Course Code: 28117

INSTITUTE OF PETROLEUM ENGINEERINGHERIOT-WATT UNIVERSITY

DEGREE OF MSc / DIPLOMA IN PETROLEUM ENGINEERING

PRODUCTION TECHNOLOGY - Module G11PT

Thursday 2x April 20xx, (3 hours 15 minutes)

This is a closed book examination

1. This is a Closed Book Examination.

2. Examination Papers will be marked anonymously. See separate instructions for completion of Script Book front covers and attachment of loose pages. Do not write your name on any loose pages which are submitted as part of your answer.

3. This Paper consists of 1 Section:- Attempt 4 numbered Questions from 6

4. Marks for Questions and parts are indicated in brackets

5. This Examination represents 80% of the Class assessment.

6. State clearly any assumptions used and intermediate calculations made in numerical questions. No marks can be given for an incorrect answer if the method of calculation is not presented.

Question1

(a) You are the Production Technologist responsible for completion of a well in a new field. Briefly list what techniques you would use to help you in the decision as to whether sand control measures need to be installed.

N.B. A core has been taken across the pay zone. [6] (b) This field has been declared marginal and can only be economically developed with subsea wells. Briefly describe how this will affect your decision:

(i) On the need for the installation of sand control measures and (ii) Type of sand control measures installed. [4] (c) The field is developed with an oil well producing through a gravel pack. The (Darcy) skin due to presence of the gravel pack and the resulting pressure drop (∆Ps) may be calculated from:

Sk k L

d nand

PB

KLS

Dqd n

or

P q SDq

d n

g

s

s

=( )

= +

= +

2

4 2

4 2

96

141 2

0 00539

µ

/

.

.

∆

∆

q

(see Table 2 for definition of the parameters and numerical values) Calculate the (Darcy) skin value (S) and the resulting pressure drop for a perforation density of 4 shots/ft. [3]This is the target, allowable pressure drop in the well.

(d) Well testing found that the turbulent (non-Darcy) resulted in an unacceptably high pressure drop of 374 psi. You are required to advise management as to whether the next well should be completed with:

Case Cost Shot Density DiameterA Low 12 shots/ft 0.5 inB High 4 shots/ft 1.0 in

and whether it will meet the target, allowable pressure drop. [4]

(e) Briefly comment on which case you would have expected to give the better inflow, and why. [3]

Table2

Well Production (q) 2500 STB/DTotal Production Height (h) 23 ftReservoir Permeability (k) 578 mDOil Viscosity (µo) 0.310 cpFormation Volume Factor (Bo) 1.636 bbl/STB20-40 Mesh Gravel Permeability 120,000 mDPerforation Penetration (L) 6 inPerforation Diameter (d) 0.5 inPerforation Density (n) 4 shots/ftNon-Darcy (turbulance factor) (D) 0.01

Question2

2(a) “Advanced” wells and in particular horizontal and multi-lateral wells, can enhance the business case of a field development by any of 3 primary techno-economic drivers.” What are these? [3] 2(b) Draw a simple sketch of the Composite Production System, indicating clearly the systems start and end points [4]

2(c) Write one or two basic equations to quantify the “Total System Pressure Drop” [4]

2(d) Wells producing from : i) a solution gas drive reservoir and ii) a water drive reservoir where there is a large aquifer present the Production Technologist with differing challenges when he manages the well’s performance.

Draw a simple sketch to compare and contrast reservoir performance of these two drive mechanism types [4]

2(e) For each of the above reservoir types, list 2 of the resulting Production Technology challenges that will control the well design and Production operations Policy. [5]

Question3

3(a) A recommendation is required to choose a perforating system for a completion in a formation with a variable rock strength – ranging from a weak Unconfined Compressive Strength (Cf = 2,000 psi) to a strong value (Cf = 18000 psi).

Calculate the expected perforation lengths for the following perforating guns to be run in a 9 5/8 in. OD casing placed inside a 12 1/4 in. drilled hole.

Gun Type API RP 19B Test Penetration

in. Wireline through tubing gun 10 in. 7 in. Tubing conveyed perforating gun 43 in. 31/2

N.B. API RP 19B data available for these guns can be converted to downhole performance usingthe equation:

Pf=Pt * e0.086*(Ct – Cf)/1000

Where Pf is the expected penetration (inches) in formations with an Unconfined Compressive Strength, Cf (psi) and Ptis the API RP19B test penetration in the test formation (Unconfined Compressive Strength, Ct = 6,500 psi) [3]

3(b) Drilling of the strong formation (Cf = 18,000 psi) results in a hole with the same diameter as the drill bit. By contrast, drilling of the weak (Cf = 2,000 psi) formation resulted in an enlarged hole (or “washout”). The hole diameter has increased by 8 inches.

Which perforating guns do you recommend and why? [3]

3(c) A new drilling mud with a low leak-off rate is chosen for the weak formation. This mud creates a zone 2 in. deep around the wellbore of Formation Damage or reduced permeability (permeability is reduced to 5% of the original value). Also, a better quality hole is drilled; the washout (hole enlargement) is now only 3 in. greater than the drilled hole diameter.

