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# Drilling Engineering - Drilling Economics

Date post: 01-Dec-2014
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Petroleum Engineering, Drilling Engineering, Drilling Economics
47
DRILLING ECONOMICS JAMES A. CRAIG
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DRILLING ECONOMICS

JAMES A. CRAIG

Drilling Cost Prediction Cost Specification Authorization for Expenditure (AFE) Drilling Optimization Drilling Optimization Techniques

Drilling Cost Equation Breakeven Calculations Decision Making

DRILLING COST PREDICTION

Drilling cost predictions are made so that sound economic decision can be made.

Predictions depend primarily on: Location – governs the cost of preparing wellsite,

moving rig to location, and daily operating cost. Depth – governs the lithologies to be penetrated,

thus the time required to complete the well.

C = cost, \$ a, b = constants depending on well location D = depth, ft

( )expC a bD=

Drilling costs tend to increase exponentially with depth.

= −

COST SPECIFICATION

Drilling costs can be broken down into 3 groups: Fixed Daily Unit

Fixed Costs

Fixed costs are determined by the nature of the well, such as: Wellheads Site preparation Casing, cement, tubing and packers

Daily Costs

Daily costs are related to the time spent on the operation. Offshore rigs have high expenses which listed below. Daily costs include:

Payments to drilling contractors (rig time) Tool rental Payment to specialist services Salaries, wages etc Fuel Lubricating oil, grease Drilling consumables (rope, soap and dope) Transport of materials

Unit Costs

This is the price of a unit of a commodity such as the price per tonne of barite or bentonite.

This can be optimized in the tendering process, which is Drilling Manager responsibility.

Good site supervision can ensure that consumption is not excessive.

AUTHORIZATION FOR EXPENDITURE (AFE)

The operators, should know how much a well is going to cost if it is dry, tested or completed.

Consequently, AFEs should be broken down into sections.

AFE makes it easier to carry out post-well assessment and cost-comparisons between wells.

AFEs are broken down into the following sections: Preparation Drilling and abandonment Testing Completion

AFE Components

Preparation This part of the AFE covers the costs incurred

to the point at which the rig is brought on to location.

For onshore wells this would include site building and well engineering as the main cost.

For offshore wells, the main costs are site surveying and well engineering.

Drilling and Abandonment This is the ‘dry hole’ drilling component of the

well. It assumes drilling reached the TD, logging

carried out and no economic finding. The well is, therefore, proposed for

abandonment and appropriate cost is allocated to it.

Testing It is only the testing cost charged by the testing

company It must also include all the ongoing daily costs

associated with the rig such as:rig day ratefuel oilsite personneloffice personneloffice overheads

Completion It is not only the cost of completion equipment and

services but also the costs of: rig day rate fuel oilextra casing string if runperforationsite personnel office personneloffice overheads

Costs can be estimated fairly for development wells

Costing for exploratory wells is a much harder task.

The service companies will give the operating companies the main costs: drilling contractors mud loggers electric logging companies mud companies cementing companies bit companies casing companies wellhead companies tool rental companies coring companies

The Time Depth Graph created for the Drilling Programme provides an estimate of the days to be spent on the well.

By costing in the charges for these days, the AFE begins to take form.

Some assumptions must be made, e.g.: It is difficult to fix charges such as coring on an

exploration well with the limited knowledge available regarding formations to be drilled. The AFE could either include one 20-m core or several runs.

A contingency factor should be applied to the AFE.

This can be in the form of: A lump sum, or A percentage of well costs.

DRILLING OPTIMIZATION

Drilling optimization is minimizing the cost of reaching the well’s objective while maintaining safety standards.

This minimum drilling cost is also the optimum drilling cost.

The optimization process is a cycle that starts with using the existing data base of drilling information.

More data are collected during the practical drilling process.

The new data are then analyzed to update the data base for future use.

The process of optimizing drillling process is not always straight-forward.

Because of uncertainties involved, there is always need for some trade-offs.

For example, optimization might mean paying more to obtain a better tool, such as choosing a rig with a higher day rate to obtain better equipment.

DRILLING OPTIMIZATION TECHNIQUES

The following optimization techniques are popular in drilling: Drilling cost equation Breakeven calculations Cost-effective decision making

Drilling Cost Equation

Also known as the cost per foot equation.

Cdrill = cost per foot for the interval concerned, \$/ftCbit = cost of delivered bit at the drill site, \$Ctools = cost of tools or repair to tools, \$Cmud = cost of mud to drill the interval, \$Crig = rental rig rate, \$/hourCsupport = support cost, i.e. third-party contractor rates,

\$/hour

( )( ) bit tools mud rig support tool rental trip bit lostdrill

bit avg

C C C C C C T T TC

T ROP

+ + + + + + + =×

Ctool rental = rental of tools, \$/hourTtrip = round trip time, i.e. time to pull and run a bit, hoursTbit = bit life, i.e. time required to drill the interval, hoursTlost = non-rotating time, i.e. time chargeable to non-

drilling task, hoursROPavg = average rate of penetration during bit run,

ft/hour

Eleven variables are listed in the drilling cost equation.

Most of these interact with one or more other variables.

Because the degree of interaction is often impossible to determine intuitively, the drilling cost equation can aid decision making

Breakeven Calculations

Breakeven calculations are economic evaluations that determine the change in a dependent variable that is required to create a beneficial change in an independent variable.

