Liquid loading phenomenon is known as the inability of the produced gas to carry all the co-produced liquid to the surface. Under such condition, the non-removed liquid accumulates at the wellbore resulting in reduction of the production and sometimes cause the death of the well. Several studies were carried out and correlation were developed based on field and experimental data with the aim to predict the onset of liquid loading in a gas well. However, each model provides different indication on the critical gas velocity at which the liquid loading exists. Thus, to have a clear understanding on the difference between most used models, experiments were performed in an upward inclinable pipe section. The 60-mm diameter test pipe was positioned at angles of 30°, 45° and 60° from horizontal. The fluids used were air and light oil. Measurements include fluid velocities and fluid reversal point. High-speed video cameras were used to record the flow conditions in which the onset of liquid loading initiated. Experimental results were compared with existing models by
Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
In this paper we describe a novel method for water unloading of natural gas wells in mature reservoirs experiencing low reservoir pressures. Current methods for water unloading from gas wells have at least one of the drawbacks of restricting gas production, requiring external energy, using consumable surfactants, or being labor intensive. The proposed design offers a new approach to water unloading that does not restrict or interrupt gas production. It can operate without external energy, and uses no consumables. Virtual and physical simulators have been developed and the full-scale version of the concept has been studied in test wells to demonstrate the feasibility and performance of the new water-unloading concept. An industrial-grade preproduction prototype was tested successfully in a test gas well to validate this study.
Junwen, Wu (Sinopec Research Institute of Petroleum Exploration and Development) | Wenfeng, Jia (Sinopec Research Institute of Petroleum Engineering) | Rusheng, Zhang (Sinopec Research Institute of Petroleum Exploration and Development) | Xueqi, Cen (Sinopec Research Institute of Petroleum Exploration and Development) | Haibo, Wang (Sinopec Research Institute of Petroleum Exploration and Development) | Jun, Niu (Sinopec Research Institute of Petroleum Exploration and Development)
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
Rasoanaivo, Ombana (TOTAL S.A.) | Danquigny, Jacques (TOTAL S.A.) | Henry, Pierre (Petroleum Experts) | Hopkinson, David (Petroleum Experts) | Liu, Adeline (TOTAL E&P) | Marty, Jacques (TOTAL S.A.) | Marmier, Rémy (TOTAL E&P)
Using a software integrator, a commercial reservoir simulator is tightly coupled with a commercial Transient Well Model. This is required when transient reservoir behaviour interacts with transient wellbore phenomena. It is the case in a tight gas field which is being developed since 2012 in China; long natural cycles of gas production in liquid loading regime followed by period of low or quasi nil-gas production are observed. Cyclic production is also being implemented to optimize the average gas production. In both cases, usual decline curve analysis is no longer valid. And computing long term production forecast becomes a challenge. The innovative application presented in this paper is an optimization of Cyclic Production in Liquid Loading Regime of a tight gas reservoir by coupling transient modelling of reservoir and wellbore.
A workflow is implemented in the software integrator RESOLVE which enables the coupling between a well and its multiple hydraulically fractured reservoirs. It ensures consistent results between the reservoir model and the transient well model in terms of mass flow rate, transient inflow performance and bottom hole flowing pressure. It also enables to visualize the cross-flow which occurs between the two reservoirs, and some water imbibition into the matrix during shut-in periods.
Tested on various reference wells, this new methodology represents properly the historical behaviour of the wells during steady-state flow and during self-killing periods. When modelling cyclic production, various shut-in / restart criteria can be handled by the workflow. It enables to optimize the average production of the wells and deliver some guidelines to the field operation teams. This is a great achievement compared with the need to implement long "cyclic production testing" campaigns.
Also, two-month coupled cyclic production modelling is performed at regular yearly intervals. Combining these long term production forecasts with the evolution of "average static pressure vs. cumulative gas production" derived from reservoir standalone long-term forecast, enables to compute reliable long term production forecast which accounts for cyclic production in liquid loading regime. The current results show significantly larger production than the one derived from usual decline curves.
Overall, the study is a leap forward in understanding transient well and reservoir interactions in order to improve field Estimated Ultimate Recovery. This field tested methodology can also be applied to many other situations when well instabilities interfere with reservoir transient behaviour (gas-lift heading, interference between unstable outflow and multi-layers inflow behaviour). To our knowledge, it is a "World First" of a coupling between a full commercial reservoir simulator and a commercial transient wellbore software.
Saradva, Harshil (Sharjah National Oil Corporation) | Jain, Siddharth (Sharjah National Oil Corporation) | Hamadi, Masoud Al (Sharjah National Oil Corporation) | Thakur, Kapil Kumar (Schlumberger) | Govindan, Gunasekar (Schlumberger) | Ahmed, Ahmed Fadl Mustafa (Schlumberger)
This paper presents a case study from Onshore wells in Sharjah, UAE on investigating liquid loading in 5 multilateral gas wells having various trajectories ranging from toe-up, toe-down and hybrid openhole legs. These wells are subjected to wellhead pressure reduction to maximize production rates. The main objective of the study was to evaluate the production performance for different completion designs with respect to liquid loading onset and overall production assessment with declining reservoir pressure.
Dynamic multiphase flow simulator was used to conduct this study to accurately capture the details of the multilaterals system and its complex trajectories. The first step involved validating the well model with reasonable history match between the simulation and actual production data. The validated model then was used as a basis for predicting the liquid loading onset point for a given reservoir pressure decline. Multiple cases were investigated to evaluate various completion options (i.e. with or without tubing) to determine how and when the liquid loading occurs at different laterals with varying lateral trajectory.
