B41oa oil and Gas Processing Section a flow Assurance Heriot-Watt University

1.4.2 Gas Hydrates Formation: Well Clean-up and Testing 
Gas hydrates could form and block the well-tubing, resulting in serious safety 
and operational problems, as follows: 
•
If the water (or drilling fluid) in the well column is not adequately 
inhibited against gas hydrate formation. 
•
If the well has been closed for considerable time and the tubing 
temperature has dropped to that of ambient temperature. 
•
If gas expansion and depressurisation in vertical flow results in further 
reductions in system temperature. 
•
If fluid flow is controlled by a control valve (or choke), the resulting 
pressure drop could lead to gas hydrate formation. 
Figure 11: Well Temperature and Pressure Conditions – Typical 
Offshore Static Case 
The temperature profile shown in Figure 11 shows the typical temperature 
profile for an offshore well, but one should carefully note that it corresponds to 
a well under static, or no flow, conditions. 
Moving from the platform downward, the temperature reduces with increasing 
water depth, reaching a minimum of 4
o
C near the sea floor. After this point, the 
temperature will follow that of the geothermal temperature gradient, which 
depends on local conditions (a typical value is around 30
o
C/km). Notice that 
the depth could be
converted into pressure (knowing the water density). 
In figure 11, the hydrate phase boundary for the reservoir fluid is 
superimposed on the temperature profile. The gas hydrate phase boundary is 
a function of the reservoir fluid composition and the salinity of either the 
completion fluid, or the produced water (in the case of well-testing). 
The resulting plot shows that at certain depths the system is inside gas 
hydrate stability zone. As a result, there is a potential of gas hydrate formation, 
within the shaded zone and bounded by the red dotted lines. 

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TOPIC 1: Gas Hydrates 
 
 
 
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Clearly when the well is perforated and/or fluid flow is established the 
temperature profile should be revised accordingly. Generally a transient fluid 
flow simulator could be used for this purpose, though a steady-state fluid flow 
simulator could show the range of temperature and pressure variations during 
well clean-up and testing – this is shown in Figure 12: 
Figure 12: Well Temperature Profiles – Typical Offshore Flowing Case 
In order to minimise gas hydrate problems during well clean-up and testing, 
the following factors should be considered: 
•
Analyse the temperature and pressure profiles along the well prior to 
fluid flow. 
•
Determine the hydrate phase boundary for the reservoir fluid using 
either experimental or predictive techniques – take into account the 
effect of completion fluid and/or produced fluid. 
•
Combine the above two plots and find the depths that gas hydrate 
formation can occur. 
•
Locate Sub-Surface Safety Valve (SSSV) and inhibitor injection points 
outside hydrate stability zone – using the above plot. 
•
Control flow rate should be and analyse/measure pressure and 
temperature effects. 
•
Design casing insulation with a view to preventing gas hydrate 
formation. Bear in mind that, although casing insulation will conserve 
fluid temperature, it could have negative effect on gas hydrate 
dissociation (if gas hydrates are formed). 
•
Prepare action plans – to be implemented should gas hydrate 
formation occur. 

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TOPIC 1: Gas Hydrates 
 
 
 
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NIVERSITY B41OA December 2018 v3 
Various alternative strategies for avoiding gas hydrate problems should be 
considered – some potential options are listed below: 
1. Replace all or part of the completion fluid with hydrate inhibited fluid. 
2. Increase system temperature by circulating warm fluid. 
3. Commence inhibitor injection with perforation and/or well flow through 
inhibitor injection line. An inhibitor injection programme could be 
prepared based on transient fluid flow simulator and/or temperature 
and pressure monitoring.