Rapidly Deployable Thermal Hydrate Preventer for Oil Spill Mitigation Draft Final ... · 2016. 10....

Rapidly Deployable Thermal Hydrate Preventer

for Oil Spill Mitigation

Draft Final Report

Contract Number: E12PC00042

October 30, 2013

Prepared for:

Timothy Steffek

U.S. Department of Interior

Bureau of Safety and Environmental Enforcement

Oil Spill Response Division

381 Elden Street

Herndon, VA 20170-4879

Prepared by: Composite Technology Development, Inc.

2600 Campus Drive, Suite D

Lafayette, CO 80026

This final report has been reviewed by the BSEE and approved for publication. Approval does not signify that the contents necessarily reflect the views and policies of the BSEE, nor does mention of the trade names or commercial products constitute endorsement or recommendation for use.

2 6 0 0 C A M P U S D R I V E , S U I T E D • L A F A Y E T T E , C O 8 0 0 2 6 • 3 0 3 - 6 6 4 - 0 3 9 4 • W W W . C T D - M A T E R I A L S . C O M

http:WWW.CTD-MATERIALS.COM

Table of Contents

1 Executive Summary .................................................................................................................. 1

2 Introduction............................................................................................................................... 2

2.1 Need for Subsea Oil Spill Recovery Tools .......................................................................2

2.2 Problems Posed by Methane Hydrates in Deep Sea Wells ...............................................3

3 Project Objectives ..................................................................................................................... 4

4 Task 1 - Definition of Deep Sea Environment ..........................................................................5

4.1 Locations and Conditions of Off Shore Wells ..................................................................5

4.2 THP Design Goals ............................................................................................................7

5 Task 2 – Hydrate Prevention Feasibility Study ........................................................................7

5.1 Hydrate Formation and Dissociation in Deepwater Conditions .......................................8

5.2 THP Energy Balance.......................................................................................................10

5.3 THP Design Implications ................................................................................................12

6 Task 3 - Scaling Rules for THP Systems for Different Size Wells ........................................13

6.1 Scaling of THP Design Parameters .................................................................................13

6.2 Design Considerations for Various Release Rates..........................................................15

7 Task 4 - Thermal Hydrate Preventer System Preliminary Design ..........................................17

7.1 THP Isolation Dome .......................................................................................................17

7.2 Riser Design and Analysis ..............................................................................................20

7.3 THP Deployment and Support ........................................................................................23

8 Task 5 – Thermal Hydrate Preventer Demonstration Plans ....................................................23

8.1 Dry Test .......................................................................................................................... 24

8.2 Shallow Water / Tank Test .............................................................................................25

8.3 Deep Water Test .............................................................................................................26

9 Task 6 – Commercial Implementation Plan............................................................................28

10 Conclusions............................................................................................................................. 29

11 References............................................................................................................................... 30


Contract Number E12PC00042, Final Report ii


1 Executive Summary The recent Deepwater Horizon incident has shown that a well control accident can affect the biologic, physical, socioeconomic, and sociocultural resources over extensive coastal and offshore areas. More than 500 miles of U.S. shoreline were affected by this recent spill, and the impacts of that accident are still felt today.

Because this accident occurred at a deep-water location, the response to the incident was difficult to manage and oil spilled into the ocean for an extended period of time. Moreover, the spill was difficult to contain because hydrates formed within the system and thus blocked the flow of captured effluent to the surface, resulting in the uncontrolled release of oil into the sea. Hydrates form when gas present in the effluent mixes with cold seawater under high pressures (i.e., deep water conditions) to form crystallites that accumulate within pipelines and block the flow of fluids through the system.

The Thermal Hydrate Preventer (THP) was designed to provide a rapidly deployable tool that can be used in the event of a deep-water spill. The THP possesses heating and diluent delivery capabilities that can be used to prevent the formation of hydrates and thereby ensure the flow of captured effluent to containment vessels positioned at the surface. Moreover, the device was designed to work in instances where a water-tight seal to the damaged well is difficult to achieve. Thus, the THP can prevent hydrate formation when a significant amount of cold seawater mixes with the effluent.

This project included six tasks associated with the development of THP system designs. Those tasks include:

Task 1 – Definition of Downhole Environment to use for System Design

Task 2 – Hydrate Prevention Feasibility Study

Task 3 – Develop Scaling Rules for THP Systems for Different Size Wells

Task 4 – Thermal Hydrate Preventer System Preliminary Design

Task 5 – Thermal Hydrate Preventer Demonstration Plans

Task 6 – Commercial Implementation Plan

The results of this work show that the THP device can prevent hydrate formation in deep-water oil spill response operations. Hydrate formation is prevented through the application of heat and the flow of diluent to the well. In addition to performing analyses related to hydrate formation, preliminary designs for the THP dome, riser system, and supporting vessels needed to deploy and operate the tool were also developed. The related analyses include energy balances associated with the operation of the heating system, the flow behavior within the dome, and stress analyses on the riser system. The following report also includes outlines for test plans for validating the performance of the device under various test conditions.


Contract Number E12PC00042, Final Report 1


2 Introduction 2.1 Need for Subsea Oil Spill Recovery Tools

The recent Deepwater Horizon incident has shown that a well control accident (Figure 1) can affect the biologic, physical, socioeconomic, and sociocultural resources over extensive coastal and offshore areas. More than 500 miles of U.S. shoreline were affected by this recent spill, and the impacts of that accident are still felt today.

In response to the Deepwater Horizon incident and resulting oil spill, the Department of the Interior (DOI) is developing measures to improve the safety of oil and gas exploration and development on the Outer Continental Shelf. This effort includes the development of advanced technologies related to well control, including: subsea and surface blowout preventers, well casing and cementing, secondary intervention, unplanned disconnects, recordkeeping, well completion, and well plugging.

In certain circumstances, the uncontrolled release of crude oil from a subsea well can occur due to equipment failures. While careful steps are taken to avoid such releases, it is exceedingly important to move quickly and effectively to capture the oil being released while further steps are taken to permanently stop the flow of oil into the environment. One method of stopping the flow of effluent involves the placement of a Lower Marine Riser Package (LMRP) Cap Containment System over the Blow Out Preventer (BOP). This method was attempted in the Deepwater Horizon spill, but initially failed due to the formation of methane hydrates. As shown in Figure 2, LMRP systems include a funnel-like cap and associated equipment that are lowered into position from a drillship. When complete, the effluent is captured and pumped to a collection reservoir

Figure 1. Uncontrolled release of effluent after Deepwater Horizon accident.

Figure 2. Positioning of LMRP Cap onto a Blowout Preventer.




aboard the drillship. This process allows for some of the leaking oil to be recovered, and the natural gas may be flared off.

The installation and operation of LMRP caps is complicated by the remoteness of deep-sea wells, the conditions at the sea floor, and by interactions between the components of effluent and the surrounding seawater. For example, the effluent may exit the well under intense pressure and at a temperature of about 60°C (140 °F). At an ocean depth of approximately 1,500 meters (~5,000 feet), the hydrostatic pressure of seawater is about 150 bar (~2,200 psi) and the water temperature may be about 4 °C (39 °F). If the effluent contacts seawater at these conditions then methane hydrates can form. If hydrates form during the use of an LMRP cap, the recovery tools may become plugged and the flow of effluent to the surface will stop.

