lesson 13 well engineering

8/12/2019 Lesson 13 Well Engineering

1/74

Harold Vance Department of Petroleum Engineering

Lesson 13

Well Engineering

Read: UDM Chapter 5

Pages 5.1-5.41

PETE 689Underbalanced Drilling (UBD)


2/74


Well Engineering

Circulation Programs

Circulation Calculations (air, gas, mist).

Circulation Calculations (gasified liquids).


3/74


Wellhead design.Casing design.

Completion design.

Well Engineering


4/74


5/74



Fundamentally no different than for

balanced or underbalanced situations.Basis for hydraulics design:

Guarantee adequate hole cleaning.

Ensure vertical transport of cuttings inannular zones where velocities are reducedbecause of change in annular area.


6/74



Maintain wellbore stability.

Mitigate formation damage andto operate within the pressureand rate constrains of thetubulars and the surfaceequipment.


7/74


Circulation Calculations

(air, gas, mist)

Angel's approximate method:

Collect the required information for thecalculations. This includes:

Drilled hole size (inches).

OD of the drill pipe (inches).Drilling rate (ft/hr).Depth (thousands of feet).


8/74


In the table Appendix C, determine Qoand N. Interpolate values as required.Calculate the required circulation rate

using:

Q= Qo+NH

Qo, N...parameters from Appendix C.H.........depth in thousands of feet.Q.........circulation rate (scfm).


(air, gas, mist)


9/74



(gasified liquids)

Approximate volumes andpressures, for gasified liquids, canbe determined using thetechniques described previously.

More precise predictions requireadded levels of sophistication.


10/74


Wellhead Design

Low Pressure

Gas, mist, and foam drilling arenormally utilized on lowpressure wells.

Low pressure wells requiresimple wellhead designs.

Some operators opt for a simpleannular preventer alone.


11/74


However, a principal manufacturer ofsuch equipment strongly cautions that

such use exceeds the design criteria ofthis equipment.

The minimum setup should consist of arotating head mounted above a tworam set of manually-operated blowoutpreventers, consisting of a pipe ramand a blind ram.

Wellhead Design

Low Pressure


12/74


Slightly higher pressure systems

should also have an annularpreventer between the rams andthe rotating head.

For added safety the BOP system

should be hydraulically operated.Working pressure of these rotating

heads is ~400-500 psi MWP.

Wellhead Design

Low Pressure


13/74


14/74


Blind rams should be installed in thebottom set of rams (when a two ramsystem is used).

Sometimes a third set of rams (piperams) is utilized.

In this case the RBOP is installed atopan annular preventer.

The blind ram is placed between thetwo sets of pipe rams.

Wellhead Design

High Pressure


15/74


The lowermost set of rams shouldbe installed directly atop the

wellhead (or an adapter spool ifnecessary).

You should never place any choke orkill lines below the lowest set of

rams.If one of these lines cuts out, there

is no way to shut in the well.

Wellhead Design

High Pressure


16/74


Care must be taken to utilize a rigwith a substructure high enoughso that the wellhead is not belowground level, with space enough

to put the entire desired BOPstack below the rig floor.

Wellhead Design

High Pressure


17/74


Snub drilling and CT drilling have BOP

stacks that allow tripping at muchhigher pressures than other forms ofUBD (routinely up to 10,000 psi).

Snubbing and CT units can be used for

UBD at pressure that cannot bemanaged by conventional surfaceequipment.

Wellhead Design

Snub Drilling


18/74


Casing Design

Casing design for UBD is notsignificantly different than

conventional.

With air drilling, the casingtension should always be design

with no buoyancy considered.No difference in burst design

usually


19/74


20/74


Casing Design

Corrosion Control

For fluid filled wells, corrosion is usuallynot considered when drilling.

Corrosion is not a factor when drillingwith dryair.

Corrosion must be considered when

drilling with mist, foam, or aeratedfluids.

Corrosion inhibitors should be added tothe system.


21/74


Casing Design

Casing wear

Casing wear is accelerated withgas drilling.

This is due to less lubrication bythe drilling fluid.

Most air drilled holes are drilled

faster and less time is spentrotating.

Doglegs add to casing wear.


22/74


23/74


UB Completion TechniquesRunning production casing, liners,

slotted liners and other toolsunderbalanced.

Controlled cementing of productioncasing or liners.

Running production tubing anddownhole completion assemblies.

Perforating underbalanced.


24/74


Running Casing and Liners UBIf the completion is not open hole,

casing or liners must be run.

Surface pressures are usually reducedby bullheading a heavier fluid downthe annulus.

This fluid may be more dense thanthat with which the well was drilled,but still must be light enough toprevent overbalance.


25/74


For casing and un-slotted liners,the well is usually allowed to flow

while running the casing.This helps to prevent excessive

surge pressures.

A snubbing unit might be requiredto get the casing started in thehole.

Running Casing and Liners UB


26/74


27/74


Cementing Pipe UB

If casing is run underbalanced,

cementing should also beaccomplished underbalanced.

