Development and Applications of a Fully Implicitly Coupled Wellbore-Reservoir Simulator

In this dissertation, we develop a compositional multiphase wellbore-reservoir simulator, GURU-MSW. The compositional reservoir simulator GURU serves as the starting point of this work. GURU-MSW fully implicit couples a multi-segment wellbore (MSW) model with the reservoir simulator GURU. Although taking the most developing effort, the fully implicit coupling mechanism is considered to be unconditionally stable and fast. After developing the general framework of the simulator, the coupled MSW-reservoir simulator is tested in two application scenarios, both being the first attempt in the literature. The first application is to analyze the well interference phenomenon. Well interference, introduced by the inter-well fracture hits, is a major production issue in shale reservoir development. When fracture hits occur, GURU-MSW can capture the sudden production rate jump caused by the wellbore crossflow. We also apply GURU-MSW to model a case with three wells under well group control. The second application of GURU-MSW is the simulation of liquid loading phenomenon. Liquid loading is an inevitable production issue in mature gas fields, which occurs when the producing gas rate is not high enough to carry all the liquids to wellbore surface. This is a phenomenon that can neither be comprehensively simulated by a single wellbore simulator nor a single reservoir simulator because of the dynamic interaction between wellbore and reservoir. GURU-MSW successfully characterizes the dynamic interaction between wellbore multiphase flow and reservoir multiphase flow. We systematically analyze a cyclical production phenomenon, which was only reported as field observations previously. Two new gas-liquid drift-flux models are proposed in this dissertation. The first model incorporates the flow regime transition criteria from annular flow to churn or slug flow for vertical, slanted and horizontal pipes. The model is specially designed for the application of liquid loading modeling in horizontal gas wells. The second model is a unified model for all pipe inclinations. The new model is tested against 5805 experimental measured data points from 22 sources as well as 13440 data points from the OLGA-S library. The numerical stability of the model is tested with GURU-MSW. The drift-flux model commonly applied in MSW simulation only covers a pipe inclination range from 2 degrees (nearly horizontal) to 90 degrees (vertical upward). The proposed model has a potential in filling in the gap left by the existing drift-flux model

Development of a multiphase flow simulator for drilling applications

Drilling, or gas kick, simulators are becoming prevalent in industry due to their ability to replicate wellbore conditions that are not feasible in a laboratory setting. This is becoming more desirable as deeper wells are being explored. One of the biggest dangers that could happen during drilling operations is the onset of a gas kick. This occurs when a zone in the formation whose pressure is higher than that of the wellbore is breached. This allows for the undesired influx of formation fluids into the wellbore. If left uncontrolled, it could develop into a blowout. Gas kick simulators allow for testing of procedures that could be used to contain kicks at such depths. Furthermore, the use of drilling simulators could provide more insight into other phenomena. These include wellbore breathing and fracture ballooning, that cause similar kick symptoms at the surface and lead to expensive misdiagnosis, and the dissolution of gas into oil based mud, which could delay the identification of a kick. This thesis investigates the development of the initial integration of a drilling simulator into UTWELL, the wellbore simulator program developed at The University of Texas at Austin, by implementing a gas kick module. The transport equations of mass and momentum conservation were discretized using a Semi-Implicit Homogeneous Method over a one dimensional staggered grid. The multiphase phenomena were modelled using a Drift Flux approach as opposed to a mechanistic, Two Fluid approach. This was due to increased stability of the solution and faster computation time, despite the risk of loosing accuracy. The simulator was successful at simulating single phase flows for fluids with distinct rheology models, and with wellbores with discontinuities in the geometry. When attempting to simulate the well control of a gas kick in water based mud, the results were mixed. Attempt at simulating a `Floating Mud Cap' method failed due to the simulator's inability to perform drainage functions that allow for the raising and lowering of the mud level in the wellbore. However, the simulator was successful at capturing the behaviour of the gas kick as it entered and migrated through the wellbore, matching literature results. The simulator was compared to experimental data gathered from a test well. Three different scenarios were tested: No Drillstring, Semi-Submerged Drillstring and Drillstring at the Bottom. In all three cases, there was a good match between the experimental and simulation results for the bottomhole and choke pressures. The pit gain was severely overestimated in the 'No Drillstring' and 'Semi-Submerged Drillstring Case', however this was due to a higher influx of simulated gas having entered the wellbore during simulations. The 'Drillstring at the Bottom' simulation matched well with all data and with other simulators. Recommendations included full integration and testing of a compositional model to simulate oil based mud cases, implementation of automatic choke control and special flux splitting techniques in the discretization in order to better handle pressure waves caused by discontinuities.Petroleum and Geosystems Engineerin

