1 Middle and deep geological conditions of the Nanyishan gas reservoir
The Nanyishan structure is an anticline structure with two faults and one uplift. The internal faults are developed, and the two wings of the structure are cut by two large faults. Its reservoir lithology is dominated by carbonate rocks, containing a small amount of argillaceous rocks and clastic rocks. The reservoir space is integrated with cracks and pores, with an average porosity of 31.92% and a permeability of (10-200)×10 2 3μm 2 . The main channel of oil and gas seepage is crack.
2 continuous gas lift process design
2 1 process selection
The Nanyishan condensate gas reservoir is a medium-deep gas reservoir. The pressure of the gas reservoir is high, and there is a certain self-spraying ability at the beginning of mining. Therefore, the continuous gas lift process selects the open gas lift method.
2 1 2 gas lift compressor and gas lift valve 2 1 2 1 compressor Because there is no high-pressure gas source condition in the deep condensate gas reservoir in the south wing mountain, it is necessary to use the gas lift compressor to boost the low pressure gas after treatment on the station. After the gas lifts the water and floods the well. The gas lift compressor is selected from the equipment of Sichuan Zizhong Machinery Factory. Its model is ZTY265H71/ 2′′×4′′. The main working parameters are: suction pressure: 0 1 5MPa～1. 5MPa; displacement: 3×10 4 m 3 / d ; Exhaust pressure: 12MPa ~ 15MPa; rated power: 265kW.
2 1 2 1 2 gas lift valve gas lift valve uses unbalanced bellows gas lift valve.
The main performance parameters are as follows: pressure resistance: 32MPa; dimensions: 25×425mm; connecting thread: ZG12 1 7mm; temperature resistance: 150°C; corrosion resistance, wear resistance; maximum pressure difference of bellows: 25MPa; effective corrugated pipe Cross-sectional area: 199 1 9mm 2.
2 1 2 1 3 Design Principle
1 The injected gas volume is designed according to the required gas volume, that is, the appropriate flow pressure gradient curve is selected according to the maximum gas injection capacity, gas output volume and oil pipe size of the compressor.
2 The depth of the top valve is determined by the maximum starting pressure and hydrostatic gradient of the ground gas injection.
3 The depth of the remaining valve is determined by the reopening pressure of the second valve above the valve and the differential pressure of the injected gas through the valve.
4 Because the bottom hole flow pressure cannot be determined, the gas injection point is unknown, so pressing any one of the valves may be the working valve design.
5 Normal and single-point gas injection must be unloaded to ensure normal startup and improve system efficiency of gas lift drainage.
2 1 2 1 4 The main steps of the continuous gas lift process design (see Figure 2) 1 The hydrostatic gradient curve is determined based on the liquid production rate and the specific gravity of the liquid in the wellbore before unloading to determine the depth of the unloading valve.
2 According to the ground gas injection pressure and the average temperature of the wellbore, the gas injection pressure line is obtained from the drawing board, and then the temperature distribution curve is made.
3 Calculate the depth of the top valve from the hydrostatic surface depth H static, the ground gas injection starting pressure P ko , the tubing flow pressure P tf and the hydrostatic gradient G s 4 According to the maximum gas injection capacity, gas production volume, liquid production volume and tubing size, select the appropriate flow pressure gradient curve, and read the gas-liquid ratio required for the top valve unloading pressure distribution line from the selected flow pressure gradient curve, and then The required amount of gas is calculated from the amount of liquid produced, and the amount of injected gas is corrected based on the temperature T r @L 1 of the valve at the gas injection pressure P v @L 1 and the specific gravity of the injected gas, and finally the actual injected gas amount Q 1 is obtained. 5 From the upstream pressure P UPI ( P v @L 1) and the downstream pressure P dn1 (minP t @ L 1) and the injected gas volume, the valve hole diameter d 1 of the top valve is detected from the drawing. 6 Determine the depth of the second valve H 2 seat aperture and the amount of gas injection. a. The injection valve pressure line of the top valve is shifted to the left by 0 1 35 MPa to obtain the injection pressure distribution line of the second valve, and then the parallel line and the gas injection pressure of the hydrostatic gradient are taken as the starting point from minP t @L 1 . The line intersects at a point where the depth of the second valve is recorded as L 2 and the gas injection pressure is recorded as P v @L 2 . b 1 Determine the minimum tubing pressure minP t @L 2 of the second valve, and then determine the first valve by selecting the intersection of the appropriate flow gradient curve and the top valve depth at the injection point of the wellhead and the second valve. The maximum tubing pressure maxP t @L 1 . c 1 Calculate the additional tubing effect of the top valve, AddTE 1 = < maxP t @L 1 - minP t @L 1 > ×TEF 1, then determine the second valve gas from the flow pressure gradient curve according to minP t @L 2 The gas-liquid ratio required for establishing the pressure gradient curve is determined and the gas injection amount of the second valve is determined, and finally, the injection gas amount Q 2 of the second valve is corrected. d 1 determines the diameter d 2 of the second valve seat from the upstream pressure P UP2 (P r @L 2 - AddTE 1) and the downstream pressure (P dn 2 = minP t @L 2) and the gas injection amount map. 7 The lower depth L n of the remaining valves, the diameter of the valve hole dn, the amount of gas injection Q