Does this alter the perforating gun you recommend? Explain the reasoning behind your answer. [3]

3(d) Briefly list 4 major advantages & 3 disadvantages of using a tubing conveyed perforating system. [7]

3(e) Briefly list 3 different techniques used to detonate a tubing conveyed perforating gun. [4]

Question4

4(a) Seal assemblies, surface controlled, sub-surface safety valves, side pocket mandrels, sliding side doors, perforated joints and landing nipples and among completion string components. Briefly explain them and their roles. [6]

4(b) Tubing flow without annular seal is one of the options available for flow conduit selection. Describe the advantages and disadvantages of this technique (use sketches). [4]4(c) A well is drilled in an unconsolidated formation. Sand production is expected in particular after water breakthrough. The reservoir produced 15,000 bbl/day during DST with a drawdown of 500 psi. The reservoir and well data are as followings:

Oil gravity 35o APIBottom hole temperature 100o CTop of the reservoir 6,500 ftThickness of the pay-zone 200 ftGOR 500 scf/bblH

2S 30 ppm

CO2

1 mole%Total Depth Drilled 6,800 ftReservoir pressure 4,500 psiaBubble point pressure 3,000 psiaKv/Kh 0.15

Identify the available options for completion.

I. What will you select for the bottom hole completion and flow conduit and why? [4]

II. After 2 years of production, the reservoir pressure has dropped to 3,500 psia and the water cut has increased to 30%, resulting in significant reduction in the well flow rate. Well test analysis shows that the aquifer is not very active and reservoir pressure drop is likely to continue. Suggest a workover strategy and justify your answer. [3]

III. Is it possible to avoid/delay this workover by modifying initial tubing design? How?

[3]Question5

5(a) Describe the role of packers and their components (use sketches where necessary) and their various setting mechanisms. [6]

5(b) Describe the available options for completion configuration in a dual zone reservoir (use sketches), assuming no fluid mixture. Mention their advantages and disadvantages. [6]

5(c) Field “A” is an offshore field in approximately 1,000 ft water. The exploration wells proved the existence two reservoirs with similar fluid compositions. The top of the two reservoirs have been identified at 6,000 and 7,500 ft.

Gas injection is required for achieving optimum production rate from both reservoirs. However, due to a low burst pressure rating of the top 1,000 ft of the casing, it is not possible to inject gas through annulus.

I. Your task is to develop an outline completion string for the oil production wells, producing from both reservoirs. It is necessary to have flexibility in selective production and/or stimulation of individual reservoirs. Identify key design features and the reasons for their selection. [4]

II. Identify the components required for the completion configuration. Draw a sketch of your proposed completion configuration. [4]

Question6

The Alpha oil reservoir is a small offshore field which is currently being considered for development. It is likely that the field will require 3-5 production wells. Currently the use of a small fixed jacket is preferred with the possible use of a subsea template/completion if further delineation causes a significant downsizing in reserves.

The general conditions for the field are shown in Table 1 with the fluid and reservoir characteristics shown in Table 2 and 3 respectively. A projected casing schedule is shown in Table 4.

The reservoir consists of a consolidated to friable, heterogeneous, fine grained sandstone withlimited clay content. It is slightly overpressured and overlain by a thin (150 ft) shale layer. It is anticipated that the well deliverability will require the use of 41/2” OD tubing. The reservoir is expected to be produced by depletion drive; hence well deliverability will decline almost immediately.

Use short notes and sketches to answer the following questions.State all assumptions and give reasons where possible.

1. For this particular development, discuss the options for the bottomhole completion technique; namely, cemented and perforated liner; screen or openhole. Discuss briefly what you recommend and why? [5]2. What would be your objectives when selecting a drill-in fluid for the 6 inch hole when drilling the reservoir section [5]3. Provide a sketch of a conceptual configuration for the completion of the oil production wells. Specify:

a) Key components and your reasons for their selection

b) Approximate setting depths [7]

4. The wells are to be drilled overbalanced. How would you lower the bottomhole pressure to initiate flow? [3]

Water depth 180 ftLocation 100 miles offshore NE ScotlandAdjacent existing platform is 8 miles to the SWNo. of wells projected 3-5Reserve estimate 47 x 106 STBAquifer NoneGas cap at initial reservoir pressure None

Table 1 - Field Location and General Data

Oil density 31º APIOil viscosity at reservoir conditions 7 cpGOR 420 scf/bblH2S concentration 5 ppmCO2 concentration 8%Bubble point of crude oil 2,800 psia

Table 2 - Reservoir Fluid Data

Top of oil column 5,900 ft TVDSSThickness of reservoir sand 140 ftBottom hole temperature 180°FPermeability 80-270 mdAverage permeability 170 mdInitial reservoir pressure 2,900 psia at 5,900 ftkV/kH = 1.0 (approx)

Table 3 - Reservoir Data

Table 4 - Provisional Casing Schedule

Hole Size Casing Size Setting Depth (TVDSS) From To26” 20” Surface 1,000 ft17 1/2” 13 3/8” Surface 2,600 ft12 1/4” 9 5/8” Surface 4,700 ft8 1/2” 7 4,200 ft 5,950 ft6” option 1. 4 1/2” 5,500 ft 6,150 ft option 2. 4” screen option 3. Open hole