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Hydrate plugging of hydrocarbon production conduits can cause large operational problems resulting in considerable economical losses. Modeling capabilities to predict hydrate plugging occurrences would help to improve facility design and operation in order to reduce the extent of such events. It would also contribute to a more effective and safer remediation process. This paper systematically describes different operational scenarios where hydrate plugging might occur and how a hydrate plug formation prediction tool would be beneficial. The current understanding of the mechanisms for hydrate formation, agglomeration and plugging of a pipeline are also presented. The results from this survey combined with the identified industrial needs are then used as a basis for the assessment of the capabilities of an existing hydrate plug formation model, called CSMHyK (The Colorado School of Mines Hydrate Kinetic Model). This has recently been implemented in the transient multiphase flow simulator OLGA as a separate module. Finally, examples using the current model in several operational scenarios are shown to illustrate some of its important capabilities. The results from these examples and the operational scenarios analysis are then used to discuss the future development needs of the CSMHyK model.

This thesis was inspired by the project funded by Bureau of Safety and Environment Enforcement (BSEE) to study the use of epoxy (or any cement alternative) to plug offshore wells damaged by hurricanes. The project focuses on non-cement materials to plug wells that are either destroyed or damaged to an extent where vertical intervention from the original wellhead is no longer possible. The proposed solution to this problem was to drill an offset well and intersect the original borehole at the very top and spot epoxy (or any suitable non-cement plugging material) in the original well. The spotted epoxy then would fall by gravitational force all the way down to the packer and then settle on top of the packer to plug the annulus of the damaged well permanently. This thesis mainly concentrates on the factors affecting the fall rates and how to correlate them in order to derive an applicable test that can be conducted on the field or lab to calculate the terminal velocity of the known epoxy composition. Determining the settling velocity of the epoxy is crucial due to the fact that epoxy should not set prematurely for a better seal and isolation. The terminal velocity and the recovery for epoxy based plugging fluids were tested by using an experimental setup that was developed for this purpose. The results were also validated by using an alternative experiment setup designed for this purpose. Factors affecting the terminal velocity and recovery of epoxy were studied in this research since the settling velocity of the epoxy is crucial because epoxy should not set prematurely for a better seal and isolation. The study was conducted by using an experiment setup that was specially developed for terminal velocity and recovery calculations for plugging fluids. Results obtained from the experiment setup were successfully correlated to epoxy's composition for estimating the terminal velocity of the mixture.

The goal of this research was to evaluate the application uniformity of subsurface drip distribution systems and the recovery of emitter flow rates. Emission volume in the field, and laboratory measured flow rates were determined for emitters from three locations. Additionally, the effects of lateral orientation with respect to slope on emitter plugging was evaluated. Two different emitters were tested to evaluate slope effects on emitter plugging (type Y and Z). The emitters were alternately spliced together and installed in an up and down orientation on slopes of 0, 1, 2 and 4% and along the contour on slopes of 1 and 2%. The emitters were covered with soil and underwent a simulated year of dosing cycles, and then flushed with a flushing velocity of 0.6 m/s. Initial flow rates for the two emitter types were 2.38 L/hr with a C.V. of 0.07. There was no significant difference in flow rates among slopes for type Y emitters, but there was a significant difference between the 1% and 2 % contour slopes for type Z emitters. Application uniformity of three different laterals at each site was evaluated. Sections of the lateral from the beginning, middle and end were excavated and emission volumes were recorded for each emitter. Application uniformity of laterals ranged from 48.69 to 9.49%, 83.55 to 72.60%, and 44.41 to 0% for sites A, B, and C, respectively. Mean emitter flow rate was 2.21, 2.24, and 2.56 L/hr for sites A, B, and C, respectively under laboratory conditions. Application uniformity under laboratory conditions ranged from 70.97 to 14.91%, 86.67 to 79.99%, and 85.04 to 0.00% for sites A, B, and C, respectively. A flushing velocity of 0.15 m/s with no chlorination, shock chlorination of 3400 mg/L and flushing velocity of 0.15 m/s, and shock chlorination of 3400 mg/L and flushing velocity of 0.6 m/s treatment regiments were applied to all laterals collected to assess emitter flow rate recovery to the nominal flow rate published by the manufacturer. All laterals showed an increase in the number of emitters within 10% of the published nominal flow rate.

