The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Li, Chen (Chengdu University of Technology, China) | Yan, Bicheng (King Abdullah University of Science and Technology, Saudi Arabia) | Kou, Rui (Texas A&M University, United States) | Gao, Shunhua (Texas A&M University, United States)
Abstract The Fast Marching Method (FMM) is a highly efficient numerical algorithm frequently used to solve the Eikonal equation to obtain the travel time from the source point to spatial locations, which can generate a geometric description of monotonically advancing front in anisotropic and heterogeneous media. In modeling fluid flow in subsurface heterogeneous porous media, application of the FMM makes the characterization of pressure front propagation quite straightforward using the diffusive time of flight (DTOF) as the Eikonal solution from an asymptotic approximation to the diffusivity equation. For the infinite-acting flow that occurs in smoothly varying heterogeneous media, travel time of pressure front from the active production or injection well to the observation well can be directly estimated from the DTOF using the concept of radius of investigation (ROI). Based on the ROI definition, the travel time to a given location in space can be determined from the maximum magnitude of partial derivative of pressure to time. Treating travel time computed at the observation well as the objective function, we propose a FMM based deep learning (DL) framework, namely the Inversion Neural Network (INN), to inversely estimate heterogeneous reservoir permeability fields through training the deep neural network (DNN) with the travel time data directly generated from the FMM. A convolutional neural network (CNN) is adopted to establish the mapping between the heterogeneous permeability field and the sparse observational data. Because of the quasi-linear relationship between the travel time and reservoir properties, CNN inspired by FMM is able to provide a rapid inverse estimate of heterogeneous reservoir properties that show sufficient accuracy compared to the true reference model with a limited number of observation wells. Inverse modeling results of the permeability fields are validated by the asymptotic pressure approximation through history matching of the reservoir models with the multi-well pressure transient data.
Alan, Cihan (Istanbul Technical University) | Cinar, Murat (Istanbul Technical University) | Onur, Mustafa (University of Tulsa)
Abstract The objective of this paper is to investigate the estimation of layer permeability, skin, and inflow profile from observations of production-logging-tool (PLT) and/or distributed temperature sensing (DTS) for a multilayered system where the layers communicate only through the wellbore. To achieve this objective, we develop a thermal, transient coupled reservoir/wellbore simulator that numerically solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The simulator accounts for the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection effects for predicting the flow profiles across the wellbore. A comparison of the developed model with a commercial simulator is provided for the single-phase fluid flow of oil or geothermal brine from partially penetrating vertical or inclined wells with distinct fluid and formation properties. A sensitivity study on transient pressure, rate, and temperature profiles to identify the effect of the layer petrophysical properties and the layer thermophysical parameters is also conducted through synthetically generated test data sets from the developed simulator. In addition, nonlinear parameter estimation with the use of both profiles is shown to be useful to reveal permeability and skin information about individual layers. The results show that temperature transient data are more reflective of the properties of the near wellbore region, while wellbore pressures are determined more by average reservoir parameters. The simulator proves practical for designing a PLT test provided that limitations such as single-phase fluid flow having vertical or inclined well equipped with a thorough fluid characterization (EOS) are met. Such design tests may provide a good source for cross-checking PLT flow profiles and validating the fluid contributions from layers that are open to flow. It is often that the spinner of the field PLT tool does not operate properly at very low flow rates. Also, the spinner may fail to calculate and construct PLT plots accurately at very high flow rates. To the best of our knowledge, this is the first study that presents a coupled transient reservoir/wellbore model for predicting layer permeability, skin, and inflow profile of a well from observations of pressure, temperate, and/or rate data from production-logging-tools (PLTs) and/or distributed temperature sensing (DTS) fiber optic cables.
Langanke, Nils (Clausthal University of Technology) | Leblanc, Thierry (SNF SA) | Fadili, Ali (Shell Global Solutions International B.V.) | Hincapie, Rafael E. (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
Abstract The properties of polymeric materials are commonly modified by adjusting the dispersity of the molecular weight distribution, since polymer properties are dominated by intermolecular interactions. We utilized this approach to alter the rheological behavior of polymer solutions for application sub-surface and other porous media flow. We correlate the molecular weight distributions with screen factor measurements and in-situ rheological behavior. Aqueous solutions were prepared using mixtures of partially hydrolyzed polyacrylamide (HPAM) having different molecular weights. The behaviour of the solutions was studied in single-phase flooding experiments using Bentheimer and Berea outcrops, as well as a glass-silicon-glass microfluidic device that mimics porous media. The in-situ rheological behavior determined from flooding experiments was monitored by differential pressure measurements. To improve data accuracy, the core flooding experimental set-up was equipped with multiple pressure sensors along the core. Polymer solutions of same shear viscosity but significantly different dispersities were utilized for the investigation. Elongational viscosities were determined by screen factor measurements. We show that the apparent viscosity during polymer injection is significantly altered for polymer solutions of same average molecular weight but different dispersity. Namely, the onset of shear thickening occurs at lower equivalent shear rates when dispersity is high. Furthermore, the flow of polymer solutions in porous media was correlated to screen factor measurements. This effect of the dispersity of the molecular weight distribution can be used to optimize polymer solution applications in porous materials.
