caofeidian new town geothermal reservoir that the total amount of geothermal resources, using the proposed calculation method, is found to be 1.23e+18 J, and the total geothermal fluid volume is 8.97e+8 m3. Moreover, this approach clearly identifies the regions with the highest potential for geothermal resources. We believe this approach provides an alternative method for geothermal potential assessment in oil fields, which can be also applied globally.

Waterflooding efficiency estimation using capacitance-resistance model with non-linear productivity index

A modified Capacitive Resistive Model (CRM), with a non-linear Productivity Index (PI), has been suggested to evaluate efficiency of waterflooding in heterogeneous reservoirs. CRM model is based on continuity equation between production and injection, and has several additional advantages. The technique does not require sophisticated geological and hydrodynamics numerical simulation modeling, which would require expensive computing time and based on actual hydrodynamic data. The model adequately describes depletion process and can be used for production forecasting and waterflooding mechanism. Capacitance-resistance model with non-linear productivity index has been tested against numerical model as well as actual production data. Additionally, non-linear productivity index based CRM model was compared against the CRM model with linear productivity index function. The calculations algorithm does not require building static geological models and running dynamic simulations, nor it demands extensive computational resources and time, thanks to using production and injection history only, therefore it can be deployed easily. Keywords: waterflooding; capacitance-resistance model; non-linear productivity index; efficiency; monitoring; forecast.

Natural-Gas-Foam Fluid Reduces Water Needed for Fracture Stimulations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201450, “Reducing the Volume of Water Needed For Hydraulic Fracturing by Using Natural-Gas-Foamed Stimulation Fluid,” by Raj Malpani, SPE, Chris Daeffler, and Sandeep Verma, SPE, Schlumberger, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. NG-Foam Fluids Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits. The authors write that using NG foams is likely to provide long-term sustainable benefits in areas where water procurement and disposal costs are high, where natural gas may be available from a central processing facility through pipelines, and where the reservoir is relatively shallow and contains clay-bearing minerals. This work is inspired by a program sponsored by the US Department of Energy to investigate NG as an alternative to N2 and CO2 in foamed fracturing fluids. Initially, the project focused on identifying a thermodynamic path-way to use NG obtained from producing wells and processing plants. The study later extended into laboratory-scale experiments to measure NG-foam-fluid rheology, which was found to be comparable to foams based on N2 and CO2. The first step in the work flow is to build a static geological model to capture the reservoir description. The subsequent step is to use the rock characterization to simulate the induced hydraulic fractures. The hydraulic-fracture simulator also predicts the proppant distribution and its conductivity and treating pressure. The simulated treating pressure is matched with observed pressure during stimulation treatment to calibrate the hydraulic-fracture model. The hydraulic fractures are then gridded in the static geological model to generate the reservoir model for flow modeling. This is a critical step in the process because the static model is linked to the dynamic simulator without losing the details of the hydraulic fractures. The reservoir simulator is used to match the historical production performance to calibrate the reservoir model and forecast future production profiles. This hydraulic-fracture modeling, followed by the flow-modeling process, is repeated for various pumping schedules and recipes to perform a sensitivity analysis, which is detailed in the complete paper.

Baseline monitoring for time-lapse pressure tomography: Initial results from Otway Stage 3

As part of the CO2CRC Otway stage 3 project, time-lapse cross-well pressure tomography methods are being developed to demonstrate unobtrusive, continuous and low-cost monitoring of an injected CO2 plume. Active pressure tomography relies on a robust baseline set of water injections and environmental monitoring to characterise the aquifer in its base state, before CO2 has been injected. Here, we report the initial results from such baseline testing. In late 2019, 4 new monitoring wells were drilled (CRC-4 to 7), in addition to the existing CRC-2 well (where CO2 injection occurred during the stage 2C project) and the CRC-3 well which is the primary CO2 injection well for stage 3. These wells were completed in the Paaratte aquifer formation at depth ≈1500m TVD. Two sets of baseline test sequences were performed, with water injection occurring sequentially at CRC-4, 5, 6 and 7, with all wells (including CRC-2 and 3) continuously monitoring the subsurface pressure. High-quality downhole, surface and weather data were acquired for each sequence, with monitored downhole pressures generally repeatable to within the base environmental noise level. An adjoint Bayesian inversion method was developed to invert for the depth-averaged aquifer petrophysical properties, based on the monitored pressure signals. The Bayesian framework utilised prior aquifer information - interpreted faults and an independently developed geological static model - to inform and constrain the inversion. The resulting baseline model is able to capture the complex time-series pressure propagation across the aquifer subject to the various water injections. Heterogeneous regions of permeability, porosity and aquifer thickness account for the subtle variations in pressure peak arrival time and magnitude observed at the various wells, with spatial variations at a resolution that is a small fraction of the well spacing. The baseline injections and aquifer model provide a robust base for repeat water injections once CO2 has been injected in the next stages of the project.