The hydrostatic head of the slurry-HSP can be reduced by entraininggas, or by reduced densityadditives.


28/74


No matter the productioncasing/liner design, productionwill almost always be required.

With cemented casing andliners, the tubing can be runconventionally.

Running Tubing UB


29/74


Tubing can be run underbalanced in

a number of ways:Snubbing.

CT.

Diverting flow.Setting a packer above the open

zone with a temporary plug.

Running Tubing UB


30/74


Bit Selection

The bit selection process:

1. Assemble offset well data.

2. Develop a description of the well tobe drilled.

3. Review offset well bit runs.

4. Develop candidate bit programs.

5. Confirm that the selected bits areconsistent with the proposed BHAs.

6. Perform an economic evaluation, toidentify the preferred bit program.


31/74


32/74


Develop A Description of

The Well to Be Drilled

Characterize the proposed holegeometry:

Hole size.

Casing points.Trajectory.


33/74


Outline the anticipated values ofrock hardness and abrasivity at all

depths.

Sonic travel time logs givequalitative indications of formation

hardness.Low travel times - high rock

compressive strengths




34/74


Abrasivity is more difficult to quantify

It is possible to form a qualitativeassessment of the rockspotential forabrasive bit wear.

Abrasiveness is related to:

Hardness of its constituent minerals.

Bulk compressive strength.

Grain size distribution.

Shape.




35/74


Make note of any formations that

may have a special impact on bitperformance.

Divide the well into distinct zones

Each zone corresponds to asignificant change in formationproperties or drilling condition.




36/74


Review Offset Well Bit Runs

Determine what bits were used todrill through each formation likely to

be penetrated.

Identify which bit gave the best orworst performance.

Look at the bit grading.

Use the bit performance to inferformation hardness and abrasivity.


37/74


38/74


Roller Cone BitsKey design considerations for roller

cone bits are:

Cutting structure.

Bearing.

Seal types.

Gauge protection.

Should be matched to a formationsanticipated hardness and abrasivity.


39/74


Fixed Cutter Bits

Key design considerations for fixedcutter bits are:

Cutting structure.

Body material and profile.

Gauge.

Stabilizing (anti-whirl) features.

Should be matched to formationshardness and abrasivity.


40/74


Fixed Cutter Considerations

PCD cutters wear rapidly in hard

formations.Impregnated and natural diamond

bits tolerate very hard and abrasive

formations.Gauge protection is dependent on

abrasiveness.


41/74


Develop

Candidate Bit Programs

At this stage, develop severalalternative bit programs.

Consists of type of bit, start and

end depths, and anticipatedpenetration rates.


42/74


Confirm that the Selected Bits are

Consistent with the Proposed BHAs

Do the operating parameters of

the proposed BHAs inhibit bitperformance?

Is WOB limited?

Do the selected downhole motorsexceed the rpm capabilities ofthe bits?


43/74


Use the estimated penetration rate and bitlife to predict the probable cost for each bit

run:

Chi= CriTi+ Cbi

Cri

the hourly cost of operating the rig duringthat bit run, including the rig rate, fuel, allspecial services and rental items.

Ti the duration of the run in hours.

Cbi the cost of the bit.

Perform an Economic Evaluation, to

Identify the Preferred Bit Program.


44/74


Perform an Economic Evaluation, to

Identify the Preferred Bit Program.

Predicted cost of the interval isthe sum of all the bit costs forthe particular bit program.

Rank all the alternative bit

programs.


45/74


Bit Selection for Dry Gas,

Must and Foam Drilling

Roller cone

Fixed cutter


46/74


Roller Cone Bits

Dry gas drilling produces asmoother hole bottom than with

mud, and full coverage of thebottom of the hole with cutters isnot as important.

Larger teeth can be used for harderformations.

Abrasive wear is normally higherfor dry gas drilling.


47/74


Cone offset is not as important

with dry gas drilling.

Good gauge protection is veryimportant.

Utilize sealed bearings.

Roller Cone Bits


48/74


Fixed Cutter Bits

PDC bits are usually a poor choice

for dry gas drilling.

Not has heat tolerant.

Diamond bits may be heat tolerant.


49/74


50/74


Underbalanced Perforating

Can be performed withwireline or with tubingconveyed perforating guns.


51/74


52/74


Example 6

Consider a planned well, where themaximum weight on a 8-inch bitwill be 50,000 lbf, the drill collar sizewill be 6-inch OD, by 2 13/16-inches ID, the drilling medium will beair and the excess collars should beten percent to ensure that thedrillpipe remains in tension.Determine the number of thirty-footdrill collars that will be required.


53/74


The weight per foot of a drill collar canbe determined from:

Wf= 2.67(Dp2Di

2) = 2.67(6.5 22.8125 2)

Wf= 92 lb/ft

Di inside pipe diameter (inches)Dp outside pipe diameter (inches)Wf weight per foot in air (lb/ft)

Example 6


54/74


The length of the drill collars can becalculated using Equation(5.32). Since thiswell is to be drilled in air, the buoyancy

factor is one. It will not be one in othercircumstances.

