Cost management for petroleum exploration part a

Cost Management and Performance Measurements for
Petroleum Upstream Industry
Hamdy Rashed, CMA, CAPM
Bsc of Accounting,
E-mail: rashed.hamdy@gmail.com,

Updated on February 15, 2013
Abstract
Cost control and management is not appropriate only for manufacturing and commercial industry;
cost management is applied in upstream industry such as Petroleum exploration, development and
production cost. Many Petroleum Companies don’t pay more attention to cost control and
especially during exploration phase except if Companies face financial dilemma, declining
production or if they see they cannot meet their planned schedule of Capital program that lead
them to not meet their obligation, commitments and required return, therefore, they start
considering cost reduction or control. This paper provide management accountant, cost controller,
financial controller, financial manager, internal auditor and cost recovery auditor with brief of cost
control, how cost is analyzed and managed and performance is measured in Petroleum upstream
industry.
The technical information that is covered in this paper is useful for accountant and non-technical
staff who are interested in understanding the cost behavior in petroleum upstream industry. Also,
we don’t criticize or indicate to fishing period that stated in Standard Handbook of Petroleum and
Natural Gas Engineering is wrong but we cover and adjust the fishing period formula and add new
fishing period formulas in management accounting view only.
Keywords: Cost Management and analysis for petroleum exploration, Optimizing production, exploration and
development programs, Project Cost Management and Analysis for Petroleum Upstream Industry, Procurement
Cost Management, Drilling Cost Management, Production Cost Management, G&A Cost reduction.

It was noticed that few major oil companies
hired management accountant and cost control
accountant who are assigned to the correct tasks
and duties that include measuring management,
department and overall company’s performance,
support management and provide with required
financial and non-financial information that can
help management to take a decision, participate
in putting plan and strategy for the company.

Before discussing about the cost management
and performance evaluation in oil and gas E&P
companies, we like to draw our reader’s
attention that this paper does not criticizing the
drilling practices of oil and gas companies but it
provides fundamental concepts for the
possibility of managing costs in such industry.
Accountant and internal auditor needs to
understand what is the type of costs per function
in oil and gas industry, to assign KPI of cost
management to each functional department. The

Cost Management and analysis for performance evaluation

costs that are assigned to each functional
department shall be direct costs that are effected
by cost drivers rather than decision-making such
as barrels produced of petroleum, hours spend
by staff, meters or days drilled, KM2 seismic
run, processed or interpreted, meter square or
cubic meter of space occupied.

1) Oligopolistic Market
Oligopoly is created when there are few number
of large firms in the industry that explore and
produce somewhat similar commodities of oil
and gas and there are many buyers because
entering the market is not easily because it is too
costly for exploring and producing oil and gas,
the major part of such cost are fixed or sunk cost
that increase the break-even output. The profit is
maximized when the marginal cost equals
marginal revenue. In summary, we assess the
petroleum upstream producers market as
oligopolistic market due to the following
characteristics:
1- Small number of large firms
2- Somewhat similar commodities that
could be differentiated by its nature that
is referred to the quality of oil and gas
produced.
3- Natural barriers to entry that high set-up
cost and exploration costs.
4- Elasticity of oil supply is relatively
inelastic [Tom Konrad, Jan 26, 2012.
The End of Elastic Oil. Forbes] & [John
C.B Cooper. March 2003. Price
Elasticity of demand for crude
oil:estimates
for
23
countries.
Organization of Petroleum Exporting
Countries]
Oligopolistic Company could take advantage of
economics of scale that reduce production costs
by reducing average fixed costs and take
advantage of high price that is determined by
setter who has price power. The disadvantage of

Hamdy Rashed; CMA, CAPM

oligopolistic company can allocate the resources
and produce inefficiently.
But many less experienced small or medium Oil
and Gas Companies pay less attention to cost
reduction in exploring and producing oil and gas
because many of such companies thought that all
costs incurred for exploration, development and
production will be cost recovery, the finding and
operating costs of one barrel or mscf does not
reflect major part of oil and gas price. In other
word, whatever it has been spend for finding and
producing oil, the large recoverable reserves
could payout the costs in very short time and
such costs will be spread among the recovered
reserves which lead to reduce the average costs
to the level which make it immaterial. However,
low finding cost and operating costs could lead
to have more feasible well and attract companies
to produce oil for such well.

2) Cost Analysis and Estimation
All costs have not same behavior, there are costs
are proportion to changes in volume range of
production, other costs such as Labor hours and
machine hours of production facility
equipments. And there are costs that are not
changed in responding to changes in volume
range of production. Understanding Cost
behavior enable Oil and Gas Companies to the
following:
a) Identify the breakeven and Costvolume-profit analysis
b) Evaluate organizational or departmental
performance.
c) To make routine decisions
d) To make non-routine decisions
Before identifying the direct or indirect costs.
Management accountant should identify critical
costs in petroleum upstream Companies. Then
break the costs into elements and costs drivers to
enable the management accountant to identify

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and group the controllable costs from noncontrollable costs and the responsibility centers.

2.1) Critical Costs Identification.
Petroleum Company in Upstream Industry shall
maintain detailed and accurate records if they
are serious in cost control-orientation to enable
Company to track the costs and to find ways for
cost management improvements.
When Drilling Department or Exploration
Manger finalized Project Management Plan and
Work Breakdown Structure (WBS) they specify
which materials and services they need to buy
and what are the specifications of those
materials and services. Also, Operation
Department need to determine how much
materials and what are the services they need to
buy based on their Materials and Services
Requirement Plan and based on their
experimental judgments and historical data.
Responsibility centers, Program Manager or
investment center manager should conduct with
management accountant or cost controller to
understand the critical costs and cost behaviors
and identify the controllable costs.

broker’s fees and legal costs for acquiring the
licenses.
Before taking decisions for acquiring the
licenses and signing the related contracts with
host government. Management accountant
should prepare Contract cash flow projection
and understanding the effect of the Contract
terms to the cash flow projection and providing
recommendation to program or exploration
manager to have good negotiation with host
government. The contract terms that could
impact on the Production Sharing Contracts cash
flow projection are as follow:
a)
b)
c)
d)

Royalties
Profit Oil Split
Work commitments
Non-recoverable Costs
1. Annual Bonuses
2. Signature Bonuses
3. Acquisition Costs, If any.
e) Cost Recovery ceiling
Also, management accountant should consider
other variable inputs for PSC cash flow
projection such as
a) Petroleum Price
b) Required Rate of Return
c) Estimated
Finding
(Exploration,
development and facility) Costs
d) Preliminary chance of success
e) Preliminary potential Petroleum reserves
f) Corporate Income Tax
g) Estimated Operating Costs

All Oil and Gas Exploration and Production
Companies financially categorize the costs into
five major category as follow:

2.1.1) Pre-acquisition and Acquisition
Cost
Management accountant should help program
manager or investment center manager to get
and analyze the acquisition costs to enable the
program manager to get in very good negotiation
with government or third party to acquire license
at lower costs. The Pre-acquisition and
acquisition costs include cost of purchasing
seismic data, cost of G&G analysis for this data,
cost of license bonuses and signature bonuses,


If there is no attractive potential reserves or the
preliminary chance of success is very low due to
new discovery area, the Company can get into
good negotiation with host government and
obtaining Production Sharing Contract with
good terms but if the expected rate of return of
the cash flow projection does not encourage
company to acquire the license

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2.1.2) Exploration Cost
Exploration costs are costs incurred after
acquiring the license and before decision is
made for developing the license. Such costs
include the following:
- Geological and Geophysical studies that covers
- Seismic Acquisition cost
- Seismic processing/reprocessing
- Seismic interpretation
- Velocity modeling
- Other G&G study
- Cost of holding the undeveloped licenses
- Cost of drilling and testing exploratory wells
Cost Management or Cost Controller should
estimate the exploration costs that be used in
Cash flow projection and viability analysis of
discovering petroleum. Program manager or
exploration manager should understand that the
higher Capital Costs that represents exploration
and development costs, the higher minimum
target size of reserves will be, and the lower
expected monetary value and higher opportunity
loss may occur. Cost Controller or Management
Accountant should analyze the service contracts
that are related to seismic acquisition,
processing, drilling contracts and others and
investigating for higher costs and find the best
alternative way to manage the costs without
reducing the quality of service, materials or the
performance of subcontractor’s in HSES.
Management Accountant or Exploration
Manager need to know when to use 2D, 3D or
4D seismic, the quality of providing seismic
acquisition and management accountant should
consider the costs of high quality seismic in
comparison of cost of drilling dry well. Also,
exploration manager may not expect that
petroleum will not be discovered in geological
formation that its thickness will be less than 3
meters, therefore, exploration manager may
contract with Seismic Compmany to use less
frequency of seismic waves that include the less


than 3 meter formation into prior or consecutive
thicker formation which going to be neglected in
the seismic processing and the costs will be
reduced, but exploration manager might be
wrong, and Company may carry higher costs for
drilling wrong well or for not having accurate
seismic mapping. Any decision for having some
specification in contracts should be reviewed by
cost controller to check the cost and benefit of
such quality or specifications.
Even the cost of exploratory or development
wells, such costs are combined into drilling
contract, cementing, logging and fluid contracts.
Cost Controller or contract specialists,
management accountant and exploration
manager should not looking for only the lower
cost of tender, they must consider the technical
performance of such subcontractors. The lower
performance the higher costs could be incurred
in late time.

