Course:- 28117Class:- 289033a

HERIOT-WATT UNIVERSITYDEPARTMENT OF PETROLEUM ENGINEERING

Examination for the Degree ofMEng in Petroleum Engineering

Production Technology 1b

Friday 23rd April 199909.30 - 12.30

NOTES FOR CANDIDATES

1. This is a Closed Book Examination.

2. 15 minutes reading time is provided from 09.15 - 09.30.

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

4. This Paper consists of 2 Sections:- A and B.

5. Section A & B:- Attempt 4 numbered Questions from 7 with at least 1 Question from eachSection

6. Marks for Questions and parts are indicated in brackets

7. This Examination represents 55% of the Class assessment.

8 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.

9. Answers must be written in separate, coloured books as follows:-

Section A:- BlueSection B:- Green

SECTION A

A1. Advanced wells and in particular horizontal and multi-lateral wells, can enhance the businesscase of a field development by any of 3 primary techno-economic drivers. What are these?

[3]

Multi-lateral well configurations can in the main be classified as stacked, opposed or planar, butthe selection of the optimum geometry must be based on the reservoir structure and flow characteristics. Discuss this statement giving examples to illustrate the application of the variousoptions - use sketches as appropriate.

[7]

A2. Two subsea well completion designs are shown in Figures 1 and 2 - review and compare each ofthese designs for the following applications:

(a) 10,000ft T.V.D. oil producer, normally pressured with a GOR of 400scf/bbl.[5]

(b) Water injection completion for the same reservoir.[5]

A3. The well shown in Figure 3 is an overpressured oil producer. If pressure buildup is experiencedin the 103/4 x 7 annulus at surface:

(a) What are the potential sources of the pressure?[3]

(b) What method(s) and tools could be used to identify the cause of the leakage(s)?[4]

(c) What corrective measures would you propose for the causes identified in (b) above?[3]

Typical InjectionCompletion Schematic

Typical ProducerCompletion Schematic

Tubing hanger

3.812" RQ' Landing nippleinjection valve

4 1/2 " 2.6lb/ft new vam tubing

4 1/2 " alloy 'MMG' SPM

4 1/2 " 12.5 lb/ftvam tubing

Seal unit

4 1.2"PBR

Tubing anchor latch

Millout extension

Wireline re-entry guide

2.750" XN nipple

2.313' XN' No-Go landing nipple

3.1 2/9' /AM perforated at

9 5/8' SAB-3 HYD set permanent packer

3.812' 'XN' No-Go lancing nipple

PBTD

PERFS

PBTD

PERFS

Annuluscheckvalve

Annuluscheckvalve

4 1/2" TRCHSV

4 1/2" 12,6 lb/ft VAM J55 Tubing

4 1/2" Alloy 'MMG' SPM

4 1/2" PBR

9 5/8" 40lb/ft NBS vam casing

9 5/8" SAB-3' HYD set permanentpacker O/W millout extension

Tubing anchor latch

Seal unit

3.912" 'XN' No-Go landing nipple

3.588" RN' No-Go landing nipple

2.756" XN' No-Go landing nipple

2.313" XN' No-Go landing nipple

Wireline re-entry guild

Figure 1 and 2

Perforations

7" CRA production liner

7" TR SSV

7" CRA tubing

9 5/8" liner

A-Ryte sealassemblew/ anochor latch

Liner top isolation packer

10 3/4" tie -back

Liner hanger

Liner hanger w/lower swal bore

9 5/8" shoe @10700'Liner top isolation packerw/ upper seal bore andBi-directional slipes and w/ bulletseals on lower seal assembly

Full bore nipple profile

13 3/8" shoe @ 5700'

7" shoe @ 14500'

Figure 3

SECTION B

B4.(a) Sketch the main components of a 3 phase (gas/oil/water) horizontal separator and briefly (one

sentence) explain the function of each of the main components.[8]

(b) Indicate how the export of the oil/water/gas flows are controlled and why the outlets are situatedat your indicated locations.

[3]

(c) Stokes Law (below) describes the velocity of separation of one liquid from another

V kd d cc

=

2 ( )

An oil/water 2-phase separator has been in use in a field for many years. The main producingzone (35 API, saline formation water) is now depleted and it is proposed to produce a shallower,subsidiary zone (17 API oil, fresh formation water). The required data are given in Table 1.You are required to advise management as to whether the existing separator capacity is sufficientwhen the subsidiary zone is producing at 1% and 75% water cut.

Fluid properties at Producing zoneseparator conditions Main sand Subsidiary sandOil viscosity cp 2.5 40 density/gcm-3 0.85 0.95Water viscosity cp 0.9 0.7 density/gcm-3 1.1 0.99

N.B. The production rate from the subsidiary zone is only 10% of that achievedfrom the main zone.