Lc= [W(1+DF)] / WfB

B buoyancy factor (air=1)DF design factor (decimal)Lc length of the bottom hole assembly (feet)W bit weight (lb)

Example 6


55/74


56/74


The number of thirty-foot drill collars would be:

598 ft / (30) = 19.93 or 20 drill collars

The total weight, Wtc, of twenty drill collarswould be:

Wtc= 598 ft x 92 lb/ft = 55,016 lb

To develop 50,000 lb of drilling weight, twentydrill collars are required. The total weight of thedrill collars will be approximately 55,016 lb,including the ten percent design factor.

Example 6


57/74


58/74


Using the data from example 6, determine thedrillstring configuration for 12,000 foot deepwell. The drillpipe available is 5-inch, 19.50

lb/ft, Grade E and 5-inch, 19.50 lb/ft , GradeG. The tensile capacity of the Grade E and Gpipe are 311,000 lbf and 436,000 lbfrespectively. All the drillpipe is API Premium

Class and the tensile strengths can be foundin the API RP7G, available from the AmericanPetroleum Institute. Use design factor of 1.10and an overpull of 100,000 lbf.

Example 7


59/74


From the example 6, the collarweight at the bottom of the Grade Epipe will be 55,000lb. The maximumpull on the Grade E, with the 1.10design factor would be:

Pmax= Pmax/ DFDF design factor (decimal).Pmax length of the bottom hole assembly (feet).Tst bit weight (lb) .

Example 7


60/74


61/74


The maximum length, Lmax, that can be used is:

Lmax= Wmax/Wf = 128,000lb/19.5 lb/ft

Lmax= 6,564 feet (Grade E)

The maximum pull, Pmax, on the Grade G, with

the 1.10 design factor, would be:

Pmax= 436,000 lb/ 1.10 = 396,000 lb

Example 7


62/74


The maximum weight, Wmax, of Grade G thatcan be used with 100,000 lbf overpullremaining is:

Wmax= 396,000-55,000-100,000-128,000

Wmax= 113,000 lb

The maximum length , Lmax, of Grade Gdrillpipe that can be used is:

Lmax= 113,000/19.50=5,795 feet

Example 7


63/74


Since the length of the Grade G is greater thanthat necessary to reach the surface, Grade G

is acceptable to the surface. The drillstringwould consist of the following:

598 feet of drill collars (refer to Example 6).6,564 feet of 5-inch, 19.50 lb/ft, Grade E

drillpipe.4,838 feet of 5-inch, 19.50 lb/ft, Grade G

drillpipe.

Example 7


64/74


In this example, the maximum force that

can be pulled on the drillstring in theevent it becomes stuck is 100,000 lbfover the string weight, once all of theGrade E drillpipe is in the hole. The weak

point will be at the top of the Grade Edrillpipe. If the drillstring is changed, thenew maximum pull must be calculated.

Example 7


65/74


Separator DesignCapacity is a function of:

Size.

Design and arrangement.

Number of stages.

Operating P and T.

Characteristics of fluids.Varying gas/liquid ratio.

Size and distribution of particles.


66/74


Capacity is a function of:Liquid level.

Well-fluid pattern.

Foreign material in fluids.

Foaming tendency of fluids.

Physical condition of separator.

Others.

Separator Design


67/74


The maximum gas velocity in an oil and gasseparator that will allow separation of liquid mistfrom the gas can be calculated with the following

form of Stokes, law:

Vg= Fco[(Lg)/g] (1)

Where

Vg maximum allowable gas velocity, ft/secFco configuration and operating factor

(empirical) (see Fig. 12.32 for values)L density of liquid at operating conditions, lbm /cu ft

g density of gas at operating conditions, lbm /cu ft

Maximum Gas Velocity


68/74


Configuration and operation factor FCOforoil and gas separators and gas scrubbers

(see Eqs. 1 and 4 through 6)

Fco ( CONFIGURATION AND OPERATION FACTOR) see equations 1,4,5 and 6

Va

L/D

RA

TIOF

OR

VERTICALSAPA

RATORS

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

0 0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

0.33

0. 67

1.0

1.33

1.67

2.0

2.33

2.67

3.0

L/D

RATIOF

OR

VERTICALSAPARATORS

L/DRATIOF

OR

HORIZONTALSEPAR

ATORS


69/74


Gas Separating Capacity

The maximum allowable gasvelocity Vg of Eq. 1 is the

maximum velocity at which thegas can flow in the separator andstill obtain the desired quality ofgas/liquid separation. Only the

open area of the separatoravailable for gas flow isconsidered in calculating itscapacity.


70/74


71/74


GAS CAPACITY OF VERTICAL OIL AND GAS SEPARATORS

SEPARATOR


72/74


LIQUID CAPACITY OF VERTICAL OIL AND GAS SEPARATORS

LIQUID CAPACITIES ARE BASED ON:


73/74


GAS CAPACITY OF HORIZONTAL OIL AND GAS SEPARATORS

LIQUID DEPTH


74/74

lesson 13 well engineering

Documents