Abstract An innovative optimization methodology for field development planning is presented. A new mixed integer optimizer is described. The optimization tool's "user-friendly" plug-in in a commercial reservoir characterization and simulation package is developed, and methodology applications in exploration projects are outlined. An effective methodology is developed to optimize well placement and facility options in oil fields with multiple reservoirs. The optimized field development plan is selected for individual reservoirs from various well placements, well trajectories, injection strategies, and facility scenarios significantly impacting field oil recovery. Multiple subsurface models representing uncertainties in subsurface descriptions are applied in the optimization process. An effective mixed integer optimizer is developed. The optimizer is based on sequential cycles of a) selection of "promising" scenarios changing one decision variable per simulation and b) evaluations of combinations of the "promising" scenarios using Latin Hypercube sampling. The optimization workflow is implemented as a user-friendly plug-in to a commercial package, which allows one to a) define locations and trajectories of potential wells, b) define well placement and facility scenarios, c) run optimization workflows, and d) evaluate optimization results. The developed optimization methodology is successfully applied in several exploration projects. Effectiveness and significant benefits from the optimization applications are demonstrated. This paper can bring significant benefits to the state of knowledge in the petroleum industry by a) describing the novel methodology for optimizing field development scenarios that have significant impacts on oil recovery, b) applying the new optimizer, c) implementing the optimization plug-in in a commercial package.
Abstract If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the back-produced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in literature. Thus, laboratory measurements were performed to improve storage performance predictions for an Underground Hydrogen Storage (UHS) project in Austria. A high-pressure-high-temperature experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of back-produced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients which impacts UHS performance
Abstract Finite element simulations investigate the effect of cement sheath length and proximity to perforations, varying the spacing of these and their length. The motivation is to assess the well integrity risk in fracturing operations, typical in shale gas or tight sandstone stimulation operations. Other applications are de-risking of injection operations in CO2 or H2 storage. Simplified simulations highlight unwanted associated fracturing in hydraulic fracturing operations, or as additional consequences of unplanned fracturing occurring due to injectivity impairment. Several cases are simulated: 1. Cased, cemented and perforated horizontal well interval; 2. Open hole perforated horizontal well interval; 3. Vertical cased and cemented interval. Results show that under some circumstances, fracturing may be expected in the well's cement sheath. These are locations where simulations show a possible fracturing scenario which could lead to unwanted pressure communication. However, the simulations all agree that there is no induced fracturing at more distant cement sheath sections. The major risk shown here is fracture initiation close to the perforated interval, suggesting that propagation along the cement sheath, although possible, is less likely.
Abstract CO2 injection in subsurface geological formations (e.g. deep saline aquifers) causes pressure perturbations over a large area surrounding the injection well. Observation wells are widely considered in geologic CO2 storage (GCS) projects where the pressure perturbation induced by CO2 injection is measured. In this work, we use analytical and numerical modeling tools along with field data to examine the pressure behavior in GCS projects before and after CO2 arrival at an observation well. Prior to CO2 arrival, a baseline pressure trend is established which corresponds to single-phase brine flow across the observation well (approximated by Theis solution). Therefore, analysis of early-time pressure data is straightforward, provides the single-phase flow characteristics (mobility and storativity), and helps establishing a baseline pressure change that can be extended beyond the single-phase flow period at the observation well. Upon CO2 arrival, a departure from this baseline trend is expected. For the pressure to detect the CO2 arrival at an observation well, the departure from baseline pressure behavior must be significant and well above the background noise levels. We use existing analytical models to determine the strength of the expected pressure departure signal from the baseline trend upon CO2 arrival. The strength of the expected pressure departure is found to be directly proportional to the mobility ratio. Accordingly, we establish a criterion to determine whether the pressure at an observation well can detect the CO2 arrival. We present an analysis approach through application to synthetic and field data and show the characteristic pressure behavior before and after CO2 arrival. We show that while generally the pressure can be either above or below the expected baseline pressure trend, it would be likely above the baseline upon CO2 arrival. This is because the mobility ratio becomes less than unity after CO2 arrival. We show that depending on the reservoir characteristics, changes in the pressure trend may or may not be sufficient to detect the CO2 arrival.