2.2 Problems Posed by Methane Hydrates in Deep Sea Wells

Methane hydrate is a crystallized concentration of methane and water that occurs under specific pressure and temperature conditions. Hydrates are often associated with permafrost and cold temperatures, but the pressure created by the hydrostatic head of deep water also creates conditions that favor the formation of hydrates.

The hydrate dissociation curve shown in Figure 3 indicates the temperature and pressure conditions under which hydrates will form. Hydrates will form when methane contacts seawater at temperatures and pressures above and to the left of hydrate dissociation curve (or within hydrate envelope). For combinations of temperature and pressure below and to the right of hydrate dissociation curve, hydrates will not form. Moreover, crystalline hydrates will dissociate into liquid water and gaseous methane in conditions outside of the hydrate envelope.

In order to maintain the flow of effluent through recovery tools, it is necessary to maintain the effluent at temperature and pressure combinations outside of the hydrate envelope, or to avoid significant contact between effluent and seawater. In some cases, where hydrates have already formed, it may also be necessary to dissociate any hydrates that are blocking the valves, pipes, or tubing needed for effluent removal. Because the surrounding seawater is a nearly infinite heat sink, and the seawater surrounding LMRP cap is very cold, maintaining the effluent at a satisfactory temperature and pressure combination is very challenging.

The Macondo Well blowout in the Gulf of Mexico was a clear lesson about the formation of hydrates when methane combines with 4°C water at high pressure. At this deep sea site, hydrate formation prevented the capping of the well for several weeks and likely made the total spill about 25% larger than it might have been. In this instance, the initial attempts at a “top kill” through the kill line of the BOP may also have been affected by the formation of hydrates. In this case, the water in the kill mud mixed with the gas flowing out of the well to form a plug that prevented the kill mud from pushing the oil back down the hole. After this initial attempt failed,

Figure 3. Thermal hydrate formation in seawater.




3

the problem with hydrates was clearly recognized and addressed and the leak was successfully terminated by another top kill attempt. To prevent the kill line from “hydrating off” again, the kill mud was oil based to avoid hydrate formation.

While the oil-based mud allowed for the leak to finally be stopped, other methods of preventing hydrate formation include pumping heated fluids from a drillship and/or using one or more diluents, such as methanol. Thus, a tool that could deliver both the diluent and heat to the deep-sea well site would ensure that hydrates do not form and block the flow of effluent to the collection reservoir at the ocean surface.

Project Objectives The objective of this project is to demonstrate the feasibility of a rapidly deployable Thermal Hydrate Preventer (THP) that can be used to mitigate subsea oil spills until a permanent solution can be established. The THP [1] is designed to prevent the formation of hydrates that block the flow of spilling oil to the surface. As previously discussed, hydrate formation caused considerable damage in the Gulf of Mexico because the flow of oil through the recovery tools was blocked, and the escaping oil flowed into the ocean for several weeks until the well could be contained.

The THP tool builds on CTD’s Coiled Umbilical Tubing (CUT) technology and allows for heat and diluent to be delivered to the failed well, and for the leaking oil to be captured and transported to a storage vessel on the surface. The primary benefit of this device is that it can be quickly deployed so that spill containment can begin in a matter of hours or days, whereas existing capabilities require several weeks or months to implement. Figure 4 shows a conceptual illustration of the THP device being positioned onto a damaged well. As seen below, the THP system includes an Isolation Bell and an umbilical that are positioned over a failed well, as well as supporting surface vessels that provide power to the deep sea site and store the leaking oil that is captured by the device.

Figure 4. Deployment of a Thermal Hydrate Preventer onto a damaged well. 2 6 0 0 C A M P U S D R I V E , S U I T E D • L A F A Y E T T E , C O 8 0 0 2 6 • 3 0 3 - 6 6 4 - 0 3 9 4 • W W W . C T D - M A T E R I A L S . C O M



This project included six technical tasks associated with the development of THP system designs. Those tasks were:

Task 1 – Definition of Downhole Environment to use for System Design Task 2 – Hydrate Prevention Feasibility Study

Task 3 – Develop Scaling Rules for THP Systems for Different Size Wells

Task 4 – Thermal Hydrate Preventer System Preliminary Design Task 5 – Thermal Hydrate Preventer Demonstration Plans

Task 6 – Commercial Implementation Plan

The following report describes the results obtained for each of the above tasks.

4 Task 1 - Definition of Deep Sea Environment The goal of this task was to establish a set of requirements and operating conditions to be used as a basis for THP development. An emphasis was placed on addressing a well failure similar to that which occurred in the Gulf of Mexico with the Deepwater Horizon platform, but consideration was also given to the following:

(1) Conditions that represent the majority of existing sub-sea wells;

(2) Conditions that reflect trends in new and planned wells to ensure that the THP will be able to address failures that may occur at these locations (such as deeper water, higher flow volumes, more complex equipment situated on the sea floor, etc.); and

(3) Conditions that may exceed the anticipated capability of a THP so we can bound the capabilities of the system and ensure that it will be suitable to mitigate the wells it will be used for.

4.1 Locations and Conditions of Off Shore Wells

Global deep-water oil production has tripled since 2000, and approximately one third of this activity has occurred in the Gulf of Mexico [2-3]. In addition to increased production from the Gulf of Mexico, offshore exploration and production at depths of more than 500 meters (~1,500 feet) is expanding in areas such as the North Sea, Western Africa, eastern Canada, Brazil, and the Bay of Bengal. Figure 5 shows a map of this worldwide activity and highlights both active oil fields and deep-water development areas. The map below highlights the locations of the deep-water fields where hydrate formation has the potential to impede recovery activities in the event of an accidental release. The majority of these locations are in the Gulf of Mexico, along the Atlantic Coast of the United States, and off the east coast of Brazil. Because of the large number of sites near U.S. waters, well conditions associated with these sites were emphasized in the design of the THP device.




Figure 5. Deep‐water oil exploration and drilling [4].

As a matter of practice, deep-water wells are cemented to prevent leaks and use blowout preventers (BOP’s) at the wellhead. There are currently more than 14,000 deep-water wells in service and only very few spills have occurred. However, when there are problems, the depth and distance can lead to challenges in containing the spills. It was recently estimated that response times to offshore accidents off the coasts of Africa, South America, and Asia would take 4-8 weeks to contain with capabilities that are currently in place [5].

At deeper sites, the formation of hydrates must also be prevented to secure damaged wells. Hydrates typically form at depths greater than 1,500 m (~5,000 feet) – where the temperatures and pressures are favorable for formation – and can quickly complicate the efforts to repair these wells. The ready formation of hydrates at these depths is illustrated in Figure 6 [6]. In this example, a large hydrate formation developed on the exterior of offshore oil production equipment in the Gulf of Mexico. This image shows that large hydrate accumulations can form when gas is exposed to cold seawater, and how readily this could occur after an uncontrolled release of oil and gas from deep-sea wells.