2.1.3) Development and Facility Cost
Development costs are costs incurred after
taking the decision for developing the license or
reservoir that include:
- Cost of drilling and testing development well
- Cost of completing and equipping production
well
- Cost of facilitating in producing oil or gas such
as building facility equipments of separator,
treator, storage, waste disposal system.
- Cost of improved recovery equipments.

2.1.4) Operating Cost
The third important activities that are performed
for producing oil or gas which include:
- Labor costs engaged in operation of well and
related facility equipments
- Cost of repairs and maintenance of producing
equipments
- Cost of materials and fuel consumed and cost
of services that are used in operations of wells
and facility equipments.

4


2.1.5) Site restoration Cost
It is costs of plugging and abandoning wells and
dismantling all the surface equipments in
accordance with production sharing agreement
or local regulations.

neglect the following risks and the costs
associated of buying high volume and building
up stock.
-

3) Elements of Costs
Whatever the type of costs or the functional
activities that cause costs, the costs are contains
three elements which are:
- Materials
- Labor
- Other expense
And each of the above elements are either
directly and completely assigned to specific
units or charged to prime costs or indirectly
elements that cannot be assigned to the specific
unit or charged to prime costs the most
appropriate example of indirect costs are
overhead such as drilling overhead, exploration
overhead, administrative overhead.
Exploration, development and production costs
can be divided into materials and services, labor
and overhead. Each of this costs can provide an
opportunity for controlling and managing the
costs.

3.1) Materials/Assets or services Cost
Procurement Department and Drilling Manager
shall ensure that they are obtaining the best
prices with very good quality of materials and
assets, check with variety of suppliers to find the
best prices and materials via tenders and based
Procurement Management Plan.
3.1.a) Materials
Procurement Manager, Operation Manager,
Drilling Manager, or Exploration Manager may
intend to buy in large volume of drilling
materials or operation materials to obtain
purchasing discount, saving transportation cost,
meet variations of drilling needs, but they may

Obsolescence and selling the materials
less than actual costs at late time
High storage Cost
Opportunity costs of keeping high value
of surplus inventory. However, if such
money invested in bank with free-risk
interest, it can generate income to the
Company by 4% or more annually
depends on the interest rates prevailed at
that time.

Building materials and supplies Inventory in oil
and gas upstream industry is subject to the type
of costing.
When Company enter in production phase, it
applies costing process system for production
process, therefore, they follow Materials
Requirement Plan, but they apply job-order
costing system for exploration and development
drilling that allow to use Just-In Time Inventory.
However, drilling wells in specific geological
formation may vary from place to another, and
availability of suppliers may vary from country
to another, Many of Petroleum Companies
intend to buy their drilling materials or assets
(Casing and wellheads) based on their estimated
requirements of proposed wells to be drilled plus
10% - 20% as contingency.
Many PSAs require to pass title of drilling
materials or assets to the host government at the
termination of PSAs, which lead Company to
bear the loss of disposed assets. To mitigate such
loss, Petroleum Companies are supposed to have
very clear and practical drilling schedules in
foreign Companies and high experienced
technical and drilling staff to have the best
estimate of actual needs of drilling
materials/assets that will be bought.

5


In Petroleum upstream Companies, the
followings are the major materials costs that
could be controlled and managed properly.
-

-

-

Tanigble Drilling cost such as
o Casing
o Tubing
o Wellhead
Operating materials such as
o Treating chemicals
o Small tools & supplies
Furniture’s and equipments
Facilities Assets such as
o Pumper
o Generators
o Gathering compression
o Flowlines
o Treater, Sperator

3.1.b) Services
After preparing the WBS, Drilling Department
and Procurement Department will outline the
requirements for services in Contract Statement
of work (SOW) after identifying the type of
contract and the risks, Company and Contractor
will bear them. Most of the Petroleum service
contracts is fixed price contracts with economic
price adjustments.
Drilling and Procurement Departments defines
the technical, functional, and performance
specification and the exact works that are needed
from Contractor in enough detail to mitigate the
disputes between the Company and Contractor.
SOW and contract must clearly define the
parameters for acceptable performance and
timeline for each section of work based on the
nature of the work.
Drilling Department, Procurement Departments
or Exploration Management may be trapped
themselves unknowingly by increasing the
specification and wrong assumption that may
increase the unnecessary costs. Specification


must not be very open or loose with missing
important details.
Drilling and Procurement Manager shall have
open meeting with all suppliers and reply to
their inquiries equally, provide adequate and
accurate information of specification equally
‘cause missed details may lead ineffective
suppliers purposely providing lower bidding
price to win the contract and they know the
contract price will be changed then by issuing
variations or purchase orders. And this action
will lead to increasing the costs.
Drilling Department and procurement shall
define the evaluation criteria if there is no
Corporate policy that define them. Internal
auditor shall review the objectivity of evaluation
criteria and if they are properly updated and
applied by concerning staff. Internal auditor
shall review the SOW and contracts either
before it has been signed to mitigate the
potential risks or after it was signed and
implemented, for lessons learned and avoid the
same mistakes or risks in future. Also,
management accountant, cost controller or
contract specialists can review the activities and
terms of contracts after the implementation for
lessons learned if the Control-Self Assessment
(CSA) program is applied.
The major and most common services requested
by Petroleum Company are as follow.
-

Drilling service
Cementing service
Drilling Fluids service
Logging and Testing service

3.2) Labor Cost
Labor costs in oil & gas Companies represent
high part of total costs after materials/assets and
services costs, even services costs contains
materials and labor costs but it is not practically
to determine such costs from services

6


contractors’ invoices except for Consultancy
services that does not contain materials cost.
Labor costs that we need to indicate to, is the
cost of employees that have a direct contracts
with an Oil and Gas Company.
Oil and Gas Company should be look for the
ways to improve labor efficiency. In
production/operation Department, Petroleum
Company shall keep track of how much oil or
gas produced during specific period of time per
labor hour and look for variables and correlate
that can increase the productivity, such as direct
labor cost, and labor costs of home office. Even
in Drilling and Exploration Department,
Petroleum Company shall keep track of how
much proved reserves of oil or gas discovered
per labor hours, and how much unproductive
hours (Unproductive drilling hours include the
time spent for lost circulation, stuck pipe,
fishing) to total drilling hours per well, cost
center and overall.
Petroleum Company should know their
employees’ strengths, weakness and skills,
determine suitable training for them, schedule
them for the positions that allow Company to
make optimum use of their abilities. Petroleum
Company that are seriously seeking for cost
control may replace high cost of their expatriates
by the lower costs of high technical skilled labor
after train them managerially.
Petroleum Company shall have incentive and
salaries payments that are more reasonable and
relating to performance of labor and managers
that can change the slope of learning curves of
labor to higher and reducing the unproductive
time. Also, Petroleum Company shall review
and update their performance measurements
systems and payments system frequently to
consider all the necessary appropriate combined
factors that determine the payments systems for
salaries, bonuses or incentives for low level of


employees to high level of management. For
example, Oil & Gas Company that face annual
loss or will face difficulty in availability of cash
and need to reduce its costs shall give more
weight for factor of finding oil and commercial
oil and factor of reducing costs more than other
factors such as HSES factor to enable
management and employee to focus on
maximizing their productivity by lower costs,
but if the opposite is happened. If Company pays
more attention to HSES than any other factors,
management and employee will focus on
spending more money for HSES that its cost
may exceed the benefit because it will be easily
achievable for management and employee and
distract management attention and energy from
generating profit from normal course of business
and reducing costs, that will lead Company to
generate its profit and cash flow from abnormal
course of business such as selling working
interests which could have been potentially and
significantly profitable for the company in
future. HSES is important but should be
combined with other important factors and be
weighted based on the strategy that company
want to follow.
Also, clear promotion and recruitment policy
and procedures help company to control labor
costs and increase labor efficiency.

3.3) Overhead Cost
Overhead costs are costs that cannot traced to
particular object of costing. Most of such
overhead are fixed over time but such cost
cannot be indirect for all cases, it can be traced
to specific cost center but cannot be traced to
specific project or production. The most likely
costs that are considered overhead are
Headquarter’s expenses that are considered as an
overhead costs. And many of PSAs does allow
to recover part of foreign Headquarter’s costs as
cost oil but not all overhead expenses.
Therefore, many Petroleum Companies are
seeking to cut such costs by using their facilities

7


and capabilities as fully as possible. However,
those PSAs allow to recover all direct overhead
of offices allocated in the host countries but they
need to use either appropriate basis or equal
basis for allocating such costs to the licenses
obtained. Therefore, the part of allocated
overhead to exploration block may lead
Petroleum Company to reduce such this
overhead cost.

