scholarly journals Study on a New Transient Productivity Model of Horizontal Well Coupled with Seepage and Wellbore Flow

Processes ◽  
2021 ◽  
Vol 9 (12) ◽  
pp. 2257
Author(s):  
Peng Liu ◽  
Qinghua Wang ◽  
Yanli Luo ◽  
Zhiguo He ◽  
Wei Luo
Keyword(s):  
Real Time ◽  
Horizontal Well ◽  
Single Phase ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Digital Transformation ◽  
Two Phase ◽  
Transient Model ◽  
Wellbore Flow ◽  
Oil Gas

Digital transformation has become one of the major themes of the development of the global oil industry today. With the development of digital transformation, on-site production will surely achieve further automated management, that is, on-site production data automatic collection, real-time tracking, diagnosis and optimization, and remote control of on-site automatic adjustment devices. In this process, the realization of real-time optimization work based on massive data collection needs to be carried out combined with oil and gas well transient simulation. Therefore, research of the horizontal well capacity prediction transient model is one of the important basic works in the work of oil and gas digital transformation. In this paper, the method and process of establihing the transient calculation model of single-phase flow in horizontal wells are introduced in detail from three aspects: reservoir seepage, horizontal wellbore flow (taking one kind of flow as an example), and the coupling model of two flows. The model is more reliable through the verification of pressure recovery data from multiple field logs. The transient model of single-phase seepage in horizontal wells will lay the foundation for the establishment of transient models of oil-gas two-phase seepage and oil-gas-water three-phase seepage.

Impact of 750kV Transmission Line Series Compensation Capacity on Power Frequency Overvoltage

2014 ◽  
Vol 986-987 ◽  
pp. 330-333
Author(s):  
Ding Jun Wen ◽  
Xiu Bin Zhang ◽  
Hong Gang Chen ◽  
Feng Jiang ◽  
Ya Ming Sun
Keyword(s):  
Transmission Line ◽  
Single Phase ◽  
Power Transmission ◽  
Series Compensation ◽  
Two Phase ◽  
Transient Model ◽  
Power Frequency ◽  
Arc Current ◽  
Recovery Voltage ◽  
Insulation Coordination

The overvoltage calculation of 750kV transmission line with series compensation has great significance on the design, insulation coordination and protection of the line. In this paper, a transient model of 750kV power transmission system with series compensation is established. Effects of different capacity on no-load capacitive rise overvoltage, single-phase grounding overvoltage, two-phase grounding overvoltage are calculated. Secondary arc current and recovery voltage of different series compensation capacity in single-phase grounding is also calculated.

Experiment and Dynamic Simulation of PIG Motion during Pigging Operation in a Slope Pipeline

2018 ◽  
Vol 16 (9) ◽  
Author(s):  
Jun Zhou ◽  
Tao Deng ◽  
Guangchuan Liang ◽  
Jinghong Peng ◽  
Tian Meng ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Water Pressure ◽  
Oil And Gas Industry ◽  
Unsteady Motion ◽  
Stable Operation ◽  
Two Phase ◽  
Transient Model ◽  
Water Pressure Test ◽  
Pressure Test ◽  
Hydraulic Pulse

Abstract Pigging techniques are widely used in the oil and gas industry. The unsteady motion of the PIG in an undulating pipe section during the pigging process after a water pressure test affects the stable operation of the pipeline and also causes a pipe rupture accident in serious cases. First, an experimental study was conducted to investigate the pigging process of air–water two phase pipe flows, and the PIG reverse movement and hydraulic pulse phenomenon were observed. Subsequently, a hydraulic transient model of the pigging process after a water pressure test was established in a dual-grid system. The model combined mass and motion equations of gas and liquid and PIG dynamic equations, considered three types of PIG motion states, namely positive movement, reverse movement and still, and used the method of characteristics to solve the equations. The model exhibits the ability for PIG tracing and hydraulic pulse prediction. It can be used to obtain the position and speed of the PIG. Finally, the field data and simulation results were compared, and the results indicated that they are essentially identical. This verified the accuracy of the model that is established in this study and the reliability of computed results and provided a reliable and effective theoretical basis for the development of field pigging plans.

The Effect of Well Azimuth or Don't Let Your Landman Plan Your Well Path!