This thesis is part of a project funded by the Minerals Management Service (MMS) (now Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE)) to study the use of epoxy to plug hurricane damaged wells. Some of the wells destroyed by hurricanes are damaged to an extent that vertical intervention from the original wellhead is not possible. These wells have to be plugged to prevent future flows through the well to protect the environment. Cement is usually the preferred plugging material because it is very cheap compared to other materials like epoxy. However, cement can easily get contaminated by sea water or brines present in wells as completion fluids. Therefore, to be able to use cement it has to be placed at the bottom of the well by drilling an offset well all the way to the bottom of the original well. Epoxy, on the other hand, being much more chemically stable can be placed at the very top of the well and let to settle by gravity without fearing contamination. Therefore, in wells described above, epoxy can be much more economical than cement. Placing epoxy at the top of a well and letting it settle by gravity can also be more economical than using cement in other situations such as in a leaking annulus of a well where circulation in that annulus is not possible, or if a well that has been previously plugged starts leaking again after the rig has been removed. Placing epoxy in the manner described can be achieved without using a rig and therefore, would be much more economical than cement. One of the most important factors in this process is to be able to predict the settling velocity of the epoxy to be able to determine the required setting time of the epoxy so that the epoxy does not set prematurely. In addition, it is important to evaluate whether the epoxy can successfully settle to the bottom and how much of it will adhere to the pipe walls while freefalling. This thesis aims to design, build and run an experimental setup that would help study the settling velocity of epoxy. Some experiments were conducted to assess the effect of different parameters that might affect the settling velocity of the epoxy such as the epoxy’s density, the annulus size and the inclination angle. The results show that the settling velocity was proportional to the epoxy’s density. Also the settling speed was almost double in experiments done at an angle compared to experiments done at vertical position. The annulus size did not have any clear effect on the settling speed. The adhesion to the pipe walls was found to be proportional to the epoxy’s viscosity and angle of inclination and was inversely proportional to the annulus size.

The goal of this research was to evaluate the application uniformity of subsurface drip distribution systems and the recovery of emitter flow rates. Emission volume in the field, and laboratory measured flow rates were determined for emitters from three locations. Additionally, the effects of lateral orientation with respect to slope on emitter plugging was evaluated. Two different emitters were tested to evaluate slope effects on emitter plugging (type Y and Z). The emitters were alternately spliced together and installed in an up and down orientation on slopes of 0, 1, 2 and 4% and along the contour on slopes of 1 and 2%. The emitters were covered with soil and underwent a simulated year of dosing cycles, and then flushed with a flushing velocity of 0.6 m/s. Initial flow rates for the two emitter types were 2.38 L/hr with a C.V. of 0.07. There was no significant difference in flow rates among slopes for type Y emitters, but there was a significant difference between the 1% and 2 % contour slopes for type Z emitters. Application uniformity of three different laterals at each site was evaluated. Sections of the lateral from the beginning, middle and end were excavated and emission volumes were recorded for each emitter. Application uniformity of laterals ranged from 48.69 to 9.49%, 83.55 to 72.60%, and 44.41 to 0% for sites A, B, and C, respectively. Mean emitter flow rate was 2.21, 2.24, and 2.56 L/hr for sites A, B, and C, respectively under laboratory conditions. Application uniformity under laboratory conditions ranged from 70.97 to 14.91%, 86.67 to 79.99%, and 85.04 to 0.00% for sites A, B, and C, respectively. A flushing velocity of 0.15 m/s with no chlorination, shock chlorination of 3400 mg/L and flushing velocity of 0.15 m/s, and shock chlorination of 3400 mg/L and flushing velocity of 0.6 m/s treatment regiments were applied to all laterals collected to assess emitter flow rate recovery to the nominal flow rate published by the manufacturer. All laterals showed an increase in the number of emitters within 10% of the published nominal flow rate.

In order to obtain a better understanding of hydrate plug formation mechanism in natural gas pipelines, formation and growth of hydrate layer within a rectangular channel formed by brass bottom and top surfaces and an insulated inner and an outer surface of transparent polycarbonate tube was studied experimentally. A gas mixture of 90 % methane balanced with propane was supplied at specified flow rates while the humidity and temperature of the supply gas was controlled at desired values using bubble type saturators and heat exchangers placed in series. Hydrate formation occurred along the top and bottom brass surfaces maintained at temperatures below equilibrium hydrate formation temperature, while the transparent tube served as window for visual observation. A series of carefully controlled laboratory experiments were performed to reveal the shape of porous hydrate layer under different combinations of under-cooling and moisture concentrations. The observed transient characteristics of hydrate layer profiles will provide important data that can be used for validation of numerical models to predict hydrate plugging of natural gas pipelines.