4) Cost Drivers Identification
The costs that cannot be measured, it cannot be
managed but may be cut or void. The costs that
can be measured are costs that varied based on
independent variables and can be stated or
estimated in a formula by identifying the unit of
activity that causes the changes in prime activity
costs and the price of unit activity. Developing
cost drivers in formula is as follow.
Total Cost = Variable Cost + Fixed Cost
Variable Cost = Cost per unit x quantity used

Petroleum Company should prepare Cause and
Effect Analysis to know how different factors
and variables relate together and can effect the
costs of particular object.

4.1) Direct Cost
Direct costs can be charged to particular object
of costing, either project, cost centers or
production. Most of direct costs are variable
costs that are vary in total to changes or activity
of project, cost center or production. labor cost
formula and materials formula.
Labor Cost = Labor rate x Labor hours + Constant labor
cost when labor hours is 0
Cost of Materials = Unit cost of materials x quantities of
materials consumed + Constant cost of materials when
consumption of materials is 0
Cost of Services = [Labor rate x Labor hours + Constant
labor cost when labor hours is 0] + [Unit cost of
materials/equipment x quantities of materials/equipment


consumed x period of time to be used + Constant cost of
equipment when equipments are not used or in standby]

4.2) Fixed and Indirect Cost
Fixed costs are stay constant regardless of
activity or throughout the production level, life
of a project, depth of drilling well, time spend to
use equipments or materials

4.3) Sunk Costs
Sunk costs are irrelevant costs that cannot be
varied by obtaining different decision and need
not to be considered in decision analysis. The
historical costs and fixed costs are most likely
considered as sunk costs.

5) Cost Control Techniques
Cost control techniques can help Petroleum
Companies achieve good financial results and
overcome difficulties they face. Cost control can
allow Company to know if they are really spend
more than it should be for petroleum
exploration, development and production. The
below techniques will give our accountant more
information about how to manage such costs.

5.1) Cost and Contract Analysis
Petroleum Company shall breaking down the
cost and classifies them by management
function and nature to enable to assign
responsibility of cost to appropriate management
or department and should track them and record
them in proper cost accounts.
Management accountant, cost analyst or cost
controller should develop Worksheet of actual
costs and applying statistical analysis to
determine the correlation between cost and
variable factors.
Management accountant, cost analyst or cost
controller should conduct with technical staff to
know the appropriate relationship between
variables and costs formulas.

8


Petroleum
Company
should
authorize
management accountant, cost analyst or cost
controller to analyze service contracts and
measure the hidden (implicit) costs of
Contractors due to inefficiency, missed details of
Statement of Work (SOW), inappropriate
evaluation criteria, inappropriate applying tender
and procurement process.
For example, Petroleum Company can calculate
the total costs incurred by its drilling service
contractor. Contract Analyst should consider the
efficiency of drilling wells and experience of
driller by computing the hours that it is taken for
trip time for changing bits. The lower hours the
higher efficiency of contractor is and lower costs
can incurred. Also, the higher experience
drilling engineer, the lower probability of lost
circulation and stuck pipe that are due to lack of
knowledge and experience of personnel or
drillers then the lower costs can be achieved.
The higher technological which driller use, the
lower costs can be achieved by avoiding lost
circulation and stuck pipe. Also, the experience
of drillers or drilling personnel or management
to drill in different type of drilling such as
horizontal drilling or deviated drilling that can
reduce the total costs by saving the cost of site
construction.
Missed Contract details that describe the SOW,
open contract, providing information unequally
to suppliers with knowing that changes will be
incurred after winning the business can cause
higher services costs.

5.2) Reporting and Accounting System.
Management accountant or cost controller shall
realize that different companies use different
financial and cost accounting system.
Petroleum Company shall combine between
financial and cost accounting and determine
which cost accounting system is the best to help
several level of decision makers. Also, cost and


financial reporting is important to know the
profitability and measure the performance of
Petroleum business segments.
Financial accounting is different from cost or
project accounting, Company’s system should
be designed in manner that can provide relevant,
reliable, consistent and comparable information
to several stakeholders. The financial
information is most likely used by investors,
creditors, analysts, stock brokers, government,
management and employees but the cost or
project accounting information is most likely
used internally by different level of management
and employees.
Financial and cost accounting system should
categorize, group and consolidate transactions or
events by designing accounts codes that
determine the transactions that can be
categorized, grouped and consolidated and
reported in specific manner to meet the financial
requirements which is ruled by GAAP or IFRS,
and that could be categorized, grouped and
reported in specific manner to meet the cost or
project requirements which is ruled by
prevailing industry’s practices, stakeholders’
needs and company policy.
We will assumed that how the costs of two
vehicles hire, one is leased for supporting
seismic acquisition activities and it is nonrecoverable and another is leased for supporting
development activities for drilling Well A, how
these costs should be recorded in the financial
and cost accounting system. Company’s system
include chart of accounts that contains the
financial accounts, project and cost accounts,
cost recovery accounts. Let’s assume that
seismic acquisition compaigne was approved by
AFE300 and it is categorized under sub-account
No. 10 that is assigned for G&G expenses and
G&G is expensed but intermediated by second
head account no. 70 and first head account No.
02 which is assigned for exploration and

9


evaluation and element cost no. 6000 is assigned
for vehicle hire. Also, the AFE200 for well A
campaign was approved by partners, which is
categorized under sub-account no. 25 that is
assigned for drilling cost which is under second
head account no. 20 that is assigned under
development costs and first head account no. 02.
And R is assigned for the recoverable costs code
and N is assigned for the non-recoverable costs
code. The coding will be lined as follow:
02.70.10.AFE300.6000.N
02.20.25.AFE200.6000.R
Based on the above coding line. The coding
contains Financial accounting codes that
represents exploration and evaluation code (02),
exploration (70) or development (20) codes and
financial activities coding that determine if it is
seismic or drilling the seismic acquisition code
is (10) and drilling code is (25) + Projects
accounting codes which is flexible codes that is
established based on AFE for example (seismic
acquisition AFE300 and AFE200 for drilling
Well A) + cost accounting code that represents
the detailed type of costs and assigning code
6000 for vehicle hire+ Recovery accounting
codes.
Based on appropriate accounts coding, the
Company will be able to generate the
appropriate reporting for several purposes. And
based on the above example, the company can
generate financial statements by grouping all the
amounts of transactions that contains exploration
code (70) in the income statements under
exploration expenses and development cost that
contains code 20 under capital expenditures of
exploration and evaluation balance. Also, can
generate cost reports that grouped the costs by
function (exploration, development), activity
(G&G, seismic acquisition or drilling) and by
detailed type of costs elements, and can generate
a cost recovery report to the government by


grouping the transactions that contains recovery
code.
Also, the financial, project and cost accounting
systems must be integrated, the system should
be designed smartly to enable to enter nonfinancial input data in the project systems and
cost accounting system such as volume of
reserves, volume of production, depth of well,
area that run seismic based on service requisition
or technical reports on frequently basis to enable
the cost accounting system to calculate the cost
of production, and cost at completion for
projects and completion percentage for
managerial purposes and determine the DD&A
and accrued expenses for financial purpose.

5.3) Budgeting
Budget is tool for planning at the beginning of
the period and can be used as tool of control at
the end of the period to help management to
measure the performance against plan of sales,
capital expenditures, production cost. Therefore,
Petroleum Company prepares comprehensive
Master budget by using computer software to
enable Company to compare the actual figures to
estimated figures easily.
Petroleum Company may use one or all of the
below type of budget processing.
5.3.a) Traditional Budget
Traditional budget is adding and subtracting a
percentages in comparison to last period to find
new budget for the coming year. This is more
appropriate to be used for utilities expenses,
sales budgets and specific production costs
items.
5.3.b) Zero-Based Budget (ZBB) and ActivityBased Budget (ABB)
ZBB and ABB examine costs and benefit for all
activities, ZBB start from scratch but ABB not.
These techniques help Company to measure the

10


Where: Variable Cost per unit = Direct
Production cost ÷ Volume of production in
barrels

performance of management’s effectiveness but
preparation of ZBB consume lot of time to be
prepared. Many Oil and gas companies use
project budget which is more similar to ABB.
Theoretically budget can be used for identifying
standard costs for all cost elements, but
practically standard costs cannot be used in
petroleum upstream industry for all cost
elements, it might be used to time writing costs
to monitor and plan for the cost of expatriates
but it is difficult and impractical to apply
standard costing system for all costs elements.

6) Breakeven and Cost-Volume-Profit
(CVP) Analysis
CVP and breakeven analysis help management
accountant to perform useful analysis. breakeven
is branch of CVP analysis that determine the
sales which matches the costs and generate zero
profit.
Petroleum Company can use CVP
breakeven analysis to know the following

and

a) Daily production and sales volume that
is required to breakeven
b) Daily production and sales required to
earn a desired profit.
c) How the changes in oil/gas price,
variable operating costs and fixed
Finding & Development costs.
However, the oil/gas price is less to be
controlled, but Major oil producers and
consumers in the world participate in determine
the oil/gas price in world market. Therefore, rise
of breakdeven price is mainly caused by
increasing in operating costs and increasing in
F&D costs. The below formulas compute the
breakeven point (BEP) and CVP in units.


