answer haggis field

PAB 2094 Well Completions and Production

Nguyen The Thao

WELL COMPLETIONS AND PRODUCTION

THE HAGGIS FIELD

Name:

ID:


Nguyen The Thao


THE HAGGIS FIELD

Name:


Nguyen The Thao


THE HAGGIS FIELD

Nguyen The Thao

11828


WELL COMPLETIONS AND PRODUCTIONPAB 2094

THE HAGGIS FIELD

Nguyen The Thao

11828



THE HAGGIS FIELD ANSWER FORM

Nguyen The Thao



ANSWER FORM

Nguyen The Thao

THE HAGGIS FIELD


ANSWER FORM

THE HAGGIS FIELD


ANSWER FORM

THE HAGGIS FIELD

11828


ANSWER FORM

PAB 2094 Well Completions and Production THE HAGGIS FIELD

Nguyen The Thao 11828

DECLARATION I Nguyen The Thao confirm that this work submitted for assessment is my own and expressed in my own words. Any uses made within it of the works of other authors in any form (e.g. ideas, equations, figures, text, tables, programs) are properly acknowledged at the point of their use. (A list of the references employed should be included.) Name: NGUYEN THE THAO Signed: Date: 04/11/ 2010 ___________________________________________________________________________

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Section A: 1) The well Haggis-3 is used as the base case well for the Haggis field throughout this

exercise. In order to minimise the computer time involved in simulations, the model used contains only components are significant and that contribute significantly to the pressure drop along Haggis-3. Therefore, the model contains only the following nodes:

Node No. Component Name Bottom Depth, MD (ft)

1 Tubing 1 850.0 2 SSS Valve 850.0 3 Tubing 2 1000.0 4 Tubing 3 1500.0 5 Tubing 4 4000.0 6 Tubing 5 5600.0 7 Casing 6530.5 8 9

The attached Figure A1 illustrates the nodes used in the WellFlo model.

[5%] 2) In flow simulations on WellFlo, Haggis-3 was modelled using the following correlation:

Hagedorn & Brown (Mod) [STD/MOD]. [10%]

There are two main reasons why this correlation was chosen: a) The oil rate simulated by this correlation is closest to the given oil rate of 4770

STB/day at 2800psi and 30% WC; compared to the other correlations.

The attached Figure A2 supports this reasoning. b)

i) Because the 7 pairs of TVD versus Depth values (that were given from a recent pressure survey from Haggis-3; Fig. A2.1) are closest to the Hagedorn & Brown (mod) correlation curve (with 5 near and 2 exact to the curve).

ii) Because Hagedorn & Brown (mod) has a good accuracy in pressure profile predictions for a wide range of water-cuts. The correlation developed is independent of flow patterns.

Reference: Hagedorn, A. R. and Brown, K. E.: .Experimental Study of Pressure Gradients Occurring during Continuous Two-Phase Flow in Small Diameter Vertical Conduits, J. Pet. Tech. (Apr. 1965) 475-484.

[20%]



Section B: In order to evaluate the viability of producing Haggis-3 under increased water-cuts and reduced reservoir pressures, a number of sensitivity analyses were performed on the production from Haggis-3 using WellFlo. These sensitivities are illustrated by the following figures: B1, B2, B3, B4 and their results are summarised in Table B-1 below: PRes.

WC 2800 (psia) 2700 (psia) 2600 (psia) 2500 (psia)

30% 4770 4042 3277 2459

35% 3777 3094 2357 1525 40% 2876 2212 1489 NOP 45% 2054 1413 NOP NOP

Table B.1: Haggis-3 Production Forecast [10%]

Since artificial lift cannot be supported by the production facilities on the Haggis platform at present, you agree with your engineers that you have to start a water injection scheme to maintain the reservoir pressure at 2800 psia. Under these circumstances, Haggis-3 will produce economically (1500+ BOPD) at a maximum water cut of 48.7 %, and at an oil production rate of 1500 BOPD, as illustrated by Figure B5. This is considered to be the Base Case scenario, against which all other schemes in section C will be compared.

