Example of time-depth curve
Elements Of Well Costing
Risk Assessment In Drilling Cost Calculations
Drilling Contracting Strategies
Authorization For Expenditure
elements which comprise the well cost:
rig, casing, people, drilling equipment etc.
The final sheet summarizing the well cost is usually described as the AFE: “Authorization For Expenditure”.
The AFE is the budget for the well.
Once the AFE is prepared, it should then be approved and signed by a senior manager from the operator.
The AFE sheet would also contain:
project description, summary and phasing of expenditure, partners shares and well cost breakdown.
Details of the well will be attached to the AFE sheet as a form of technical justification.
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FACTORS AFFECTING WELL COST
Well costs for a single well depend on:
land or offshore, country
Type of well:
exploration or development, HPHT or sour gas well
vertical/ horizontal/ multilateral
land rig, jack-up, semi-submersible or drillship and rating of rig
Knowledge of the area:
wildcat, exploration or development
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time spent on a well
The time spent on a well consists of:
Drilling times spent on making hole, including circulation, wiper trips and tripping, directional work, geological sidetrack and hole opening.
Flat times spent on running and cementing casing, making up BOPS and wellheads.
Testing and completion time.
Formation evaluation time including coring, logging etc.
Rig up and rig down of rig.
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time required to drill the well
Before an AFE can be prepared, an accurate “estimate” of the time required to drill the well must be prepared.
The time estimate should consider:
ROP in offset wells.
From this the total drilling time for each section may be determined.
Flat times for running and cementing casing
Flat times for nippling up/down BOPs and nippling up wellheads
BHA make up times.
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DETAILED TIME ESTIMATE
Detailed time estimates can be prepared for each hole section by considering the individual operations involved.
This exercise requires experience on part of the engineer and also detailed knowledge of previous drilling experience in the area. Fall 14 H. AlamiNia Drilling Engineering 1 Course (3rd Ed.) 8
Detailed time estimate for 30” conductor
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Calculation of time -depth curve
Assume the following well design for Well Pak-1:
36” Hole / 30" Conductor 50 m BRT (below rotary table)
26” Hole / 20" Casing 595 m BRT
17.5”Hole / 13.375" Casing 1421 m BRT
12.25” / 9.625" Casing 2334 m BRT
8.5” Hole / 7" Casing 3620 m BRT
Total Depth 3620 m BRT
From three offset wells, the following data was established for average ROP for each hole section:
36” Hole 5.5 m/hr
26” Hole 5.5 m/hr
17.5”Hole 7.9 m/hr
12.25” 4.6 m/hr
8.5” Hole 2.5 m/hr
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Calculation of time -depth curve (Cont.)
The expected flat times for this well are :
Calculate the total drilling time and plot the depth-time curve.
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Calculations of planned drilling times
Example 17.1: Calculation of time -depth curve, WECPGO: 752
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ELEMENTS OF WELL COSTING
There are three main elements of the well cost. No matter what service or product is used, it will fall under one of the following three cost elements, namely:
For offshore wells there are other costs which must be included:
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As the name implies, rig costs refer to the cost of hiring the drilling rig and its associated equipment.
This cost can be up to 70% of well cost, especially for semi-submersible rigs or drilling ships.
Rig cost depends entirely on the rig rate per day, usually expressed as $/day.
Rig rate depends on:
Type of rig
Length of contract
Days on well
Mobilization/ Demobilization of rig and equipment
Additional rig charges
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Tangibles refer to the products used on the well. These include:
For an example: length of casing and selecting the appropriate casing grades/weights for each hole section
Tubing/ completion equipment
Solids control consumables
Fuel and lubes
Other materials and supplies
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This group of costs refers to any service required on the well. Services include:
usually required in offshore operations
both open & cased hole logs
Solids Control Equipment
determination of hole angle and azimuth.
includes the cost of single shots, magnetic multi-shots (MMS) and gyros
only included if experience in the area dictates that fishing may be required in some parts of the hole
including jars, shock subs
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NON PRODUCTIVE TIME (NPT)
The time required for any routine or abnormal operation which is carried out as a result of a failure is defined as Non Productive Time (NPT)
Non-Productive Time (NPT) in drilling operations currently account for 20% of total drilling time.
the NPT is calculated as the time from when the problem occurred to the time when operations are back to prior to the problem occurring.
The NPT time includes normal operations such as POH, RIH, circulating etc.
Waiting on weather or waiting on orders, people or equipment is not NPT. This is standby time.
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CLASSIFICATION OF NPT
(Down time due to: Mud pumps, generators, shakers, rotary table, top drive/Kelly, hoist, drilling line, gauges, compressors and anchors.
Note that within the rig contract a fixed time is allowed for rig repairs/ maintenance. The NPT rig time should be the time recorded above the agreed fixed repair time).
Stuckpipe and Fishing of BHA equipment
Casing Hardware and Cementing Equipment
Testing and Completion NPT
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two major elements of well cost estimates
it is essential that cost estimates are made realistic, as low as possible and produced in a consistent manner.
These criteria are achieved through the application of risk assessment.
Well cost estimates are made up of two major elements:
Time dependent costs
Rig costs and services are greatly impacted by the time estimate.
Tangible costs can be estimated at the budgetary stage (before a detailed well plan is made) or at the AFE stage after the detailed well plan is made.