2015 ◽  
Author(s):  
Fen Yang ◽  
Larry K. Britt ◽  
Shari Dunn-Norman
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Principal Stresses ◽  
Lateral Direction ◽  
Well Completion ◽  
Stimulation Of

Abstract Since the late 1980's when Maersk published their work on multiple fracturing of horizontal wells in the Dan Field, the use of transverse multiple fractured horizontal wells has become the completion of choice and become the “industry standard” for unconventional and tight oil and tight gas reservoirs. Today approximately sixty percent of all wells drilled in the United States are drilled horizontally and nearly all of them are multiple fractured. Because a horizontal well adds additional cost and complexity to the drilling, completion, and stimulation of the well we need to fully understand anything that affects the cost and complexity. In other words, we need to understand the affects of the principal stresses, both direction and magnitude, on the drilling completion, and stimulation of these wells. However, little work has been done to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the question, in what direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal) or do I drill it in the direction of the minimum horizontal stress (transverse)? The answer to this question relates directly back to the title of this paper and please "Don't let your land man drive that decision." This paper focuses on the horizontal well's lateral direction (longitudinal or transverse fracture orientation) and how that direction influences productivity, reserves, and economics of horizontal wells. Optimization studies using a single phase fully three dimensional numeric simulator including convergent non-Darcy flow were used to highlight the importance of lateral direction as a function of reservoir permeability. These studies, conducted for both oil and gas, are used to identify the point on the permeability continuum where longitudinal wells outperform transverse wells. The simulations compare and contrast the transverse multiple fractured horizontal well to longitudinal wells based on the number of fractures and stages. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affected the decision over lateral direction in both oil and gas reservoirs. Additionally, how does completion style affect the lateral direction? That is, how does an open hole completion compare to a cased hole completion and should the type of completion affect the decision on in what direction the lateral should be drilled? These simulation results will be used to discuss the various horizontal well completion and stimulation metrics (rate, recovery, and economics) and how the choice of metrics affects the choice of lateral direction. This paper will also show a series of field case studies to illustrate actual field comparisons in both oil and gas reservoirs of longitudinal versus transverse horizontal wells and tie these field examples and results to the numeric simulation study. This work benefits the petroleum industry by: Establishing well performance and economic based criteria as a function of permeability for drilling longitudinal or transverse horizontal wells,Integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy,Developing well performance and economic objectives for horizontal well direction (transverse versus longitudinal) and highlighting the incremental benefits of various completion and stimulation strategies.

Investigation of the Effects of Completion Geometry on Single-Phase Liquid Flow Behavior in Horizontal Wells

2000 ◽  
Vol 123 (2) ◽  
pp. 119-126 ◽  
Author(s):  
Weipeng Jiang ◽  
Cem Sarica ◽  
Erdal Ozkan ◽  
Mohan Kelkar
Keyword(s):  
Liquid Flow ◽  
Horizontal Well ◽  
Single Phase ◽  
Flow Behavior ◽  
Horizontal Wells ◽  
Main Flow ◽  
Test Facility ◽  
Small Scale ◽  
Phase Liquid ◽  
Single Phase Liquid Flow

The fluids in horizontal wells can exhibit complicated flow behaviors, in part due to interaction between the main flow and the influxes along the wellbore, and due to completion geometries. An existing small-scale test facility at Tulsa University Fluid Flow Projects (TUFFP) was used to simulate the flow in a horizontal well completed with either circular perforations or slotted liners. Single phase liquid flow experiments were conducted with Reynolds numbers ranging approximately from 5000 to 65,000 and influx to main flow rate ratios ranging from 1/50 to 1/1000. For both the perforation and slot cases, three different completion densities and three different completion phasings are considered. Based on the experimental data, new friction factor correlations for horizontal well with multiple perforation completion or multiple slots completion were developed using the principles of conservation of mass and momentum.

scholarly journals Comparative Study of CFD and LedaFlow Models for Riser-Induced Slug Flow

Energies ◽  
2020 ◽  
Vol 13 (14) ◽  
pp. 3733
Author(s):  
Rasmus Thy Jørgensen ◽  
Gunvor Rossen Tonnesen ◽  
Matthias Mandø ◽  
Simon Pedersen
Keyword(s):  
Slug Flow ◽  
Oil And Gas ◽  
Cfd Simulation ◽  
Numerical Models ◽  
Oil And Gas Industry ◽  
Test Facility ◽  
Cfd Model ◽  
Two Phase ◽  
Transient Model ◽  
Vof Model