Scenario Maximum Economic Water Cut Oil Production Rate @ 30% Water Cut @2800 psi

Base Case 48.7 % 4770 STB/day

[5%] With a water injection scheme in place, you expect to face even more severe water production from Haggis-3. One way of dealing with such a problem is to plug-off “watered-out” perforations. List two advantages and two disadvantages of plugging off. Advantages:

i) Prevent, reduce or isolate water production, hence no need to dispose water, which results in cost-saving.

ii) Increases flowing pressure, allowing higher flow rates at upper zones. Stability of zones also increases.

Disadvantages:

i) If cement plug is set it could damage the formation, reducing permeability and increase the skin effects, and thus, reduces production. Solutions that are injected in plugging operation can reduce hydrocarbon flow out of producing formation.

ii) Plugging off operation is costly and time consuming.

Reference: Johnson, D. E., and Pile, K. E. 2002. Well Logging in Non-technical Language. Tulsa, Oklahoma: Penn Well Publishing.

[20%]



Section C: Tubing Selection a) Assuming that we have an option to choose the optimum production tubing size.

Examine the tubing performance for depleting reservoir pressure.

PRes.

OD 2800 (psia) 2600 (psia) 2400 (psia)

3.5” 3393 2477 1328 4.0” 4019 2860 1458 4.5” 4496 3140 1521 5.0” 4736 3258 1533 5.5” 4845 3309 1531

Table C1: Oil production forecast as functions of tubing sizes and reservoir pressures.

[10%] b) After installing optimum tubing size of 5.5 inch diameter (OD), Haggis-3 is having

maximum water cut at which the well can produce economically of 48.7 %. (See figure C4)

c) Scenario Maximum Economic Water Cut Oil Production Rate

@ 30% Water Cut

Optimum Tubing Size 48.7% 4845 STB/day

[5%]

d) State the two main factors in choosing the optimum production tubing size. Explain your

answer. 1. The tubing size that is selected must have a lower pressure drop due to friction and

turbulence. So since larger tubing size will yield lower frictional flow, it will cause lower pressure drop, and thus, maintain an optimized oil production rate.

2. The water cut. This is because at reservoir pressure 2800 psia, the oil production rate is highest at 4845 STB/day with the best maximum economic water cut of 48.7%. The aim is to get high oil rate. This means we should increase of tubing size. However, by doing this, we need more energy to lift up the oil, so need high water cut (so that energy needed is less). But this water cut can't be too high to avoid excessive water production.

References: WCP lecture notes; John, F. Hydrocarbon Exploration and Production, Standard Handbook of Petroleum & Natural Gas Eng.

[15%]



Section D

A. Electrical Submersible Pumps. a) The most suitable pump of Haggis-3 given the present conditions is HC9000/KMH562

Series/#1/Centrilift. Figure D.A.1 shows the performance plot of this pump. This pump is the optimum choice because

1) The power required to operate HC9000 is the lowest among the ESPs tested, which is140.662 kW. Cost of operation can be reduced when the power required is lower.

2) HC9000 has the highest efficiency, where 44.2% of electric power are converted into pumping power, which is cost saving.

3) The operating point is located within the range of maximum and minimum flow rate.

[5%]

b) Surface facilities limit the quantity of water that can be produced from the well. To

maintain a lower water cut, water injection could be suspended and the reservoir allowed depleting. Sensitivity of the model to declining reservoir pressure is illustrated by the following figures: D.A.2, D.A.3, D.A.4, D.A.5 & D.A.6. The results are summarised in Table C.3 below.

PRes.

Pump 2800 psia 2600 psia 2400 psia 2200 psia

GC 8200 6296.6** 5888.3 5237.4 4161.7 HC 7000 6296.8** 5968.7** 5541.3 4998.9 HC 9000 6299.1 5312.2 4106.0 2633.5*

KC 12000 6289.9 4919.5* 3531.2* 2208.3* KC 15000 6263.3* 4839.1* 3313.1* 1726.6*

Table D.1: Haggis-3 Production (Oil) Forecast with ESP installed, ** denotes rate out with the operating range of the pump.