An underinhibited system is defined as a system where an insufficient amount of thermodynamic inhibitor is present to prevent hydrate formation. Underinhibition might occur due to malfunctioning of equipment, temporary limitations in the inhibitor supplies or operational limitations or errors. Understanding the plugging risk of such systems is important in order to take the correct precautions to avoid blocked flowlines. In this paper we summarize the experimental efforts for the last decade within StatoilHydro on the hydrate plugging risk in underinhibited systems. The flow simulator has been used as the main experimental equipment. The overall results for systems underinhibited with ethylene glycol or methanol show that the plugging potential increases up to a maximum at concentrations around 10-15 wt%. At higher concentrations the plugging potential reduces compared to the uninhibited system. The results can be explained as follows: As water is converted to hydrates in a system containing a thermodynamic inhibitor, the inhibitor concentration will increase until the remaining aqueous phase is inhibited. This self-inhibited aqueous phase will wet the hydrate particles, giving raise to the characteristic term of “sticky” hydrate particles. The aqueous layer surrounding the hydrate particles will form liquid bridges, by capillary attractive forces, upon contact with other hydrate particles or the pipe wall. During the hydrate formation period, there is also a possibility that some of the liquid bridges are converted to solid ones, strengthening the agglomerates. Depending on the oil-water interfacial tension, the phase ratio between the aqueous phase and the solid hydrates and the conversion of liquid bridges to solid ones, this leads to increased plugging risk at lower concentrations of inhibitor (< 20 wt%) and reduced risk at higher concentrations as compared to the uninhibited system.

The continuous effort to understand the complicated behavior of gas hydrates in multiphase flow has led to the evolution of a new paradigm of hydrate blockage. The hydrate community continues to debate the impact of kinetics, agglomeration, and oil chemistry effects on hydrate blockage formation in pipelines and wellbores. However, today’s industry for the most part still continues to rely on thermodynamic means to develop strategies to prevent hydrates altogether in its production systems. These strategies such as thermal insulation of equipment, electric heating, dead oil displacement, and methanol injection add CAPEX, OPEX, and operational complexities to system design. In spite of high oil prices, adopting such strategies to mitigate perceived hydrate blockage risk can end up taxing economics of marginal fields. Developing a comprehensive multiphase flow simulator capable of handling the transient aspects of production operations - shut-in, restart, blowdown and blockage prediction - continues to drive the research in Flow Assurance. New operating strategies based on risk management approach seem to be evolving from the model predictions. A shift in paradigm that allows for operations inside the hydrate region based on sound risk assessment and management principles could be a factor enabling future developments of marginal fields. This paper discusses the challenges and opportunities that have led to the change in focus from prevention of hydrates to prevention of blockage, and describes some initial successes in the development of a first generation empirical tool for the prediction of hydrate blockages in flow lines. Also presented in this article are new experimental data that shed some light on different ways that hydrate blockages can manifest in the field.

Every year, many wells are subject to well intervention operations for a variety of different reasons, such as Plug and Abandon (P&A) operations or well control situations. Wells that are not properly plugged, in addition becoming an inherent blowout threat, can act as a preferential pathway for surface contaminants to reach and impair ground water quality, and could cause injury to livestock, wildlife, or humans. Hence, federal code (or state code if in state waters) states that the wells must be plugged according to regulations. If attempts with a surface intervention operation fail, a relief type subsurface intervention project is deemed appropriate. A relief well type of intersection into each target wellbore will create a hydraulic flow path suitable for plugging operations. The plugging operation will require the placement of permanent plugging fluids into the Target Well (TW) to meet Mineral Management Services (MMS), or other regulatory agency, approved plugging criteria. Evidently, there is a need to design a method to insure that the scenarios are accurately defined, analyzed and the results can be effectively implemented to complete the plug and abandonment operations. A software package, coupled with the skill of a hydraulic modeling specialist, could provide final resolution to and better understanding of the problem. However, considering uncertainties in some input information, there is a need to develop a multi-purpose package which enables the user to manipulate dynamically a wide range of input data in order to obtain the best fit. Therefore, the decision was made to develop a software package specifically built and designed to address the common problems encountered during well intervention projects. The well intervention toolkit will be used to investigate the plugging and abandonment scenarios. The well intervention toolkit not only provides the critical input parameters to other commercial software but would also be a means to analyze and simulate the well intervention hydraulics