Figure 6. Hydrate formation on the outside of deep‐sea oil production equipment in the Gulf of Mexico.




Hydrates can also form in shallower water if the temperature is low enough. Thus, while primary designs were directed towards well conditions in the Gulf of Mexico, cold-water sites such as the Arctic and North Sea were also considered in the development of THP designs.

4.2 THP Design Goals

Based on the growing number of deep-sea wells, as well as recent goals established in response to the Deepwater Horizon accident, the following design goals were established for the design of the THP system. These design goals were developed to specifically address well sites in which the formation of hydrates may complicate the control of a failed well, and include:

Mobilization of the tool with 24 hours, and operational within one week.

Support ships capable of transporting and deploying THP’s will be considered as a part of the design to ensure that the tool can be efficiently deployed and operated using existing surface vessels.

Capability to be deployed at depths ranging from 300 to 3,650 meters (approximately 1,000 to 12,000 feet) and to withstand corresponding water pressures up to 36.9 MPa (5,350 psi).

Able to deliver sufficient heat and/or diluents to the well site to prevent hydrate formation. This aspect of the THP system design requires that the design of the tools, as well as the size and capabilities of the surface ships needed to support them, be considered.

Ability to capture effluent at the well site and transfer it to surface vessels.

Tools sized to capture 25,000, 50,000, and 100,000 bbl/day of escaping oil will be evaluated in the design phase of this project. Flow rates from the Macondo well were estimated to be 50,000 to 70,000 bbl/day [7], so the flow rates to be evaluated will consider worst-case scenarios for deep-water spills.

Wellhead pressures up to 100 MPa (~15,000 psi). This is consistent with pressures in offshore oil wells, including the Macondo and other wells currently producing in the Gulf of Mexico.

Each of the above was considered in developing the design of the THP, and in evaluating the formation/dissociation of methane hydrates at undersea well sites.

5 Task 2 – Hydrate Prevention Feasibility Study The goal of this task was to determine the feasibility of using the THP device for controlling damaged oil wells in deep water conditions. In this task, CTD and researchers at the Center for Hydrate Research (CHR) at the Colorado School of Mines considered the chemistry and thermodynamics of hydrate formation. The objectives of this work were to:

1. Prevent the formation of hydrates during the process of interfacing and initially capturing oil flowing from a damaged well on the sea floor,




2. Maintain a hydrate-free environment once the THP is successfully engaged with the damaged well, and

3. Develop approaches and system requirements on how the THP system may be able to dissolve hydrates that may form prior to, during, or after the THP system has been engaged with the damaged well.

The outcome of this work was a determination of the feasibility of the THP concept from a hydrate chemistry and thermodynamic standpoint, and the results were later used to guide the THP system conceptual design (Task 4).

5.1 Hydrate Formation and Dissociation in Deepwater Conditions

Initially, hydrate formation/dissociation was estimated for offshore well conditions in the Gulf of Mexico. These calculations assumed pressures and depths for current and anticipated well sites, as well as typical gas mixtures, found in this region. The gas mixtures include methane, ethane, and propane. The ethane concentration is typically 8.1 mole percent. Thus, as seen in Table 1, the methane concentration ranges from 91.9 to 86.6 mole percent, with corresponding propane concentrations of 0 to 5.3 mole percent. It should be noted that seawater salinity in the Gulf of Mexico can vary slightly by depth and region, but it is mostly within the range of 3.35 to 3.75 weight percent NaCl [8]. A salinity of 3.5 weight percent was therefore assumed in performing the following calculations.

Table 1. Typical natural gas mixtures in the Gulf of Mexico. Values are in mole percent.

Mixture Methane Ethane Propane

1 91.9 8.1 0

2 91.4 8.1 0.5

3 90.9 8.1 1.0

4 90.4 8.1 1.5

5 89.9 8.1 2.0

6 89.1 8.1 2.8

7 88.4 8.1 3.5

8 87.5 8.1 4.4

9 86.6 8.1 5.3

As seen in Figure 7, hydrate formation is favorable at low temperatures for all of the above gas mixtures. In addition, hydrate formation is more favorable in gas concentrations with higher propane concentrations. For example, if the gas contained no propane (i.e. 0 mole percent) then hydrate formation could be avoided by maintaining a temperature of 19˚C at the Macondo Well pressure/depth. Alternatively, a propane concentration of 5.3 mole percent would require a




temperature of 24˚C to prevent hydrate formation at this same pressure/depth. It should be noted that the propane concentration at the Macondo Well was 5.3 mole percent, and this is at the higher end of propane concentrations present in the Gulf of Mexico. This relatively high concentration also likely contributed to the problems with hydrate formation during the initial attempts to contain the spilled oil after the well failure occurred.

In addition to heat, the presence of diluents was also considered as a means of preventing hydrate formation. The effect of Methyl alcohol (MeOH), also known as Methanol, and mono ethylene glycol (MEG) as diluents was evaluated in this work. Methanol is more commonly considered for use in the Gulf of Mexico and appears to be more effective in limiting hydrate formation. In other regions of the world, MEG is more commonly used because it is less flammable. As seen in Figure 8, the temperature of hydrate formation in gas with a propane concentration of 5.3 mole percent is reduced from 24˚C when no diluent is present (Figure 5) to approximately 14˚C when either 20 weight percent MeOH or 40 weight percent MEG is used. Increasing the amount of diluent would further reduce the temperature (and as a result the heat energy needed to maintain this temperature) to prevent hydrate formation. In these calculations, the amount of diluent is the weight percent of diluent in seawater (in g/g).

Figure 7. Hydrate formation boundaries for natural gas with varying concentrations of propane as a function of ocean temperature and pressure/depth.




Figure 8. Hydrate formation boundaries for natural gas with 5.3 mole percent propane and varying concentrations of MeOH and MEG as a function of pressure/depth.

The preliminary design concepts for the THP device included the ability to provide both thermal and chemical inputs to prevent hydrate formation. The results of these initial calculations provided more details on how much heat and diluent, or combinations thereof, will be needed to control hydrates in the event of a future spill at the ocean floor.

5.2 THP Energy Balance

Next, a thermodynamic model was developed to assess the various sources of heating within the THP device. A basic geometry was assumed for these initial calculations, and the volume of the THP was similar to that of the “top hat” used in the initial attempts to control the Macondo well. The structure was assumed to be of steel construction with foam insulation. The total volume of THP used in these estimates is 3.2 m3 and the external surface area is 13.2 m2. The notional geometry of the THP used for these initial calculations, as well as the various sources of heat into the system, is shown in Figure 9.

The energy balance considers the flows of oil, gas, and seawater into the devices, as well as the loss of heat through the structure walls to the surrounding ocean. In a sealed system, such as a capped well, the formation of hydrates is unlikely because the heat from the subsea Figure 9. Heat flows within a notional formation prevents hydrate formation. However, cold THP structure.

