The haggis field increased water cuts

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)
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9	Reservoir	6530.5

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

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[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.

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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
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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 How Do You Meet My Professor’s Standards? We tailor your paper to your rubric—structure, tone, everything. Our writers decode academic expectations, and editors polish it to perfection, ensuring it’s grade-ready.

[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 What’s Your Editing Process? Upload your draft, tell us your goals, and our editors will refine it—boosting arguments, fixing errors, and keeping your voice. You’ll get a polished paper that’s ready to shine.

[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% Can You Suggest Paper Topics? Sure! Need ideas? We’ll pitch topics based on your subject and interests—catchy and doable. Pick one, and we’ll run with it, or tweak it together.	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 Do You Offer Rush Revisions? Yes! If you need quick edits, our team can turn it around fast—hours, not days—tightening up your paper for last-minute perfection.	1500	2000	2500	3000	3500	4000 Can You Provide Outlines First? Absolutely! We’ll draft an outline based on your topic so you can approve the plan before we write—keeps everything aligned from the start.
Oil production rate Q, bopd		7497	9789	11058	11945	12622	13144	13604 Can You Include Data Analysis? You bet! Need stats or charts? Our writers can crunch numbers and craft visuals, making your paper both sharp and professional.	14003
Increment of oil rate dQ, bopd	dQ=Q-4770	2727	5019	6288	7175	7852	8374	8834 How Do You Handle Long-Term Projects? We break it down—delivering each part on time with consistent quality. From proposals to final drafts, we’re with you all the way.	9233
Additional revenue R, 103 $	R=dQ*6 month*30 days*15 $/1000	7362	13551 Can You Write for Global Standards? Yep! Whether it’s UK, US, or Australian rules, we adapt your paper to fit your institution’s style and expectations perfectly.	16977	19372	21200	22609	23851 Is there a possibility of plagiarism in my completed order? We write every paper from scratch just for you, and we get how important it is for you to feel confident about its originality. That’s why we double-check every piece with our own in-house plagiarism software before sending it your way. This tool doesn’t just catch copy-pasted bits—it even spots paraphrased sections. Unlike well-known systems like Turnitin (used by most universities), we don’t store or report anything to public databases, so your check stays private and safe. We stand by our plagiarism-free guarantee to ensure your paper is totally unique. That said, while we can promise no plagiarism from open web sources or specific databases we check, no tech out there (except Turnitin itself) can scan every source Turnitin indexes. If you want that extra peace of mind, we recommend running your paper through WriteCheck (a Turnitin service) and sharing the report with us.	24929
Capital expenditures CAPEX, 103 $	CAPEX=(2000+section length)*850 $/1000	2125 When will my order be assigned to the writer? The moment you place your order, we jump into action to find the perfect writer for you. Usually, we’ve got someone lined up within an hour. Sometimes, though, it might take a few hours—or in rare cases, a few days—if we need someone super specialized. If no writers from your chosen category are free, we’ll suggest one from a lower category and refund the difference if you’d paid extra for that option. Want to keep tabs on things? You can always peek at your order’s status on your personal order page.	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.

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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

3. An earlier water breakthrough can occur
4. 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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