According to Table D.1 the optimum ESP for Haggis-3 for declining reservoir pressure is GC8200, at a water cut of 30%. This pump is the optimum choice because GC 8200 can operate in all of the specified layer pressure except 2800psia. It has larger operating range compare to other pumps. Other pumps have two or more layer pressure. They are not stable thus cannot operate under this condition.

[10%]

** - above pump max; * - below pump min



c) If the optimum ESP is installed in Haggis-3 the maximum water-cut at which the well will produce economically with no depletion is 76.667%. (see figure D.A.7)

Scenario Maximum Economic Water Cut

Oil Production Rate @ 30% Water Cut

Optimised ESP 77.40% 6296.634 STB/day

[Refer to Figure D.A.8] [5%]

B. Gas Lift Design a) The gas lift design for Haggis-3 given the present conditions is shown in Figure D.B.1.

The required gas injection rate for the design production rate is 1.57 MMSCF/day.

[Refer to Figure D.B.2]

The purpose of the operating valve is to allow the lift gas to be inject during normal production. It should be OPEN when assessing the gas lift design.

The purpose of the unloading valves is to allow the displacement of original fluid and enable the circulation of the lift gas. It is also use to depressurize the pump when the critical pressures downstream reach. These should be OPEN/CLOSED when assessing the gas lift design.

[10%]

b) If the reservoir is allowed to deplete, sensitivity of the gas lift model to declining reservoir pressure becomes an issue. This is illustrated in Figure D.B.2 where the operating rate is plotted against the Lift gas injection rate (sensitivities: 1. layer pressure 2. Gas Lift injection rate). These results are summarised in table D.2 below.

Table D.2: Technical Optimum gas injection rate for Haggis-3.

The criteria used to choose the optimum injection rate :

i) Depth of injection. ii) Amount of the gas inject. iii) Tubing size.

PRes.

2800 psia 2600 psia 2400 psia 2200 psia 2000 psia

Technical Optimum injection rate

MMscf/day

7 6 6 5 4



Higher injection rates do not improve production as the reservoir pressure declines because higher injection rates will also increase gas production rate, which will then cause the friction term increase faster than the hydrostatic depletion rate. The oil production rate will be reduced due to friction between fluids and tubing.

[15%]

c) After recalculating the valve positions for the optimum injection rate for 2800 psia the maximum water-cut at which the well will produce economically is 76%. (See figure D.B.3).

Scenario Maximum Economic

Water Cut Oil Production Rate @ 30% Water Cut

Optimised Gas Lift 74% 6302.634 STB/day [Refer to Figure D.B.5] [5%]

Section E: Summary

a) Table E below summarises the results from the various simulations carried out on the

Haggis-3 well. Scenario Maximum Economic

Water Cut Oil Production Rate @ 30% Water Cut

Base Case 46.704% 4771.754 STB/day Optimum Tubing Size (4.5 OD)in 47% 4498.513 STB/day Optimum ESP 77.667% 6296.634 STB/day Optimum Gas Lift 74% 6544.245 STB/day

Table E: Haggis-3 simulation summary

b) Based on the WellFlo simulations carried out and my assessment of them, I am

recommending that Big Kahuna Inc. invest in a water injection scheme to maintain Haggis’s reservoir pressure at 2800 psia. In addition, I am recommending that Big Kahuna adopts the Optimum Gas Lift because the optimum maximum economic water cut will make the well have longer well life. And, optimum gas lift scenario able to give us the highest oil production, which is 7298.245 STB.day compare to other scenarios.

[10%]



Risk/Uncertainty How this adds uncertainty to above assessment?

Steps that can be taken to account/minimise this uncertainty

1) Volume of Oil Initially in Place (OIIP)

The volume of oil initially in place for this assessment only been estimated based on the initial oil production rate. The volume will affect the economical factor of the field development. Hence add uncertainties to the assessment.