Electric Heating

Production flow Gas Lift or ESP Assisted

Diluent Injection

Gas Flow from Well

Oil Flow from Well

Sea Water ingress

Heat Loss to Sea




seawater can readily enter a damaged system and interact with the natural gas to form hydrates.

Calculations that consider these two scenarios were performed to establish design constraints for the THP. The well site conditions used for these calculations were determined previously in Task 1 and are summarized in Table 2. As seen in Table 3, the heat from the well would prevent hydrate formation if a capped condition could be established. This result was expected because the condition simulates the continuous flow of oil in a functioning well.

Next, the maximum amount of water that could enter the system without the need for additional heating was determined. These calculations assume that the dome was pre-heated to 24˚C to prevent hydrate formations during installation (see Figure 7). Maintaining the dome at this temperature with cold seawater on the interior and exterior surfaces is expected to require 0.2 MW of power to be supplied through power umbilicals. As seen in Table 4, 42 weight percent water flowing into the dome would require no additional heating to prevent hydrate formation within the THP. Measurements of the water content within the “top hat” used in the Macondo well accident found 23 weight percent water. Thus, while the “top hat” could not prevent the formation of hydrates in the recent accident, these analyses indicate that the THP can accommodate almost twice as much water as that found in the “top hat” and still ensure the flow of captured effluent through the system.

Whereas the conditions used in Table 2 are associated with the Macondo well incident (i.e., a relatively high gas concentration and an API of 37), other regions within the Gulf of Mexico may have either lower gas concentrations or API’s on the order of 27-32. As shown previously in Figure 7, lower gas concentrations in the effluent will make hydrate formation less likely and thus require less heat and/or diluent to ensure flow through the system. Effluent with lower API would likely have a higher viscosity, but the capture of medium-weight oil should proceed similarly to light crude.

Table 2. Well conditions used for THP energy balances.

Condition Value Comment Well discharge rate 70,000 BOPD Wellhead pressure 82.7 MPa Oil temperature 60˚C Oil API range 37 lighter crude Water in formation Minimal

Macondo well gas86.6% methane, 9.1% ethane, Gas composition composition, values in mole 5.3% propane percent Seawater temperature 4˚C

Corresponds to a depth of Seawater pressure 20 MPa ~1,500 meters Heated to assure no hydrate Dome temperature 24˚C formation (see Figure 8)




Table 3. Heat flow in THP system if well is capped.

Component Energy Description Dome -0.104 kW Cooling to the sea through the dome Oil 8191 kW Heating from the oil discharge Gas 1346 kW Heating from the gas discharge Seawater 0 kW Cooling from seawater entering the dome Diluent -305 kW Cooling from diluent entering the dome Dissociation 0 kW Hydrate dissociation Energy Flow into Dome 9186 kW Additional heating required if negative

Table 4. Heat flow in THP system with seawater ingress of 42% by weight of fluid recovered.

Component Energy Description Dome -0.104 kW Cooling to the sea through the dome Oil 8191 kW Heating from the oil discharge Gas 1346 kW Heating from the gas discharge Seawater -9186 kW Cooling from seawater entering the dome Diluent -350 kW Cooling from diluent entering the dome Dissociation 0 kW Hydrate dissociation Energy Flow into Dome 0 kW Additional heating required if negative

5.3 THP Design Implications

The results of this showed that the THP concept can be used to capture effluent in the event of a well failure, and prevent the formation of hydrates that can block the flow of fluids to the surface. These initial calculations assumed a basic design with a similar volume of the “top hat” first used in the Macondo well accident. In that instance, however, hydrates formed and prevented the capture of the effluent at the ocean floor and led to further spills into the ocean.

The calculations performed in this study have shown that incorporating combinations of heat and diluent provide more than sufficient energy to prevent hydrate formation. An important aspect of the design, however, was to ensure that the hydrates do not form in the upper portions of the device where the volume necks down to meet the smaller diameter piping. This will require that the device be heated as it is lowered into position, but this is possible with existing tools. Moreover, the power needed to provide this heat can be readily provided using conventional generators that can be supplied with the THP device.




6 Task 3 - Scaling Rules for THP Systems for Different Size Wells Sub-sea wells vary considerably in size, depth, oil chemistry, oil release pressure and temperature, and mechanical design of the wellhead on the sea floor. In this task, a series of scaling rules that can be used to size the THP system were developed to address these variations. Well conditions similar to those experienced during the Deepwater Horizon incident in the Gulf of Mexico were used as the basis for these evaluations because there is a considerable amount information available about this site. In addition, the range of conditions was expanded to assess the effects of depth, oil/gas ratio, formation temperature, etc. on the THP design. Expanding the design conditions will allow the tool to be effectively used in responses to spills of varying sizes and circumstances.

6.1 Scaling of THP Design Parameters

The design of the THP must initially consider the volume of effluent to be recovered. In this work, three flow rates will be used as design points for the device. The effluent flow rates considered in this work are: (1) less than 10,000 BOPD, (2) 10,000 to 70,000 BOPD, and (3) 70,000 to 100,000 BOPD (Task 1). These three conditions represent relatively small leaks, flow rates typical of the Macondo Well in the Gulf of Mexico, and flow rates that represent some of the largest wells currently in operation, respectively. The highest flow rate considered in the design study is considered to be the highest flow rate for which an emergency response tool is needed based on anticipated production sites.

In Task 2, the combination of heat and diluent needed to prevent hydrate formation were calculated. Those results showed that it was possible to maintain a dome at conditions that will prevent hydrate formation through the application of heat and diluent flow even when a relatively high concentration of water is present. Using that information, the effect of seawater ingress into the dome was calculated under conditions in which effluent flow rates of 10,000, 70,000, and 100,000 barrels of oil per day were assumed. As seen in Figure 10, higher effluent flow rates require less heating because the thermal energy and high flow rate of the effluent will maintain the system at a sufficiently high temperature to prevent hydrates from forming once the THP is in position. However, smaller spills (or leaks) will need more heating and diluent (methanol) because the effluent will be rapidly cooled as it combines with the seawater.




Figure 10. Effect of effluent flow rate on heating power required to maintain dome temperature above the dissociation temperature.

The plot in Figure 10 assumes a depth of 1,600 meters (approximately 5,000 feet), a gas-to-oil ratio (GOR) of 42 cubic meters of gas per barrel of oil (1,500 standard cubic feet of gas per barrel of oil), an effluent temperature of 60˚C, and sea water temperature of 4°C. These parameters are similar to those of the Macondo Well and illustrate the heating energy needed to prevent hydrate formation for different effluent flow rates. While these estimates use known conditions, similar calculations can be performed to assess the effects of different depths, GOR’s, and effluent temperatures. In general, the higher flow rates will require less heating because of the thermal energy associated with the effluent, but more heating power will be needed for deeper wells under similar seawater ingress conditions because of the higher pressure at these locations. It should be noted, however, that controlling hydrate formation during the installation of the dome is critical to the success of the operation. If hydrates form as the device is lowered into position, then the flow of captured effluent to the surface will be restricted before the recovery process can begin.