Where: Operating Profit before tax = Net profit ÷
(1-Tax rate)

7) Leverage
Leverage is common techniques is used in
Petroleum upstream industry, it calculates the
operating leverage and financial leverage which
shows how much an sales increase/decrease by
1% can expect Company’s Earning Per Share
(EPS) to increase or decrease by percentage. The
high degree of leverage is, the high risk the
Company would face if the production or
commodity price is declined.
The high oil/gas price enable inefficient
producers to continue exist and enables to
produce from inefficient wells which it was
infeasible before increase of oil/gas price and
become feasible after rising price of oil.

8) Performance
Scorecards

Measurement

and

Performance is measured through Key
Performance Indicators (KPIs) which are
essential tools used by management to
understand how far their business is successful.
The KPIs are grouped together and presented in
dashboard which is called scorecard to enable
the management to take a glance over the view
of how the Company is performing its business.
Most of Scorecards grouped such KPIs into four
perspectives or more as follow:
Financial perspective measures the performance
of for-profit organizations whichever they are

11


public or private. Financial perspective includes
the following KPIs
-

Operating Profit Margin

Operating Profit Margin can provide an
indication of the operating efficiency of a
company. Operating profit is calculated by
deducting the operating costs from revenue
generated from normal course of business, the
revenue generated from extraordinary items or
discontinued operations is not considered, and
divided by the operating revenue to get
operating profit margin:
Operating Profit Margin = (Revenue – Operating
Cost) ÷ Revenue
The information of the above formula is
obtained from the financial statements and
periodical financial or accounting reports of a
system. Company can monitor this indicator on
monthly, quarterly and annual basis.
If a company faces difficulty to generate revenue
from normal course of business activity and
operating profit margin is reasonably high, it can
give an indication to cost leadership strategy that
company may follow and the ability of
managing operating cost well, otherwise, the
company may seek to sell part of its working
interests to generate revenue and recover part of
its costs.
-

Net Profit Margin

Net Profit Margin can provide an indication of
the overall business efficiency of a company.
Net profit is calculated by deducting the
operating costs, financing cost, general and
administrative cost, cost of extraordinary or
discontinued operations from all revenues that
are generated from normal course of business, or
extraordinary and discontinued operations, and
divided by the operating revenue to get
operating profit margin:


Net Profit Margin = (Revenue – Operating Cost
+ Other Income – Finance, G&A & Other
expense) ÷ Revenue of normal course of
business
system. too Company can oversea this indicator
periodically.
If Company faces low operating profit margin
and high net profit margin, it gives strong
indication that Company generate revenue from
not main business activity e.g. sell part of its
working interests in some licenses
-

Total Shareholder Return/ Return On
Equity

Return on ordinary Shareholder’s Equity
(ROE) measures the profitability exclusively the
return on the real owners’ funds. Stockholders
are primarily interested in the relationship
between net income and their investment in the
company. This is probably the single most
important ratio to judge whether the firm has
earned a satisfactory return for its equity-holders
or not. Its adequacy can be judged by comparing
it with the past record of the same firm, interfirm comparison and comparisons with the
overall industry average. The higher rate is, the
more efficiency in utilizing the owners’ funds.
ROE = (Net income-Preference
dividend)/Average Ordinary Shareholder’s
Equity
system. Company can measure its profitability
frequently.
The more costs are decreased, the higher ROE
ratio will be. The high ROE gives an indication

12


that company does not need to depend on loan to
finance its projects.
-

Capital Expenditures to Revenue Ratio

Oil and Gas Companies intend to acquire new
property, develop current proved property, or
even explore unproved property to generate
future benefits. This ratio is comparing the
capital expenditures to sales or revenue (Capex
for specific period ÷ Revenue for the same
specific period) which gives us impression of
how much Company is investing for future
benefit. Lower ratio is not always good
indication and vice versa for higher ratio. To
know how better the Company invest for future,
the ration should be compared with the average
industry or other peers’. Also, Company should
consider that much investing in petroleum
acquisition, exploration, development without
producing enough oil or gas can give bad
indicator about the technical management
performance of Company.
Information for calculating the above ratio is
obtained from accounting or financial systems.
But different accounting method can lead us to
different results and misstate this ratio, but many
companies prefer to charge all the exploration
cost to Capex then to take it off to expenses to
give total capital expenditures for the current
period.
-

Price/Earning Ratios

Many companies use price/earnings ratio to
know how their stocks (shares) are attractive in
stock market for potential investors. This ratio
searches for the relationship between the stock
price and company’s profit.
P/E Ratio = Current stock price ÷ (Net profits
per share)
Also, this ratio can express the time for
recovering back the initial investment in buying


Company’s stock. In cost management, P/E ratio
can be increased if the cost managed to be
reasonably decreased. Therefore, the higher P/E
ratio is, the more stock is attractive for potential
investors who pay more for each dollar (unit of
currency) of net income, and the more expensive
the stock is.
-

Finding & Development Cost Ratio

It can be used for evaluating the efficiency of a
company in adding new reserves. If we want to
measure the performance of technical
performance of companies or managements the
finding cost ratio which include only exploration
costs the reserves extensions and discoveries can
reflect how efficient they are, the high ratio, the
more efficient they are. To know how the overall
efficiency or experience of company’s
management, we can consider all the costs and
all reserves additions into your considerations.
[Charlotte J. Wright and Rebecaa A. Gallun, 5th
Edition, 2008,Fundamentals of OIL & GAS
Accounting, PennWell Corporation, Tulsa,
Oklahoma, USA. Page 711-713]
-

Success Rate

This rate is calculated by dividing the cost of
drilling successful well to total cost of
investment in drilling wells, that shows the
performance of exploration and drilling
departments. The higher rate is, the higher
technical performance Company has and good
indication that Company is managing its Capital
expenditures well.
-

Present Value of expected cash flow for
proved and probable reserves per share

McDep LLC is independent researchers focused
on stocks of oil and gas Companies, which
originate McDep ratio that measures Company’s
ability to generate discounted cash flow in future
from oil/gas or other business for covering its
market capitalization at current stock price and

13


BCWP = Percent work complete x Initial Budget
Cost (BAC)

debt. The Company that is low Market
Capitalization and debt to present value of
oil/gas reserves and other business is performed
better and more profitable than Company’s stock
is high capitalization and debt to present value
ratio.

Where: Percent Complete = BCWP ÷ BAC

-

It computes the difference between actual
cost and what it is expected to spend.

Internal process perspective include the
following KPIs
-

CV = Budgeted costs for work performed
(BCWP) – Actual costs for work performed
(ACWP)

Capacity Utilization Rate

Capacity utilization is good measure that
provides management with oversight how the
production facility units are utilized and are their
appropriateness to the production when they are
purchased.

Positive CV gives better indication of doing
better on costs than it is planned.
-

SV = Budgeted costs for work performed
(BCWP) – Budgeted costs for work scheduled
(BCWS)

The lower rate is, the more slacks are, and
higher inefficiency is in the process. And can
give strong indication that Cost of facility
equipments is high too because Company
purchased assets has much higher capacity than
the wells can produce. Which can increase the
finding cost, DD&A, decrease the operating
profit and net profit that may lead Company to
face difficulty in profitability in future.

Positive amount indicates that project is a
head of schedule and negative variance
reflects to beyond schedule
-

Cost Performance Index (CPI)

It is the rate at which project performance is
meeting cost expectations during a period of
time or from beginning up to a point in time.

Information for calculating the above rate is
obtained from technical internal process system
and capacity of facility equipments can be
estimated and obtained from equipment data that
is provided by manufacturer.

CPI =

If the CPI is equal or greater than 1, it is
favorable value that indicates cost
performance is perfect or physical progress
is accomplishing at less than forecasted
costs. and vice versa

Earned Value or Budget Cost of Work
Performed (EV or BCWP)

Earned Value is one of operational processes
that used as a tool for combining costs,
schedule,
performance
and
risk
managements. It measures how much the
value of actual work performed during
period of time


Schedule Variance (SV) and SV%

It computes the difference between where
the project is and where the project is
planned to be in the schedule.

Capacity Utilization Rate = Actual production per
day ÷ maximum quantities is produced per day for
the facility equipments.

-

Cost Variance (CV) and CV%

-

Schedule Performance Index (SPI)

It is rate which project performance is
meeting schedule expectations up to point in

14


a time. The performance Indices measure
the efficiency as percentage.

It is the expected cost that is required to
spend from the current point of time to the
end of the project.

If the SPI is equal or greater than 1, it is
favorable value that indicates schedule
performance is perfect or physical progress
is accomplishing at faster than planned
schedule. and vice versa and vice versa
-

-

It measures the difference between the
original budget and what we expect to spend
at completion. If the result is positive
amount it indicates that Project team is
doing better than projected and negative
indicates to project is run over on costs.

Estimate At Completion (EAC)

Is the amount which the project is expected
to cost at its completion.

Variance At Completion (VAC)

or

EAC is frequent evaluation of project status.
The revised EAC does not mean that
corrective action is taken. Company should
know the factors that cause the increase in
EAC to know where is the overrun activities
that occur high cost? It is preferred to
identify the EAC by group of activities to
consider the actual or revised of work
packages not yet begun into the calculation
of EAC.