[9]

(d) An assumption has to be made in the above calculations. Indicate its impact on the conclusionreached in the unfavourable (separator capacity insufficient) case and indicate two remedialactions that could be taken.

[5]

B5.(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.[8]

(b) This field has been declared marginal and can only be economically developed with subseawells. 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.

[5]

(c) The field is developed with an oil well producing through a gravel pack. The (Darcy) skin due topresence of the gravel pack and the resulting pressure drop (Ps) may be calculated from:

Sk k Ld n

and

P qBKL

S Dqd n

or

P q S Dqd n

g

s

s

=

= +

= +

96

141 2

0 00539

2

4 2

4 2

( / )

.

.

(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 4shots/ft.

[4]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 dropof 374 psi. You are required to advise management as to whether the next well should becompleted with:

Case Cost Stort 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.[5]

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

Well production (q) 2500 STB/DTotal production height (h) 23 ftReservoir permeability (k) 578 mDOil viscosity ( m o) 0.310 cpFormation volume factor (Bo) 1.636 bbl/STB20-40 mesh gravel pearmwability 120,000 mDPerforation Penetration (L) 6 inPerforations Diameter (d) 0.5 inPerforation Density (n) 4 shots/ftNon-Darcy (turbulence factor) (D) 0.01

B6.(a) List up to 6 key features for both Rod Pumps and Gas Lift that form the basis of the following

statement:

Worldwide, 85% of Artificial Lift equipment installed is rod pumps. This is mainly in stripperwells while gas lift is the most popular artificial lift technique for higher rate wells.

[6]

(b) Most gas lift fields have insufficient gas to lift all the wells at their (technical) maximumproduction. Briefly describe the process of optimal allocation of available lift gas; mentioningthe key economic parameters involved.

[6]

(c) Design a gas lift installation for the following conditions:

Tubing 3.958 inRequired Production Rate 3000 STB/dayOil Cut 100%Gas Specific Gravity 0.65Average Flowing Temperature 150FReservoir Productivity Index 4 bpd/psiReservoir Depth 10,000 ftReservoir Pressure 3400 psiLift Gas Injection Gradient 20 psi/1000 ftMinimum flowing tubing head pressureto transfer fluids to facility 250 psiDead Oil Density 35 API or 0.368 psi/ftBrine Density 0.44 psi/ftLift Gas Injection Rate 3,000,000 scf/d

A pressure traverse curve is provided as Figure 4.

Assume that the well is closed in with dead oil in the tubing and brine in the casing/tubingannulus.

(i) does this well require artificial lift to produce?[2]

(ii) what depth should the gas lift valve be installed in a single valve lift installation in order toachieve the required production?

[6]

HINT: Note that the relevant portions of the pressure traverse curve can be approximated bystraight lines.

(iii) what is the minimum surface gas injection pressure to kick the well off in the configurationdescribed?

[4]

(iv) how does this change if dead crude oil was present in the casing/tubing annulus instead ofbrine?

[1]

B7.(a) Briefly contrast the generalised selection criteria for matrix acidising and fracturing treatments

when considering carrying out a stimulation treatment on a well.[5]

(b) List 2 sources of formation damage encountered during drilling and completion operations and 3damage sources during production operations. Briefly indicate how the fluid selection for a(matrix) removal treatment will be influenced by the damage source (examples may clarify youranswer).

[6]

(c) A well completed on 40 acre spacing (re = 745 ft) has a damaged region extending 1 ft beyondthe wellbore (rw = 0.328 ft).

The Hawkins formula may be used to calculate the skin due to formation damage:

S kk

r

rd

o

d

d

w

=

1

while the productivity ratio (Ji/Jd) of the well with and without the above formation damage isgiven by:

JiJd

rr S

rr

e

w

e

w

=

+

ln

ln

Use the above to illustrate the statement:

Formation Damage reduces well productivity greatly while the stimulation effect of increasingthe near wellbore permeability above the initial value has limited effect.

HINT : estimate the relative well productivity with 95%, 75%, 50% formation damage and10 times increase in near wellbore formation permeability.

[6]

(d) Your service company has designed the following fracturing treatments:

Wellbore radius (rw): 0.328 ftReservoir height: 100 ft; bounded by competent shalesReservoir Permeability: 0.1 mDProppant available: 300,000 lbDesign Fracture Conductivity (kf*w): treatment A

- 1500 mD.ft at 4 lb/ft2 proppant loading

treatment B- 850 mD.ft at 2 lb/ft2 proppant loading

(i) Use the accompanying graph from Cinco-Ley and Samiengo to advise management as towhether treatment A or B will give the highest well productivities.

[6]

(ii) Why would you expect one of these treatments to be preferred?[2]

0.1 1

1

2

010 100 1000

FCD =

S f +

ln

(x f/r w

)

Kf.wK.xf

End of Paper