Abstract Due to the maturity of water-flooded oil reservoirs, as a consequence of heterogeneity, fluids move preferentially through the most permeable layers, leaving large volumes of mobile oil remain unswept. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Droplet size distribution and porous media heterogeneity are the principal features that characterize displacement front uniformity. The intent of this work is therefore to provide a fundamental insight into number of factors may influence the dispersion flow in porous media. The workflow in this study is comprised of three stages. First, O/W dispersions with low oil concentrations were prepared and characterized. Second, a series of O/W dispersion injection experiments was conducted. The objective of this stage was to evaluate the distribution of retained oil droplets, pressure drop and permeability reduction in different sandstone core-plugs. Finally, a mathematical model based on the experimental setup was developed to describe the dynamics of O/W dispersion flow. Finite element method (FEM) was employed to numerically solve the governing equations. The experimental results revealed that the number and size of retained oil droplets decay with the core depth and correspondingly in the effluent. Verification of the numerical model was performed by comparing the pressure drop and permeability reduction to the results of analytical solutions. The model showed good validation with the experimental data. The numerical results were closely match those of the analytical solutions. The current work presents a potentially efficient method of modelling to describe the dispersion flow in porous media. However, for field applications, further improvement to the model complexity is required.
Abstract Connection sealability is critical for well integrity and carbon control. With current operating practices, there is no way to know that a connection is about to fail and leak before failure actually occurs. API leak equation is uniaxial. Premium connection ratings are biaxial. To measure, monitor, and maintain connection sealability during drilling and production operations, a triaxial Integrity Safety Factor (ISF) for connections is introduced in this paper. Three leak constants evaluated from simple physical tests determine the connection ISFs. Example connection in the paper is 7-inch 35-ppf N80 LTC. Results from FEA leak predictions for 23 load cases, comprising both internal and external leak, show unexpected leak behavior relative to pipe failure.
Shaker Shiran, Behruz (NORCE Norwegian Research Centre AS) | Djurhuus, Ketil (NORCE Norwegian Research Centre AS) | Alagic, Edin (NORCE Norwegian Research Centre AS) | Lohne, Arild (NORCE Norwegian Research Centre AS) | Rolfsvåg, Trond Arne (Hydrophilic AS) | Syse, Harald (Hydrotell AS) | Riisøen, Solveig (Hydrotell AS)
Abstract As oil is produced from a reservoir, the free-water-level (FWL) rises. Monitoring the FWL during oil production is of high value for the operators. This knowledge can aid placement of new wells on the field, improve the production strategy on a well level and reduce the production of water. We propose a new method for continuously measuring in-situ water pressure in an oil reservoir and investigate, both experimentally and by simulations, how this information can be used in reservoir monitoring. Laboratory experiments with Berea sandstone and Mons chalk core samples were performed using mineral oil and synthetic brine in a test setup designed for this study. The pressure in the water phase is measured with hydrophilic probes at five locations on the core during drainage and imbibition processes. Data including temperatures, pressures, resistance, water production, and pump logs were continuously collected in a cloud solution for live monitoring during the experiments. The experimental results were interpreted using a numerical simulator (IORCoreSim) to identify key mechanisms behind probe response and upscaling to reservoir scale. A new setup with 5 internal pressure probes for measuring in-situ water pressure with higher oil pressure was successfully designed and tested. An advanced watering system to inject water to the probe tips was included in the test setup and can be operated automatically. Experimental results showed that the water-wet probes can measure low water pressure inside high pressure oil column. The change in water pressure during drainage of low permeable Mons core and medium permeability Berea core was continuously measured. The probes were able to measure water pressure in different sections of the core with change of water saturation in the core. After the drainage process, the water pressure at one side of the core was increased. The propagation of water pressure at low water saturations were then detected in the 5 probes along the core sample. This paper presents a revolutionary technique to measure pressure in a thin film of water with low mobility. Continuous monitoring of water pressure inside the hydrocarbon phase can be used to enhance the production on a well level and improve the strategy on a field level. This results in increased production, reduced operational costs and environmental impacts.