Project Manager or Cost controller should not
only monitor the costs, they should manage the
costs. Cost controller should prepare Project
Reports to the executives and internal auditor
that contain the following information:
-

-

Also, Time at completion (TAC) is useful to
now the new length of the project, the longer
the project is the longer time and higher
costs it needs to be completed.

-

-

Estimate To Completion (ETC)


Performance that show the progress to
date such as PV, EVand AC, and
material procurement and usage if there
is no any Materials Report issued by
Materials and Logistics.
Status that identify where the project is
today and shows CV and SV.
Projection that calculate the EAC, ETC,
SPI and CPI.
Exceptions that justifying the variances
and identify the problems, causes and
situations.
o Indication of drilling problems such
as the flow out and flow in, mud
return rate, mud pit volume, cannot
pickup pipe.
o Causes of drilling problems such as
high formation permeability, low
formation pore pressure, using

15


wrong drilling fluid or mud weight.
Carving, differential pressure.
o The results of drilling problems
such as Cost of mud used, cost of
fishing, loss of hole.
The lessons that are learned from
drilling programs. Such as Lack of
experience and knowledge of personnel,
and needs of crew education, and study
wells in area, using centralizers, drill
collars.

of leadership, communication, culture or
work environment and staff development
opportunities. Scoring the answers and give
high rate for positive answer and low rate
for negative answer, then compute the
percentage of total scores to total questions.
The higher index the better indication of
higher satisfaction.

Learning and Growth perspective this
perspective focus on employees. Nowdays and
in future the employees represent significant
assets. However, such assets are not
accountingly recordable in ledgers. This
perspective include the following KPIs

Recruiting and developing employees take
long time and more cost. Employee
retention save such time and costs. Also,
replacing
employees
or
promoting
inappropriate people can cost company a
lot.. Therefore, oil and gas companies
intended to recruit and retain talented staff
specially in technical and finance or
accounting departments. The company can
monitor the employees turnover by tracking
the such ratio overtime and in different type
of job. The employees turnover is calculated
by dividing the Total number of leavers in
specific job over specific period by average
total number of employees during the same
period. The lower ratio the more
employment settlement is, indication of less
problems
in
management
practices,
philosophy and leadership style and less
costs and time incurred in recruiting new
employees

-

-

-

Human capital value added (HCVA)

Human capital value added is calculated by
adding the employment costs to operating
profit and dividing the results by number of
full time employees. The bigger the ratio
overtime, the better profitability per
employee goes.
-

Average employment and training costs
by skills

The average employment and training costs
by level of skilled employees provide
management the cost rate of different level
of skilled employees which can be used for
cost allocation or to enable the company to
know how much they spend for each level of
worker in salary or training and whether the
cost
-

Average employee tenure ration enable
Company to know how long its employee
stay in the organization on average by total,
gender, level of management, type of job or
departments. The longer tenure the lower
costs incurred for recruiting and training
staff. Also, the longer tenure indicates to
high employee satisfaction and loyalty to the
Company. Average employee tenure ration
(AET) is calculated as follow:

Employee satisfaction index (ESI)

To measure employee satisfaction, the
company needs to have survey, ask few
questions and ranking the optional answer,
the survey questions needs to cover the style


Employees Turnover and average
employee tenure

16


∑(Years of service x (Number of
employees) ÷ Total number of employees
-

Salary Competitiveness Ratio

Company needs to know how much they
pay to their employees in comparison to
competitor’s pay or market price to
employees in similar position and job area to
enable Company to know if it is potential
employer and if payment is a reason to leave
the company. This ratio can be calculated as
follow and for specific job and position and
by industry.

court. HSES cases always have civil disputes
that caused by accidents, illness, breach of law
or contractual terms and negligence.
The employers should reasonably and
practicably ensure they achieve minimum legal
and ethical requirements of HSES and welfare of
all employees that can include the following:
a.
b.
c.
d.
e.
f.

Salary competitiveness ratio = Salary
offered by the Company ÷ Salary offered by
the competitor or market
Company should consider the efficiency,
effectiveness and proficiency of employee
too before paying more than competitors or
above industry average because paying
salaries to inefficient and ineffective or low
proficient employees costs a company a lot
for low quality of work.

Corporate Social Responsibility Perspective
Health, Safety, Environment and Security
(HSES) issues have criminal and civil effects.
The criminal law imposes on natural or in-kind
personnel for protecting another natural or inkind personnel. Criminal court may allocate the
punishment among the personnel who commits
the offences. Court can award compensation to
victims or injured party. Civil Law concerns
about the disputes between personnels. Plaintiff
may bring complaint to court to get
compensation and defendant try to reduce the
compensation through involving the plaintiff in
contributory negligence. Civil courts is looking
for liability of two parties rather than for guilty
and non-guilty that are concerned by criminal


Safe System or Work
Training and Supervision
Safe place of work
Written Safety policies and procedures
Insure for work accident and fidelity
Safeguard materials and people who are
not in their employments but affected by
employers’ activities

Employees should take reasonable care of
themselves and others who are affected by their
activities, and should follow Company’s HSES
policy to enable Company to achieve their legal
obligations and reducing potential risks.
Suppliers or contractors must follow Company’s
HSES policies or their own policies whichever is
better for eliminating or reducing risks of HSES.
As we indicate to employer’s responsibilities
that HSES policy should be maintained and
monitoring its application. The HSES policy
should be clearly and simply stated to be
understandable by different level of skills. The
policy should include the following:
a. Names and position of HSES people
who are in charge and HSES advisors
b. Duties toward each others (employers,
employees, suppliers, customers,
community)
c. Short-term and long term objective
The HSES’s objectives and performance targets
could be mentioned in brief as follow:
a. Reducing number of accidents

17


Environment pollution is one of most
serious challenges that our planet is
encountered. Most of Oil and Gas
Companies play important role to mitigate
the environment pollution, the most
effective index that measure the pollution
rate is “Carbon/gas mission rate”, “waste
reduction rate”. Many countries adopt
legislation for environment protection. Also,
some oil and gas companies might be
granted ISO 14001 that cover the
environment protection requirements. The
lower pollution rate that caused by
Company, the less long-term costs may be
incurred and higher image the company can
create for itself among community. For
calculating the carbon or gas emission rate,
the following factors should be considered:

b. Reducing number and period of
absenteeism.
c. Reducing criminal and civil claims
d. Achieving international or national
Safety requirements and obligations
Company shall frequently assess the risks of
HSES by determining the volume and costs of
severity and the likelihood of occurrence. Then
to determine the proper and urgency of actions.
However, HSES is new and important issues,
Companies should not exaggerate its care of
HSES on other accounts of successful factors.
Company should always look for cost and
benefit of HSES controls.
Corporate Social Responsibilities include the
following KPIs:
-

Injury/Incident Index

o
o
o

Health and Safety issues could cause
increasing
costs
that
represents
compensation to injured party, violation of
regulations, cost of losing opportunity for
hiring skilled employees, attracting new
long-term and ethical investors or
contracting with high quality-experienced
suppliers and paying high insurance
premium.

o

-

Gender Work Participation

Woman and Man are working to improve
their community. After activating the
international organization for woman rights
and claiming for equality with man in
obtaining equal opportunity for working and
conducting
managerial
duties.
Oil
Companies’ social responsibilities are to
enhance
gender
work
participation.
Therefore, some oil companies announce in
their sustainability report the gender work
participation in different level of
managements.

Company should measure injury/incident to
total working hours ratio which reflects the
reduction of criminal/civil claims, reduction
of number of accidents/injury and reduction
in costs.
The Injury/accident Ratio is calculated as
follow:
Injury/Accident Index = Number of injury or
accident ÷ Total working hours * specific
numbers

-

Number of business travel
Energy consumed by company
Transportation of materials and
commodity
Waste generated.

Female employees Percent
Number of Females in Company

Total Number of employees

Pollution mission rate

18


The higher female employee percent
encourage the high skilled woman to join
working in such companies. Also, to reduce
number of claims that are related to gender
discrimination if companies take such target
seriously.

9) Cost management by nature
The below formulas are basic formulas for
calculating, drilling costs per day, cementing
costs services, mud services, casing and
wellheads costs and production costs. Those
formula are very easy to understand by nontechnical professional, however, complex
calculation for cementing, mudlogging, drilling
fluids and others are not easy to be done by hand
of non-technical professional due to complexity
that need technical staff to use specialized
program to solve the problems.
Those basic formulas can help management
accountant, cost controller who are not engineer
to understand the variables of drilling and
production costs in Petroleum upstream
industry.