This study has showed that in such complex multi-lateral wells, laterals load up at different points in time and reservoir pressures, being affected mainly by the geometry and orientation of lateral and the production contribution. Moreover, installing tubing in these wells had the opposite anticipated effect on liquid loading by accelerating the liquid loading onset in the laterals due to the imposed additional restriction. Generally, toe-down trajectory tends to have thicker liquid film and a potential for reduced flow contribution due to liquid accumulation at the toe.
These wells have a fishbone openhole multilateral network with comingled flow in the vertical section. It is observed that production tubing in the vertical section provides friction that accelerates the onset of liquid loading and hence results in decreased production for wells operating in very low reservoir pressure range. Based on overall production assessment ‘no tubing’ scenario would be more beneficial. Further, the timing of implementation of the tubing restriction later in the field life can be selected based on dynamic simulations (also evaluating economic constraints vs production gain).
Transient mechanistic flow model captures the liquid loading phenomena by film reversal which usually occurs before the critical rate limit based on droplet drag forces assessment. Further, liquid loading onset occurs in the laterals first rather than the tubing section which reduces the applicability of conventional nodal analysis tools. Evaluating liquid loading behaviour in such multilateral wells with proper dynamic simulation is critical for understanding the laterals behaviour and therefore optimizing the production performance to maximize the wells uptime and ultimately the overall gas recovery as well as optimal usage of CAPEX.
Praditya, Yusuf Alfyan (Premier Oil Indonesia) | Satiawarman, Anugerah (Premier Oil Indonesia) | Nurrahman, Fahmi (Premier Oil Indonesia) | Medianestrian, Medianestrian (Premier Oil Indonesia) | Rochaendy, Risnawan (Premier Oil Indonesia)
Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading.
This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
Surfactants are used in gas well deliquification to generate foam to lift liquid condensates and brine from a well during gas production. In this paper, the effect of various hydrocarbon components typically found in natural condensates on selected foaming surfactants was studied. The screening methodology used a modified blender test to evaluate foam height and its half-life. The foaming results from the blender tests are reported for a number of alpha olefin sulfonates (AOS), alkyl ether sulfates (AES), and betaines at 25 C and ambient pressure. The surfactants were also evaluated using dynamic foam carry-over apparatus at ambient conditions for further validation. This work helps to elucidate problems associated with choosing the proper gas well deliquification surfactant suitable for a condensate of a specific composition.
As gas fields mature and water production increases, understanding and managing the dynamic flow behaviour of the well and production system are critical for maintaining, and even optimising, production. This knowledge could be the difference between a successful and an unsuccessful attempt at re-starting a wet gas well after it is shut-in. When a well is in production, choking the well to optimise stable facilities operation and maintain water production within the water handling constraints of the facilities can be a fine line between achieving continuous stable production and the well ceasing production due to high liquid loading.
This paper describes the successful kick-off and unloading of two high-water producing gas wells within the operational constraints of the offshore facility. Transient multiphase flow models were developed for a platform well and a subsea well to simulate the wellbore flow dynamics during start-up. The models were tested over a range of values for parameters such as reservoir pressure, inflow performance and water gas ratio for different kick-off strategies but always honouring the facility's water surge management constraints.
The outcome of these simulations facilitated the development of tailored bean-up strategies for each high-water producing gas well, which provided a mechanism to engage with key stakeholders and demonstrate confidence in the execution of these strategies. Dedicated procedures were developed and subsequently executed successfully to re-start the two wells with the wells continuing to produce after kick-off and unloading, operating within the water surge management limits of the facility. Similar strategies are being developed for other high-water producing gas wells including those with material sand production.
This paper demonstrates strategic capability to realise additional value using dynamic modelling to kick-off mature high-water producing gas wells through proactive development of mitigation strategies which avoid production disruption.
Conventional artificial lift systems are limited in their application by depth, borehole trajectory and chemistry of the produced media. This paper presents a concentric tubular pumping system, combined with an efficient hydraulic pump to overcome the limitations of existing artificial lift systems and to assure a cost-effective production.
This pumping system consists of a specially designed plunger assembly and barrel combination, which is driven by a hydraulic pressure unit from the surface without any mechanical connection. The hydraulic pump itself can be circulated into and out of the borehole or can be run by slickline, resulting in fast and low-cost operations. The pump is designed to be run as a concentric tubular pumping system with several advantages, especially in enhanced oil recovery and unloading of gas well operations. This new pump type is designed and manufactured in cooperation with the industry and tested at the Montanuniversität Leoben, Austria.
The performance tests have demonstrated the saving potential regarding energy efficiency as well as a reduction in CAPEX and OPEX. The unique design of this pump owns a very low number of moving parts, such no mechanical connection to the surface, and such providing minimal exposure to wear and corrosion. Tests have shown that the pump is very adaptable regarding production rate, which requires just a change in surface hydraulic pressure. Based on experience the concentric tubular pumping system is the best selection for unloading of gas wells to enhance the lifetime of the completions. As a result, of the natural phase separation of liquids and gases, the presented pumping system has shown to be the ideal choice for the usage in all types of wells.
This completely new pump type exceeds the performance of existing artificial lift systems for unloading of gas wells, increases the mean time between failures and reduces the lifting costs essentially. These major issues are most important in times of low gas price.