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The haggis field increased water cuts

Disclaimer: This work has been submitted by a student. This is not an example of the work written by our professional academic writers. You can view samples of our professional work here.

Any opinions, findings, conclusions or recommendations expressed in this material are those of the authors and do not necessarily reflect the views of UK Essays.

Published: Mon, 5 Dec 2016

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 nine components and nodes:

Node No.

Component /Node Name

Bottom Depth, MD (ft)

1

Xmas tree

0

2

Riser

350

3

Wellhead

350

4

Tubing 5.5

850

5

SSS Valve

850

6

Tubing 5.5

4000

7

Tubing 5

5600

8

Liner

6530.5

9

Reservoir

6530.5

The attached Figure A1 (screenshot of the WellFlo model nodes and components) illustrates the nodes used in the WellFlo model.

[5%]

2) In flow simulations on WellFlo, Haggis-3 was modelled using the following correlation: Hagedorn and Brown correlation (std) [STD/MOD].

[2%]

There are two main reasons why this correlation was chosen:

a) Hagedorn and Brown correlation has the best matching with real data given on the pressure versus depth plot.

The attached Figure A2 supports this reasoning.

b) Hagedorn and Brown correlation is widely used for flow calculations. The well Haggis-3 is not significantly deviated, that is why the standard Hagedorn and Brown correlation should be used. Therefore this flow correlation includes Griffin correlation considering friction forces and in-situ phase fraction. Moreover it is based on the field’s data and also takes into account the presence of three phases.

[ 6.5 %]

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 (4 graphs: one fixed WC per each graph): B1, B2, B3, B4, and their results are summarised in Table B-1 below.

P Res.

WC

2800

2700

2600

2500

psia

30%

4770

4040

3275

2462

35%

3780

3085

2352

40%

2864

2203

45%

2040

Table B.1: Haggis-3 Oil Production Forecast

[5%]

Since artificial lift can not 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 48,5%, and at an oil production rate of 1508 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

Base Case

48.5%

4772

[2.5%]

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:

  1. It is used to prevent water breakthrough.
  2. Plugging off watered layers reduces produced fluid density in the wellbore to lower operating expenditures.

Disadvantages:

  1. This operation can block pay zone and requires time and additional expenses.
  2. It can lead to skin factor increasing due to slurry invasion in the reservoir and partial exposure .

[4%]

Section C:

C.1: Acidising

a) Assuming that acidising restores the original rock permeability, then after acidising Haggis-3 the maximum water cut at which the well can produce economically is 50.5%. (See figure C 1.1)

Scenario

Maximum Economic Water Cut

Oil Production Rate

@ 30% Water Cut

Acidising

50.5%

5637

[2.5%]

b) A production model of well Haggis-1 is expected to show that Haggis-1 will produce economically at the maximum water cut of 50.5% after acidising.

What are the implications of this if it is decided to carry out a campaign in which the Haggis wells are to be acidised in a certain order?

Modelling of acidizing for wells Haggis-3 and Haggis-1 shows a positive effect which represents some increasing in the oil production rates and maximum economic water cuts. It is recommended to carry out acidizing treatment in the well Haggis-1 because of this well has a greater skin factor than another one.

[2.5%]

C.2: Deviated and Horizontal Wells

a) Sidetracking Haggis-3 to a 400ft horizontal well running through the middle of the reservoir is investigated in figure C 2.1. While sidetracking Haggis-3 to a 75° deviated well is investigated in figure C 2.2. The results are summarised in the table below.

Option

Scenario

Maximum Economic Water Cut

Oil Production Rate @ 30% Water Cut

C2.a1

400ft Horiz.

52.5%

6747

C2.a2

75° Deviated.

53%

7161

[5%]

b) To match the performance (oil rate) of a 75° deviated well; Haggis-3 will have to be sidetracked to a horizontal well with a horizontal length of 450 ft. (see Figure C 2.3) [2.5%]

c) Given the engineering and economic factors and assumptions adopted by the management for drilling horizontal wells Table C.2 below was constructed. Sensitivity to effective length is presented in Figure C 2.4.