To further illustrate the impact of well depth on the scaling of THP designs, the energy and diluent inputs needed to prevent hydrate formation was assessed at depths ranging from 800 meters (2,500 feet) to 3,200 meters (10,000 feet). As seen in Figure 11, more heat and diluent are needed for deeper wells because the higher pressure creates more favorable conditions for hydrate formation. In this instance no heating from the well effluent is assumed, so this plot represents a worst-case scenario in which the maximum amounts of thermal and chemical inputs are needed for the conditions (water ingress, GOR, etc.) assumed in this particular calculation.




Figure 11. Effect of depth scaling on diluent concentration and heating power required to prevent hydrate formation.

In the instance of the Macondo Well accident, the effluent flow rate was on the order of 70,000 BOPD and the well was located at a depth of approximately 1,600 meters (5,000 feet). In this instance, hydrate formation complicated the control of the spill and led to extensive damage to the economy and ecology of the region. At the time, there was not a tool capable of providing heat and diluent to the damaged well and effluent continued to escape while alternative solutions were developed. The above calculations provide information about spills of varying sizes (i.e., effluent flow rates), well depths, and water content that were considered in the design of the THP device (Task 4).

6.2 Design Considerations for Various Release Rates

The above calculations establish design constraints for THP designs for various effluent flow rates and well depths. Most notably, high effluent flow rates were shown to be less susceptible to hydrate formation because of the heat associated with the release, whereas lower flow rates will need thermal and chemical inputs to ensure that hydrates do not build up during the spill containment operation.

Table 5 outlines the various components needed for THP systems based on the release rates and well depths discussed in the previous section. As seen below, the primary system components will include a dome-type structure that approaches the damaged well, umbilicals that provide power for heating, sensors, and diluent to the dome, and a riser for transferring the captured effluent to the surface.




Table 5. THP System Components for Various Effluent Release Rates

Release Rate (BOPD)

Dome Umbilical Riser

0-10,000 Dome size must be proportional to flow rate to reduce water fraction and prevent hydrate formation (i.e., smaller dome for lower flow rates)

CTD-CUT umbilical with 3.5" flow channel could handle up to 10,000 BOPD

May not be needed on domes of this size if CUT umbilical is used

10,000 to 70,000 70,000 BOPD is maximum Macondo release estimate

Power and sensors to dome

3.5" to 6" diameter riser constructed from 40' sections of joined tubing

70,000 to 100,000 100,000 BOPD is the maximum flow rate for spill response system design

Power and sensors to dome

7" to 9 5/8" diameter riser constructed from 40' sections of joined tubing

For release rates of less than 10,000 BOPD, it may be possible to combine a dome with Coiled Umbilical Tubing (CUT) [9]. Under this condition, the Coiled Tubing-based system can serve as both an umbilical to provide power to the dome as well as a conduit for transferring the captured effluent to a storage vessel on the surface. This combination could be rapidly deployed to contain small spills or leaks until a permanent solution can be established.

Larger spills will require risers that are capable of transferring these volumes of captured effluent to the surface. These risers will likely require more time to establish than the Coiled Tubing-based system, but this approach will still provide a means of rapidly mitigating the uncontrolled release of effluent into the sea. While the riser diameter will be dependent upon the amount of oil released, the dome design is expected to be similar for spill sizes ranging from 10,000 to 100,000 BOPD.

In all three of the scenarios seen in Table 5, artificial lift will likely be needed to ensure a continuous flow of captured effluent to the surface. For smaller spills (< 10,000 BOPD), the dome may not be sealed to the well and in this instance the well pressure would not be transferred to the umbilical/riser. Under these circumstances, an electric submersible pump would offer an effective means of transferring the oil to the surface. Interventions in larger spills would also likely benefit from artificial lift. In these instances, the riser will have a larger diameter to accommodate the higher volumes of effluent. Providing lift will ensure that the flow of captured effluent is regulated throughout the recovery operation, and that hydrate formation is prevented as the fluids are transferred from the well site to the surface.




7 Task 4 - Thermal Hydrate Preventer System Preliminary Design The THP is a versatile tool that can be used to rapidly respond to deep-water oil spills ranging in size from less than 10,000 to 100,000 barrels of oil per day (BOPD). The primary components of the system include: (1) an isolation dome that is positioned above a damaged well, (2) a riser that is used to transport captured effluent to the surface, and (3) surface vessels and other equipment for deploying and operating the device, as well as for storing the captured fluids. A conceptual illustration of a deployed THP system is shown in Figure 12. This image shows the dome positioned above a deep-sea wellhead, the riser connecting the THP to the surface, and a support vessel and umbilical cables that deliver power and diluent to the device.

The following sections discuss the various design considerations for the THP system, as well as the operation of the device under various spill and recovery conditions.

7.1 THP Isolation Dome

The THP isolation dome was designed to interface with damaged or leaking wellheads, and to accommodate spills ranging in size from 10,000 to 100,000 BOPD. The dome design includes integrated heating and diluent supply capabilities to prevent the formation of hydrates that can limit or altogether block the flow of captured effluent to the surface. In this work, the mechanical design of the dome was developed and Computational Flow Dynamics (CFD) were used to assess the flow of effluent through the device.

7.1.1 Mechanical Design of THP Dome

The THP dome provides a range of capabilities for controlling damaged or leaking wells in deep water environments. The prevention of hydrate formation is a key distinguishing feature of this tool, and addresses a critical technical challenge that was encountered in the response to the Macondo Well accident in the Gulf of Mexico. As previously discussed, hydrate formation occurs when cold seawater mixes with effluent from the well and causes the gas to crystallize. These crystalline solids accumulate along the walls of the recovery device and eventually block the flow of effluent. Hydrate formation can be prevented through the application of heat and diluent, and the THP includes these capabilities to ensure the flow from damaged, deep-water wells.

Figure 12. Illustration of the THP system connected to an underwater wellhead.




As seen in Figure 13, the upper end of the dome connects to a riser that transfers captured effluent to a surface vessel. The riser adapter can connect to risers ranging from 8.9 to 24.4 cm (3.5 to 9.6 inches) in diameter, depending on the size of the spill. In addition, the dome includes a heating system and an injection port through which diluent is introduced into the system.

A plume capture adaptor is located at the bottom of the device, and interchangeable adapters can be used to respond to different well and spill conditions. The funnel-type adapter shown here assumes that rigid contact to the well is not possible, and in this configuration the dome is positioned above a spill without a rigid connection to the wellhead. Other attachments include standard connectors to H4 connectors or stubs.

The ROV control and umbilical connection panel allow power delivery to the electric heaters within the system. The heater system may require up to 1 MW to provide sufficient energy to prevent hydrate formation, but less power is needed when diluent is also used, or when negligible amounts of cold water are introduced into the flow.

