Liquid loading in producing gas wells is the inability of the produced gas to remove produced liquids from the wellbore. A review of existing flow loops worldwide revealed that specialized areas of research such as liquid loading in gas wells are still lacking dedicated test facilities. This project presents the design of a new dedicated facility to be located at the TowerLab at the Richardson building with adequate operating conditions to reproduce the flow regimes encountered prior to and after the onset of liquid loading in gas wells. The facility consists of a compressed air system, pipelines for air and water, a pressure vessel containing glass beads, an injection manifold, and flow control and monitoring devices. Our results show that three compressors working in parallel is the most technical and economic configuration for the TowerLab based on the overall costs provided by the supplier, the footprint but most importantly the flexibility. The design of the pressure vessel required a cylindrical body with top and bottom welded-flat head covers with multiple openings to minimize its weight. The pipelines connecting major equipment and injection manifold located at the pressure vessel were selected based on the superficial velocities for air and water. These values also showed the need for independent injection using two manifolds instead of commingling flow through a tee joint. The use of digital pressure gauges with an accuracy of 0.05 to 25% and coriolis or vortex meters to measure air flowrate is also suggested. For the water line, installation of turbine meters results in the most economic approach.

Liquid loading is a serious problem in gas wells. Many proven artificial lift methods have been used to alleviate this problem. However, a complete workflow to determine the most suitable artificial lift method for given well conditions does not exist. In 2008, Han Young Park presented his thesis of decision matrix tool using a decision tree technique for data mining that determined the best artificial lift method for liquid loading in gas wells from seven artificial lift methods: plunger lift, gas lift, ESP, PCP, rod pump, jet pump, and piston pump. He determined the technical feasibility and the cost evaluation of these seven techniques. His workflow consisted of three rounds. The first round was the preliminary screening round. By using all input well conditions, the impractical techniques were screened out. In the second round, all the techniques from round one were graded and ranked. In the third round, the economic evaluation was performed by using cost for each artificial lift method and assuming the constant additional gas production per day to determine net present value (NPV) and internal rate of return (IRR). In this thesis, we propose an extended workflow from the Han-Young’s thesis for the decision matrix tool. We added integrated production simulations (reservoir to wellhead) step with commercial software in between the second and third round. We performed simulations of the various artificial lift methods to see the additional gains from each technique. We used the additional gas production resulted from simulation to calculate economic yardsticks (the third round), NPV and IRR. Moreover, we made the decision matrix more complete by adding three more liquid unloading techniques to the decision matrix: velocity string, foam injection, and heated tubing. We have also updated all screening conditions, the technical scores, and the costs for the decision matrix from the previous study using literature reviews, information from the project’s sponsor, information from service company and our own judgment. The aim of the decision matrix is to allow operators to screen quickly and efficiently for the most suitable artificial lift method to solve the liquid loading problem under given well conditions.

Field-proven solutions already exist to reduce the loss of gas production when liquid loading begins to occur. However, the choice of remedial technique, its feasibility, and its cost, vary considerably depending on a field's location, size export route, and the individual operator's experience. The selection of the best remedial technique and the timeframe within which the remedial action is undertaken are critical to a project's profitability. Although there are literature reviews available regarding solutions to liquid loading problems in gas wells, a tool capable of helping an operator select the best remedial option for a specific field case still does not exist. This thesis proposes a newly developed decision matrix to screen the possible remedial options available to the operator. The matrix can not only provide a critical evaluation of potential solutions to the problem of liquid loading in gas wells vis-à-vis the existing technical and economic constraints, but can also serve as a reference to operators for investment decisions and as a quick screening tool for the selection of production optimisation strategies. Under its current status of development, this new tool consists of a decision algorithm built around a decision tree. Unlike other data mining techniques, decision trees quickly allow for subdividing large initial datasets into successively smaller sets by a series of decision rules. The rules are based on information available in the public domain. The effectiveness of the matrix is now ready to be tested against real field datasets.

One of the major challenges in fracturing low permeability/tight/unconventional gas formations is the loss of frac water and well productivity due to fluid entrapment in the matrix or fracture. Field results have indicated that only 15-30% of the frac fluid is recovered at the surface after flow back is initiated. Past studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped due to the high capillary pressure in the matrix. Significant efforts have been made in the past to understand the impact of liquid blocking in hydraulically fractured conventional gas wells. Numerous remediation measures such as huff and puff gas cycling, alcohol or surfactant based chemical treatments have been proposed to reduce fracture face damage. However, when considering hydraulic fractures in unconventional reservoirs horizontal wells, the fluid may also be trapped within the fracture itself and may impact the cleanup as well as productivity. This study shows that under typical gas flow rates in tight / shale gas formations, liquid loading within the fractures is likely to occur. Most of the previous simulation studies consider a 2D reservoir model and ignore gravity, considering the high vertical anisotropy (or extremely low vertical permeability) in these tight reservoirs matrix. However, this study presents the results of 3D simulations of liquid loading in hydraulic fractures in horizontal wells, including gravity and capillary pressure effects. Both CMG IMEX and GEM have been used to study this phenomenon in dry and wet gas cases. The impact of drawdown, fracture and reservoir properties on liquid loading and well productivity is presented. Results show that low drawdown, low matrix permeability or low initial gas rates aggravate the liquid loading problem inside the fracture and thereby impact the cleanup and gas productivity during initial production. A clear understanding of the phenomena could help in selection of optimal production facilities and well profile. / text