Maximize the use of the available data from the exploration and logging activities in estimating the volume of oil initially in place. Apply the most appropriate correlation to determine the nearest estimation toward the true value.

2) Reservoir Pressure Declination Rate

When the production starts, there will be declination in the reservoir pressure. The rate of declination can sometimes become unpredictable because it depends on various factors that are not easy to control.

Choose optimum rate of production that can reduce the effect on reservoir pressure. Plan and install pressure recovery techniques for the reservoir during primary recovery. (water flooding/ natural gas recycling)

3) Reservoir Formation Strength

Reservoir formation can be damaged due to production depending on the strength of the rock formation. Damages on the reservoir formation can cause uncertainties in oil production as it reduces the reservoir permeability.

Apply an appropriate perforation and completion program. Implement suitable well stimulation and fracturing techniques. Maintain the optimum production rate that prevents damage on the formation.


Nguyen The Thao

The nodes used in the WellFlo model.


Nguyen The Thao



Nguyen The Thao





Section

Figure

Section A

11828

Figure A1

PAB 2094 Well Completions and Production Section A


Pressure and Temperature vs Depth Analysis for adonisSensitivity To: Well and riser flow correlation

Liquid Oil Water Gas WaterRate Rate Rate Rate Cut GOR(STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)6815.364 4770.755 2044.609 2.624 30.000 550.0006321.894 4425.325 1896.568 2.434 30.000 550.0004738.173 3316.721 1421.452 1.824 30.000 550.0006851.437 4796.005 2055.431 2.638 30.000 550.0005999.784 4199.849 1799.935 2.310 30.000 550.000

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Pressure: Q liq = 6815.365 STB/day, Corr, v = Hagedorn and Brown (mod)Temperature: Q liq = 6815.365 STB/day, Corr, v = Hagedorn and Brown (mod)Pressure: Q liq = 6321.894 STB/day, Corr, v = GrayTemperature: Q liq = 6321.894 STB/day, Corr, v = GrayPressure: Q liq = 4738.173 STB/day, Corr, v = EPS mechanisticTemperature: Q liq = 4738.173 STB/day, Corr, v = EPS mechanisticPressure: Q liq = 6851.437 STB/day, Corr, v = Beggs and Brill (mod)Temperature: Q liq = 6851.437 STB/day, Corr, v = Beggs and Brill (mod)Pressure: Q liq = 5999.785 STB/day, Corr, v = Duns and Ros (mod)Temperature: Q liq = 5999.785 STB/day, Corr, v = Duns and Ros (mod)P:Measured data

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Figure A2


Nguyen The Thao


Nguyen The Thao


Nguyen The Thao



Section

Section A

11828

A2.1

PAB 2094 Well Completions and Production Section A


Selected L-factor =0.9759

Pressure and Temperature vs Depth Analysis for adonisSensitivity To: Well and riser L-factor

Liquid Oil Water Gas WaterRate Rate Rate Rate Cut GOR(STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)6812.940 4769.058 2043.882 2.623 30.000 550.0006815.364 4770.755 2044.609 2.624 30.000 550.0006815.364 4770.755 2044.609 2.624 30.000 550.0006817.774 4772.442 2045.333 2.625 30.000 550.0006817.774 4772.442 2045.333 2.625 30.000 550.0006820.201 4774.141 2046.060 2.626 30.000 550.000

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Pressure: Q liq = 6812.941 STB/day, L(v) = 0.9760 (fraction)Temperature: Q liq = 6812.941 STB/day, L(v) = 0.9760 (fraction)Pressure: Q liq = 6815.365 STB/day, L(v) = 0.9759 (fraction)Temperature: Q liq = 6815.365 STB/day, L(v) = 0.9759 (fraction)Pressure: Q liq = 6815.365 STB/day, L(v) = 0.9759 (fraction)Temperature: Q liq = 6815.365 STB/day, L(v) = 0.9759 (fraction)Pressure: Q liq = 6817.775 STB/day, L(v) = 0.9758 (fraction)Temperature: Q liq = 6817.775 STB/day, L(v) = 0.9758 (fraction)Pressure: Q liq = 6817.775 STB/day, L(v) = 0.9758 (fraction)Temperature: Q liq = 6817.775 STB/day, L(v) = 0.9758 (fraction)Pressure: Q liq = 6820.202 STB/day, L(v) = 0.9757 (fraction)Temperature: Q liq = 6820.202 STB/day, L(v) = 0.9757 (fraction)

