Mature fields

Liquid-Loading-Mitigation Strategies Maximize Recovery From Gas Reservoirs

To predict liquid-loading tendencies and to identify opportunities for production enhancement, the performance of 150 gas wells was analyzed in two gas fields in India.


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 reported 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.

Action Plan and Implementation. The plan included recompleting the well with an SRP. To ensure better natural anchorage, it was decided to drill down and place the pump below 1460 m.

Now that Well B2 has been completed with an SRP, both intervals have been kept open. A 1½-in. pump has been placed at a depth of 1450 m and tail-pipe has been run to 1500 m. At the time of writing, the well is producing 5500 m3/day of gas and 5 m3/d of liquid.

Field A: Revisiting an Old Reservoir After Field B

Field A is an eastern onshore gas field. Production began in 1975. In most wells, the gas can no longer efficiently lift the associated liquids to the surface. To identify production-enhancement opportunities, 90 gas wells were analyzed for identification of liquid loading on the basis of ­critical-rate and pressure-gradient surveys. After the analysis, 29 gas wells were identified for deliquification. Of these, plunger lift was found to be feasible in three wells, while SRPs were found to be most feasible in wells with pump-setting depths below 2000 m. In the remaining wells, pump-setting depths above 2000 m and high gas/liquid ratios limit the application of conventional SRPs; therefore, the use of suitable heavy-duty SRP equipment was explored for these wells.

Well Y18 is the first well in the field selected for continuous deliquification. The well was initially completed in Reservoir MP-30 with a 1675- to 1678-m perforated interval. The average production from the well was 25 000 m3/d of gas. After continuous liquid production from the zone with no deliquification measures in place, the well was worked over in December 2011 and recompleted in the perforated interval (1396 to 1398 m). The average production from the well from the present perforations was 37 000 m3/d, with 5 m3/d of liquid. The well was again recompleted in a perforated interval of 1435 to 1439 m. The last well-flow rate (13 892 m3/d) was far below the critical rate for the present well parameters.

Encouraged by the results of implementation in the initial two gas wells of Field B, the operator planned to open the isolated sand interval in the well. The action plan included reperforating the interval after reservoir testing to assess well potential and remaining recoverable reserves.

The 1396- to 1398-m interval was perforated and an influx study was performed in the well. On the basis of that study, the well was recompleted with SRP. Because the spare surface unit available was smaller and the pump could not be lowered down below 1200 m, a tailpipe was lowered from 1200 to 1550 m (111 m below the perforation) in order to achieve natural gas separation. Initially, even the echometer survey for liquid-level estimation was unavailable and the liquid level was assessed on the basis of parameters such as casinghead pressure and gas production. On the basis of the estimated level, the SRP was run intermittently.

The well is producing gas at the rate of 45 000 m3/d through the casing tubing annulus while pumping 2 m3/d of water through the tubing. Thus, a gain of 30 000 m3/d has been realized from a single well by reviving production from an older sand.


In Field A, a total of 21 flowing and eight nonflowing wells were identified for continuous deliquification. Of the 21 flowing wells, deliquification measures were not required in five wells in the sand in which they were currently producing. These wells had ceased flowing in the past because of liquid loading in old sands and were subsequently recompleted in present sands. However, opportunity existed to enhance production by revisiting the old sands. Furthermore, in four of the remaining 16 flowing wells, the production has dropped because of liquid loading. Additionally, in these wells, earlier sands had also been isolated as a result of liquid loading, and the analysis indicated a significant production potential. The remaining 12 wells require deliquification in the present reservoir. The envisaged gas gains from these wells is approximately 0.65 Lakh std m3/d.

Of the 23 nonflowing wells, eight wells have been identified that ceased flow because of liquid loading. The analysis indicates an opportunity to enhance production by approximately 2.1 Lakh std m3/d by reviving these wells. The remaining 15 nonflowing wells have either been converted to effluent disposal wells or have been permanently abandoned.

In Field B, six of the nonflowing wells have either been abandoned or have been converted to effluent disposal wells. The remaining 54 wells also have been analyzed in the study. Opportunity exists to enhance gas production by approximately 1.5 Lakh std m3/d using continuous de­liquification by reviving production from 12 out of 17 flowing wells and 19 nonflowing wells. In two of these nonflowing wells (B1 and B2), SRPs have already been installed. In the remaining 16 nonflowing wells of Field B, neither production history nor gradient survey is available and, hence, well potential could not be assessed. The gains envisaged and realized so far for both fields are shown in Table 1.



The main focus of this paper is on already-abandoned zones that have zero contribution to the operator’s production figures. The paper shows that even wells that have been abandoned because of liquid loading can be brought back to production by applying the right approach, and recoveries can be increased from 70 to 95%. In the case studies discussed, by putting deliquification into actual practice, not only has the gas production increased, but nonflowing wells have been revived.

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.