Using inappropriate bit and drilling fluids or
mud during drilling, may lead to reducing the
penetration rate, increasing drilling problems
,expanding drilling length time and increasing
the total costs. However, using heavier bit
weight in harder formation, increase rotary
speed, and using light mud weight are good
alternatives to increase the penetration rate and
reducing the drilling costs, problems may be
occurred during the drilling such as failing to lift
rock cuttings to surface and results stuck pipe or
fails to keep high-pressure formation under
control that results in gas kicks or blowout.
The above formula is the preliminary calculation
of drilling cost. However, there many factors
that could indirectly participate in cost
reduction. There are many other drilling costs
that may has significant relative amounts
specially if there is drilling problems such as
stuck pipe and lost circulation problems.
Also, there are other costs that are not covered
by above formula that are related to the
following activities and materials.
a)
b)
c)
d)
e)

9.1) Drilling Cost
To know how to control and manage drilling
costs, we need to know the main cost drivers of
drilling costs. The Below formula can help us to
compute drilling costs which are effected by
variables that could be controlled and managed:
Drilling Cost = (Bit Cost + Rig Cost x (Drilling Time +
Trip Time)) ÷ (Length Drilled)
Drilling Cost => drilling cost $ per length unit ($/ft, $/m)
Bit Cost => bit cost, $
Rig Cost => rig cost per hour, $ / hour, cost of hiring rig
may represents 25% of total drilling costs. Rig rate is timebased drilling cost
Drilling Time => total drilling time, hour
Trip Time => trip time taken to change bit, hour
Length Drilled => total length drilled by drill bit, ft or m


Cementing and fluids materials
Cementing and drilling fluids Engineers
Casing and tubing
Testing and logging
Completion cost

Petroleum Company shall perform cost analysis
and determine, categorized the causes of
increasing costs objectively and find out the
appropriate resolutions to reduce such costs.
For example, if the higher costs is due to human
errors, Company may need to train current staff
or find replacing current technical staff with
higher experienced skilled staff. And if they are
refer to inefficient and effective contractor,
Company may updating evaluation criteria to
stop dealing with such Contractor.

19


9.2) Petroleum Services
Petroleum services may represents about 20% of
total well costs, Petroleum services cover, mud,
cementing, mud and testing. Cementing and
Mud, logging is depth-based drilling costs.

Cements are should be used with slurry and
other additives. The additives should be added in
specific percentages to enable the cements to be
binded fast. The more lost circulation is, the
faster binding particles is needed for cementing
materials.

9.2.1) Cementing
Cementing is used during drilling operations to
support casing and stop moving fluid outside the
casing, and to protect casing from corrosion.
To determine the required total sacks of lead or
trail cements, we need to know how many sacks
are required in annulus and in casing or yield
quantities of lead cement.
Number of sacks of lead cement required = Feet to be
cemented * annular capacity ft3/ft * excess ÷ yield
ft3/sk lead cement.

Per the above formula the volume in casing is
measured in sacks and additives can be
measured in bbl, where 1 bbl equal 42 US
gallon. Company can estimate the cost of
cementing and additives costs by multiplying the
quantities in sack, bbl or gallon by unit price.
9.2.2) Volume of Mud
To determine the volume of mud to fill up the
inner of the cylindrical objects, it can be
computed by the following equation.
Inner Volume, bbl = Inner Capacity, bbl/ft x Length, ft

Number of sacks of Trail cement required = Sacks
required in annulus + sacks required in casing.
Sacks required in annulus = ft to be cemented * annular
capacity ft3/ft * excess ÷ yield, ft3/sk Tail cement
Sacks required casing = no. of feet between float collar &
shoe * casing capacity ft3/ft ÷ yield ft3/sk Tail cement
Casing Capacity, bbl = Casing capacity, bbl/ft * feet of
casing to float collar.

Drilling Engineer can compute the volume of
mud, cementing any many drilling costs that is
supposed to be occurred in specific well based
on the several well information that is obtained
from contractors and company’s representative
in the field. The project cost system should
segregate the duties between the Company’s
representative in the field site and drilling
engineer in the office to verify the information
that is obtained from Company’s representative
in the field site to drilling logs readings. Project
Cost System or Cost accounting System need to
be designed to ensure the existence, accuracy
and completeness of vendor’s billings with the
technical information and Report any exceptions
noted to be adjusted or solved manually for
flexibility characteristic of the system.
9.2.3) Well planning, Site Construction/Civil
Works and Rig Move .
Mobilization/Demobilization, Rig move, site
construction and well planning represents about
10% of total well costs and they are considered


20


as fixed costs regardless the depth of well or
days lasts for drilling. But they are varied from
well to another except for mobilization and
demobilization they are fixed in total but they
can be varied in average based on the number of
wells that are drilled. Rig move is fixed in total
and average regardless the number of wells
drilled.
For well planning, the Company can reduce
drilling costs by appropriately design well plan
and considering the mistakes that were made in
the past to predict the future. Also, Company
should properly determine the proper labor
needs of skill and experience. Well Planning
costs might be high if the Company prepare well
study for new basin that it does not have
adequate technical information but when the
Company purchase several data, make and
process seismic, consider the information of
previous wells drilled, the well planning does
not take time to be completed and get more
accurate information.
Civil work costs can be high if the Company
does not plan for it feasibly, oil companies may
spend a lot of money for asset protection and
civil works that are unnecessary and
inappropriate ways e.g. pay much money in cash
to local community people that can be
questionable for type of fraud or illegal acts.
Also, such practice of paying cash money to
local community people make the Company to
carry high costs, and this cash money can be
misused by local community people which
threatens the interests of Company and host
government instead of obtaining benefit. The
more civilian activities (e.g. building school,
clinic, drilling water well, and others) that are
performed by Company, the more benefit the
Company will take from local community by
reducing the future community affairs and
security costs in long-term.


However, Site construction costs can be high too
based on the ecological features of the location,
Company can reduce the site construction costs
by awarding the contracts to the best vendor and
by transparent tender invitation and by
eliminating the duplicated or unnecessary civil
activities but locating one civil camp in near all
the sites to serve all wells and the entire property
efficiently.
9.2.4) Testing and Long-term Production Tests
Testing costs can be the major part of well costs.
And the well test is made by well logs and drill
stem test that will be explained below in brief.
Litholigical Log is sampling and coring test that
helps engineer to lists the depth by geological
rocks and describe the rock to note the rock
textures, color, grain size, cementation, porosity,
microfossil. The source of such information is
from samples of rock cuttings that are flow out
to the surface during the drilling
Mud Log is chemical analysis of drilling mud
and well cuttings that determine the rocks which
bear oil or gas. The abnormal expected
information in this log is called “show”
Wireline Well Logs are a readings obtain either
during drilling well or after drilling well but
after cleaning well by circulating drilling mud
and pulling drilling equipment. For knowing the
main purpose or advantages of such logs. Please
see the below table.
In drill stem test (DST), drillstring of perforated
drillpipe which can be less than 5” run into the
target formation in the well. Two packers are
installed between the upper and lower level of
probable productive formation to enable the oil
gas to flow into the well and if the oil or gas is
adequate to be flowed up to surface the pressure
gauge and valves measure the flow. The valve is
opened and closed on several times to record the
pressure and to calculate the formation

21


permeability and reservoir pressure. The longer
test is, the more accurate information is and
more costs occurred. The hydrocarbons that are
located in porous formation can be tested within
30 days and get accurate information of gas or
oil but for the hydrocarbons that located in the
fractures of basements take more than 30 days
and might be reach to two years for adequate
testing. In this case the testing is called Longterm production testing.
The questions are whose is the title of
production tests? And how the costs and revenue
of long-term production testing is accounted for?
The title of the production tests is depend on the
host government and PSCs. If the PSCs or host
government’s regulations gives the Company
right to share the specific percentage of longterm production tests. The revenue of sold
production testing petroleum should be offset
against development costs in accordance IAS
16.17.e. For entering long-term production
testing phase, Company should determine the
costs and benefits of taking such decision and
ensure that the revenue from production test will
exceed the incremental costs of obtaining such
decision.
Development and drilling department and
exploration program manager needs to reduce
testing costs to the minimum level. Drilling
manager needs to not request tests in formation
that does not show good show during mud log or
in formation location which hydrocarbon may be
migrated from since very long time ago. Also,
Drilling manager should not request different
well logs that gives almost the same results, or
asking for running a well log that its result might
not be used or considered. Not merely, Drilling
or exploration manager should not request
equipment for specific well log and using
different log which lead company to pay standby
rate of unnecessary well log or the formation or
type of drilling may not need such type of


logging. And extending the period of tests for
less potential formation can lead to increase
unnecessary costs too. All the above points need
to be considered and the drilling manager or
exploration manager should think and plan
appropriately before determining the well log,
period of test and target formation that will be
tested.
Also, Engineers should to detect their seismic
processing mistakes and interpreting the seismic
processing based on their readings of well logs
and revise their seismic mapping based on the
well logs and to have more comprehensive and
deep knowledge of the geological formations in
basin to reduce the probability of dry wells and
reduce the costs, or reduce the probability of
facing lost circulation or stuck pipe during the
next drilling wells

9.3) Management and Supervision
Studies, drilling management and supervision
may represents about 5% of total well costs but
such costs could be more than 10% for less
efficient supervision and management if the
company does not have effective performance
measurements method.

9.4) Casing, tubing & Wellhead
Wells costs contains the cost of wellhead, casing
and tubing and several accessories costs. Casing
costs is determined based on the following
formula.
Casing/tubing cost = cost per meter * meter of
casing/tubing required for drilling well.