A Fully-Coupled Implicit Transient Two-Phase Wellbore Simulator

Boreholes under operation conditions typify a highly non-linear and complexly coupled thermo-hydraulic-chemical (THC) system. Multiple parameters, such as temperature, pressure, specific heat, enthalpy, viscosity, flow regime, heat transfer, degassing, steam quality, salinity and solubility are inter connected. Production and injection often entail several engineering challenges and operational problems within the boreholes but also up and down stream (reservoir-power plant-reservoir), which can be very diverse in their character. Finding solutions or working on process optimization prerequisite a profound understanding and a reliable tool to quantify these processes. Compared to reservoirs, the processes in boreholes are highly dynamic and fluctuating. Most existing simulators provide either only steady state solutions or are based on a just weakly coupled numerical scheme. We develop a new tool solving for the aforementioned parameters in a fully-coupled, implicit, and transient manner, which is a prerequisite to realistically model dynamic borehole conditions. Herein, we present the current state of the development of the simulator for multicomponent non-isothermal two-phase flow. To demonstrate the capabilities of the code, validation results and synthetic test cases for compressible single-phase flow as well as two-phase drift-flux are shown. Applications of such a tool are manifold. It can be used for exploration in early stages of the reservoir development, to constrain the static formation temperature (SFT) from logging data measured under dynamic production/injection conditions. What-if-calculations support the design and dimensioning of future power plants. Optimization of production and injections scenarios are more reliable when they are based on solid quantifications of thermo-hydraulic borehole processes. Furthermore, borehole simulation can also be the basis for managing the complex handling of co-produced noncondensable gases or preventing scaling formation and steel corrosion

Improved bottomhole pressure control for underbalanced drilling operations

Maintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee the success of jointed-pipe underbalanced drilling (UBD) operations by avoiding formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions is an unmet challenge that continues motivating not only research but also technological developments. This research proposes an UBD flow control procedure, which represents an economical method for maintaining continuous underbalanced conditions and, therefore, to increase well productivity by preventing formation damage. It is applicable to wells that can flow without artificial lift and within appropriate safety limits. This flow control procedure is based on the results of a new comprehensive, mechanistic steady state model and on the results of a mechanistic time dependent model, which numerically combines the accurate comprehensive, mechanistic, steady-state model, the conservation equations approximated by finite differences, and a well deliverability model. The new steady state model is validated with both field data and full-scale experimental data. Both steady state and time dependent models implemented in a FORTRAN computer program, were used to simulate drilling and pipe connection operations under reservoir flowing conditions. Actual reservoir and well geometries data from two different fields, in which the UBD technique is being employed, were used as input data to simulate simultaneous adjustments of controllable parameters such as nitrogen and drilling fluid injection flow rates and choke pressure to maintain the bottomhole pressure at a desired value. This value is selected to allow flow from the reservoir to substitute for reduction or cessation of nitrogen injection during drilling and for interruption of nitrogen and drilling fluid circulation during a pipe connection. Finally, a specialized procedure for UBD operations is proposed to maximize the use of natural energy available from the reservoir through the proper manipulation of such controllable parameters based on the results of the computer simulations

An Integrated Modeling Approach for Vertical Gas Migration Along Leaking Wells Using a Compressible Two-Fluid Flow Model

Gas migration behind casings can occur in wells where the annular cement barrier fails to provide adequate zonal isolation. A direct consequence of gas migration is annular pressure build-up at wellhead, referred to as sustained casing pressure (SCP). Current mathematical models for analyzing SCP normally assume gas migration along the cemented interval to be single-phase steady-state Darcy flow in the absence of gravity and use a drift-flux model for two-phase transport through the mud column above the cement. By design, such models do not account for the possible simultaneous flow of gas and liquid along the annulus cement or the impact of liquid saturation within the cemented intervals on the surface pressure build-up. We introduce a general compressible two-fluid model which is solved over the entire well using a newly developed numerical scheme. The model is first validated against field observations and used for a parametric study. Next, detailed studies are performed, and the results demonstrate that the surface pressure build-up depends on the location of cement intervals with low permeability, and the significance of two-phase co-current or counter-current flow of liquid and gas occurs along cement barriers that have an initial liquid saturation. As the magnitude of the frictional pressure gradient associated with counter-current of liquid and gas can be comparable to the relevant hydrostatic pressure gradient, two-phase flow effects can significantly impact the interpretation of the wellhead pressure build-up

Pressure Build-Up in Closed Wells During Kick Migration and Fluid Compressibility Effects

If a kick is migrating in a closed well, this will lead to pressures building up in the well. It has earlier been shown that for Non-Newtonian fluids, suspension effects will make it impossible to deduce a unique gas velocity from the pressure build-up behavior. In this work, it will be shown that also for Newtonian fluids, the pressure build-up will depend on both kick size and well volumes. Both very small kicks sizes typically seen in MPD operations and larger kick sizes handled in conventional well control operations will be considered. It will be demonstrated that both the shape of the pressure build-up and the final pressure levels achieved will vary significantly. It is especially when considering very small kick sizes that one starts to see large changes in the profile of the pressure build-up. The main reason for the differences is related to the fact that the liquid phase is compressible and this will again have consequences for how much a gas kick can expand and what pressures it can bring to surface. An analytical model will be developed that shows directly which parameters have impact on the pressure build-up behavior. Simple closure laws for gas density, fluid density and gas slip will be chosen. The model will be verified against two transient models which are based on the Drift-Flux formulation. It is demonstrated that the pressure build-up and final pressure level will depend on initial kick volume, initial fluid volume, liquid compressibility and fluid density. The effect of numerical diffusion when comparing the two transient models will also briefly be discussed. The purpose of the paper is to increase fundamental knowledge about two phase flow dynamics and show that an analytical model for the situation considered here can give results that are comparable with the results achieved with more complex transient flow models.acceptedVersio

MPD and use of the AUSMV model to simulate and analyze propagation of pressure pulses.