Horizontal Length

Parameter & Unit

Formula

500

1000

1500

2000

2500

3000

3500

4000

Oil production rate Q, bopd

7497

9789

11058

11945

12622

13144

13604

14003

Increment of oil rate dQ, bopd

dQ=Q-4770

2727

5019

6288

7175

7852

8374

8834

9233

Additional revenue R, 103 $

R=dQ*6 month*30 days*15 $/1000

7362

13551

16977

19372

21200

22609

23851

24929

Capital expenditures CAPEX, 103 $

CAPEX=(2000+section length)*850 $/1000

2125

2550

2975

3400

3825

4250

4675

5100

Operating expenditures OPEX, 103 $

OPEX=dQ*6 month*30 days*8 $/1000

3926

7227

9054

10332

11306

12058

12720

13295

Profit (Terminal Cash Surplus) TCS, 103 $

TCS=R-CAPEX-OPEX

1311

3773

4947

5640

6068

6301

6455

6533

PIR (Profit to Investment ratio)

PIR=TCS/CAPEX

0,616

1,479

1,663

1,658

1,586

1,482

1,380

1,281

(In the space above, enter the parameter, formulas used and intermediate working)

Table C.2: Economic analysis of sidetracking Haggis-3.

Table C.2 indicates that the optimum horizontal section length for Haggis-3 is 1500ft.

[15%]

d) If Haggis-3 is sidetracked to the optimal horizontal length, then the maximum water-cut at which the well will produce economically is 57.5%. (see Figure C 2.5)

Scenario

Maximum Economic Water Cut

Oil Production Rate @ 30% Water Cut

Horizontal Well

57.5%

11058

(Use this result to compare the benefits from this project to the other proposed projects, and as a basis for your recommendations in section D)

[2.5%]

C.3: Artificial Lift Options

C.3.1 Electrical Submersible Pumps

a) The most suitable pump of Haggis-3 given the present conditions is HC 9000. Figures C 3.1.1, C 3.1.2, C 3.1.3, C 3.1.4, C 3.1.5 show the performance plot of the pumps.

This pump is the optimum choice because

HC 9000 was chosen because of it has the best parameters in comparison with other pumps. An operating rate of this pump coincides with an operating range in the given well conditions. Also the pump shows maximum efficiency and has less number of stages.

[2.5%]

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 to deplete. Sensitivity of the model to declining reservoir pressure is illustrated by the following figures: C 3.1.6, C 3.1.7, C 3.1.8, C 3.1.9, C 3.1.10. The results are summarised in Table C.3 below.

P Res.

Pump

2800

2600

2400

2200

psia

GC 8200

6300*

5848

5096

3887

HC 7000

6310*

5947*

5482

4882

HC 9000

6277

5212

3913

2314*

KC 12000

6287

4849*

3425*

2016*

KC 15000

6241*

4741*

3167*

1533*

Table C.3: Haggis-3 Oil Production Forecast with ESP installed,

* denotes rate outwith the operating range of the pump (e.g. 5923* – outwith, but 5923 -in the range).

According to Table C.3 the optimum ESP for Haggis-3 for declining reservoir pressure is GC 8200, at a water cut of 30%.

This pump is the optimum choice because

GC 8200 shows the most stable work during pressure depletion. Furthermore this pump operates with maximum production rates.

[5%]

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%. (see Figure C 3.1.11)

Scenario

Maximum Economic Water Cut

Oil Production Rate

@ 30% Water Cut

Optimised ESP

76%

6300

[2.5%]

C.3.2 Gas Lift Design

a) The gas lift design for Haggis-3 given the present conditions is shown in Figure C 3.2.1.

The required gas injection rate for the design production rate is 1.352.