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Figure A3

PAB 2094 Well Completions and Production Section B


Inflow/Outflow Curves for adonis 2_reservoir pressureSensitivity To: Layer pressure and Water cut

Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2248.345 6815.365 4770.755 2044.609 2.624 30.000 550.000 Stable2234.081 5773.815 4041.670 1732.145 2.223 30.000 550.000 Stable2223.418 4680.924 3276.646 1404.277 1.802 30.000 550.000 Stable2218.226 3512.997 2459.097 1053.899 1.353 30.000 550.000 Stable

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Inflow: 2800.000 psia and 30.000 per centOutflow: 2800.000 psia and 30.000 per centInflow: 2700.000 psia and 30.000 per centOutflow: 2700.000 psia and 30.000 per centInflow: 2600.000 psia and 30.000 per centOutflow: 2600.000 psia and 30.000 per centInflow: 2500.000 psia and 30.000 per centOutflow: 2500.000 psia and 30.000 per cent

Figure B1




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2317.239 5811.467 3777.453 2034.013 2.078 35.000 550.000 Stable2305.720 4759.481 3093.663 1665.818 1.702 35.000 550.000 Stable2300.431 3626.121 2356.978 1269.142 1.296 35.000 550.000 Stable2306.653 2346.712 1525.363 821.349 0.839 35.000 550.000 Stable

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Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2391.587 4793.699 2876.219 1917.479 1.582 40.000 550.000 Stable2386.665 3686.875 2212.125 1474.750 1.217 40.000 550.000 Stable2389.636 2481.361 1488.816 992.544 0.819 40.000 550.000 StableNo operating point

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Figure B3




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2473.818 3735.250 2054.387 1680.862 1.130 45.000 550.000 Stable2476.183 2568.705 1412.787 1155.917 0.777 45.000 550.000 StableNo operating pointNo operating point

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Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2540.150 2923.776 1501.593 1422.183 0.826 48.642 550.000 Stable2540.207 2923.099 1501.158 1421.942 0.826 48.645 550.000 Stable2540.260 2922.452 1500.737 1421.715 0.825 48.648 550.000 Stable2540.296 2922.027 1500.460 1421.566 0.825 48.650 550.000 Stable2540.351 2921.368 1500.035 1421.333 0.825 48.653 550.000 Stable2540.405 2920.717 1499.613 1421.104 0.825 48.656 550.000 Stable2540.459 2920.057 1499.186 1420.871 0.825 48.659 550.000 Stable2540.495 2919.632 1498.910 1420.722 0.824 48.661 550.000 Stable2540.549 2918.985 1498.490 1420.495 0.824 48.664 550.000 Stable2540.604 2918.323 1498.062 1420.260 0.824 48.667 550.000 Stable

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Inflow: 2800.000 psia and 48.642 per centOutflow: 2800.000 psia and 48.642 per centInflow: 2800.000 psia and 48.645 per centOutflow: 2800.000 psia and 48.645 per centInflow: 2800.000 psia and 48.648 per centOutflow: 2800.000 psia and 48.648 per centInflow: 2800.000 psia and 48.650 per centOutflow: 2800.000 psia and 48.650 per centInflow: 2800.000 psia and 48.653 per centOutflow: 2800.000 psia and 48.653 per centInflow: 2800.000 psia and 48.656 per centOutflow: 2800.000 psia and 48.656 per centInflow: 2800.000 psia and 48.659 per centOutflow: 2800.000 psia and 48.659 per centInflow: 2800.000 psia and 48.661 per centOutflow: 2800.000 psia and 48.661 per centInflow: 2800.000 psia and 48.664 per centOutflow: 2800.000 psia and 48.664 per centInflow: 2800.000 psia and 48.667 per centOutflow: 2800.000 psia and 48.667 per cent

fg

Figure B5

PAB 2094 Well Completions and Production Section C


Inflow/Outflow Curves for Copy of adonis 3_reservoir pressureSensitivity To: Layer pressure and Inside dia. of all well nodes

Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2407.703 4846.595 3392.616 1453.979 1.866 30.000 550.000 Stable2335.273 5741.421 4018.994 1722.426 2.210 30.000 550.000 Stable2280.058 6423.568 4496.497 1927.070 2.473 30.000 550.000 Stable2252.365 6765.700 4735.990 2029.710 2.605 30.000 550.000 Stable2239.735 6921.729 4845.209 2076.519 2.665 30.000 550.000 Stable

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Inflow: 2800.000 psia and all valuesOutflow: 2800.000 psia and 3.068 inOutflow: 2800.000 psia and 3.548 inOutflow: 2800.000 psia and 4.090 inOutflow: 2800.000 psia and 4.494 inOutflow: 2800.000 psia and 4.767 in

Figure C1





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Inflow/Outflow Curves for Copy of adonis 3_reservoir pressureSensitivity To: Water cut at Inside dia. of all well nodes = 4.767 in


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f

f

Inflow: 48.642 per centOutflow: 48.642 per centInflow: 48.645 per centOutflow: 48.645 per centInflow: 48.648 per centOutflow: 48.648 per centInflow: 48.651 per centOutflow: 48.651 per centInflow: 48.654 per centOutflow: 48.654 per centInflow: 48.658 per centOutflow: 48.658 per centInflow: 48.661 per centOutflow: 48.661 per centInflow: 48.664 per centOutflow: 48.664 per centInflow: 48.667 per centOutflow: 48.667 per centInflow: 48.670 per centOutflow: 48.670 per cent

fg

Figure C4


Nguyen The Thao


Nguyen The Thao


Nguyen The Thao



Section

11828

Figure

Section D

11828

Figure D.A.1

PAB 2094 Well Completions and Production Section D


Inflow/Outflow Curves for Hagis-CSensitivity To: Layer pressure

Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2053.212 8994.659 6296.261 2698.398 3.463 30.000 550.000 Above pump maximum2113.449 8411.803 5888.261 2523.541 3.239 30.000 550.000 Stable2159.678 7481.182 5236.827 2244.354 2.880 30.000 550.000 Stable2180.976 5944.045 4160.832 1783.214 2.288 30.000 550.000 Stable

0

900

1800

2700

3600

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft


Minimum Flow Through PumpMaximum Flow Through PumpInflow: 2800.000 psiaOutflow: 2800.000 psiaInflow: 2600.000 psiaOutflow: 2600.000 psiaInflow: 2400.000 psiaOutflow: 2400.000 psiaInflow: 2200.000 psiaOutflow: 2200.000 psia

Figure D.A.2




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2051.527 8996.397 6297.478 2698.919 3.464 30.000 550.000 Above pump maximum2116.458 8526.404 5968.482 2557.921 3.283 30.000 550.000 Above pump maximum2176.762 7915.649 5540.954 2374.695 3.048 30.000 550.000 Stable2229.910 7139.665 4997.765 2141.900 2.749 30.000 550.000 Stable

0

1000

2000

3000

4000

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft



Figure D.A.3




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2057.544 8997.929 6298.549 2699.379 3.464 30.000 550.000 Stable2077.273 7588.216 5311.750 2276.465 2.921 30.000 550.000 Stable2089.439 5866.317 4106.421 1759.895 2.259 30.000 550.000 Stable2092.730 3760.767 2632.537 1128.230 1.448 30.000 550.000 Below pump minimum

0

750

1500

2250

3000

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft



Figure D.A.4




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2055.834 8984.529 6289.170 2695.359 3.459 30.000 550.000 Stable2047.749 7027.080 4918.955 2108.124 2.705 30.000 550.000 Below pump minimum2050.727 5043.702 3530.591 1513.111 1.942 30.000 550.000 Below pump minimum2064.259 3154.252 2207.976 946.276 1.214 30.000 550.000 Below pump minimum