The technical engineers should determine the
depth that needs to be cased in their well plan
and based on their understanding and experience
of the formations.
Procurement management shall buy casing and
wellheads via tender process, obtain the supplier
that can provide good price and good
characteristics of materials and with good terms

22


delivery and payment and in good time. The
procurement management should procure the
suitable quantities of casing, tubing and
wellhead based on drilling plans and should
consider variance between plan and actual.
Drilling and exploration manager should know
preparing plan on early time enable procurement
department to contract with third party to
provide the casing, tubing and wellhead on
proper time before drilling start. Procurement
department and exploration management should
not exaggerate in purchasing bulk of casing,
tubing and wellhead for not facing rigid capital
due to surplus in drilling materials and selling
those equipments and materials at price less than
original costs later on. Also, Drilling and
exploration management should coordinate with
higher management and treasury department for
availability of funds, because unrealistic drilling
plan can cause huge of unnecessary purchases.

Casing Hanger, Oil and gas companies could use
casing hanger to assemble to different sizes of
casing lines instead of running casing from the
surface to the bottom hole and to reduce the
costs but casing hanger might be used or not
depend on the drilling method, characteristics of
rocks of formation and experience of engineers.


9.5) Drilling Problem
8.5.1) Lost Circulation and Kick
Drilling problem can increase the well costs
rapidly within days or weeks. It can exceed the
actual drilling costs if there is lack of knowledge
and experience among technical management.
Lost Circulation is a reduction or absence of
fluid flow up the annulus when it is travelled
through drillstring. Lost circulation consume
time and costs without drilling the well that is
either due to mechanical malfunction of
formation or lack of experience and knowledge
of personnel.
Losses divided into two categories.
1) Minor Loss which it is less than 500
barrels (80m3) or can be controlled
within two days by increasing viscosity
of fluid such as Bentonite or Polymers
with additives
2) Severe loss that is more than 500 barrels
(80m3) or takes more than two days to
be controlled. And this type may lead
the Company to stop drilling the well
and try to move few kilometers to drill
near the first well.
The main causes of lost circulation are as
follow:

23


There are several causes of kick (Wellbore
Influx) that can be listed below
1- Lack of Knowledge and Experience of
personnel who has no ideas what can
causes well control problem e.g.
personnel may pump lighter fluid into
wellbore which reserves pressure may
overcome hydrostatic pressure.
2- Light density fluid in wellbore
a. Light pills, sweep, spacer in
hole
b. Gas cut mud
3- High abnormal Pressure of zone that is
over current mud weight in the well can
cause kick.
4- Unable to keep the hole full all the time
while drilling and tripping.
9.5.2) Stuck Pipe
Stuck pipe is more common problem in Oil and
Gas Industry that causes serious drilling
problems and cost Company by loss of
drillstring and complete loss of well and can be
caused by mechanical malfunction or lack of
knowledge and experience of personnel. The
causes of stuck pipe that we can stated them are:
1) Mechnical sticking that is caused by
physical obstructed or restriction such as
a. Settled Cuttings
b. Cementing sticking or Junk in
the hole
c. Mobile formation
d. Casing failures
e. Hole packoff and bridges
2) Differential sticking that is caused by
differential pressure forces from
overbalanced mud column acting on
drillstring against filter cake deposited
on permeable formation, such as
a. High overbalance pressure
b. Thick Filter cake
c. High-solids or density of muds


Those causes of stuck pipe has warning
signals and preventive actions which the
Drilling Department should be aware of
them.
9.5.3) Fishing Junk or stuck pipe
The consequent of stuck pipe and stuck junk can
cost the company a lot. The costs of consequent
of stuck pipe and junk may include the costs of
unproductive drilling time during fishing and
fishing costs, close well, sidetrack or restart
well.
The number of days that allows for fishing
before taking decision to sidetrack drilling/
restarting the well or milling of junk tools.
Number of days =

Where:
Cs: is the estimated cost of drilling sidetrack, milling
of junk tool or restart well
R: is the replacement value of fished equipment
F: is the cost per day of fishing equipments and
services
Cd: is the cost per day of drilling rig

The formula has been taken from the below
reference (Standard Handbook of Petroleum and
Natural Gas Engineering. By William C. Lyons,
Ph.D., P.E., Gary J Plisga, BS. 2005. Elsevier
Inc. UK. Page 4-378) but it has been revised by
us by subtracting the replacement value of fished
equipments from the estimated costs of drilling
sidetrack, milling of junk tool or restart well.
Our revision in the formula does not indicate
that the formula was not correct, but as per our
analysis in the below Figure 1: Fishing Cost
shows the replacement value needs to be
subtracted to get the costs of fishing that equal to
the costs of sidetracking. If we add the
replacement costs of fished equipment the

24


number of days will exceed the feasible period
of fishing.
Also, the above formula can calculate the
maximum period of fishing that management
must not exceeds because the cost of fishing will
equal the costs of the alternative decision of
sidetrack. If the management decide to continue
fishing after the maximum period, it will give
very strong indication of the poor financial
knowledge of management, more optimistic
decision than it should be or will draw forensic
accountant’s attention to something wrong.
In addition to the above formula, we like to add
the financial formula that compute the
maximum, minimum and optimal number of
days for fishing. We assumed that initial costs of
fishing and sidetracking can be determined, and
daily costs of alternative decision can be
determined too.
The minimum number of days for fishing
Minimum number of days =

∆
∆

Period of fishing can be optimum if the
management consider the cost of risk that could
be carried. Means, management will accept
specific amount of cumulative marginal fishing
that exceeds the expected cumulative sidetrack
costs or to be in compliance with fishing budget
that management should not exceed it.
The optimal number of days for fishing
Optimum period of fishing =

Or
∆
∆

Where:
RT is the risk tolerance or the positive cumulative marginal
costs between fishing and sidetracking/restart well costs

The reasons of junk or stuck pipe has been
briefly discussed previously under stuck pipe
and due to careless during drilling operations
and other reasons that drilling engineer can take
preventive action before it happens.

Where:
∆ Initial costs is incremental costs for sidetrack, start
well or milling of junk tool e.g. cementing and
cementing plugin costs and replacement value of
fishing equipment
∆ Daily Costs is the incremental daily costs for side
track, start well or milling of tools.

The minimum period of fishing enable technical
management to take the decision when the
cumulative daily fishing costs exceeds the
expected cumulative daily sidetracking costs. As
long as the marginal costs of fishing is less than
marginal costs of sidetracking, the fishing
decision is in the safe margin and fishing
process is still valid and management hope to
get the junk out to save costs that could be
occurred by sidetrack activity. This period is
very pessimistic.


9.6) Facility Cost
Facility cost includes tanks, storage, treaters,
heater, meter run, separators, flow-line pipes,
Vapor recovery, circulating pump, Injection
pump. All those items have specifications and
capacity. The procurement department and
development management can manage costs by
reducing the procurement costs via good
negotiation and not trapping themselves
unknowingly with unnecessary specifications.
For example, Company should consider the
capacity of the well, initial formation pressure
and formation pressure decline over period of
time, the power that is supplied by electrical
motor to select the appropriate centrifugal
pumps because the capacity of Horizontal
Centrifugal End Suction Pumps is wide range
from about 2100 barrels per day to 100,000
barrels per day and it is not logically to select

25


pump that can produce 50,000 bpd for well that
its maximum production is 3000 bpd. Not
merely, even the specification of heating and
treating equipments and piplelines should be
properly determined.
Even purchasing vehicle hires and building
camps, Company should consider the
requirement of the production sharing contracts
and applicable laws that may require to buy such
materials for building camps from local market.
Procurement department and development
manager should consider the price and
specification of materials that can be obtained
from local market and international market.
Many Oil and gas Companies may prefer to buy
from international market with very high costs
of such materials and equipments that can
exceed three times of local price and with few
difference in quality which can be tolerated. Not
merely, Company should take care of buying
any equipments and materials that might not be
used. However, Company might find itself
compelled to hire vehicle from locals for
mitigating security risks or hire unnecessary
building or vehicle at high price specially in the
countries that has high Corruption Perceptions
Index (CPI) that is published by Transparency
International (TI). In this case, Company
management should consider their country’s
anti-corruption law and not try to violate terms
of FCPA, criminal code or any anti-corruption
regulations. Also, it should consult legal advisor
for any suspicious transactions.

charged to the license costs, but in practice such
equipments can serve several fields such as oil
plants, pipelines, vehicles and in country offices.
Paragraph 26 and 36 of SFAS 19 are specifically
addressed the depreciation of support equipment
and facilities that are not tied to a particular
field.
As we indicate above, the support equipment
and facilities that support production operations
frequently serve more than one cost center or
multiple activities or multiple licenses that are
owned by different partners often results
disputes in charging such costs to the cost center
or license that are in tied to the same equipment
and facilities. Therefore, Such costs and the
costs that are associated in operating facilities
equipments should be allocated to several cost
category, multiple license based on the
appropriate and fair allocation method of fee
base. We will discuss few of such support
equipments and facilities as below.
-

9.7) Overhead and Joint Cost
Overhead and common costs are a disputed
expense item and draws attention of joint
venture and cost recovery auditors.