Liquid loading in gas wells is generally described as the inability of the well to lift the co-produced liquids up the tubing, which may ultimately kill the well. There is a lack of dedicated models that can mimic the transient features that are typical of liquid loading. Improved characterization of liquid loading in gas wells and enhanced prediction of future well performance can be achieved from the measurements and analyses resulting from this project. An experimental investigation was carried out to study the onset of liquid loading and the subsequent transient phenomena, using a large scale flow loop to visualize two-phase flow regimes, and to measure pressure and liquid holdup along a 42-m long vertical tube. From this investigation, it is possible to conclude that liquid loading should not be characterized based on onset criteria alone, and that it may not be a wellbore-only problem, as it would seem that the reservoir also plays a key role in determining if/when/how liquid loading manifests itself. Additionally, the results from the experimental campaign were used to compare the performance of different wellbore flow simulators. State-of-the-art simulators do not seem to fully capture the nature of liquid loading in vertical tubes. A simplified model is roposed here to evaluate the liquid transport during the transition from one flow regime to another, during the loading sequence.

In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. As gas hydrocarbons are produced from underground reservoirs to the surface, liquids can come from condensate dropout, water break-through from the reservoir, or vapor condensation in the wellbore. In all three cases, the higher density liquid needs to be transported to the surface by the gas. If the gas phase does not provide sufficient energy to lift the liquid out of the well, the liquid will accumulate in the wellbore. The accumulation of liquid will impose an additional backpressure on the formation that can significantly affect the productivity of the well. The additional backpressure appears to result in a "U-shaped" pressure distribution along the radius in the near-wellbore region that explains the physics of the backflow scenario. However, current modeling approaches cannot capture this U-shaped pressure distribution, and the conventional pressure profile cannot explain the physics of the reinjection. In particular, current steady-state models to predict the arrival of liquid loading, diagnose its impact on production, and screen remedial options are inadequate, including Turner's criterion and Nodal Analysis. However, the dynamic interactions between the reservoir and the wellbore present a fully transient scenario, therefore none of the above solutions captures the complexity of flow transients associated with liquid loading in gas wells. The most satisfactory solution would be to couple a transient reservoir model to a transient well model, which will provide reliable predictive models to link the well dynamics with the intermittent response of a reservoir that is typical of liquid loading in gas wells. The modeling work presented here can be applied to investigate liquid loading mechanisms, and evaluate any other situation where the transient flow behavior of the near-wellbore region of the reservoir cannot be ignored, including system start-up and shut-down.

Every gas well ceases producing as reservoir pressure depletes. The usual liquid presence in the reservoir can cause further problems by accumulating in the wellbore and reducing production even more. There are a number of options in well completion to prevent liquid loading even before it becomes a problem. Tubing size and perforation interval optimization are the two most common methods. Although completion optimization will prevent liquid accumulation in the wellbore for a certain time, eventually as the reservoir pressure decreases more, the well will start loading. As liquid loading occurs it is crucial to recognize the problem at early stages and select a suitable prevention method. There are various methods to prevent liquid loading such as / gas lift, plunger lift, pumping and velocity string installation. This study set out to construct a decision tree for a possible expert system used to determine the best result for a particular gas well. The findings are tested to confirm by field applications as attempts of the expert system.

Low-pressure, low-producing natural gas wells commonly encounter liquid loading during production. Because of the decline in the reservoir pressure and the flow capacity, wells can fall below terminal velocity. Identifying and predicting the onset of liquid loading allows the operators to plan and prepare for combating the liquid loading hence saving valuable reserves and downtime. The present industrial applications of artificial lift, wellhead pressure reduction by compressor installation at the wellheads and reduction in tubing size are costly and often intermittent. The thesis examines the above aspects to generate a workflow for identifying and predicting the liquid loading conclusively and also assessing the application of Auger Tool and foam combination towards achieving a cost effective and more efficient solution for liquid unloading. In chapters I-IV, I describe the process of using production surveillance software of Halliburton Digital Consulting Services, named DSS (Dynamic Surveillance Software), to create a workflow of identifying the liquid loaded wells based on well data on daily basis for field personnel and engineers. This workflow also decides the most cost effective solution to handle it. Moreover, it can perform decline analysis to predict the conditions of liquid loading. In chapters V-VIII of the thesis, I describe the effort of handling the problem of liquid loading in a cost effective manner by introduction of an inexpensive Auger Tool in the bottomhole assembly and using WhiteMax surfactant soapstick from J&J Solutions. Four different combinations of well completion and fluid were tested for performance in respect to liquid hold up, pressure loss in the tubing, unloading efficiency and critical flow requirement. The test facilities and instruments, along with the operational methods, are discussed in chapter VI. Except for the reduction of the operational envelope with the inclusion of Auger Tool, the performance improved with the insertion of Auger Tool. The best combination of Auger and foam system could be a result of flow modification by the Auger Tool caused by reduced pressure loss and increase in drag coefficient and also by reduced density and surface tension of foam.