0

750

1500

2250

3000

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft



Figure D.A.5




Operating Liquid Oil Water Gas WaterPressure Rate Rate Rate Rate Cut GOR(psia) (STB/day) (STB/day) (STB/day) (MMSCF/day) (per cent) (SCF/STB)2053.055 8946.561 6262.592 2683.968 3.444 30.000 550.000 Below pump minimum2041.454 6913.356 4839.349 2074.007 2.662 30.000 550.000 Below pump minimum2034.341 4732.559 3312.791 1419.768 1.822 30.000 550.000 Below pump minimum2040.464 2465.330 1725.731 739.599 0.949 30.000 550.000 Below pump minimum

0

700

1400

2100

2800

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft



Figure D.A.6



Inflow/Outflow Curves for Hagis-CSensitivity To: Water cut


0

1000

2000

3000

4000

Pre

ssure

(psi

a) at T

ubin

g 5

, MD

5000.0

00 ft


i i i i i i

h

h

h

hh

h

Minimum Flow Through PumpMaximum Flow Through PumpInflow: 76.000 per centOutflow: 76.000 per centInflow: 76.222 per centOutflow: 76.222 per centInflow: 76.444 per centOutflow: 76.444 per centInflow: 76.667 per centOutflow: 76.667 per centInflow: 76.889 per centOutflow: 76.889 per centInflow: 77.111 per centOutflow: 77.111 per centInflow: 77.333 per centOutflow: 77.333 per centInflow: 77.556 per centOutflow: 77.556 per centInflow: 77.778 per centOutflow: 77.778 per centInflow: 78.000 per centOutflow: 78.000 per cent

hi

Figure D.A.7



Gas Lift Valve Positions - Hagis-C

Unloading ObjectiveValve MD TVD Casing Tubing TemperatureNo. Pressure Pressure

(ft) (ft) (psia) (psia) (degrees F) 1 2654.591 2649.780 1249.106 956.145 147.408 2 3196.366 3189.075 1209.389 1040.417 148.080

7500

5000

2500

0

-2500

Tru

e V

ertic

al D

epth

(ft)

3000225015007500Pressure (psia)


Objective Tubing Pressure: Q liq = 9000.000 STB/dayTemperature: Q liq = 9000.000 STB/dayUnloading Casing Pressure, 1200.000 psiaOperating Casing Pressure, 1091.329 psiaUnloading sequenceDesign operating valve

Figure D.B.1



WellFlo Performance Analysis for Hagis-COperating Rate vs Lift gas injection rate

0

2500

5000

7500

10000

12500

Opera

ting R

ate

(S

TB

/day)

107.552.50Lift gas injection rate (MMSCF/day)

Layer pressure = 2800.000 psiaLayer pressure = 2600.000 psiaLayer pressure = 2400.000 psiaLayer pressure = 2200.000 psiaLayer pressure = 2000.000 psia

Figure D.B.2



Inflow/Outflow Curves for Hagis-CSensitivity To: Water cut


0

900

1800

2700

3600

Pre

ssure

(psi

a) at P

roduct

ion L

iner, M

D 6

530.5

00 ft


g

ggg

g

g

g

g g g

f

f

ff

f

f

f

f

f

f

Inflow: 30.000 per centOutflow: 30.000 per centInflow: 71.111 per centOutflow: 71.111 per centInflow: 72.222 per centOutflow: 72.222 per centInflow: 73.333 per centOutflow: 73.333 per centInflow: 74.444 per centOutflow: 74.444 per centInflow: 75.556 per centOutflow: 75.556 per centInflow: 76.667 per centOutflow: 76.667 per centInflow: 77.778 per centOutflow: 77.778 per centInflow: 78.889 per centOutflow: 78.889 per centInflow: 80.000 per centOutflow: 80.000 per cent

fg

Figure D.B.3

answer haggis field

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