Master's thesis in Petroleum engineeringOffshore drilling is one of our era’s most challenging operations in the petroleum industry. Conventional drilling methods face difficulty in certain prospects, such as drilling in deep water reservoirs and depleted offshore reservoirs. This is due to the narrow drilling window present in these types of reservoirs. There is a small margin between the pore pressure gradient and the fracture gradient which causes difficulty to drill with conventional methods. Managed pressure drilling (MPD) has emerged as a solution to many of the conventional drilling problems like kick scenarios, lost circulation, stuck pipe problems and drilling in depleted reservoirs. MPD provides us with precise control in these narrow margin wells by allowing drilling close to the pore-pressure gradient. The conventional drilling problems are either reduced or eliminated completely by using MPD technology. Most of MPD is executed by drilling in a closed well loop utilizing a Rotating Control Device (RCD) with a minimum of one drill string Non-Return Valve, and a Drilling Choke Manifold. The choke can be controlled manually or automatically. In today’s world the most common type is the automatic choke regulation. It requires PID controllers as a regulation technique, this is based on the difference between measured pressure vs required pressure. In addition to that, the automation process is supported by hydraulic simulator models. Wellbore control is very precise in MPD, assuming that the wellbore is sealed and able to contain the pressure. If this is the case, it is then possible to monitor the pressure throughout the wellbore in real time at the surface. Pressure changes are seen immediately in a closed system. MPD offers more precise control of the annular wellbore pressure profiles; hence influxes and losses are detected immediately. Safety of personnel and equipment during drilling is improved. Drilling economics is improved in MPD due to the reduction of drilling mud costs and reduction in non-productive time. The Drift Flux model is used in the petroleum industry among other things to evaluate transient flow responses of drilling operations. It has its roots in the laws of conservation for two phase flow, and its goal is to describe the characteristics of flow in pipes or wells. The AUSMV (Advection Upstream Splitting Method) scheme is a hybrid flux-vector splitting scheme. The AUSMV scheme is used in this thesis to simulate different scenarios concerning propagation of pressure pulses in a well. In the simulations we studied the pressure pulse propagation caused by pump start up and choke valve adjustments. It was demonstrated what effect friction has on the pulses and if the differences between having a one-phase and two-phase flow system. In the latter case, we also show how the gas volume content in the well affects the propagation velocities. Pressure pulse propagation caused by pump start up and choke valve adjustments is studied in the simulations with the help of the AUSMV scheme. Studying the propagation of pressure pulses generated by adjusting the choke, is of importance in MPD because situations arise where we have to increase the choke pressure to avoid kick. In a MPD system, presence of gas might easily occur since the system is designed for taking small gas kicks while drilling. Hence, in a long extended reach well, this is maybe an effect that one has to consider when working with an automated choke regulation system. After a given choke adjustment, one must give the well time to respond before an additional choke adjustment is introduced. The results of the simulations show that the sonic velocity depends both on gas fraction and pressure. If we operate with gas in a well, typically we find that the sonic velocity is reduced most at the top of the well. As the pressure increases with well depth, the sonic wave propagation velocity increases. Therefore, if we adjust the choke by making fast updates based on frequent measurements in long wells, there is a possibility that this “time lag” is a factor which must be taken into account. This will particularly apply to underbalanced drilling systems where we know there will be significant volumes of gas in the well

Predicción del flujo multifásico en tuberías: artículo de revisión

In this work a review about the most relevant methods found in the literature to model the multiphase flow in pipelines is presented -- It includes the traditional simplified and mechanistic models, moreover, principles of the drift flux model and the two fluid model are explained -- Even though, it is possible to find several models in the literature, no one is able to reproduce all flow conditions presented in the oil industry -- Therefore, some issues reported by different authors related to model validation are here also discussedEn este trabajo se presenta una revisión de los métodos más relevantes en la industria del petróleo para modelar el flujo multifásico en tuberías -- Se incluyen desde los modelos simplificados hasta los modelos mecanicistas además de explicar los principios de los modelos drift flux y two fluid -- Existe una gran cantidad de modelos en la literatura para simular el flujo multifásico en tuberías, empero, ningún modelo es capaz de reproducir todas las condiciones de flujo multifásico presentes en la industria del petróleo -- Finalmente, se mencionan algunos temas en los que se requiere más investigación que lleven a simulaciones con resultados más cercanos a los datos de pozos reale