Manivannan, Sivaprasath (Ecole Polytechnique) | Bérest, Pierre (Ecole Polytechnique) | Jacques, Antoine (Total SA) | Brouard, Benoît (Brouard Consulting) | Jaffrezic, Vincent (Total SA) | De Greef, Vincent (Ecole Polytechnique)
In wells producing water, oil, gas or geothermal energy, or in access wells to hydrocarbon storages, it is critical to evaluate the permeability of the formation as a function of depth. Continuous permeability logs in these wells are typically derived using tools that measure electrical, nuclear, magnetic or acoustic signals, using empirical relations that are often formation dependent. The permeability logs derived using these empirical relations often show significant differences when compared to the permeabilities obtained from core samples or well tests.
A new technique is proposed in this paper in which the open hole is scanned with an interface between two fluids with a large viscosity contrast. The injection rate into the formation depends on interface location and well pressure history. An inverse problem is solved to estimate permeability as a function of depth from the evolution of flow rates with time. During the test, the well is equipped with a central tube, typically a drill string, and the scanning is done by injecting in the central tube a liquid that is different from the liquid in the annulus, at a constant wellhead pressure. Injection and withdrawal rates are measured at the tubing and the annulus wellheads, respectively; the difference between these two rates gives the formation injection rate. Interface location is also estimated from the flow rates and pressure at the wellhead and an injection profile in the open hole is derived.
A permeability log is derived from this injection log by considering a radial, monophasic flow in each layer and same skin value for all formation layers. Initial formation pressure and storativity, estimated from other logs, are also used as inputs. The sensitivity of the permeability log to these inputs is estimated using analytical expressions. The proposed methodology is applicable to oil or water bearing formations drilled using oil or water-based muds, respectively.
A continuous permeability log is estimated from the synthetic test data using the proposed interpretation workflow; it shows a correlation of 0.95 (on a scale of 0 to 1) when compared to the input permeability log. A laboratory model that mimics a multi-layered formation is used to study the repeatability of the technique and the validity of the uniform skin assumption by creating a mudcake at the inner radius. Four consecutive tests were performed on the same set of samples and the interpreted permeability logs are compared to the benchmark permeability log; correlations are greater than 0.94.
Kar, Taniya (Reservoir Engineering Research Institute, Palo Alto, CA) | Chávez-Miyauchi, Tomás-Eduardo (Universidad La Salle México) | Firoozabadi, Abbas (Reservoir Engineering Research Institute, Palo Alto, CA) | Pal, Mayur (North Oil Company, Doha, Qatar)
Low salinity water injection when effective in increasing oil recovery is often thought to be through increase in water wetting. Recently, oil-water interfacial rheology has been suggested to be related to oil recovery from low salinity water flooding. We have also discovered that addition of a very small amount of a functional molecule in the injection brine increases oil recovery significantly. Quantitative effect of interfacial elasticity and the effect of rock on oil recovery is investigated at 100 ppm concentration in this work for the first time. A light crude oil is used in four sets of waterflooding experiments in a carbonate rock. The injection brine is modified by adding 100 ppm of a non-ionic surfactant. To understand the recovery performances, interfacial viscoelasticity, interfacial tension and contact angle measurements are performed using brines of varying salinities. In interfacial rheology the effect of equilibration of the aqueous phase with the rock is also investigated. Additionally, adsorption of the surfactant in the carbonate rock is investigated for various aqueous phases via UVvis spectrometry. Crude oil, calcite and reservoir brine show moderate oil-wetting behavior. Addition of surfactant molecules makes the system more water-wet, however, the change is not pronounced. From coreflooding experiments, addition of surfactant in high salinity brine increases recovery by over 20% which we interpret to be due increase in interface elasticity. The phase angle which is a direct measure of interface elasticity decreases by 70% in an aqueous phase at about 4 wt% salt due to the surfactant. High interface elasticity reduces oil snap off and increases oil recovery. An effective molecule dissolved in water can increase the interface elasticity significantly. In relation to low salinity water injection we have established that there is an optimum salt concentration for high oil recovery. The injection of an aqueous phase without salt gives a lower recovery than injection of say 0.1 wt% salt in the injected water.