Finally, the interior of the device will be coated with a hydrate-phobic material. In recent work, a blend of 80 weight percent poly(ethyl methacrylate) (PEMA) and 20 weight percent fluorodecyl polyhedral oligomeric silsesquioxane (POSS) was found to significantly decrease the adhesive strengths of hydrate-to-steel bonds. In that study [10], the adhesive strength between hydrate and steel was found to be 422 ± 69 kPa, whereas the adhesive strength of the PEMA/POSS-coated steel was 90 ± 16 kPa. The advancing surface energies of these two interfaces were 36 and 9 mJ/m2, respectively. Thus, the coating reduces the adhesive strength between hydrates and steel by 79% and the surface energy is reduced by 75%. These reductions in bond strength will help to prevent the adherence of hydrates to the walls of the dome and further ensure that the flow of effluent during emergency spill responses.

7.1.2 Computational Flow Dynamics

As a part of the THP conceptual design, CFD analyses were used to predict the flow behavior of effluent within the dome. In this work, flow rates of 10,000, 70,000, and 100,000 BOPD were evaluated. Laminar flow will occur at flow rates on the order of 10,000 BOPD, whereas turbulent flow will be present at the higher flow rates. Turbulent flow is more likely to result in hydrate formation because water, if present, can mix more rapidly with the effluent rising from the well. However, the formation of hydrates will be mitigated when heat and/or diluent are introduced into the dome. Moreover, because the dome walls are coated with a hydrate-phobic

Figure 13. External features of the THP dome.




substance, the accumulation of hydrates along the dome surfaces should be mitigated in both flow regimes.

As seen in Figure 14, the maximum effluent velocity is predicted to range from 0.1 m/sec (0.33 ft/sec) at 10,000 BOPD to 0.7 m/sec (2.3 ft/sec) at 100,000 BOPD. The pressures along the inner walls of the dome are predicted to be on the order of 1 x 107 Pa (1,450 psi) for all three flow conditions, with the maximum pressures occurring where the structure tapers from the cylindrical body of the dome to the riser. It should be noted that there is very little variation in pressure from the minimum to maximum values as seen in Figure 15 and is nearly equal to the seabed pressure. Thus, with the use of hydrate-phobic surface coatings, and through the application of heat and diluent, hydrate formation can be mitigated in each of the instances evaluated in this study.

Figure 14. Velocity of effluent within the THP dome (in m/sec) at flow rates of 10,000, 70,000, and 100,000 BOPD.

Figure 15. Pressure distribution along the THP dome walls (in Pa) at flow rates of 10,000, 70,000, and 100,000 BOPD.




7.2 Riser Design and Analysis

Riser designs for the THP considered spill sizes of 10,000 and 100,000 BOPD at ocean depths of 1,500 and 3,000 meters (5,000 and 10,000 feet). For smaller spills a 8.9-cm (3.5-inch) diameter riser was assumed, whereas a 24.4-cm (9.625- inch) diameter riser was assumed for spills up to 100,000 BOPD. As seen in Figure 16, the design includes a passive telescopic joint placed above the dome to compensate for the vertical motion (heave) of the surface ship and thereby prevent the device from lifting off of the wellhead. Finally, ten-year hurricane sea conditions in the Gulf of Mexico were modeled to evaluate the survivability of the system in severe weather conditions. These ten-year conditions include 24-meter (80 foot) surges (horizontal ship motion) and heaves (vertical ship motion) of approximately 7.6 ± 3.8 meters (25 ± 12.5 feet).

In each case, the stresses in the riser were estimated to verify that the system would withstand the anticipated mechanical loads associated with these storm conditions. The analysis considers the both the external and internal pressures on the dome, as well as the axial weight loads on the telescopic joint. Furthermore, the analyses described below assume that the riser is rigidly attached to a surface vessel, and this configuration constitutes the highest possible stress on the riser. In practice, a rotary table would be used to reduce the stresses in the riser at the point of attachment to the vessel. A rotary table is a device that compensates for the motion of the vessel and thus reduces the stress in the riser.

7.2.1 Riser Design for 10,000 BOPD Spill Response

A 8.9-cm diameter pipe with a wall thickness of 0.93 cm was used as the riser for oil spills on the order of 10,000 BOPD. In this instance, a 1.5-m length of 19.3-cm diameter pipe was positioned at the top of the THP dome to control stresses near the wellhead. Using this configuration, the stress at the riser-to-vessel connection were estimated to be 117 MPa at 1,500 m (Figure 17) and 241 MPa at 3,000 m. As seen in Figure 17, stresses are also present at the telescopic joint and are similar in magnitude to those at the surface. The allowable stress (80% of the yield stress, an API standard) of the riser is 441 MPa, so at depths of both Figure 17. Stresses in a 8.9‐cm diameter riser at

1,500 m during 10‐year storm in the GOM. 1,500 and 3,000 m there is a reasonable

Figure 16. THP dome over a damaged well and telescopic joint used in the riser analysis.




safety factor within the riser under ten-year hurricane conditions.

As seen in Figure 17 (above), the maximum heave associated with the hurricane conditions used in this analysis was 7.6 m (±3.8 m), and the telescopic joint was able to maintain the position of the dome (below). The motion within the telescopic joint and stability of the THP dome position well were found to be very similar for both the 1,500 m depth case (as shown in Figure 18) and for a well located at a depth of 3,000 m.

Figure 18. Predicted motion within the telescopic joint above the THP dome (above) and position of the dome at a depth of 1,500 m during a ten‐year hurricane in the Gulf of Mexico (below).

7.2.2 Riser Design for 100,000 BOPD Spill Response

A 24.4 cm diameter riser with a wall thickness of 2.4 cm was assumed for oil spills up to 100,000 BOPD. In this case the riser was attached directly to the top of the THP dome and the maximum stresses at the riser-to-vessel connection were estimated to be 124 MPa at 1,500 m and 220 MPa at 3,000 m. Figure 19 shows the stress as a function of depth for a riser deployed to a depth of 3,000 m. In this example, the stress at the connection to the surface vessel is estimated to be 220 MPa, and the maximum stress at the telescopic joint is 296 MPa under hurricane conditions. As was the case with the 8.9-cm diameter riser, the telescopic joint maintained the position of the dome as the surface vessel was displaced by hurricane-force surges (Figure 20).




Figure 19. Stresses in a 24.4‐cm diameter riser at 3,000 m during 10‐year storm in the GOM.

Figure 20. Predicted motion within the telescopic joint above the THP dome (above) and position of the dome (below) at a depth of 3,000 m during a ten‐year hurricane in the Gulf of Mexico.




7.3 THP Deployment and Support

The THP system is designed for rapid responses to deep-water oil spills. For the Gulf of Mexico, the system components will likely be stored at a port such as Greensport, TX. In the event of a spill, a trained response team would manage the effort from a land-based crisis center, and the THP support vessels would be dispatched to the well site. The THP itself will be configured with the most appropriate connectors based on knowledge of the well and conditions at the wellhead.

