Improving reservoir performance using intelligent well completion sensors combined with surface wet-gas flow measurement

2012 ◽  
Vol 52 (1) ◽  
pp. 181
Author(s):  
Nematollah Tarom ◽  
Mofazzal Hossain
Keyword(s):  
Data Acquisition ◽  
Gas Flow ◽  
Reservoir Management ◽  
Production Performance ◽  
Well Performance ◽  
Reservoir Performance ◽  
Well Completion ◽  
Wet Gas ◽  
Wellbore Pressure ◽  
Reservoir Conditions

Reservoir performance, in addition to day-to-day well performance, needs to be evaluated during the life of a well. The production logging tool (PLT) is conventionally designed to provide a full set of data measurements in producing wells to evaluate well and reservoir performance. Depending on the well conditions and location, running conventional PLTs may be difficult, impossible or expensive. Therefore, an alternative approach that can be applied in lieu of PLT operations—to obtain information similar to PLTs for better reservoir management—and that can optimise reservoir production performance is desireable. Data acquisition techniques such as downhole pressure/temperature gauges, fibre optic sensors at reservoir conditions and wet-gas flow meters at the surface have been considered as a viable alternative. Such data acquisition techniques help to increase flexibility in the field development and reservoir management of problematic wells with well completion technologies such as multi-lateral, horizontal and artificial lift. This study focused on the development of an alternative method of analysing problem well data on the basis of downhole pressure and temperature data collected at reservoir conditions. The proposed model has been based on the Joule-Thomson effect and radial heat and fluid flow equations to solve the transient wellbore pressure and temperature equations. It is expected this model can be used to analyse intelligent wells completed with downhole pressure and temperature sensors, and facilitate the monitoring of wells and reservoir performance without any PLT operation, especially for complex fields.

A Compositional Rescaled Exponential Model for Multiphase-Production-Performance Analysis of Boundary-Dominated Gas/Condensate Reservoirs

SPE Journal ◽  
2018 ◽  
Vol 24 (02) ◽  
pp. 618-646
Author(s):  
Ryan Will ◽  
Qian Sun ◽  
Luis F. Ayala
Keyword(s):  
Performance Analysis ◽  
Numerical Models ◽  
Compositional Analysis ◽  
Gas Condensate ◽  
Production Performance ◽  
Analytical Models ◽  
Reservoir Modeling ◽  
Well Performance ◽  
Reservoir Performance ◽  
Hydrocarbon Reservoir

Summary Hydrocarbon-reservoir-performance forecasting is an integral component of the resource-development chain and is typically accomplished using reservoir modeling, by means of either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps (1945) empirically demonstrated that certain reservoirs might decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more-complex scenarios, such as multiphase-reservoir depletion. Because of this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, we demonstrate that rigorous compositional analysis can be coupled with analytical well-performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon-fluid fractions can be expressed in terms of rescaled exponential equations for well-performance analysis. This work demonstrates that, by the introduction of a new partial-pseudopressure variable, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas/condensate-reservoir systems characterized by widely varying richness and complex multiphase-flow scenarios. A new four-region-flow model is proposed and validated to implement gas/condensate-deliverability calculations at late times during variable-bottomhole-pressure (BHP) production. Five case studies are presented to support each of the model capabilities stated previously and to validate the use of liquid-analog rescaled exponentials for the prediction of production-decline behavior for each of the hydrocarbon species.

Maximizing Asset Value & Field Recovery with Advanced Completion Solutions – A Digital Twin Field Case Study with Multilateral, Intelligent Completion, and AICD Completion Technologies

2021 ◽  
Author(s):  
Noman Shahreyar ◽  
Ben Butler ◽  
Georgina Corona
Keyword(s):  
Reservoir Simulation ◽  
Simulation Software ◽  
Well Performance ◽  
Reservoir Model ◽  
Additional Information ◽  
Well Completion ◽  
Asset Value ◽  
Reservoir Conditions ◽  
Control Devices

Abstract The drilling and completion of multilateral wells continues to expand and advance within the oil industry after three decades of accelerating adoption. The performance of these wells can be increased when integrated with advanced well completion techniques. The addition of intelligent completions (IC) and inflow control devices (ICD/AICD) enhances well performance and improves field recovery. This paper discusses a reservoir simulation case study that evaluates the productive impact these technologies provide when combined with multilateral technology (MLT), and the mechanism by which they achieve it. A reservoir model is devised and simulates under dynamic reservoir conditions the field production of dual lateral and single bore horizontal wells. The simulation is conducted for three separate scenarios where AICD and IC are incrementally implemented. The results are compared across the scenarios and their value quantified. The mechanisms by which estimated ultimate recovery (EUR) is increased will be discussed, including the increase of reservoir contact, drawdown distribution optimization, and the control and delay of water production. The study will provide an overview on the theory behind the technologies. It will also review the workflow used to conduct the study, utilizing a combination of steady state nodal analysis software and dynamic reservoir simulation software. Additional information about the reservoir model, initial and boundary conditions are detailed, to provide insight into reservoir simulation methodology.

