Luis F. Ayala

Low-Liquid Loading Multiphase Flow in Natural Gas Pipelines

Pressure and temperature variations of natural gas flows in a pipeline may cause partial gas condensation. Fluid phase behavior and prevailing conditions often make liquid appearance inevitable, which subjects the pipe flow to a higher pressure loss. This study focuses on the hydrodynamic behavior of the common scenarios that may occur in natural gas pipelines. For this purpose, a two-fluid model is used. The expected flow patterns as well as their transitions are modeled with emphasis on the low-liquid loading character of such systems. In addition, the work re-examines previous implementations of two-flow model for gas-condensate flow.

Quantification of Fracturing Fluid Migration due to Spontaneous Imbibition in Fractured Tight Formations

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-fracture productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention through laboratory experiments, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this project, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention

A density-based material balance equation for the analysis of liquid-rich natural gas systems

This study analytically cross examines the consistency among available zero-dimensional material balance equations (MBEs) for liquid-rich gas equations and derive a new simple yet rigorous MBE starting from governing equations applicable to these systems. We propose a new zero-dimensional (tank) material balance equation directly applicable to the analysis of liquid-rich (wet and retrograde) gas reservoirs expressed as a function of an equivalent gas molar density, as well as investigate and critically compare its predictions against other zero-dimensional (tank) models proposed in the past for gas reservoir cases with different amounts of condensate content (lean, intermediate and rich). All models are employed to predict reservoir performance given reservoir original-fluids-in-place and compared against benchmark examples created by numerical simulation. Actual field examples are also analyzed using existing and proposed models to test their ability to provide reliable reserve estimations using straight-line methods. The proposed density-based equation is proven to be straightforward to implement since it is written in terms of density, which allows it be directly expressed as an extension of the dry gas MBE, while not requiring the implementation of two-phase Z-factors.

MULTIVARIATE PRODUCTION OPTIMIZATION OF A NATURAL GAS FIELD

Abstract This paper presents two numerical models: a gas well model and a modified gas well model, which respectively analyse the effect of selected parameters on the final production performance of a natural gas field, and predict the combination of these design parameters for profit maximization. A sensitivity analysis is accomplished with the gas well model, thus displaying the individual and combined impact of the chosen design parameters on the system performance in terms of production rate. This is done by testing the model with several production scenarios. An economic survey is added to the previous analysis and the modified gas well model helps to determine the combination of parameters that will best allow the attainment of a given field production target, in terms of maximization of the net present value of the project.

Evaluation of “Marching Algorithms” in the Analysis of Multiphase Flow in Natural Gas Pipelines

Marching algorithms are the rule rather than the exception in the determination of pressure distribution in long multiphase-flow pipes, both for the case of pipelines and wellbores. This type of computational protocol is the basis for most two-phase-flow software and it is presented by textbooks as the standard technique used in steady state two-phase analysis. Marching algorithms acknowledge the fact that the rate of change of common fluid flow parameters (such as pressure, temperature, and phase velocities) is not constant but varies along the pipe axis while performing the integration of the governing equations by dividing the entire length into small pipe segments. In the marching algorithm, governing equations are solved for small single sections of pipe, one section at a time. Calculated outlet conditions for a particular segment are then propagated to the next segment as its prescribed inlet condition. Calculation continues in a “marching” fashion until the entire length of the pipe has been integrated. In this work, several examples are shown where this procedure might no longer accurately represent the physics of the flow for the case of natural gas flows with retrograde condensation. The implications related to the use of this common technique are studied, highlighting its potential lack of compliance with the actual physics of the flow for selected examples. This paper concludes by suggesting remedies to these problems, supported by results, showing considerable improvement in fulfilling the actual constraints imposed by the set of simultaneous fluid dynamic continuum equations governing the flow.

