Plunger lift is an economical artificial lift method to solve the liquid loading problem in gas wells. Because of the inevitable annular gap between plunger and tube wall, the liquid above plunger may leak downward and the gas may slip upward during lifting process. How to quantitatively describe the gas-liquid counter-current flow sealing property is still challenging to optimize the plunger lift method. In this paper, the liquid leakage and gas slippage were observed experimentally. The transient physical models for gas and liquid leakage were proposed and verified.
Most gas wells produce liquid such as water and hydrocarbon condensate throughout the life cycles. Both gas and liquid are originally produced to wellhead if the gas velocity is high enough to lift the coproduced liquids up the tubing1. With gas field becoming mature and gas production rate reducing below the critical rate, liquid accumulates in the bottom of the well and imposes a back pressure on the reservoir, which is called liquid loading in oil and gas industries2-4.
Vieira, C. (Norwegian University of Science and Technology) | Kallager, M. (Norwegian University of Science and Technology) | Vassmyr, M. (Norwegian University of Science and Technology) | La Forgia, N. (Norwegian University of Science and Technology) | Yang, Z. (Norwegian University of Science and Technology)
Experiments were performed with propose of mapping the flow patterns in two-phase flow in an upward inclinable 60 mm ID and 6 m long Plexiglas pipe. Air and viscous oil were used as working fluids and degree of inclination changed from 10 ͦ to 78 ͦ. Measurements includes pressure drop. Flow regime were recorded with high speed video cameras. Experimental results were compared with existing models by Barnea (1987) and with a commercial dynamic multiphase flow simulator (OLGA7.3®). Predictions with unified model had acceptable agreement with experimental data.
The need of understanding two-phase gas-liquid flow has been increasing in the recent years, as well as the need of a technical solution for handling and controlling the flow behaviour. A correct prediction of multiphase flow dynamics is critical for the design of pipelines for deep-water riser and production tubing in offshore oil and gas field development, where parameters as pressure drop and liquid holdup are strongly dependent on the flow pattern. Generally, flow pattern in gas-liquid system can exist in a wide variety of forms, depending on the flow rate, physical properties of the phases, the geometry and inclination of the tube (McQuillan and Whalley, 1985).
As production takes place in the petroleum industry, impurities are produced along with oil and gas. Sand is a common impurity associated with production. If sand is present, it is desirable to have continuous flow of even small concentrations of sand through the pipeline to avoid multiple issues like accumulation of particles and under-deposit corrosion. Experiments are performed at extremely low sand concentrations for both liquid-sand (single phase) and gas-liquid-sand (multiphase) flows to determine the critical flow rates necessary to keep sand moving in horizontal lines. In the case of gas-liquid-sand (multiphase) flow, the flow regime is stratified. The critical velocity is defined as the fluid velocity required to keep the solid particles continuously moving. Generally, the critical velocity is considered to have a direct relationship with the solid concentration for relatively low concentrations. That is for low concentrations, as the sand concentration increases the critical velocity needed for transport increases and vice versa. However, it can be reasoned that as the concentration approaches zero, the critical velocity should not be a function of concentration, since the particle spacing becomes large. In this work, this behavior has been shown experimentally, and the concentration at which the critical velocity is no longer a function of concentration is referred to as the threshold concentration. In this paper, the threshold concentration and the minimum critical velocity are examined for liquid-sand and gas-liquid-sand flows.
Drilling operations are usually intended for exploitation of hydrocarbon resources under the ground. Although the final objective is to produce these resources in the forms including oil, gas, or condensate; during the dr illing operations an influx of such material is considered a safety hazard called "kick" . Except in some special drilling techniques such as underbalanced drilling, taking a "kick" can lead to a blowout if not controlled properly. The series of actions taken after de tection of a kick aiming to control it, i.e. safely circulate it to surface without taking additional kicks, are called well control operations. Although, liquid kicks such as formation oil or water are not uncommon; the highest risk type of kick is one which enters the we ll in gaseous phase.
Venkatesan, R. (Chevron Energy Technology Company) | Tanti, R. (Tridiagonal Solutions Inc.) | Subramani, V. (Tridiagonal Solutions Inc.) | Vedapuri, D. (Tridiagonal Solutions Inc.) | Akparu, E. (Chevron Africa and Latin America Exploration and Production Company, USA) | Johnson, K. (Chevron Africa and Latin America Exploration and Production Company, USA)
Wax deposition problems are encountered in various components of the production system as the fluid travels from reservoir to surface facilities. It is well known that wax deposition could lead to a wide variety of problems in terms of reduction in pipe inner diameter, potential plugging of production strings, changes in fluid rheological properties, increased pressure drop, reduced production, risk of pig getting stuck during maintenance operations, shutdowns, increased downtimes, pipeline safety and integrity issues, settling of wax in surface facilities etc., . These problems associated with wax deposition could cost hundreds of millions of dollars every year to the energy industry. Prevention, management and remediation strategies are custom devised for each field, depending on several factors including field location, type of field development, fluid properties, ease of remediation etc. Currently, the oil and gas industry uses several methods to deal with the wax deposition issues such as insulating the pipeline, injecting chemical inhibitors, dual flowlines to allow a roundtrip pigging, heating, or using a combining of these techniques in the field.