Contribution of drone photogrammetry to 3D outcrop modeling of facies, porosity, and permeability heterogeneities in carbonate reservoirs (Paris Basin, Middle Jurassic)

This study showcases the value of drone photogrammetry in creating a meter-scale geological model of complex carbonate geobodies. Although drone photogrammetry is now commonly used for modeling the sedimentary facies and architecture of sandstone outcrops, its use is not widespread in creating geomodels of carbonate geobodies. Drone photogrammetry can generate accurate line-drawing correlation and detailed architecture analysis along inaccessible vertical faces of outcrops and permits observations of unreachable places. This work models the Bathonian limestones of Massangis quarry (Burgundy) as an example. The quarry covers an area of 0.4 km2 and is considered as an analogue for the Oolithe Blanche geothermal reservoir in the center of the Paris Basin. The Massangis quarry model represents a good analogue for reservoir microporosity and secondary porosity associated with dedolomitization. Ten facies are described and grouped into three facies associations (1) clinoforms, (2) tidal to subtidal facies, and (3) lagoonal facies. The clinoforms are sets of very large marine dunes 15–20 m high that prograded N70° across the platform as part of a regressive systems tract. Moldic rhombohedral pore spaces associated with dedolomitization are well-expressed within clinoforms and in the bioturbated levels of lagoonal facies. Drone photogrammetry combined with the “Truncated Gaussian with Trends” algorithm implemented in Petrel® software is used to create a geological model that faithfully reproduces the facies architecture observed in the quarry cliffs. Drone photogrammetry can be combined with field work to describe and locate facies and so constrain the spatial distribution of petrophysical properties. It also helps constraining the shapes of geobodies in the model grid for more realistic geological static models and helps providing 3D petrophysical models from an outcropping analogue for geothermal and petroleum reservoirs.

Data workflow for generating static geological model platform for petroleum prospect re-evaluation of Wytch Farm field, Wessex Basin, South Coast, United Kingdom

The analyses and interpretation of the old existing 3D seismic and well log data of Wytch Farm field, Wessex Basin, south coast of the United Kingdom provided relevant information employed to generate static geological model platform. The platform which is requisite for building and distributing petrophysical and production data across the field could be useful for simulating the field's performance, history matching as well as generate future prediction/forecast needful to establish the reasons for the early water breakthrough and sudden production decline from a peak value of 115,000 bbl/day in 1997 to the present production rate of less than 19,000 bbl/day. Six major faults which extend throughout the entire length of the field and five horizon surfaces which correspond to the top of Greensand, Combrash, Mercia mudstone and the top and base of Sherwood Formations aided the generation of the static geological model platform across the Wytch Farm field. The volume of delineated saturated reservoir rock lying above the Oil Water Contact (OWC) and enclosed within fault assisted anticlinal structures indicate a Gross Rock Volume (GRV) of 2,007,000,000 m3 and thus suggest that Wytch Farm field may likely still hold hydrocarbon potential beyond the present daily production rate. This potential could be unlocked through adequate reservoir management that requires detailed information such as could be generated from static geological model of the field.

Practical Aspects of Upscaling Geocellular Geological Models for Reservoir Fluid Flow Simulations: A Case Study in Integrating Geology, Geophysics, and Petroleum Engineering Multiscale Data from the Hunton Group

