Procedures, photographs, diagrams, results and recommendations are shared from an operation to remove sand plugs from a high pressure deepwater well with a failed lower completion. Specific recommendations minimize risk and provide for the safe handling of sand on the surface as the oil passes below bubble point pressure and undergoes rapid expansion. This paper includes photos, diagrams and lessons learned from an operation conducted during the month of December 2011.Removing sand plugs from a live well entails multiple risks. As the hydrocarbon is circulated to surface gas will evolve and expand rapidly, increase the velocity of the mixture and pose the risk of loss of containment due to erosion, especially if sand is entrained within the mixture. Any interruption to surface handling of wellbore fluids and sand creates the risk of stuck coiled tubing. Coiled tubing stuck inside production tubing in a live well would result in an unwelcome and probably difficult fishing job. Literature ReviewA number of papers on coiled tubing cleanouts are provided in the attached references. However none of the papers specifically address the safe handling of sand on surface. SPE 166531 Risks and Mitigations.Risks and mitigations are outlined below. RiskMitigations Flammable Hydrocarbon Gas Equipment layout allowed all liquid flowing out of the well to be contained in pressurized tanks with venting to the production platform vapor recovery unit or flare. Hydrocarbon ContaminationAll liquids were contained in pressurized tanks. The well was maintained hydrostatically overbalanced by use of the coiled tubing choke to keep the well from flowing. Sticking the Coiled TubingMultiple flow paths and redundant equipment minimized the chance of shut-in. The rate of penetration of sand plugs was synchronized with purging of the sand buster.Provisions were made to inject additional liquid (drill water) upstream of anticipated plugging points such as the sand busters. Erosion of Surface Equipment.The well was never allowed to flow, so the maximum rate was dictated by the circulation rate of the coiled tubing. Much of the sand was removed upstream of the bubble point. Multiple vessels allowed for multiple pressure steps. We had multiple spare chokes as well as a complete spare choke manifold (on a standby boat). Damage of CT Pumps by Solids 800 barrels of brine (4 times tubing volume) were on hand to allow us to dispose of used liquids. Extra tanks were provided for settlement of solids for recycle of brine. Planning.The same contractor, Schlumberger, operated the coiled tubing unit and the flow-back equipment. This helped ensure close communication during planning and execution. Bronco provided sand buster equipment and personnel. Emphasis was placed on the need for close communication and coordination. Extra supervisors were hired to ensure the operation went smoothly and folks had adequate rest. Schlumberger modeled flow in the surface equipment to ensure rates would stay below erosive velocities at the planned circulation rates. All con...
DISCLAIMER s report was prepared M q accomt of work SPOnSOd by m agency of the United States Government. Neither the Umted States Gov*nt nor any agency thereof, nor any of their employees, makes any warranty, express or mphed, or assumes any legal liability or responsibility for the accuracy, completeness: or usefulness of any information, appara~, produq or process disclo~or represents that Its use wotid not infringe privately owned rights. Reference herein to any specific commercial produc~process, or service by trade name, trademark manufacturer, or otherwise does not necessarily constitute or imply its endorsemenr ecommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. * SUppiy cooling water to the APT heat exchangers from the existing river water system using 681-6G pump house at PAR pond. This option was not evaluated due to the fact that the 681-6G pump house has not been maintained, and thus the equipment condition was suspect. The cost and feasibility associated with this option is essentially identical to Alternative 2 above. The primaly difference would be the additional cost in restoring the * A once through cooling system utilizing well water supply. This alternative is not considered feasible as the number of wells required to meet the demand would be cost prohibitive and the permitting risk associated with this production rate was considered to be extremely high. These alternatives cover the most common and frequently used types of systems. Other alternatives or variations may exist, but were not considered in this report. 4,0 Basis for Evaluation and Selection: Alternatives are evaluated on technical feasibility, direct capital costs, operating and maintainability costs, and permitting risks. Technical feasibility is evaluated on a gojno go basis, and all of the alternatives evaluated herein are technically feasible in that they can provide the required cooling given that the proper equipment (either new or modified) is in place. The remaining criteria will be assigned a numerical value or score based on a performance scale of O to 5 such that 3 is the rating of the base alternative (Alternative 2) with higher numbers increasin~yly better than the base and lower numbers increasingly worse. For the purpose of this study the criteria were weighted as: direct capital cost-20°/0, operat~r~g and maintainability costs-30°/0, and permitting risk-50°/0. 5,0 Evaluation of Alternatives for APT Site #2: 5.1 River Water Makeup (Alternative #1) Descri~tion of SVstem: This scenario relies on mechanical drafi cooling towers as the primary means of transferring heat from APT to the atmosphere. Makeup water is required to account for evaporative losses and continuous blowdown. Preliminary calculations indicate that approximately 6000 gpm of makeup water will satis& the peak demand for APT. This 6000 gpm could be supplied using a portion of the...
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