We have introduced a new IOR process based on interface elasticity which requires a very low concentration of a non-ionic surfactant. The process is neither through wettability alteration nor through significant change in IFT. The chemical we have used is environmentally friendly and of low cost. It has very low adsorption onto the rock surface.
DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO2 and Naptha in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications.
A full-physics simulator is used to model the process. The technical as well as economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics.
The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. The objective function built with economic parameters helped to maximize the NPV for the project, providing a more realistic perspective on the projects. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO2 and naptha indicate that the two have different dominant modes of improving recovery of steam only injection. CO2 increases the extent of the steam chamber while lowering the steam temperature significantly.
This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.
The hydraulic fracture containment and the impact of layering on pumping energy are critical factors in a successful stimulation treatment. Height confinement is needed to ensure effective stimulation of target zones and to maintain the fractures in the target zones. Also, the existence of beds with different ductility can impact the net pressure and pumping requirements. Layered rock properties, in-situ stress, and formations interfaces influence the lateral and height growth of hydraulic fractures. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young's modulus. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in field (SPE39950). Enhanced toughness, in-situ stress, interface slip and energy dissipation in the layered rocks should be combined to contribute to the fracture containment. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on finite element method. We use laboratory and numerical simulations to investigate the above factors and how they impact hydraulic fracture propagation, height growth, and injection pressure.
In this work a 3D fully coupled hydro-mechanical model is developed and utilized. The model uses a special zero-thickness interface element and the cohesive zone model (CZM) to model fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydro-mechanical model has been successfully verified through benchmarked analytical solutions. The influence of layered Young's modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are explicitly simulated through the usage of the hydro-mechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on preventing hydraulic fracture growth are studied.
Hydraulic fractures tend to propagate in the layer with lower Young's modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Depending on the mechanical properties and the conductivity of the interfaces, the shear-slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces could be an effective mechanism that contributes to the containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the reinitiation of a hydraulic fracture from a pre-existing flaw along the interfaces, producing an offset from the interception point to the reinitiation point.
We present an efficient numerical model for compositional three-phase flow in complex fractured media in 2D and 3D. The capillary effect is included in the simulations. The algorithm accounts for one aqueous phase and two hydrocarbon phases. CO2 is assumed to be soluble in the aqueous phase. We extend the fracture cross-flow equilibrium to three phases for the first time. The cubic plus association (CPA) equation of state describes the aqueous phase. To avoid small time steps in fracture elements we adopt an implicit time scheme discretization in the fractures. Capillary pressure gradients are computed at the element level. The phase fluxes are evaluated with the hybridized form of the mass conservative mixed finite element (MFE). A finite volume (FV) discretization is used in the mass balance equations in the fractures and the discontinuous Galerkin (DG) method is used in the matrix with an explicit time scheme. Pressure is implicit in the whole domain. Our algorithm accounts for different types of grids in 2D and in 3D.