Often, it is the thermal performance of the well that is of primary interest. This paper presents two extreme field cases where the well temperature profile was of critical importance to operations. In the first case, simulations were performed for a high-rate, gas-condensate well to determine the highest possible wellhead temperature that could be expected during operations. If the wellhead temperature was excessively high, then special materials would be required, adding $100s of millions to the project cost. In the second case, the purpose of the modeling was to determine the impact of installing vacuum-insulated tubing for an oil well with high waxing potential. The objective was to keep the oil above its wax appearance temperature by lowering heat loss to the surroundings, and thus preventing wax deposition downhole. In both cases, the heat transfer coefficient governing heat loss from the well to the surroundings was considered to be a key parameter. However, it turned out that the overall heat transfer coefficient was of, at best, secondary importance, and – for some operating conditions - negligible. By far, the most important contributor to the temperature change in both cases was Joule- Thompson cooling and other energy effects.
Sanderse, B. (Centrum Wiskunde & Informatica, Amsterdam) | Misra, S. (Centrum Wiskunde & Informatica, Amsterdam / Delft University of Technology) | Dubinkina, S. (Centrum Wiskunde & Informatica, Amsterdam) | Henkes, R. A. W. M. (Centrum Wiskunde & Informatica, Amsterdam / Shell Technology Centre Amsterdam) | Oosterlee, C. W. (Centrum Wiskunde & Informatica, Amsterdam / Delft University of Technology)
A finite volume discretization of the incompressible two-fluid model in four-equation form is proposed for simulating roll waves appearing in multiphase pipelines. The new formulation has two important advantages compared to existing roll wave simulators: (i) it is conservative by construction, meaning that the correct shock magnitude is obtained at the hydraulic jump, and (ii) it can be more easily extended with additional physics (e.g. compressibility, axial diffusion, surface tension), without rederiving the model equations. A simple, robust, first-order upwind discretization of the four-equation model is able to capture the roll wave profiles, although a fine grid is needed to achieve converged results. The four-equation model leads to new roll wave solutions that differ from existing analytical and numerical results. Our solutions are believed to be physically more correct because the shock relations satisfy physically conserved quantities.
Gas hydrates are a concern for the oil and gas industry, since they can be formed in production lines and disrupt flow. Different techniques can be applied to assure that the flow will not be disrupted by hydrate formation. Recently, the use of dispersant additives known as anti-agglomerants (AAs) have been applied to transport hydrates in the form of slurry. Anti-agglomerants are assumed to act at the hydrate interface keeping hydrates dispersed in the liquid hydrocarbon phase. In particular cases in gas or gas/condensate fields, the temperature can fall below 0°C due to the Joule-Thompson cooling effect after high gas production. For these systems, a complex and poorly studied transport of ice, hydrate and liquid will occur. Despite the similarities between structures of ice and hydrate, the effect of hydrate dispersant additives to disperse ice is unknown. A new experimental apparatus, called rock-flow cell, was used in this study which allows multiphase system, works at high pressure and different flow conditions can be obtained by varying the liquid loading and rocking conditions (angle and rate). Tests of hydrate and ice formation from water and condensate dispersions were performed aiming to study the effectiveness of AAs. It was observed that certain AAs can work to disperse hydrate/ice slurry, nevertheless its effect is highly dependent on the system conditions.
Sinquin, A. (IFP Energies nouvelles, France) | Gainville, M. (IFP Energies nouvelles, France) | Cassar, C. (IFP Energies nouvelles, France) | Boxall, J. (Chevron Australia Pty Ltd., Australia) | Estanga, D. (Chevron Energy Technology Company)
Chevron Energy Technology Company, USA Operating within the hydrate formation zone using low-dosage hydrate inhibitors (LDHI) is an emerging technical solution that may allow reducing capital investment and operating costs. Risks and efficacy of these additives is commonly assessed prior to field application; however, this process rarely considers a key multiphase flow characteristic - the flow pattern of the system. Incorporating this key variable would improve the confidence in the performance of LDHI for gas dominated systems and allow safer operations. The Additive and Hydrate at the Top of Line (AHToL) joint industry project acquired knowledge and data for gas dominant conditions using the 140 m long and two inch (5.08 * 10 The hydrate formation tests were performed under multiphase flow conditions to assess the transportability and identify risks such as hydrate plug formation and hydrate formation at the top of line with and without LDHI. Two commercially available anti-agglomerant additives (AA-1 and AA-2) were tested in gas / condensate / water system at two water cuts under different multiphase flow regimes. The tests were analysed based on pressure, temperature and pressure drop measurements along the loop, visual observations at a given position and monitoring of the overall free gas compositions and consumption. Firstly, a comparison of the two AA additive performances is presented under stratified flow. The two additives showed different behaviours regarding hydrate formation kinetics (exothermic peak locations, induction time, hydrate structure, conversion rate, …), hydrate distributions (either in the flowing liquid or adhering at the top of the line), and pressure drop evolutions.
Gas hydrate formation in oil and gas pipelines may cause flow assurance problems, especially in deep water subsea tiebacks. Agglomeration of hydrates may form plugs, thereby halting production. In the last decades, the hydrate control philosophy has shift from “hydrate avoidance” to “hydrate management”. The hydrate management approach requires a more robust study of hydrate kinetics to allow hydrate formation in a controlled manner. This work studies multiphase flow and design/operation properties such as water cut, insulation and emulsion stability, to determine their effect on hydrate formation at steady state and transient operations of a condensate subsea tieback.
Natural gas hydrates are solid compounds comprised of small gas molecules and water, which form at low temperatures and high pressures (1). Gas hydrates can cause urgent flow assurance problems in oil and gas pipelines, especially in deep water subsea tiebacks (2-3). Gas hydrate particles may agglomerate and result in hydrate plugs causing production stoppages, and posing large economic and safety concerns in the petroleum industry.