The typical variables are as follows:

Alteration in Independent Variable

Required Change in Dependent Variable

Bit type Bit life, ROPDrilling tools Bit life, ROP, Trip time

Mud type Bit life, ROP, Trip time

The procedure is as follows: Solve the drilling cost equation for present conditions to

determine the cost/ft. Specify the independent variable and the dependent

variable to be changed. Determine the change in any other parameters that will

result from the change in the independent variable. Substitute the cost/ft determined in Step 1, the

independent variable specified in Step 2, and all other variables into the drilling cost equation.

Rearrange the equation and solve to find the value of the dependent variable required for breakeven.

The breakeven calculations can also be used to evaluate whether additional rig equipment should be obtained for purposes other than to increase the rate of penetration.

Decision Making

It is difficult to exactly calculate the consequences of each decision to be made

Some degree of uncertainty concerning the consequences are made.

Decision of this type must be made on a statistical basis: a decision is made to implement the course of

action that on average results in the lowest cost.

Expected Values Method An explicit step-by-step approach to the

decision process traditionally used. The method is used to make decisions by

evaluating choices that have both different finanacial returns and different probabilities of occurence.

The best decision is that which has the lowest(or least negative) probability cost product.

The fundamental form of the expected value equations is given as follows:

1 1 2 2EV C P C P= +

1 2 1P P+ =

EV = expected value, \$C1 = cost of first event, \$P1 = probability of first event, fractionC2 = cost of second event, \$P2 = probability of second event, fraction

Example 1 – Cost per foot calculation A 17-1/2” bit drills 1,050’ of hole at an average

penetration rate of 35 ft/hr. given the following data, what is the cost per foot? Round trip = 6hrs Bit purchase cost = \$3,000 Bit life = 30 hrs Tool purchase cost = \$100 Rig cost = \$800/hr Interval mud cost = \$5,000 Tool rental = \$100/hr Support cost = \$200/hr

Ttrip = 6hrs Cbit = \$3,000 ROPavg = 35 ft/hr Tbit = 30 hrs Cmud = \$5,000 Crig = \$800/hr Ctools = \$100 Ctool rental = \$100/hr Csupport = \$200/hr

( )( ) bit tools mud rig support tool rental trip bit lostdrill

bit avg

C C C C C C T T TC

T ROP

+ + + + + + + =×

( )( )3,000 100 5,000 800 200 100 6 30 030 35drillC

+ + + + + + + =×

8,100 39,6001,050drillC +

=

\$45.43/ftdrillC =

Example 2 – Breakeven calculation When planning a well. It has been determined that the

next section requires a polymer mud that costs \$15/bbl. The rig has inefficient shale shakers, which the drilling contractor will not replace without sharing the expense. How much should the operator be prepared to pay for the installation of the new, high-efficiency shale shakers if the rig is to be used for only a single well? Old shale shaker solid control efficiency = 65% New shale shaker solid control efficiency = 75% Anticipated average hole diameter = 13” Maximum allowable drill solids concentration = 6%

We use mud interval cost equation:

Cmud = cost of mud to drill the interval, \$ Lint = length of interval, ftCmud/bbl = mud cost, \$/bblDh = average hole diameter, in.Eff = efficiency of solids control system, %Sactive = drilled solids in active mud, volume %

( )( )2h active

mud int mud/bblactive

D 1 Eff 1 SC L C

1,029 S − −

= × ×

For the existing shale shakers:

( )( )2

mud

13 1 0.65 1 0.06C 6,000 15

1,029 0.06 − −

= × ×

mudC 6,000 15 0.9006= × ×

mudC \$81,051=

If new shale shakers were purchased:

Ecost = equipment cost, \$

( )( )2

mud cost

13 1 0.75 1 0.06C 6,000 15 E

1,029 0.06 − −

= × + ×

mud costC 57,894 E= +

( )( )2h active

mud int mud/bbl costactive

D 1 Eff 1 SC L C E

1,029 S − −

= × + ×

Breakeven occurs when the cost of existing shakers equals the cost of new shakers.

This value (\$23,157) represents the most the operator should pay for the installation of new shakers.

Any amount less that this can be negotiated with the drilling contractor represents a net savings.

cost81,051 57,894 E= +

costE \$23,157=

Example 3 – EV calculation When drilling 12-1/4” hole in an area, experience

shows that a reverse circulating junk basket (RCJB) is required on 25% of all wells. The average rental period for wells where a RCJB is required is 3 days, and 12 hours rig time is wasted waiting for the equipment.

A rig is contracted for a single well in which the 12-1/4” section is planned to take 25 days to drill.

Given: Rig rate = \$8,000/dayRCJB rental = \$150 first day plus \$25/day thereafter

Would it be advantageous to have RCJB on standby at the rigsite:

We use the EV method and decision tree.

RCJB rented

RCJB not rented

Required

Not required

RCJB not rented Not required

Required

Rig rate Interval time× 8,000 25= × \$200,000=

( ) [ ]Rig rate Interval time Waiting time RCJB rental Rental time× + + +

( ) ( )8,000 25 0.5 150 25 2= × + + + × \$204,200=

RCJB on standby

( ) ( )Rig rate Interval time RCJB rental Interval time× + +

\$200,750=

( ) ( )8,000 25 150 25 24= × + + ×

RCJB rented

RCJB not rented

Required

Not required

C = \$200,000P = 75%EV = 200,000 x 0.75EV = \$150,000

C = \$204,200P = 25%EV = 204,200 x 0.25EV = \$51,050

C = \$200,750P = 100%EV = 200,750 x 1.00EV = \$200,750

RCJB not rented Total EV = \$150,000 + \$51,050 = \$201,050

RCJB on standby Total EV = \$200,750

RCJB on standby < RCJB not rented Therefore, the better economic solution is to

have the RCJB on standby at the rigsite.

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