Optimal upscaling of a high-resolution static geologic model that reflects the flow performance of the reservoir is important for reasons such as time and calculation efficiency. In this study, we demonstrate that honoring reservoir heterogeneity is critical in predicting accurate production and reducing the time and cost of running reservoir flow simulations for the Hunton Group carbonate. We integrated three-dimensional (3D) seismic data, well logs, thin sections, outcrops, multiscale fracture studies, discrete fracture networks, and geostatistical methods to create a 100 × 150 × 1 ft gridded representative geologic model. We calibrated our gridded porosity and permeability parameters, including the evaluation of fractures, by history matching the simulated production rate and cumulative production volumes from a baseline fine-scale model generated from petrophysical and production data obtained from five wells. We subsequently reperformed the simulations using a suite of coarser grids to validate our property upscaling workflow. Compared to our baseline history matching, increasing the horizontal grid cell sizes (i.e., horizontal upscaling) by factors of 2, 4, 8, and 16 results in cumulative production errors ranging from +0.5% for two time (2×) coarser to +74.22% for 16× coarser. The errors associated with vertical upscaling were significantly less, i.e., ranging from +0.5% for 2× coarser to +10.8% for 16× coarser. We observed higher production history matching errors associated with natural fracture size. Results indicate that greater connectivity provided by natural fracture length has a larger effect on production compared to the higher permeability provided by larger apertures. We also estimated the trade-off between accuracy and run times using two methods: (a) using progressively larger grid cell sizes; (b) applying 1, 5, 10, and 20 parallel processes. Computation time reduction in both scenarios may be described by simple power law equations. Observations made from our case study and upscaling workflow may be applicable to other carbonate reservoirs.

Characterization of local capillary trap clusters in storage aquifers

Local capillary trapping occurs when buoyant CO2 moves upward in a saline aquifer during geologic carbon sequestration. The volumetric capacity of local capillary traps (LCTs) is controlled by reservoir geological heterogeneity. These traps are thus intrinsic to heterogeneous storage aquifers; their volumetric capacities are however largely unknown. To address this issue, this work employs an easily calculated criterion that requires only a static geologic model to estimate the properties of LCT clusters, including size, frequency, and extent. Specifically, this work quantitatively analyzes: i) the properties of the largest LCT cluster; and ii) the impact of reservoir heterogeneity on cluster properties. The key finding of this work is that spatially-correlated reservoir heterogeneity in the horizontal direction causes the largest LCT cluster to laterally span across a given domain even when the horizontal correlation length is small (only 1/25th) compared to the domain width. The overall work sheds useful insights of the dependence of LCT clusters on reservoir heterogeneity and its implication for CO2 trapping quantification.

Integrated workflow in 3D geological model construction for evaluation of CO2 storage capacity of a fractured basement reservoir in Cuu Long Basin, Vietnam

Carbon dioxide (CO2) capture, utilization, and storage (CCUS) have been proposed as a possible technique to mitigate climate change. In this vein, CO2 storage through enhanced oil recovery (EOR) in depleted hydrocarbon reservoirs is touted as a most effective approach because it synergistically increases oil production and enables permanent sequestration into the reservoirs. However, the construction of a reasonable 3D geological model for this storage reservoir is a major challenge. Thus, this study presents an efficient workflow for constructing an accurate geological model for the evaluation of CO2 storage capacity in a fractured basement reservoir in the Cuu Long Basin, Vietnam. Artificial neural network (ANN) has been used to predict porosity and permeability values through seismic attributes and well log data. The predicted values were selected using high correlation factors with well log data. Subsequently, the Sequential Gaussian Simulation and co-kriging methods were applied to generate a 3D static geological model by using azimuth and dip parameters. Finally, drill stem test matching was performed to validate the accuracy of the porosity and permeability models through dynamic simulation. A validation 3D reservoir model, which integrates geophysical, geological, and engineering data from fractured basement formation in Cuu Long Basin, was further constructed to calculate theoretical CO2 storage capacity. As a result, the calculated storage capacity for the fractured basement reservoir ranged from 7.02 to 99.5 million metric tons. These estimated results demonstrate that fractured basement reservoir has a combined potential for CO2 storage and EOR in the Cuu Long Basin.

Modeling of Petrophysical Properties and Reserve Estimation of Mishrif Formation-Garraf Oil Field

In this study a build-up a 3D geologic model both depend on the information of field and subsurface is a usual task in geologic studies including resource evaluation and hazard assessment. During this study a 3D geologic model for Mishrif Formation in Garraf oil field has been set-up by using petrel 2015 software system. Mishrif Formation represents the foremost important reservoir in Garraf oil field. Four vertical oil wells and one directional well were chosen in Garraf Oil Field so as to set-up structural and petrophysical models delineated by a 3D static geologic model in 3 dimensions. The structural closure is shifted from GA-3 well to GA-A1P well. Mishrif Formation was divided into 10 zones. Sequential Gaussian Simulation algorithm was used to build-up Petrophysical model (NTG, permeability, water saturation and porosity) for Mishrif Formation keeping with information analyses and also the results from modeling the units (M1.2, L1 and L1.2) are thought-about as prime quality reservoir units because of the high PHIE and low water saturation. Units (L2, L2.2, L2.3 and L2.4) are thought-about as poor reservoirs because of low PHIE and high water saturation, and non-reservoir units include (Top Mishrif, M1 and M2) thus, they represent cap units. Cross sections of petrophysical model were conducted to Illustrate the vertical and horizontal distribution of porosity, permeability, Net to gross and water saturation between wells within the field. This study calculated the reserves of the Mishrif formation of Garraf oilfield by petrel, that alter the issue that the reserves parameters are difficult to properly acquire when estimate complex reservoir’s reserves in terms of ancient volume technique.

