Liquid-Loading-Mitigation Strategies Maximize Recovery From Gas Reservoirs
Authors: Carpenter Chris 
Published: December 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194600, “Revisiting Old Sands With a Different Perspective: A Pragmatic Approach for Maximizing Recovery From Gas Reservoirs,” by Sagun Devshali, SPE, Vinod Manchalwar, SPE, Budhin Deuri, Sanjay Kumar Malhotra, Bulusu V.R.V. Prasad, Mahendra Yadav, SPE, Avinav Kumar, and Rishabh Uniyal, ONGC, prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, 9–11 April, Mumbai. The paper has not been peer reviewed.

In two gas fields in India, many sands had to be isolated after the wells ceased to flow because of liquid loading in the absence of continuous deliquification. To predict liquid-loading tendencies and to identify opportunities for production enhancement, the performance of 150 gas wells was analyzed. All technically feasible methods of deliquification were evaluated and compared to achieve maximum ultimate gas recovery.

Deliquification Techniques ­­in Well-Life Extension

A properly designed tubing string can solve the problem of liquid loading to some extent. With a smaller tubing size, gas velocity can be exceeded and can be kept greater than the critical velocity, thus preventing loading in the beginning phase. However, this is not a viable long-term solution. During later stages, the energy of the gas is not sufficient to lift the liquid droplets with even the smallest tubing. At that point, the use of artificial-lift modes becomes necessary.

Case Studies

Field B. This onshore field in western India produces primarily oil with only 60 gas wells. During the time of study, 17 out of 60 wells in the field were producing gas; the remaining 43 were nonflowing either because of depletion in reservoir pressure or loading. Analysis determined a total of 31 gas wells for deliquification. Of these, in the first phase, two ceased wells (B1 and B2) were selected. Sucker-rod pumps (SRPs) were selected as the most suitable mode of lift in both wells. These wells were then worked over and SRPs were installed in the wells for continuous deliquification.

Well B1. This well was completed in the 1507.5- to 1511-m interval, with 2⅞-in. tubing and 5½-in. casing, in 2011. During the time of study in 2017, the well was not producing. The last production re-ported was 3900 m3/d of gas and 1.4 m3/d of liquid. The critical rate to prevent loading in the well has been calculated as 14 000 m3/d. Analysis indicated that the well has been flowing below the critical rate since 2011. A gradient survey performed in October of 2016 indicated that the liquid level was below 370 m.

Action Plan and Implementation. The plan included recompleting the well with an SRP unit with the pump placed at 1520 m and tailpipe run to a depth of 1570 m to prevent gas interference. The design included approximately 10 sinker bars to prevent buckling.

Well B1 has been completed with the SRP method. A 1½-in. subsurface pump has been placed at 1520 m and tailpipe has been run to a depth of 1570 m. Sucker rods of ⅞ in. have been used as sinker bars. The well has been completed with guides and at the time of writing is producing 6500 m3/d of gas and 6 m3/d of liquid.

Well B2. This well was completed with 2⅞-in. tubing in 2002. The well has not produced since August 2015. The last production reported was 8000 m3/d, less than the critical rate of 11 000 m3/d. A gradient survey performed in December 2016 indicated that the liquid level was below 800 m.