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Kleckner, J.J.,* Sun E and P Co.; Dickerson, R.C.,* Chevron U.S.A. Inc.; Snider, P.M.,* and Zublin, J.A., National Supply Co.; Sphan, R.L., Exxon Co. U.S.A.; Menne, P.F.,* Amoco Production Co.; Van Der Lichte, J.H., and Ter Horst, H.S., The Nederlands Aardolie Mij-B.V., Akkerman, N.H.,* Ava Intl., Rorden, L.H.,* and More, H.S.,* Develco Inc.; Kattner, J.E.,* Sun E and P Co., and Samuels, A., Gas Sweetner Assocs., and Wendt, R.A., Loyola U.; Hoh, T.,* Advanced Pumping Systems Inc.; Beauregard, E.,* and Ferguson, P.L.,* Ferguson Beauregard Inc.; Carnell, P.J.H., Imperial Chemical Industries plc, and Clark, H.H.,* Amoco (UK) Exploration Co. *SPE Members The Production Operations Forum is designed to allow the discussion of and dissemination of information about technical innovations and solutions in production engineering that are of immediate practical use but do not warrant a full-scale paper. practical use but do not warrant a full-scale paper. Each subject is presented in a five to eight minute period with a discussion period of seven to ten period with a discussion period of seven to ten minutes. A wide range of subjects is encompassed in the session. Abstracts of the presentations follow: I. "A Practical Approach for Liquid Removalin Low Pressure, Low Volume Gas Wells, Utilizing 1-1/4" Coil Tubing" The presence of liquids in a gas flow stream, whether the liquids are condensate or formation water, requires energy to be lifted to the surface. If sufficient energy is not present, liquids will accumulate in the wellbore and exert additional back pressure on the formation. This results in erratic production, poor compressor performance, and inaccurate data in multi-rate back pressure testing. In the case of low reservoir pressure, the accumulation of liquid may kill the well. Several methods including plunger systems, sucker rod lift, liquid diverters and gas lift installations are used to successfully move liquids from the wellbore. This discussion will address specifically the use of 1.25" concentric pipe (coiled tubing) as a production string to reduce cross-sectional area of flow, thereby increasing the stream velocity and continuously unloading liquids from the wellbore. In many cases the wells requiring liquid lift are low pressure gas wells sensitive to remedial work and kill fluids. Use of a custom machined spool and slip assembly in conjunction with a pump out plug and coil tubing unit injection head allows for the installation of the coil tubing without killing the well. Installation is accomplished by shutting in the well at the bottom master valve and removing the tree above the shut in valve. The spool and slip assembly is installed and a coil tubing unit with injection head is rigged up on the spool. The tubing is run to the desired depth, the slips are set, and the tubing is packed off. The tubing is cut above the injection head and the BOP's and injection head are removed. The tubing is dressed off 2-3 inches above the bowl and slip assembly and the tree is installed. The coil tubing is pressured up with N2 or gas to release the plug and the well is flowed to sales. This "no kill" method has alleviated past problems of returning low pressure gas wells past problems of returning low pressure gas wells to production following workovers. The economics of installing a reduced diameter tubing string must be closely evaluated prior to expenditure. Data necessary to make the evaluation includes use of Turner, Hubbard. and Dukler's equation of the minimum gas stream velocity required to lift liquid in vertical conduit. An economic limit is then calculated and compared to the minimum flow rate required for liquid removal. Construction of a back pressure curve using well data or field history is then used to deter-mine reservoir abandonment pressure at the economic limit. Remaining reserves can be determined by extrapolation of BHP/Z versus cumulative production to the abandonment BHP/Z. As a result of the "no kill" method of installing 1-1/4" coil tubing in three 9000' Cotton Valley gas wells, operating expenses and downtime have been reduced by eliminating swabbing costs. |
