Several gas fields are being developed off the coast of Western Australia. The risk for hydrate blockages in these fields is high and presents several challenges for hydrate inhibition, including high subcoolings, low water salinities, and high system temperatures. The current strategy is to use mono-ethylene glycol (MEG) for hydrate inhibition, which includes MEG regeneration units (MRUs) in the design of the facilities. The installation and maintenance of MRUs capable of handling the large required volumes of MEG is costly and other issues such as scale, foaming, and accumulation are a concern when using an MRU. Therefore, the use of a low dosage hydrate inhibitor (LDHI) is being considered for some developments. Kinetic hydrate inhibitors (KHIs) are typically considered for gas fields, not anti-agglomerate low dosage hydrate inhibitors (AA-LDHIs). KHIs, however, are not effective at high subcoolings and can become unstable when subjected to the high temperatures of the MRUs. Instead, a new generation of AA-LDHI chemistry can be considered for Australian gas fields. Field data will be presented supporting the new AA-LDHI’s effectiveness in inhibiting hydrate blockages in a gas/condensate field, eliminating the need for MEG and the MRU. The new AA-LDHI chemistry is being evaluated for several Australia projects, and data supporting the chemistry’s stability at temperatures greater than 150°C and its effectiveness with low-water salinities will also be presented. The new AA-LDHI chemistry could eliminate the need for MEG or greatly reduce the volume of MEG required for inhibition, which would reduce CAPEX and OPEX.
A number of gas fields have been developed in the Middle East, Offshore Western Australia and in the Asia-Pacific region for the last five years as the demand for Liquefied Natural Gas (LNG) has grown tremendously worldwide. Most of these gas field production systems consist of long subsea flowlines, which are flowing with three phase fluids gas, condensate and water. The cold temperatures of the subsea environment pose a flow assurance risk to production, especially for hydrate blockages.The only solution currently being considered to address the risk for hydrate blockages in gas fields is the usage of Kinetic Hydrate Inhibitors (KHIs), not Anti-Agglomerate Low Dose Hydrate Inhibitors (AAHIs). The most significant production concern for all producers associated with this production scenario is that the performance of the KHI is compromised in the presence of the Corrosion Inhibitor (CI). The reason for not considering the AAHIs for this application, whose performance is not compromised by the corrosion inhibitor, is the general belief that these chemistries are predominantly water soluble and therefore increase the toxicity of the produced water.The published literature to-date is focused on understanding the interactions between the KHI and the CI chemistries to solve the incompatibility issue. The lack of literature to-date showcasing the success of such an understanding warrants a solution with a different perspective. Data is available for new generation chemistries currently being used in the industry that show greater than 99% oil solubility and would hence overcome the toxicity concern that was valid for the first generation AAHI chemistry.This new generation chemistry was tested by Heriot-Watt University in the United Kingdom (UK) that shows the product effectiveness up to 90% water cut at a reasonable subcooling, applicable for these subsea flowlines in discussion. The performance at these high water cuts will make this new generation chemistry more applicable for these subsea flowlines without the risk of hydrate blockages.
A new subsea tieback in the Gulf of Mexico (GoM) is expected to experience temperatures as low as 10 o F in the system due to high levels of expansion cooling. The system will operate within the hydrate region, at a high degree of sub-cooling. Current test methods used to select and determine the effectiveness of Low Dosage Hydrate Inhibitors (LDHIs) are capable of evaluating at temperatures down to 39 o F. A new test method was developed to effectively evaluate the performance of LDHIs at temperatures as low as approximately 10 o F.The flowline for the subsea tieback is un-insulated and the flexible riser is partially insulated by the layers in the construction of the pipe. The fluids will experience expansion cooling due to the Joule-Thomson effect as they move up the riser and will not be able to adequately take advantage of the "warm" surrounding seawater. As a result, the lowest expected temperature in the system is 10 o F. This lower temperature also means a higher degree of sub-cooling. Typically, the higher the subcooling, the higher the dose rate required to inhibit hydrates using an LDHI. To date, there is no data supporting antiagglomerate low dosage hydrate inhibitors (AA-LDHIs) are effective with black oils at operating temperatures between 10 o F and 30 o F. A new test method was required to show that an AA-LDHI will effectively inhibit hydrates at the system conditions of the subsea tieback.A description of the new test method used to evaluate AA-LDHIs at temperatures below 39 o F will be presented as well as the results. The results include the evaluation of produced fluids with and without the addition of AA-LDHI. These results demonstrate that hydrate formation and the effectiveness of AA-LDHI to inhibit hydrate blockage can be detected at low temperatures using the new test method. It is shown that the AA-LDHI effectively inhibits hydrate blockage at approximately 10 o F. It is also demonstrated that the mixture of produced water and AA-LDHI will not freeze at system temperatures.
The paper describes conditions involving the plugged flowline of a >20 mile subsea tieback in the Gulf of Mexico and the innovative techniques and procedures that were utilized in the remediation process. The procedures performed also provided information used for locating and identifying the plug composition. Included is a description of the system and a diagram of the well, wellbore and flowline. The paper explains the innovative technique that was utilized for lowering the flowline pressure on the backside of the plug while minimizing the risk in resolving the plugged flowline. Alternatives to the innovative procedures are extremely costly, ranging in the Millions of dollars, and can be very time consuming in terms of resolving it by means of using an intervention vessel. The application of the procedure involves utilizing the tubing volume between the process choke valve (PCV) and the surface controlled subsurface safety valve (SCSSV) as a means to bleed the pressure off of the flowline. Included in the application is a description of the type of chemicals and produced fluids involved, the valve setup and different arrangements used in the well and at the wellhead. Also included are the diameters, lengths, volumes, pressures and temperatures of the system and the components. The results from the implementation of the procedure include the calculated location and informed assessment of the composition of the flowline plug based off the information gathered from the application. The procedure was performed multiple times with similar results, indicating its repeatability. Results are included from multiple applications of the procedure. The results and observations from the implemented procedure provided the producers with the appropriate information to make an informed decision on a path forward that improved the efficiency of the subsequent remediation procedures. A conclusion of the paper is that the new technique and/or operating procedures for flowline bleed down operations are successful and repeatable for this system and those similar in design. The implementation of the new innovative procedures can provide a significant cost savings and eliminate the risk to the environment and personnel from interventions. Introduction Conditions can occur in flowlines, jumpers, wellheads and even wellbore tubing such that they become plugged. In this instance, the flowline of a >20 mile subsea tieback became plugged after producing for many years without any flowline blockages. The type of plug that can form in a system depends on the composition of the fluids being produced. Typically plugs that form can be composed of either paraffin, hydrates or in some cases a combination of both. Scale and other solids deposition such as sand/sediment and asphaltenes can also cause plugs. The produced fluids in the >20 mile subsea flowline were from a predominately gas producing well that also produced water and some condensate, which required continuous treatment for both wax deposition and hydrate formation. The >20 mile subsea flowline is un-insulated and the conditions were such that the system operated inside the hydrate formation region even during steady state production and thus required treatment for hydrate formation on a continuous basis.
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