n and other parameters are determined: a 1 the minimum tubing pressure of the upper stage valve (minP t @L n - 1) and the point where the depth is the coordinate Make a parallel line of the hydrostatic gradient line, then translate the first-stage gas lift injection pressure line to the left by 0 1 35 +∑AddTE n - 2 to obtain the injection pressure line of the n-th valve. At one point, the penetration depths L n and P v @L n of the nth stage valve are obtained from the intersection points. b 1 read the minimum tubing pressure of the nth stage valve, and select the appropriate and flow pressure gradient curve based on the injection point of the wellhead and the nth stage valve. The pressure of the curve at the depth of the n-1th stage valve is Maximum tubing pressure for the n-1th stage valve (maxP t @L n - 1. c 1 Calculate the additional tubing effect of the n - 1st valve (AddTE n - 1 = d 1 according to minP t @L n, select a suitable flow pressure gradient curve, read the gas-liquid ratio under the flow pressure distribution, calculate the gas volume required for the valve gas lift, and finally the temperature and pressure at the valve and The specific gravity of the gas is corrected to give the actual injected gas amount Q n . e 1 determines the seat diameter dn of the nth valve from the upstream pressure (P Upn = P v @L n -∑AddTE n - 1) and the downstream pressure (minP t @L n) and the amount of gas injection. f 1 repeats step 7 until the end of any of the following three conditions (1 gas injection pressure limited valve depth cannot continue to deepen; 2L n ≥ well depth; 3 injection gas volume is limited). The South 2D 4 well was put into operation in November 1996 and was shut down due to flooding in November 1997. From December 1997, the continuous gas lift discharge test was carried out. During the gas lift, the cumulative production of natural gas was 709 1 63×10 4 m 3 , and the cumulative production of condensate was 2 546t. The South 11 inclined well was put into operation in October 1997, and was flooded and shut down in April 1998. The gas lift test was started from mid-April, and the cumulative production of natural gas was 393×10 4 m 3 , and the cumulative production of condensate was 1 410t. The South 1D 3 well was put into operation in February 1997, and the initial output was as high as 10×10 4 m 3 /d. In November 1998, the production was stopped due to too much water. In May 1998, the gas lift valve was started, and the gas lift was accumulated for 2,160 hours. The cumulative increase in natural gas production was 300×10 4 m 3 , and the cumulative production of condensate was 1,076, 16 tons. The South 2D 5 well was acidified and put into operation in November 1997. The initial gas production was 12×10 4 m 3 /d. In February 1998, it was only intermittently self-sprayed due to effluent and the gas production was getting smaller and smaller. In August 1998, the gas lift valve was started, and the gas lift test was started. The accumulated gas lift was 1,607 hours, and the cumulative production of natural gas was 113×10 4 m 3 , and the cumulative production of condensate was 405 1 5t. The South 1D 2 well was put into operation in January 1997. The initial output was 4×10 4 m 3 /d. In November 1997, the foam was drained and gas was produced due to too low oil pressure. However, due to the large amount of water in the well, the foam drainage could not meet the needs. . After acidification in August 1998, the gas lift valve was tested. The cumulative gas lift time of the well was only 7 hours, and the cumulative production of natural gas was 210×10 4 m 3 , and the cumulative production of condensate was 753t. The South 2D 3 well was acidified and put into operation in February 1997. At the initial stage of production, the gas production reached 1×10 4 m 3 /d. In August, the gas lift and gas production was carried out. The accumulated gas lift was 273 hours, and the cumulative natural gas production was only 22×10. 4 m 3, cumulative production of condensate 78 1 95t. 3 1 2 Economic Benefit Analysis The continuous gas lift economic benefit analysis consists of two parts: input and output, including input for compressor depreciation, downhole operation, downhole tool, compressor fuel and other expenses (such as ground gas injection). Pipeline fees, compressor room costs and labor costs for on-duty personnel; the output includes two parts: cumulative gas production and cumulative production of condensate. The three inputs, outputs and net income of the six wells are listed in Table 3 as described above. The analysis shows that the success rate of the measures reaches 100%, the effective rate of measures is 83 1 8 %, and the input-output ratio reaches 13 16 , which has achieved good economic benefits. Total investment in the well: 487.71 million yuan; total net income of 6 wells: 1265 1.75 million. Remarks: 1 compressor depreciation expense = {compressor purchase fee (3 million yuan) × compressor cumulative running time} / {compressor life (5 years) × altitude loss rate (70%) × use efficiency (80%) } ; 2 Other expenses include ground gas injection pipeline fee, compressor machine room fee, duty personnel service fee, etc.; 3 fuel cost is calculated according to 0 1 27Nm 3 / kW. h × 265kW / 0 1 7 (combustion rate) × gas lift time; 4 input-output ratio = 1:3 1 6 4 Conclusion (1) The gas lift design and construction were successful, and the purpose of eliminating the wellbore effusion and restoring the gas well productivity was achieved. (2) The gas lift equipment works normally, and the gas lift valve is normally unloaded by repeated start-up, and the injected gas volume meets the requirements. The process has achieved good economic benefits, indicating that gas lift drainage and gas production has a broad development prospect.
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