Remobilization of Natural Gas Trapped by Encroaching Water

Ancell, K.L.; Trousil, P.M.

doi:10.2118/20753-ms

Cited by 7 publications

(2 citation statements)

References 11 publications

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“…Under the conditions of the water drive, inundation of gas as well as gas condensate fields results in the drop of gassaturated share of productive section stipulating loss of production well efficiency [4], [5]. As a result, a need arises to perform large-scale activities to restrict local water inflow, and use different procedures dewatering bottomholes of production wells [6].…”

Section: Introductionmentioning

confidence: 99%

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Improving the efficiency of production wells at the final stage of gas field development

Kondrat¹,

Matiishyn²

2022

Min. miner. depos.

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Purpose is to improve the efficiency of extraction of remaining hydrocarbons within the oil and gas fields at the final stage of their development while optimizing operational conditions of the production wells. Methods. Software package PipeSim by Schlumberger has been applied to improve the efficiency of the current well stock under the conditions complicated by liquid accumulation within a bottomhole. A hypothetic well has been used. Findings. The basic operational parameters of a production well have been calculated for different values of water coefficient (i.e. 50; 100; 150; 200; 250; 300; 350; 400 and 450 l/th.m3). The research has helped identify that increase in the water coefficient results in the increased rate of liquid as well as decreased gas rate. A nodal analysis method has been applied to identify the following: at the level of 450 l/th.m3, a production well stops flowing. The results of the studies support the idea that to activate a well efficiency at the level of 18 th.m3/day, it is required either to replace 62.0 tubing string with 50.3 mm one or reduce wellhead pressure from 10.16 down to 9.88 MPa or develop gas lift injection at the level of 1.9 th.m3/day. In addition, the results give the evidence of engineering efficiency as for the method implementation. However, expediency of the application depends upon the processing limits of industrial facilities as well as upon the ratio between the water-free and wet deposit areas. Originality. The correlation dependencies have been determined to forecast operational indices of highly watered wells. The research results help substantiate promptly the methods intensifying hydrocarbon output depending upon different types of geological and engineering limitations. Practical implications. Implementation of the results will help optimize operation of production wells under active edge and bottom water inflow into the productive pools and increase their hydrocarbon extraction respectively.

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Section: Introductionmentioning

confidence: 99%

“…A number of methods and inventions, widely used by gas industry, are applied for operation of production wells under intensive edge and bottom water inflow into productive pools [5], [15]- [18]. Authors of invention [19] have proposed to produce gas by means of periodic removal of gas-liquid mixture from a bottomhole using a gas ejector.…”

Section: Introductionmentioning

confidence: 99%

Improving the efficiency of production wells at the final stage of gas field development

Kondrat¹,

Matiishyn²

2022

Min. miner. depos.

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Increasing the Productivity of Gas Wells in Conditions of High Water Factors

Matkivskyi¹,

Хайдарова

2021

Day 2 Wed, November 24, 2021

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The overwhelming majority of natural gas fields are at the final stage of development, which, along with other features, is characterized by selective watering of productive deposits and production wells. The difficulty of extracting residual gas reserves under such development conditions is associated with depletion of productive reservoirs, accumulation of fluid at the bottom of wells, corrosion of downhole equipment and the inability to reduce wellhead pressures due to restrictions on the supply and preparation of hydrocarbon products with the existing surface infrastructure. Production wells in conditions of formation water inflow into productive deposits are decommissioned after relatively small gas withdrawals. This is due both to the insufficient implementation of methods for intensifying the removal of fluid from the bottom of the wells, and to the peculiarities of the arrangement of fields, which are usually not designed for the collection and preparation of hydrocarbon products with a high liquid content. In order to remove the gas-liquid mixture from the bottom of the wells, many techniques and inventions have been developed that are widely used in production. The developed technologies are characterized by different efficiency and have a number of technological limitations, mainly due to the peculiarities of the geological structure of hydrocarbon deposits. Considering the above, there is a need for additional research in order to improve the existing and develop new technologies for the operation of water cut wells. Using the special software package, studies were carried out to optimize the operating conditions for a water cut well under conditions of active formation water inflow into gas-saturated horizons. The study was carried out for various depths of gas-lift valves (3500 m; 3000 m; 2500 m; 2000 m; 1500 m; 1000 m) and liquid flow rates (22.5 m3/day; 33.75 m3/day and 45 m3/day). Based on the research results, graphical dependences of gas flow rates and bottomhole pressure on the amount of gas-lift gas were built; the maximum gas flow rate and the required amount of gas-lift gas from the liquid flow rate; maximum gas flow rate versus liquid flow rate at different depths of gas-lift valve installation. Based on the results of statistical processing of the calculated data for each value of the liquid flow rate, the optimal value of the depth of the gas-lift valve was established. According to the results of the studies performed, to ensure the stable operation of high-water cut gas wells, it is effective to locate the gas-lift valve at a distance of 55-58 % from the wellhead of the tubing (2033-2137 m).

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Maximizing Gas Recovery from Strong Water Drive Reservoirs

Randolph

Hayden

Anhaiser

1991

SPE Gas Technology Symposium

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Commercially viable production of 150 SCF/STB (27 m3/m3) of gas per barrel of brine has been achieved for reservoir pressure substantially below hydrostatic. Reservoir pressure at 9100 feet (2 990 m) has been drawn down to below 3460 psi (23 620 kPa) or 0.380 psi per foot (0.085 1 kPa/cm). Those wells having a gas/brine ratio in excess of 100 SCF/STB (18 m3/m3) flow because of lift by produced gas. Injection of lift gas is used 1) to start production after wells are shut-in, 2) to maintain production for lower gas/brine ratios, and 3) to increase rate or to increase wellhead pressure for operation of the surface facilities. Key features of the well completions and surface facilities to maximize recovery are: Minimizing friction losses by 1) using annular production, 2) installing tubing only to the depth required for gas lift and chemical injection, 3) using large-diameter wellhead valves and downstream piping, and 4) injecting scale inhibitor through chemical treat strings.Utilizing freewater knockouts followed by separate oil-gas separators that facilitate cooling of condensate before placing it into the stock tanks. This minimizes evaporative loss.Keeping operating costs low by 1) maintaining brine pressure above atmospheric to keep oxygen out of the system and to reduce disposal pumping costs, 2) creating large sand surface areas in the disposal zones to reduce the injection pressure, and 3) using the same compressor for both gas lift and gas sales.

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Remobilization of Natural Gas Trapped by Encroaching Water

Cited by 7 publications

References 11 publications

Improving the efficiency of production wells at the final stage of gas field development

Improving the efficiency of production wells at the final stage of gas field development

Increasing the Productivity of Gas Wells in Conditions of High Water Factors

Maximizing Gas Recovery from Strong Water Drive Reservoirs

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