A Computational Fluid Dynamics Approach to Predict Pressure Drop and Flow Behavior in the Near Wellbore Region of a Frac-Packed Gas Well

2015 ◽  
Author(s):  
Oscar Molina ◽  
Mayank Tyagi
Keyword(s):  
Fluid Dynamics ◽  
Mathematical Model ◽  
Computational Fluid Dynamics ◽  
Pressure Drop ◽  
Gas Flow ◽  
Flow Behavior ◽  
Flow Region ◽  
Production Performance ◽  
High Permeability ◽  
Well Completion

Well completion plays a key role in reservoir production as it serves as a pathway that connects the hydrocarbon bearing rock with the wellbore, allowing formation fluids (e.g. oil, gas, water) to flow into the well and then up to production facilities on the surface. Frac-packing completion (F&P) is a well stimulation technique that vastly increases the fluid transport capability of the near wellbore region in comparison with the original formation capacity by filling fractures and perforation tunnels with high-permeability proppant, thus enabling higher production rates for the same pressure drop. Hence, it is of interest for the production engineer to have an accurate description of the actual and predicted production performance in terms of pressure drop and flowrate after the F&P completion process is done. However, in developing a mathematical model of this scenario two critical challenges should be faced: (a) as fluid flows at high flowrates it begins to deviate from linear behavior, i.e. Darcy’s law is no longer valid, (b) compressible fluid flow behavior in the near wellbore region cannot be intuitively predicted due to the geometrical complexity introduced by the well completion (e.g. perforation tunnels and fractures). Additionally, this kind of mathematical model must take into account the existence of three different domains: reservoir (porous, low permeability), completion region (porous, high permeability), and free flow region. In view of these complications, this study presents a computational approach to model and characterize the near wellbore region with F&P completion using computational fluid dynamics (CFD) modeling, combining a non-linear (non-Darcy or Forchheimer) real gas flow in porous media with a turbulence model for the free flow region. This study is classified into three parts: 1) verification case, 2) Darcy vs. non-Darcy flow, and 3) erosion analysis. All simulation cases are assumed to be isothermal, steady state gas flow. Streamlines are implemented to identify the possible kinds of flow regimes, or patterns, in the near wellbore region and it is shown that gas flow pattern can be high unpredictable. Turbulence production and erosional velocity limit are also analyzed. Finally, mathematical correlations for well completion performance of this particular case study are derived using data curve fitting. In conclusion, the CFD approach has proven to be a powerful yet flexible computational tool that can help the production and/or reservoir engineer to predict flow behavior as well as production performance for a gas producing well with F&P completion, while providing an insightful graphical description of pressure and velocity distribution in the near wellbore region.

scholarly journals Temporal Scale Analysis of Gas Flow in Tight Gas Reservoirs considering the Nonequilibrium Effect

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Binglin Li ◽  
Yuliang Su ◽  
Maen Husein ◽  
Roberto Aguilera ◽  
Mingjing Lu
Keyword(s):  
Fractal Geometry ◽  
Gas Flow ◽  
Temporal Scale ◽  
Production Performance ◽  
Darcy Flow ◽  
Scale Analysis ◽  
Nonequilibrium Effect ◽  
Wellbore Pressure ◽  
The Matrix ◽  
The Impact

The fractal geometry, anisotropy, discontinuity, and non-Darcy flow of tight reservoirs exert a significant effect on well production performance. In this study, the reservoir fractal geometry is represented by exponential functions on the basis of microseismic data, while the discontinuity of the fractures is presented as a nonequilibrium effect. The impact of the nonequilibrium effect and the low velocity non-Darcy flow on the temporal scale of the wellbore pressure is predicted herein. Results showed that the time scale analysis accurately simulates gas flow in a tight reservoir. The wellbore pressure gradually increases, whereas the pressure in the matrix lags when the nonequilibrium effect is considered. The wellbore pressure is affected in the early period by the nonequilibrium effect. However, at the later stage, the pressure in the matrix is mainly affected by the non-Darcy flow. When the non-Darcy flow is dominant, the pores without gas flowing through are better presented.

Invariant method for measuring wet gas flow rate

2021 ◽  
pp. 13-19
Author(s):  
Zhanat А. Dayev ◽  
Gulzhan E. Shopanova ◽  
Bakytgul А. Toksanbaeva
Keyword(s):  
Flow Rate ◽  
Measurement System ◽  
Flow Measurement ◽  
Gas Flow ◽  
Test Results ◽  
Invariant System ◽  
Rate Measurement ◽  
Gas Flow Rate ◽  
Flow Rate Measurement ◽  
Wet Gas

The article deals with one of the important tasks of modern flow measurement, which is related to the measurement of the flow rate and the amount of wet gas. This task becomes especially important when it becomes necessary to obtain information about the separate amount of the dry part of the gas that is contained in the form of a mixture in the wet gas stream. The paper presents the principle of operation and structure of the invariant system for measuring the flow rate of wet gas, which is based on the combined use of differential pressure flowmeters and Coriolis flowmeters. The operation of the invariant wet gas flow rate measurement system is based on the simultaneous application of the multichannel principle and the partial flow measurement method. Coriolis flowmeters and the differential pressure flowmeter are used as the main elements of the system. The proposed measurement system does not offer applications for gases with abundant drip humidity. The article provides information about the test results of the proposed invariant system. The estimation of the metrological characteristics of the invariant system when measuring the flow rate of wet gas is given. The obtained test results of the invariant wet gas flow rate measurement system are relevant for natural gas production, transportation, and storage facilities.

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