A Unified Two-Fluid Model for Multiphase Flow in Natural Gas Pipelines

A unified two-fluid model for multiphase natural gas and condensate flow in pipelines is presented. The hydrodynamic model consists of steady-state one-dimensional mass and continuity balances for each phase and a combined energy equation to give a system of five first-order ordinary differential equations. The hydrodynamic model is coupled with a phase behavior model based on the Peng-Robinson equation of state to handle the vapor-/liquid equilibrium calculations and thermodynamic property predictions. The model handles single and two-phase flow conditions and is able to predict the transition between them. It also generates profiles for pressure, temperature, and the fluid velocities in both phases as well as their holdups. The expected flow patterns as well as their transitions are modeled with emphasis on the low liquid loading character of such systems. The expected flow regimes for this system are dispersed liquid, annular-mist, stratified smooth as well as stratified wavy.Copyright

Two-phase flow models for thermal behavior interpretation in horizontal wellbores

The interpretation of Distributed Temperature Sensing (DTS) real-time temperature data from downhole is essential to understand wellbore production and production operations management. This paper presents a multi-phase wellbore thermal behavior prediction model for the interpretation of wellbore fluid thermal responses. Based on our previous simulation results on single-phase flow in horizontal wellbores, a two-phase flow model (ηs-driven model) is developed for steady-state conditions in the form of homogeneous and drift-flux models applied to both openhole and perforated completion types. Case studies include the examination of water entry thermal effect and gas mixing thermal effect comparing between the two modeling approaches. Results show that the phenomena of water breakthrough and gas blended in oil can be detected from fluids temperature profiles.

Limitations of “Marching Algorithms” in the Analysis of Multiphase Flow in Pipelines

Marching algorithms are the rule rather than the exception in the determination of pressure distribution in long multiphase-flow pipes, both for the case of pipelines and wellbores. This type of computation protocol is the basis for most two-phase-flow software and it is presented by textbooks as the standard technique used in steady state two-phase analysis. Marching algorithms acknowledge the fact that the rate of change of common fluid flow parameters (such as pressure, temperature, and phase velocities) are not constant but vary along the pipe axis while performing the integration of the governing equations by dividing the entire length into small pipe segments. In this algorithm, governing equations are solved for small single sections of pipe at a time, and the calculated outlet conditions for the particular segment and then propagated to the next segment as its prescribed inlet condition. Calculation continues in a “marching” fashion until the entire length of the pipe has been integrated. In this work, several examples are shown where this procedure cannot longer accurately represent the physics of the flow. The implications related to the use of this common technique are studied, highlighting its lack of compliance with the actual physics of the flow for selected examples. This paper concludes by suggesting remedies to these problems, supported by results, showing considerable improvement in fulfilling the actual constrains imposed by the set of simultaneous fluid dynamic continuum equations governing the flow.© 2007 ASME

Avoiding Pitfalls in Multiphase Thermo-Hydrodynamic Coupling

Multiphase flow is prevalent in many industrial processes. Therefore, accurate and efficient modeling of multiphase flow is essential to the understanding of these processes as well as the development of technologies to handle and manage them. In the petroleum industry, the occurrence and consequence thereof associated with such hydrodynamic processes are encountered in offshore facilities, surface facilities as well as reservoir applications. In this paper, we consider the modeling of these processes with special consideration to the transport of petroleum products through pipelines. Multiphase hydrodynamic modeling is usually a trade-off between maximizing the accuracy level while minimizing the computational time required. The most fundamental modeling effort developed to achieve this goal is based on applying simplifications to the basic physical laws, as defined by continuum mechanics, governing these processes. However, the modeling of multiphase flow processes requires the coupling of these basic laws with a thermodynamic phase behavior model. This paper highlights the impact of the techniques used to computationally couple the system’s thermodynamics with its fluid mechanics while paying close attention to the trade off mentioned above. It will consider the consequences of the simplifications applied, as well as inherent deficiencies associated with such simplifications. Special consideration is given to the conservation of mass as well as the terms that govern its transfer between the phases. Furthermore, the implications related to the common simplification of isothermal conditions are studied, highlighting the loss of accuracy in the material balance associated with this computational time-saving assumption. This paper concludes by suggesting remedies to these problems, supported by results, showing considerable improvement in fulfilling both the basic constrains which are minimizing time and maximizing accuracy.Copyright