Modeling Commercial-Scale CO2 Injection in Mt. Simon Sandstone Near Decatur, IL Storage Sites

Advancing carbon capture and storage (CCS) to commercialization necessitates exploiting CO2 storage resources efficiently, which likely will involve multiple injection sites (or entire projects) accessing the same regional storage complex. This situation is presently occurring in central Illinois, where a series of three U.S. Department of Energy-sponsored storage projects are utilizing the Cambrian Mt. Simon Sandstone storage complex near Decatur, Illinois. From 2011 to 2014, the Illinois Basin – Decatur Project (IBDP) injected CO2 at a rate of 0.33 million tonnes per year (Mt/yr), and in 2017, the Illinois Industrial CCS Project (IL-ICCS) began injecting approximately 1 Mt/yr (planned rate) in a well 1.6 km apart. Recently, the CarbonSAFE Illinois – Macon County Project began investigating whether more than 50 Mt of CO2 can be injected into the Mt. Simon Sandstone over several decades (a target rate of 2 Mt/yr) located at a site about 5 km northwest of the other injection locations. As evaluated for this study, the Macon County well would be within the Forsyth Oil Field and drilled to access the same interval of the Mt. Simon storage complex as used by the other injection projects, namely the lower Mt Simon Sandstone. The intent of this paper is to assess the feasibility of the Forsyth site for commercial CO2 storage to further develop the storage resource by evaluating whether the target rate can be achieved, designing an injector to meet the target rate, and describing the potential contact of subsurface plumes resulting from these separate but proximal central Illinois projects. This entails modelling the behaviour of the injected CO2 and evaluating the well perforated intervals, plume sizes, pressure responses, and contact with existing CO2 plumes at the Decatur sites. To understand the interaction of three subsurface plumes, a static geologic model was generated to encompass the proposed Forsyth site (CarbonSAFE project) and the existing Decatur sites (IBDP and IL-ICCS projects), an area 22.5  22.5 km2 and a vertical section of 664 m. The static model was developed to represent the geological architecture and heterogeneity of the Mt. Simon storage complex at the Forsyth and Decatur sites through regional correlations based on geophysical data from wells at the Decatur sites. A dynamic model with integrated fluid and rock–fluid properties was constructed from the static model. The primary CO2 storage mechanisms modeled were structural and stratigraphic trapping, residual gas trapping, and solubility trapping. Mineral trapping resulting from geochemical reactions among CO2, rock, and formation water were considered negligible because the target formation is quartz sandstone.

Integrating multi-disciplinary data for building fit-for-purpose 3D mechanical earth model

Understanding the influence of geomechanics early in the field development phase facilitates reservoir management planning. To capture complex geology and associated field development, a 3D mechanical earth model (3D MEM) with finite element method (FEM) approach was selected to analyse the geomechanical-related risks associated with two fields in the North West Shelf, Australia. The 3D MEMs were constructed using geological static models, and seismic-derived horizons and faults. The 3D properties were propagated based on core-calibrated 1D properties and controlled by stratigraphy, 3D facies and seismic inversion volumes. The FEM was used to calculate the equilibrium of stresses and strains within the 3D MEMs. The 3D properties and pre-production stresses were validated in blind test wells before forward modelling. The 3D MEMs were linked to the dynamic reservoir models to capture the pressure evolution throughout the field lifecycle. The results were used to analyse the risks associated with compaction, subsidence, fault instability, completion integrity and drilling stability of infill wells through depleted reservoirs. The results provided insight in managing the risk early in field development stage. The study’s largest challenge was integrating a large volume of data to ensure that the structural complexity and rock heterogeneity were captured and consistent with the geological understanding of the field. A multi-disciplinary team of earth scientists and reservoir and geomechanics engineers worked together, and the value of data integration, good communication and teamwork were key success factors. Lessons learned and best practices were captured throughout the study and provided valuable feedback for future works.