The goal of this study is to compare mainstream Computational Fluid Dynamics (CFD) with the widely used 1D transient model LedaFlow in their ability to predict riser induced slug flow and to determine if it is relevant for the offshore oil and gas industry to consider making the switch from LedaFlow to CFD. Presently, the industry use relatively simple 1D-models, such as LedaFlow, to predict flow patterns in pipelines. The reduction in cost of computational power in recent years have made it relevant to compare the performance of these codes with high fidelity CFD simulations. A laboratory test facility was used to obtain data for pressure and mass flow rates for the two-phase flow of air and water. A benchmark case of slug flow served for evaluation of the numerical models. A 3D unsteady CFD simulation was performed based on Reynolds-Averaged Navier-Stokes (RANS) formulation and the Volume of Fluid (VOF) model using the open-source CFD code OpenFOAM. Unsteady simulations using the commercial 1D LedaFlow solver were performed using the same boundary conditions and fluid properties as the CFD simulation. Both the CFD and LedaFlow model underpredicted the experimentally determined slug frequency by 22% and 16% respectively. Both models predicted a classical blowout, in which the riser is completely evacuated of water, while only a partial evacuation of the riser was observed experimentally. The CFD model had a runtime of 57 h while the LedaFlow model had a runtime of 13 min. It can be concluded that the prediction capabilities of the CFD and LedaFlow models are similar for riser-induced slug flow while the CFD model is much more computational intensive.

Digital transformation of the oil, gas and energy value chain

2018 ◽  
Vol 58 (2) ◽  
pp. 488 ◽  
Author(s):  
Paul Taliangis
Keyword(s):  
Value Chain ◽  
Business Models ◽  
Oil And Gas ◽  
Predictive Analytics ◽  
Data Access ◽  
Oil And Gas Industry ◽  
Digital Transformation ◽  
Time Data ◽  
Energy Value ◽  
Oil Gas

This paper looks back at 2014–2017 as a period of extraordinary transition of the international and Australian oil and gas industry, with mounting evidence that the industry and broader energy value chain is entering an era of unprecedented digital transformation. This process is expected to accelerate through 2018–2025, with profound implications for industry stakeholders. The key question is: are organisations and the industry more broadly doing enough, well enough, fast enough? Emerging from the lows of a pronounced industry recession, and subsequent and ongoing consolidation, there is now growing, broad-based acceptance that the industry needs to engage new business models that leverage modern digital technology to reform productivity and broader industry performance. However, the harsh reality is that other industries are delivering superior results, faster, which is driving a need for an elevated and sustainable strategic response. This paper seeks to illustrate the digital links that must be established along the full value chain between data access and management, predictive analytics, visualisation, team collaboration and communication technology. The digital links are enabled by internet connectivity and cloud-based infrastructure, which presents an opportunity for organisations of all sizes to realise benefits along the complete chain. This paper is structured in four parts: • The strategic context – what is driving the need to engage in digital transformation? • The digital transformation value proposition – what value can be achieved? • Case studies – what are examples of digital transformation? • Key learnings – what should we note from thousands of global digital initiatives underway along the energy oil, gas and energy value chain? The main takeaways from this study are: • There is an unprecedented opportunity to transform the oil and gas value chain to deliver new growth and improved productivity, linking real-time data, predictive analytics, interactive visualisation and collaboration. • Digital transformation is affordable, readily implemented and scalable to meet current and changing future needs. • There are many powerful examples of material value add across exploration, development, operations and business management. • Many organisations and the industry as a whole is lagging others – the industry is not doing enough, well enough, fast enough. • The time to act/accelerate is now. • Digital transformation is not about technology alone. Keys to success include vision, leadership, culture and data quality.

Development of Integrated Oil and Gas Plant Information Management System (PIMS) in Indonesia

2021 ◽  
Author(s):  
M. F. Amir
Keyword(s):  
Real Time ◽  
Information Management ◽  
Oil And Gas ◽  
Task Force ◽  
Early Warning Systems ◽  
Information Management System ◽  
Gas Production ◽  
Digital Transformation ◽  
Working Environment ◽  
Integrated Monitoring