The risk involved in estimating tangibles is usually small.
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levels of risks
Risk assessment is defined in terms of the probability of meeting a given target. There are three levels of risks:
P10 (only a 10% chance of being achieved)
This is a highly optimistic estimate which can only be achieved under exceptional circumstances.
As there is no exact method for estimating P10, it is now customary to base P10 value on the best possible performance on any operation on any well in the area.
the total P10 value for a given section will be the best individual values from several wells for all operations required to drill, case and cement the given hole section.
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levels of risks (Cont.)
This is the key figure in most well cost estimates.
This estimate will be based on known information derived from offset data.
This is an estimate of well cost which is likely to be met 90% of the time and that well costs can not be exceeded except under exceptional cases.
This estimate was widely used in the oil industry before accurate cost estimating was introduced in the early 1990’s.
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There are two elements of costs which must be controlled:
Capital Expenditure (Capex):
This includes the cost of finding and developing an oil/gas field.
The cost of drilling operations is the major cost element and must be kept to an acceptable value.
Operating Cost (OPEX):
This includes the actual cost of production: cost of maintaining the platform, wells, pipelines etc.
We will not be concerned with these costs as they are part of production operations.
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Price of oil production
judging a minimum price per barrel of oil (2002):
In the North Sea, it is accepted that the principle of 1/3/3 results in a profitable operation.
$1 for finding, $3 for developing and $3 for production.
combined cost of $7 per barrel
In the Middle East, this combined cost can be as low as $2 for some giant fields.
In general the more remote the area the more expensive is the final cost of barrel of oil.
This is particularly true for deep waters in hostile environments.
The following is a list of measures to reduce costs:
Productivity improvement: e.g. faster drilling operations
Increased operational effectiveness
Incentive contracts (sharing gains and pains)
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types of contracts
There are basically four types of contracts which are currently used in the oil industry:
Integrated Services (IS)
Integrated Project Management (IPM)
The type of drilling contract used can mean the difference between an efficient and a less efficient operation.
Indeed, going for one type, say turn key, can mean that the operator has no control over the operation whatsoever and has no means of building knowledge for future operations.
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In this type of contract, the E&P company does every thing using its own staff or contractors. This is the most involved type of contract and can mean handling up to 100 contracts per well.
the operator has total control over the operation and carries full risk.
The contractor has no risk and it could be argued that
the contractor has no incentive in speeding up the operation.
This type of contract has the advantage that
lessons learnt during drilling operations are kept within the company and used to improve future operations.
Nowadays, only large operators opt for this type of contract.
A variation of the above contract is to include an incentive clause for completing operations early or if a certain depth is reached within an agreed time scale.
The contractor will be paid a certain percentage of the savings made if operations are completed ahead of the planned agreed drilling time.
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INTEGRATED SERVICES (IS)
In this type of contract, major services are integrated under two or three main contracts.
These contracts are then given to lead contractors who, in turn, would subcontract all or parts of the contract to other subcontractor.
The lead contractor hold total responsibility for his contract and is free to choose its subcontractors.
The operator still holds major contracts such as rig, wellheads and casing.
Also the operator appoints one of its staff to act as a coordinator for the drilling operation.
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INTEGRATED PROJECT MANAGEMENT (IPM)
In this type of contract, a main contractor is chosen.
This contractor is the Integrated Project Management (IPM) contractor.
The contractor is responsible for 20-30 service companies.
Service companies may be responsible for other service companies.
The drilling operation will be controlled by a representative from the IPM contractor.
The operator may hold one or two major contracts.
It is one of the worst kind of contracts for the operator because:
There is virtually no learning for the operator.
The incentive contract is built on a time-depth curve developed and based on the contractor’s experience. Use of better equipment and personnel may beat the IPM contractor’s time-curve.
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TURN KEY CONTRACT
This is the easiest of all the above contracts.
The operator chooses a contractor.
The contractors submits a lump sum for drilling a well:
from spud to finish with operator virtually not involved.
The contractor carries all risks if the well comes behind time and also gains all benefits if he should drill the well faster.
Contractors only opt for this type of contract
if they know the area extremely well or during times of reduced activities.
The operator opts for this type of contract
if he has a limited budget or has no knowledge of drilling in the area.
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CURRENT AND FUTURE TRENDS IN DRILLING CONTRACTS
There are two new development in drilling and production contracts:
Production Sharing Agreement
It stipulates that the contractor will be paid a certain percentage of the produced fluids (oil or gas) in return for the services of the contractor in drilling and producing the wells.
The agreement may be time-dependent running for a fixed number of years or may include an initial payment for the contractor in addition to a percentage of the production.
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CURRENT AND FUTURE TRENDS IN DRILLING CONTRACTS (Cont.)
Capital Return Agreement Plus Agreed Production
It stipulates that the contractor will develop a field using his own finance. In return, the operator (or national oil company) will pay the contractor all his capital expenditure plus an agreed percentage of the production.
In Iran where this type of contract is used, the agreed production is limited to a fixed number of years. The ownership of the field and its facilities always remain with the operator.
These new types of contracts were initially initiated in some Middle Eastern countries attempting to draw western investment.
These contracts are still developing in nature and have now been used by a number of third world countries.
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