Xingru Wu

Nitrogen Injection Experience to Development Gas and Gas Condensate Fields in Rocky Mountains

Nitrogen injection into gas condensate or volatile oil fields has been practiced as a method of pressure maintenance as well as enhanced hydrocarbon recovery in Rocky Mountains for more than two decades. Reservoir management has experienced miscible displacement in the gas cap, reservoir pressure maintenance, and reservoir blow down in different fields. In the implementation of nitrogen injection, a tremendous amount of experiences on injection and reservoir performance had been accumulated without appropriate documentation. Furthermore, even though nitrogen injection has been widely used in the world to enhance recovery by miscible displacement or maintaining reservoir pressure, literature survey shows that the experience with nitrogen injection is sporadic. This paper reviews reservoir characteristics and summarizes the lessons learned from nitrogen injection all of the world; then focuses on Rocky Mountains reservoir management to further analyze its production and surveillance, reservoir development stages in the life of fields, and the relationship between the fields and processing facility. Compositional reservoir simulation was performed to study the enhanced hydrocarbon recovery by injecting nitrogen and use nitrogen breakthrough information across the field as a continuous tracer to study the well connectivity between the injector and producer pairs. The main contributions of the paper are that it highlights the accumulated experience associated with nitrogen injection, and provides information on amenable reservoir features which can be used to select nitrogen as a viable alternative for enhanced oil recovery purpose.

Determining Coefficient of Quadratic Term in Forchheimer Equation

Forchheimer equation takes non-Darcy flow effect into account in the event of high flow velocity in porous media. Its application requires both permeability, which is in linear term, and Beta factor, which is in quadratic term. Permeability and Beta factor are determined by rock type, textural of rock, effective porosity, pore throat size, geometry of the pore, and connection and distribution of pores. Beta factor comes into play when the fluid flow rate is high and the flow rate deviates from Darcy’s law. Non-Darcy flow is described by Forchheimer equation. Usually the coefficient of non-Darcy flow term is hard to be determined. Existing approaches are core measurement and empirical correlations. To the best of our knowledge there is no theoretical equation available. To get an accurate estimation of flow rate or pressure drop in the reservoir, we need a method that has solid theoretical basis. The deficiency triggered our study. Starting from multiple-capillary tubes concept, we derived a rigorous relationship between pores geometry and pressure drop required for fluid flow through the pores. Through this correlation pressure drop can be calculated from known pores geometry. Since pores geometry can be often obtained from lab experiment or well logging, the new correlation also provides a unique approach to quantify the coefficient of quadratic term in Forchheimer equation. In this study we developed a governing equation through a rigorous theoretical derivation. With this equation the non-Darcy flow coefficient in Forchheimer equation can be calculated. The required input data for the new equation are readily obtained from well log interpretation. The new equation is a powerful tool in the event of no experimental measured non-Darcy flow coefficient available. It eliminates the errors or the arbitrary content in the empirical correlations.

A numerical simulation study of CO 2 injection for enhancing hydrocarbon recovery and sequestration in liquid-rich shales

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organic-rich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity.

New Method To Estimate Surface- Separator Optimum Operating Pressures

Summary The significance of setting optimal surface separation pressures cannot be overemphasized in surface-separation design for the purpose of maximizing the surface liquid production from the wellstream feed. Usually, classical pressure-volume-temperature (PVT) analysis of reservoir fluids provides one or several separator tests through which the optimum separator pressures are estimated. In case separator tests are not available, or the limited numbers of separator tests are not adequate to determine the optimum separator pressures, empirical correlations are applied to estimate the optimum separator pressures. The empirical correlations, however, have several disadvantages that limit their practical applications. In this study, we approached the problem with a rigorous method with a theoretical basis. According to the gas/liquid equilibrium calculation, the optimum separator pressures were determined. Comparisons of our results with experimental data indicated that the proposed method can simulate the separator tests very well. Because the method has a theoretical basis and does not require existing two-stage or multiple-stage separator-test data as in the application of empirical correlations, it potentially has wide applications in practice for a variety of conditions and yields a more optimal separation scheme than the empirical correlations. Furthermore, the method is independent of reservoir fluid. In the event that separator tests are available from fluid analysis, our method can be used as a quality-control tool. Because the setting for optimal separation pressures vary as the composition of the wellstream changes during the field life, our method provides a quick and low-computational-cost approach to estimate optimum separator pressures corresponding to different compositions.

A New Method To Detect Partial Blockage in Gas Pipelines

plex pipeline network. Furthermore, existing studies assume only single partial blockage in the pipeline, which limits the application of available models because the detection will be misleading if there is more than one partial blockage in the pipeline. To fill this gap, we developed a model to differentiate the single-partialblockage scenario from the multiple-partial-blockage scenario on the basis of multirate tests. The identification is critical because it guides partial-blockage detection in the right direction.

Deepwater Reservoir Characterisation Using Tidal Signal Extracted from Permanent Downhole Pressure Gauge

Permanent Downhole Gauge (DHG) technology has been widely used in deep water reservoir development in the last decade and is playing an increasingly significant role in real time reservoir/well surveillance and reservoir management. Tidal signal extracted from the highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock pore compressibility. Most previous works treated tidal signal as pressure “noise” and little has been discussed on how to utilize the tidal information in reservoir characterization. This paper will address how to use Fast Fourier Transform (FFT) to extract the tidal signal and the theory and method to process the signal for reservoir characterization purposes. In addition, several examples from some deep water fields will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid saturation change, and detect the presence of secondary gas cap. This paper will show that FFT is a fast and reliable method to process the DHG pressure data for tidal signal which can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signal are very unique because they cannot obtained in laboratory, simulation, or direct measurements because of the scale impacted by tides.