The deployment and configuration of a THP-based response to a deep-water oil spill is shown in Figure 21. The THP is connected to a vessel of opportunity that acts as the central hub for the operation. The THP operations are supported by an ROV, with electric power for the heater and diluent supplied by additional vessels. Finally, a floating storage vessel is used to collect the captured effluent and shuttle tankers are used to transfer the oil away from the site. As previously discussed, the THP is intended to be a rapid-response tool for use in the mitigation of deep water oil spills. Once the well is under control, the THP can be used until a more permanent solution is established.

Figure 21. Deployment and support of the THP system at a deep‐sea well site.

Task 5 – Thermal Hydrate Preventer Demonstration Plans The THP is a versatile tool that can be used to rapidly respond to deep-water oil spills ranging in size from less than 10,000 to 100,000 barrels of oil per day (BOPD). A conceptual illustration of a deployed THP system is shown in Figure 12. This image shows the dome positioned above a deep-sea wellhead, a riser connecting the THP to the surface, and a support vessel and umbilical cables that deliver power and diluent to the device.

In this work, a series of three tests was prepared for demonstrating the performance of the THP device. These include (1) a dry test to verify system functionality, (2) a shallow water or tank



8


test to test the performance in a simulated environment, and (3) a deep-water test to evaluate the deployment and functionality of the device in a simulated emergency response. These tests provide a stage-gate approach that increasingly verifies the performance of the device before culminating in a full-scale, open water test. This test approach was developed to minimize risk and cost, while also providing a high degree of confidence that the tool will work as planned in the event of a deep-water spill.

8.1 Dry Test

A dry test of the THP involves fitting the various pieces of the system together and verifying the functionality of the tool. This initial test would be performed on dry land, and would require cranes and other similar mechanical equipment. These tests will also assess the functionality of the equipment (e.g., heaters, valves, pressure gages, and sensors) and demonstrate the condition after testing.

As seen in Figure 22, the system can be dry-tested using various damaged-well scenarios including open riser pipes, H4 and HC connectors as found on wellheads, BOP’s, and LMRP’s. Furthermore, the THP dome can have either H4/HC or funnel-type collectors installed during these tests. The performance of the device will be documented throughout these trials, and the need for any equipment modifications will be addressed before an open-water deployment is conducted.

Figure 22. Scenarios for dry testing the Thermal Hydrate Preventer.




The outcomes of a dry test will:

1. Verify that the dome can be interfaced to various wellheads and connectors,

2. Identify any additional equipment or modifications that may be needed to improve the operation of the system, and

3. Validate the functionality of the various system components.

8.2 Shallow Water / Tank Test

A shallow water or tank test will verify the performance of the THP system in water, while providing a significantly less costly alternative to a full-scale, deep-water test. Such a test would be performed in an open-water location that provides suitable environmental conditions (i.e., wind, wave, and current), or a sufficiently large pool to enable the testing of a scaled device. For example, Texas A&M has a wave basin that is 150 feet x 100 feet x 19 feet, with a center depth of 55 feet. This pool can simulate open-water tidal conditions.

Figure 23 shows a conceptual illustration of a shallow water test of the THP system. In this example, the THP dome is configured with an H4/HC connector, and the diluent and umbilical connections to the device are highlighted. In a shallow water test, the device is deployed and operated using the support vessels described in the previous report.

Figure 23. Concept for a shallow water test of the THP system.

While not shown above, a riser will also be used in this test. The riser allows for fluids to be circulated through the system. This could include flowing diluents from a surface vessel, as well as fluids from the wellhead.




A shallow water test can be repeated for various types of well interfaces, such as open pipes, H4 or HC connectors, or potentially BOP’s or LMRP’s. In each instance, the THP interface can be evaluated and any necessary modifications to the deployment protocol or tooling can be readily identified and addressed.

When complete, the shallow water/tank test will:

1. Demonstrate the handling and installation of the THP in a simulated environment,

2. Verify the functionality of the device, and

3. Confirm that the device can be interfaced to various wellhead conditions.

8.3 Deep Water Test

Finally, a deep-water test of the entire system will be conducted. This test will utilize the deployment scenarios described in the Task 4 report so that an emergency response can be simulated as closely as possible. The test will be performed at a pre-determined and approved site within the Gulf of Mexico that has the appropriate depth and environmental considerations (wave, current, temperature, etc.). Such a test would be conducted and coordinated with assistance from the U.S. Department of Interior.

As shown in Figure 24, the Thermal Hydrate Preventer will be deployed onto a wellhead located at a depth in which hydrate formation is likely. Once in position, the functionality of the device will be validated by actuating the various valves, monitoring pressure gauges and sensors, and ultimately circulating fluids such as water and/or diluent through the system. Many of these evaluations will have already been performed in the shallow water or tank test. However, the deep-water deployment allows for a full riser length to be applied, as well as for the tool to be positioned onto a wellhead at a depth that closely approximates the conditions expected within a Gulf of Mexico oilfield.

Key outcomes of the deep-water test include:

1. Verifying that the THP can be handled and installed as intended,

2. Identifying installation methods in need of revision, or modifications that would enable a more efficient deployment of the tool in the event of an accident, and

3. Validating the performance of the entire system once it has been deployed at a deep-water site.




Figure 24. Conceptual illustration of a deep‐water test of the THP system.




9 Task 6 – Commercial Implementation Plan The analysis, design, and test plan development conducted on this project have demonstrated the feasibility of a rapidly deployable Thermal Hydrate Preventer (THP) that can be used to mitigate subsea oil spills until a permanent solution can be established. Considerably more work is required to complete the detailed system design, prepare detailed test plans and procedures, conduct the series of three increasingly demanding demonstration tests as outlined in the Task 5 report prior to commercial implementation of this system in the Gulf of Mexico. However, the results of this preliminary investigation and design effort have shown that additional investment is merited in the THP system. CTD envisions this effort to be some sort of public-private partnership where a company or consortium of companies will invest along with the US Government (likely through the Department of Interior) to bring the THP system to a commercial status.

CTD has successfully obtained a patent on the THP system concept and is anticipating a patent on our Coiled Umbilical Tubing (CUT) concept, which can be an integral and enabling part of a THP system. CTD is not a suitable company to lead the system validation, scale-up, or commercial implementation effort. Therefore, CTD will actively seek a company or consortium of companies that have the interest, capabilities, and ability to make the necessary financial investment into furthering the THP system development. In as much, CTD intends to pursue the commercialization of the THP system through a 6-pronged effort.

1. Publish information about the THP system performance and design details. With the patent awarded, it affords CTD the ability to publically disclose detailed information about the THP system. CTD has already submitted an abstract to the 2014 Offshore Technology Conference (OTC) as a means to initiate a marketing effort through the technical literature.