As appointed to represent the Indonesian government for managing entire upstream oil and gas business and operations throughout Indonesia, the Special Task Force For Upstream Oil and the Gas Business Activities Republic of Indonesia or known as SKK Migas, have established a vision to integrate monitoring all Production Sharing Contract (PSC) operators in Indonesia, transforming the conventional-manual approach—which was previously less effective and efficient, into an online integrated monitoring system. It is motivated by the digital transformation trend in the industrial world, which brings a new wave of opportunities to raise effectiveness and efficiency. However, the challenges are not easy. Despite the fact that Indonesia’s oil and gas industry has been operating for a long time ago, various technologies, some of which have used old technology, are the actual conditions that must be handled. Therefore, a systematical strategy is required. Step by step approach, by integrating real-time connections of plant information management systems are proposed to incorporate the major production systems, which are responsible for producing more than 80% of 6.600 million standard cubic feet of gas per day and 700 thousand barrels of oil per day, from major oil and gas companies in Indonesia. The system was successfully built, which provides integrated real-time monitoring dashboards of major upstream operations in Indonesia and connected online with automatic reporting systems and early warning systems. The system’s dashboards and notifications give flexibility in connection, which can be accessed anytime and anywhere if an internet connection is available. During the pandemic COVID-19, which restricts inspection activities to the fields, the system is proven effective in monitoring points of view without losing supervision over the operational aspects, which assurances the achievement of the executed programs. In conclusion, the contribution of the presented work is the digital transformation in the oil and gas sector in Indonesia in terms of operational supervision, which successfully creates a collaborative working environment in managing the oil and gas production target achievement. It changes the interaction between government and PSC operator companies regarding data capture and process monitoring, bringing a new era in supporting the decision-making process.

Geomechanical analysis of horizontal wells in terms of stability for drilling — A case study from the Peri-Baltic Syneclise

2021 ◽  
Vol 40 (11) ◽  
pp. 805-814
Author(s):  
Michał Kępiński ◽  
Pramit Basu ◽  
David Wiprut ◽  
Marek Koprianiuk
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Microseismic Monitoring ◽  
Earth Model ◽  
Gas Field ◽  
Horizontal Section ◽  
Stress Regime ◽  
Geomechanical Analysis

This paper presents a shale gas field geomechanics case study in the Peri-Baltic Syneclise (northern Poland). Polish Oil and Gas Company drilled a vertical well, W-1, and stimulated the Silurian target. Next, a horizontal well, W-2H, drilled the Ordovician target and partially collapsed. The remaining interval was stimulated, and microseismic monitoring was performed. A second horizontal well, W-3H, was drilled at the same azimuth as W-2H, but the well collapsed in the upper horizontal section (Silurian). A geomechanical earth model was constructed that matches the drilling experiences and well failure observations found in wells W-1, W-2H, and W-3H. The field was found to be in a strike-slip faulting stress regime, heavily fractured, with weak bedding contributing to the observed drilling problems. An analysis of safe mud weights, optimal casing setting depths, and optimal drilling directions was carried out for a planned well, W-4H. Specific recommendations are made to further enhance the model in any future studies. These recommendations include data acquisition and best practices for the planned well.

Numerical Investigation of Two-Phase Flow in 45 Degrees “Y” Junctions

2015 ◽  
Author(s):  
Carlos Chacon ◽  
Carlos Moreno ◽  
Miguel Arbej ◽  
Miguel Asuaje
Keyword(s):  
Oil And Gas ◽  
Two Phase Flow ◽  
Petroleum Industry ◽  
Continuous Phase ◽  
Working Fluid ◽  
Phase Flow ◽  
Two Phase ◽  
Flow Energy ◽  
Oil Flow ◽  
Oil Gas

Frequently, Two-phase flow occurs in petroleum industry. It takes place on production and transportation of oil and natural gas. Initially, the most common patterns for vertical flow are Bubble, Slug, Churn and Annular Flow. Then, for horizontal flow, the most common patterns are Stratified Smooth, Stratified Wavy, Elongated Bubble, Slug, Annular, Wavy Annular and Dispersed Bubble Flow. It is also known that after separation, each fluid is carried through pipes, so oil is moved long distances. However, as it is known, the oil energy diminishes on the way. For that reason, it is needed a pumping station for keeping the oil flow energy high for proper movement. Additionally, that fluid is transported through a network, so fittings are present, like elbows, “T” and “Y” junctions, and others. As known, on a piping network, the losses can be classified in two groups: large and localized. The former consists on losses due to wall roughness-fluid interaction. The latter is related with fittings. This study is focused on 45° “Y” junctions. The main purpose of this study is to simulate the fluid flow on a 45° “Y” junction, using a 0.1143 m diameter 2 m length pipe, in which a 0.0603 m diameter 1 m length pipe confluences, using oil-gas as the working fluid, considering Dispersed Bubble Pattern. It can be attributed a “K” flow loss coefficient for each path, from each entry to the exit of the junction. For the Two-Phase Flow, it was supposed a horizontal Dispersed Bubble Pattern, which takes place at very high liquid flow rates. So the liquid phase is the continuous phase, in which the gas phase is dispersed as discrete bubbles. Particularly three API Grades were considered for the oil, corresponding to three main types of continuous phase. For the numerical model, it was generated several non-structured grids for validation, using water as a fluid. Then the simulations were carried out, using non-homogenous model, with oil and gas, changing the gas void fraction, and the superficial velocities for gas and liquid. A commercial package was used for numerical calculations. It was encountered that changing the value of the referred variables, in some cases the exit pressure of the “Y” junction diminishes. For validation of the results, a literature model was used for comparing both “K” loss coefficients: numerically and from the bibliography. It is important to highlight that these results, permit to analyze a way of diminishing the fluid energy losses in a Two-Phase oil-gas piping network, particularly in 45° “Y” junctions which represents economically saving.