Sun, Qian (Petroleum Engineering, Texas A&M University at Qatar) | Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Alyafei, Nayef (Petroleum Engineering, Texas A&M University at Qatar) | Wang, Yuhe (Petroleum Engineering, Texas A&M University at Qatar) | Fadlelmula, Mohamed (Petroleum Engineering, Texas A&M University at Qatar)
Reservoir simulation is commonly performed on upscaled models of complex geological models. The upscaling process introduces a principal challenge in accurately simulating two-phase fluid dynamics in porous media. To tackle this challenge, it is important to upscale relative permeability accurately. In this paper, a numerical method, which is based on the mimetic finite difference method (MFD) and digital rock analysis (DRA), is proposed for relative permeability upscaling. The validation of MFD is tested by two different cases with exact pressure solution. Then, the relative permeability of the digital rock (small element) is calculated based on the pore network modeling. The small elements are combined together to make up a larger model with different sizes (4×4×4, 6×6×6, 8×8×8, 10×10×10 elements). Finally, the accuracy of the proposed method is verified by comparing simulated results of the different sizes with that of the original one. The results show that MFD can solve the multi-phase flow scenarios with high accuracy and the
Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad Sami (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
A fully-implict mimetic finite difference method (MFD) for fractured carbonatereservoir simulation is presented. MFD, as a novel discritization, has been applied to many fields due to its local conservativeness and applicability of any shape of polygon. Here we extend it to fractured reservoirs. Our scheme is based on MFD method and discrete fracture model (DFM). This scheme supports general polyhedral meshes, which gives an advantage for reservoir simulation application. The principle of the MFD method and the corresponding numerical formula for discrete fracture model are described in details. In order to assure flux conservation, fully implicit method is employed. We test our method through some examples to show the accuracy and robustness.
Risk Assessments are used to assess the impact of alternativedesigns, changes during operations, and compliance of offshore installations against tolerabilitycriteria. Typically, asset information is used to develop a mathematical model; this can beupdated to reflect changes during the facility's lifecycle. This paper examines how the use ofcloud-based technology to develop a Digital Twin improves efficiency. Allowing projectstakeholders full access to the QRA model also enables greater understanding of hazards.
Digital technology pervades all areas of business and societyand offers great advantages to safety engineering relative to traditional approaches. This paperdemonstrates how cloud basedtools canturn the traditional static QRA process into a living QRA which can be updated throughout aninstallation's lifecycle by creating a digital twin. This type of living QRA allows projectstakeholders to change key parameters and assess the effect of these changes on risk levels. Inaddition, the results can be interrogated down to fundamental levels using a Microsoft Power BIdashboard.
The output of QRAs are usually static reports providing anoverview of the detailed work undertaken and a high-level summary of the results which arecompared with tolerability criteria or to demonstrate ALARP. This paper demonstrates howcustomised internet browser tools utilising 2D and 3D graphics may be built on top of the QRA toextract more detail than previously possible and communicate risks in a flexible and interactiveway. It also shows how consistent data management can form a basis for innovating beyond thetraditional approach. This allows a wider range of stakeholders to determine risk drivers, isolatesingle accident scenarios and filter results to a greater depth than is possible through a paperreport and allow a greater understanding of their hazards.
Digitalisation is an increasingly ‘hot topic’ in the process industry. Making use of new technologies to provide greater insights can aid in better and more timelyhazard management whilst reducing costs to stakeholders. Examples of innovations which promote better assessment are provided.
How Is Industrial Augmented Reality Taking Form? Industrial augmented reality (AR) takes several forms. The holy grail—and eventually prevalent format—is headworn AR, where visualization software is installed on AR glasses such as Microsoft’s HoloLens. Nearer-term deployments also include smartphone- or tablet-based AR. The upstream sector is witnessing comparatively more implementation of the industrial Internet of things compared with other sectors of the oil and gas industry.
The Hibernia platform is 315 km east-southeast of St. John’s, Newfoundland. Hibernia Management and Development Company (HMDC) has again halted production from its 220,000-B/D Hibernia platform off Newfoundland and Labrador after another oil spill was reported 17 August. HMDC, an ExxonMobil-led consortium, had resumed production from Hibernia just 2 days earlier, ending a month-long shut down due to a first discharge. Husky Energy on 16 August also brought on stream for the first time since November 2018 its North Amethyst and South White Rose Extension drill centers at the White Rose field, where a failed flowline connector resulted in a 1,572-bbl spill—the largest-ever off Newfoundland and Labrador. The latest incident at Hibernia came as the platform’s deluge system—or water sprinkler system—inadvertently activated amid a loss of main power generation, causing drains to overflow, C-NLOPB said.