2. Explore interest of CTD’s team members and subcontractors on this on-going project to lead an effort to further the development and commercialization of the THP system.

a. The Center for Hydrate Research resides in the Chemical Engineering Department at the Colorado School of Mines. It is the largest research center in the world dealing with hydrates. Associated with the center is a consortium of energy companies that provide funding and technical oversight of research related to flow assurance in deep-water environments. CTD has been invited to present the results of the THP design study to a meeting of this consortium.

b. Horton Wison Offshore & Marine (USA), Inc. (formerly known as Wison Floating Systems) is based in Houston, Texas. The company was established in late 2009 with the goal of providing full engineering, procurement, construction and installation (EPCI) services to the upstream oil and gas industry. Since its founding, the company has been involved with design, engineering, and delivery of nearly 50 deep-water facilities. Horton Wison offers one of the most experienced project execution teams in the offshore oil and gas industry, and has been at the forefront of developing technology to meet the challenges of today’s offshore projects. Moreover, the company was involved in aspects of the Macondo Well incident and has a very good understanding of the need for new




technologies such as the THP. Because of their experience and involvement in this project, Horton Wison may very well be involved in the commercialization of the THP system.

3. Selling or licensing the THP patent and related IP through a broker. CTD has previously used this approach when the transfer of intellectual property to a third party is the most viable path to commercialization.

4. Forming a consortium of interested companies to pursue additional funding from the U.S. Government to further develop and test the THP system. Such a consortium could include current project team members and/or potential end use customers.

5. Approaching the Marine Well Containment Company (MWCC) to discuss the possible addition of the Thermal Hydrate Preventer to their offshore response capabilities. CTD met representatives of MWCC at the 2013 Offshore Technology Conference (OTC) and discussed how this technology could benefit their spill response capabilities. MWCC does not currently possess technologies that prevent hydrate formation.

6. Working with the U.S. Department of Interior’s Bureau of Safety and Environmental Enforcement (BSEE) to introduce THP technology to oil and gas companies currently operating within the Gulf of Mexico. For example, BSEE was previously involved in open-water trials of equipment developed by MWCC, and a similar involvement here would help to quickly bring the THP to market.

7. Integrating the technologies described herein with other capping stack capabilities may also be possible. For example, CTD’s heating technologies could be adapted to allow modified capping stacks capable of preventing hydrate formation.

10 Conclusions Over the course of this program, the project team developed preliminary designs for a rapidly deployable tool for deep-water oil spill containment operations. The Thermal Hydrate Preventer (THP) incorporates heating and diluent delivery capabilities to prevent hydrate formation and thereby assure the flow of captured effluent to containment vessels positioned at the surface. Hydrate formation occurs when cold seawater mixes with the gases (e.g., propane) in the effluent and causes the material to crystallize and ultimately form blockages with the system. The THP was designed to prevent the formation of hydrates even in circumstances that involve the uptake of cold seawater along with the effluent.

The key outcomes of this work show that:

1. A system involving a non-sealing dome that is positioned above a damaged well can be quickly deployed to collect effluent from leaking or damaged wells in deep-water oil fields. The Thermal Hydrate Preventer was designed to provide a rapid response capability that minimizes environmental (and economic) damage until a permanent solution is established.

2. Hydrate formation within the THP can be avoided by introducing heat and diluent into the dome. Moreover, hydrate formation is prevented even in circumstances where significant volumes of seawater (up to 42% by weight) are captured.




3. The THP system can be scaled to respond to deep-water incidents ranging in size from 10,000 to 100,000 bbl/day, and at depths on the order of 3,000 meters (10,000 feet).

4. Stresses within risers of various sizes and lengths are within the limits of the materials to withstand, even under 10-year hurricane conditions within the Gulf of Mexico. Such severe weather conditions will create the worst-case mechanical stresses within the system and are associated with heave (vertical motion) of the surface vessels.

5. The performance of the THP can be validated through a series of trials conducted in dry, shallow water (or pool), and deep-water conditions. Completing each test will provide increasing levels of confidence in the performance of the device, while also providing opportunities to make design modifications if those are identified during testing.

In addition to the engineering design, CTD is also pursuing plans to commercialize the patented technology to the offshore oil and gas industry. These include developing business plans, as well as identifying opportunities to construct and test the device under various conditions.

11 References

1. R. Worrall, C. Hazelton, and M. Tupper, “Thermal Hydrate Preventer,” U.S. Patent 8,522,881, September 3, 2013.

2. HIS Cambridge Energy Research Associates. “The Role of Deepwater Production in Global Oil Supply,” June 30, 2010. http://press.ihs.com/press-release/energy-power/ihs-cera-roledeepwater-production-global-oil-supply.

3. R. Anderson, M.A. Cohen, M.K. Macauley, N. Richardson, and A. Stern, “Organizational Design for Spill Containment in Deepwater Drilling Operations in the Gulf of Mexico: Assessment of the Marine Well Containment Company (MWCC),” Resources for the Future Discussion Paper 10-63, January 2011.

4. “Oil Industry “Double-Checking” Deep Drilling Safety,” BBC News, June 14, 2010. http://www.bbc.co.uk/news/10298342.

5. “Capping and Containment,” Global Industry Response Group Recommendations, Report No. 464, International Association of Oil & Gas Producers, May 2011.

6. K. Anderson, G. Bhatnagar, D. Crosby, G. Hatton, P. Mansfield, A. Kuzmicki, N. Fenwick, J. Pontaza, M. Wicks, S. Socolofsky, C. Brady, S. Svedeman, A.K. Sum, C. Koh, J. Levine, R.P. Warzinski, and F. Shaffer, “Hydrates in the Ocean Beneath, Around, and Above Production Equipment,” Energy and Fuels, Vol. 26, pp. 4167-76, 2012.

7. M. K. McNutt, R. Camilli, T.J. Crone, G.D. Guthrie, P.A. Hsieh, T.B. Ryerson, O. Savas, and F. Shaffer, “Review of Flow Rate Estimates of the Deepwater Horizon Oil Spill,” Proceedings of the National Academy of Sciences of the United States, http://www.pnas.org/content/early/2011/12/19/1112139108.

8. Gulf of Mexico Regional Climatology, National Oceanographic Data Center (NODC), http://www.nodc.noaa.gov/OC5/GOMclimatology/.



http:WWW.CTD-MATERIALS.COMhttp://www.nodc.noaa.gov/OC5/GOMclimatologyhttp://www.pnas.org/content/early/2011/12/19/1112139108http://www.bbc.co.uk/news/10298342http://press.ihs.com/press-release/energy-power/ihs-cera-role

9. M.L. Tupper, C. Hazelton, R. Worrall, K. Kano, M.W. Hooker, N.A. Munshi, “Coiled Umbilical Tubing,” U.S. Patent Application Number 20120006444, January 12, 2012.

10. J.D. Smith, A.J. Meuler, H.L. Bralower, R. Venkatesan, S. Subramanian, R.E. Cohen, G.H. McKenley, and K.K. Varanasi, “Hydrate-Phobic Surfaces: Fundamental Studies in Clathrate Adhesion Reduction,” Phys. Chem. Chem. Phys., 14 6013-6020 (2012).




composite technology development, inc.engineered material solutionsrapidly deployable thermal hydrate preventer for oil spill mitigationdraft final reportcontract number : E12PC00042prepared for ; Thimothy SteffekU.S. Department of InteriorBureau of safety and environmental enforcementOil spill response division

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