Optimal Route for Pipelines in Two-Phase Flow

1971 ◽  
Vol 11 (03) ◽  
pp. 215-222 ◽  
Author(s):  
Uri Shamir
Keyword(s):  
Single Phase ◽  
Oil And Gas ◽  
Two Phase Flow ◽  
Optimal Solution ◽  
Oil Industry ◽  
Phase Flow ◽  
Optimal Route ◽  
Two Phase ◽  
Aerial Photos ◽  
Single Pipe

Abstract A technique is described, which makes it possible to select the optimal route for a pipeline designed to carry oil and gas in two-phase flow. The pipeline is assumed to operate under the pressure differential naturally available between the source and the point of delivery. point of delivery. A discrete grid is established to describe the corridor through which the pipeline is to pass. Topograpbic and terrain data are given for all grid points. Cost data is given for all factors which points. Cost data is given for all factors which affect the capital cost of the pipeline. The equation for the two-phase flow becomes a global constraint, to be satisfied by the selected route. Dynamic programming is then used to solve the minimization programming is then used to solve the minimization problem. problem. A computer program is described, with which a sample problem was solved, and the results that were obtained are also presented. Introduction Great sums of money are spent annually on the construction of pipelines for the oil industry. Many of these pipelines are designed to carry gas and oil in simultaneous two-phase flow from wells to various collecting and processing facilities. The procedures for selecting the route for such pipelines procedures for selecting the route for such pipelines have followed the traditional approach of engineering judgment and selection of the cheapest among a few alternative routes laid out by hand on maps and aerial photos. Aerial photo interpretation, to yield soil types, tree cover, existence of swamps and muskeg, and other factors affecting costs, is being used in route selection. Geologists and soil engineers are brought in to evaluate soil conditions on the basis of aerial photos, as well as by examination of the route itself and soil samples. This data is then used to select a route and to design the pipeline. The present project was undertaken with the objective of improving the engineering practice. We sought to proceed beyond the stage of mere trial and error and to develop a rigorous method for determining the optimal route by using the techniques of systems engineering. The over-all problem of conveying fluids in one-and two-phase flow pipelines was reviewed. It ranges from a single pipe carrying a single-phase fluid, through two-phase flow lines, to gathering systems containing networks of pipes and other equipment, such as valves and compressors, to collect the products of a large number of wells and deliver the mixed product to processing plants. All these were considered part of the over-all project, which deals with optimal design of pipeline systems. Initially, one aspect of the over-all project had to be selected. It was decided to tackle the problem of optimizing the route for a single pipeline carrying two-phase flow. This problem presents some complications, and it was felt that if it could be solved, single-phase pipelines would present no added difficulties. TWO-PHASE FLOW PIPELINES It is common practice in the oil industry to use a single pipe to carry both oil and gas from producing wells to collecting facilities and plants. The alternative is to separate the two phases at the source and carry them in separate pipelines. Economics of the two alternatives should be the basis for a choice between them. The present work is therefore a useful tool for making a better choice possible by yielding the optimal solution for the possible by yielding the optimal solution for the two-phase line alternative. As will be shown later, the method, as well as the computer programs, can also be used to determine the optimal route for a pipeline carrying flow of a single fluid. pipeline carrying flow of a single fluid. COMPUTING SIMULTANEOUS FLOW OF LIQUID AND GAS IN A PIPELINE The regime of flow in a pipeline carrying both liquid and gas depends on many parameters. The regime, in turn, determines the pressure losses along the pipeline. The procedures for computing the two-phase flow are both elaborate and rather inaccurate. No attempt is made in the present work to change or to improve the existing methods, as this is beyond its scope. We do need, however, to modify the sequence of the computations to suit the requirements of the optimization problem. SPEJ P. 215

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