The purpose of the operating valve is to allow access for gas injected from the annulus into the tubing to reduce fluid density hence decrease hydrostatic pressure. It should be OPEN when assessing the gas lift design .

The purpose of the unloading valves is to decline injection pressure during unloading process. It should be CLOSE when assessing the gas lift design.

These should be OPEN/CLOSED when assessing the gas lift design.

[6%]

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 C 3.2.2 where the operating rate is plotted against the gas injection rate. These results are summarised in table C.4 below (to the nearest 0.5 MMscf/d).

P Res.

2800

2600

2400

2200

2000

Psia

Technical Optimum injection rate

6

5.5

5

4.5

6

MMscf/day

Table C.4: Technical Optimum gas injection rate for Haggis-3.

The criteria used to choose the (actually) optimum gas injection rate are:

The optimum injection rate of gas was chosen in order to reach maximum operating rate.

Higher injection rates do not improve production as the reservoir pressure declines because

Friction forces exceed hydrostatic pressure reduction. [6%]

c) After setting the optimum gas injection rate for 2800 psia the maximum water cut at which the well will produce economically is 74.5%. (See figure C 3.2.3).

Scenario

Maximum Economic Water Cut

Oil Production Rate

@ 30% Water Cut

Optimised Gas Lift

74.5%

7294

[2.5%]

C.4: Lowering the Xmas Tree Pressure

a) If the production facilities on the Haggis platform can be modified to allow the Xmas tree pressure of Haggis-3 to be lowered to 100 Psia, then the maximum water-cut at which the well will produce economically will become 73.5%, and the oil rate value at 30% water cut is 9297 BOPD. (See Figure C4)

[2.5%]

b) Two advantages and two disadvantages of this scheme are

Advantages

  1. Production rate increases due to pressure drawdown decreasing
  2. Operating expenditures reduce

Disadvantages

  1. An earlier water breakthrough can occur
  2. Unstable flow regimes may be developed

[4%]

Section D:

1) Table D.1 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

48.5

4772

Acidising

50.5

5637

75° Deviated Well

73

7161

Optimum Horizontal Well

52.5

6747

Optimum ESP

76

6300

Optimum Gas Lift

74.5

7294

Lowering Xmas Tree Pressure to 100 psia

73.5

9297

Table D.1: Haggis-3 simulation summary

2) 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 lowering Xmas tree pressure project /none of the projects investigated above] because it provides the best oil production rate and maximum economic water cut, also this project is not required high additional expenses.

[5%]

3) A number of risks and uncertainties have been overlooked in this assessment since only the maximum water cut at which the wells will flow at an economic rate and the oil rate at 30% wc have been used as the ranking criteria for the above projects. These risks and aspects add to the uncertainty of achieving the results on which your recommendation was based. As the Haggis field team leader it is your duty to report and account for these risks to management.

Complete Table D.3 below which should identify three major risks/aspects that have been overlooked by this assessment. Briefly explain how each one could add to the uncertainty of the assessment and prescribe steps that need to be taken to account for their effects.

Risk/Uncertainty

How this adds uncertainty to above assessment?

Steps that can be taken to account/minimise this uncertainty

1) Geological

Geological structure has influenced on the fluid production. The presence of the reservoir heterogeneity and impermeable faults can reduce oil production.

Accurate geological analysis is needed to provide. Core sampling, well logging and complex well test are required to be carried out for all necessary information collecting.

2) Technical

The sophisticated equipment is necessary to be installed. This process accompanied by high risks and difficulties, also additional costs take place.

Analysis of the equipment and volumes of the produced fluids, calculations of the capacities for those volumes, required electrical power, operating treatments has to be done.

3) Economical

Risks of oil price changing and additional expenses take place.

Economic calculations including all possible variations of oil prices and additional operating expenditures considering all projects are necessary to be completed.

Table D.3: What else (apart from maximum economic WC and oil rate @ 30% WC) should be considered in order to make the right choice?.


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