-

9.7.1) Facility Cost
Often support equipment and facilities
equipments are not tied to one single field or
license. If they support one field or license, the
costs of such equipments will be directly


-

For example, well testing equipment and
rig may be used on one location that is
in the exploration phase and also on
another location that is in the
development phase. In these situations,
the equipment or rig is being used in
both exploration and development
activities. And fee base should be used
that include the depreciation cost of rig
or testing equipments, idle costs of such
equipment, and associated direct costs
and overhead to compute the daily fee or
rental in condition of not including any
elements of profit.
The pipelines can serve multiple
licenses that each are owned by different
partners, the costs of usage of pipelines
are allocated to appropriate license
based on fee base that is organized by
Facility Agreements.
truck, for example, is being used for
multiple activities and in multiple cost

26


centers, The depreciation of vehicle
should be allocated based on kilometers
driven or some other method. The
depreciation and operating costs would
then be allocated to the activities being
served in the different cost centers.
The portion allocated to production
activities would be written off as operating
expense. The portion allocated to
development costs would be ultimately
capitalized to the wells and related
equipment and facilities accounts in each
cost center that the support equipment
serves. That cost would then be amortized
along with the other capitalized costs for the
cost center using the unit-of-production
method. The portion allocated to the
exploration would either be expensed as
G&G expense or capitalized to drilling-inprogress. The drilling in-progress accounts
would subsequently be cleared to dry hole
expense if the associated well is dry hole
expense if the associated well is dry, or
wells and related equipment and facilities if
the associated well is successful.
Theoretically, the portion of depreciation
relating to the support equipment and facilities
and the operating cost of the support equipment
and facilities should be allocated to exploration
and appraisal, development or production as
appropriate given usage of the support
equipment and facilities or production as
appropriate given the usage of the support
equipment and facilities
9.7.2) Field or Host country office costs
Field or host country office that supports
operations covering a large area serves multiple
licenses and activities of operations, exploration
development. Since some of the costs attributed
to each of these activities or phases may be
capitalized while other costs are expenses, it is
necessary to allocate a portion of offices costs to


the particular activities being served. This
treatment is also required in many operations
governed by Production Sharing Contracts
(PSCs) and Joint Operating Contracts (JOCs)
where the licenses needs to be charged by the
cost of such offices equally or using appropriate
General and Administrative allocation. It is
appropriate to group the same office activities
into cost pool then allocate the costs pools to
multiple licenses or activities based on level of
appropriate usage method.
9.7.4) Joint costs
Joint products or by-products in petroleum
upstream Industry are, crude oil, natural gas and
condensate.

The criteria that differentiates the joint product
and by-product are ;
-

-

The value sales to the total sales of all
products or profit of specific product to
total profit. The sales value or profit of
joint product represents at least 10% of
total sales or total profits of all products
which is presented in the financial
statements as business segment (IFRS
8), whereas, the by-product’s represents
less than 10%
The business and marketing purpose.
Company does not intend to produce
and generate profit the by-product as the
same as main product and by-product
are produced in very limited quantity.

How to allocate joint costs to several petroleum
upstream products?
Allocating the joint costs is necessary to
compute the cost petroleum, tax and sharing
profit petroleum and it is useful for determining
the cost of sales by product segment. There are
many allocation method for allocating the joint
costs between crude oil, natural gas and
condensate, and we can list and explain them in
brief as follow:

27


1- Allocation based on physical measure.
After unifying the physical measure of
different commodity (crude oil and gas)
either to convert oil to cf or convert cf to
equivalent oil barrel, and the net
realizable value of products are most
likely to be the same.
2- Allocation based on Sales Value/net
realizable value at split-off point, is
computing by deducting the separable
costs from sales value
The accounting that is used for by-product
depends on
‐
‐
‐

There is market for by-product
The by-product can be used as an energy
source
The by product can be used for
reinjection

The accounting treatment of by-product can be
either of the following:
1- Income generated from by-product is
reported as “Other Income”
2- Income generated from by-product is
credited the joint costs.
If the by-product is used internally as energy
source or for reinjection to produce main
product, it needs to be valued at net realizable
value of replacement cost at split-off point and
the joint costs of main product can be reduced
by the value of by-product.
9.7.3) Corporate overhead
Corporate personnel and equipments support
multiple licenses and the costs should be
allocated fairly among the licenses.

Corporate overhead may not wholly be
recovered from cost oil, Most of international
PSCs allow the contractor to recover part of it
only. Also, international JOCs allow operator to
recover part of its corporate overhead. But how


the Corporate overhead is allocated between
license. Some Companies may prefer to allocate
it equally or based on profit, sales or total costs
of each license such allocation it is not fair
enough but it might be accepted by PSC or JOC
in condition of not exceeding the allowed
amount.
The each costs pool may require different
allocation base. The below Table shows the cost
pool and allocation base as follow:
Table: Examples of Cost Pool and allocation Base
Cost Pool/Dept
Payroll Costs

Allocation
Sequence
Level 2

Purchase Dept

Level 2

Accounts Payable
Dept

Level 2

Accounts
Receivables Dept

Level 2

General Ledger Dept

Level 2

HR Dept
Admin Dept
Internal Audit Dept

Level 2
Level 2
Level 2

Fixed Assets assigned
for each dept

Level 1

Rent

Level 1

Maintenance and
repairs in office

Level 1

Electricity

Level 1

Allocation Base
Hours spent or
amount of salaries
Number of Shipments
or amount of
purchases
Number of Invoices
paid to license
payables
Number of invoices
raised for license
customers
Number of
Transactions line
Number of employees
Number of orders
Time spent for each
assignment of each
license
Depreciation is
charged to department
based on assets
assigned to dept
Rent is charged to
department based on
square meter
Maintenance and
repairs is charged to
department based on
square meter
Electricity is charged
to Dept based on total
watt of equipments of
each dept

10) Cost Analysis for Petroleum
decisions
Not all costs and revenue are useful in Cost
analysis for petroleum decisions, only relevant
costs and revenue that should be considered in

28


petroleum decision analysis. The Petroleum
decision has the following steps
1- Gather all costs and revenue of each
alternative
2- Take the sunk costs or revenue off
(Sunk costs are the past or historical
costs)
3- Select the best alternative that maximize
the revenue and profit or minimize the
costs
10.1) Buy against Lease (Cars, rig, building)
For selecting the best decision of buy or lease
vehicle, rig, equipments, materials or building,
the present value of both alternative of buy and
lease should be computed, and select the lowest
present value of alternative costs.
10.2) Further Processing (Natural gas or
LNG) or (selling from wellhead or export
port)
The company that may take a decision for
further processing or selling from wellhead or
export port needs to compute the preliminary
incremental earnings of further processing and
get the preliminary approval for making
investment analysis. A company may need to
make decision analysis for process natural gas to
produce Liquefied Natural Gas (LNG) that is
more marketable and profitable than selling
natural gas. To prepare the decision analysis for
such case, Company needs to do the following
steps
1- Compute the sales value and costs at
split-off of natural gas
2- Compute the sales and costs of further
processing for LNG
3- Compute the incremental revenue and
costs by obtaining the difference of step
1 and 2 above
4- Obtain the incremental earnings by
subtracting the incremental costs from
incremental revenue.


If the incremental revenue is greater than
incremental costs, the further processing is
preliminary feasible. If not, the Company should
not take a decision of further processing. We
intend to say preliminary feasible because
Company still needs to prepare more detailed
feasible study and investment analysis for
further processing to get the expected net present
value of further processing.
10.3) Selling below Normal or International
Market Price
If Company likes to sign sell and purchase
agreement for natural sources that is under the
normal market price or sell commodity at
significant discount and idle capacity of assets
exists, Company needs to compare the
contribution margin for the special order, if the
contribution margin is positive after providing
the lower price or significant discount because it
is still increase Company’s profitability and vice
versa. If there is no idle capacity, it is not prefer
to sell the commodity at lower price than market
price.
10.4) Acquiring or Relinquishing Acreage
For acquiring new license or not or relinquishing
existent license or not depends on investment
analysis for petroleum exploration that is
covered by our paper. The Company should
select the license that has higher expected
monetary value and continue maintaining the
license as long as the contribution margin
exceed the direct fixed costs of license even if it
is less than total fixed costs (direct fixed costs +
allocated fixed costs). If the direct fixed costs
exceeds the contribution margin, relinquishing
license will be necessary if there is no potential
profit in the license.
10.5) Determine the maximum costs of
running seismic acquisition.
Determining how much the maximum amount of
seismic acquisition that Company should pay
depends on computing the expected value of

29


-

perfect information (EVOPI). The expected
value of perfect information is obtained by
subtracting the maximum amount of expected
monetary value of alternative strategies from the
expected payoff with perfect information that
equal maximum amount of expected monetary
value of successful strategies. The Seismic
acquisition, processing and interpretation costs
may equal the expected value of perfect
information and +/-10% in most likely cases.
10.6) Drilling or not
For taking decisions to drill or not, Company
should take the probability of different cases as
follow: Dry hole as probability of lose and
different probabilities of success for different oil
or gas commodity and different size of reserves,
small, medium and large. And each case has
present value and should be multiplied by the
probability to obtain the expected monetary
value of each scenario than summing all the
results to get the expected monetary value
(EMV) of drilling a well. The higher EMV of
planned well, is the well that will be drilled first
and the less EMV will not be drilled.

Constraints that we mentioned above are
anything prevent the production process system
from achieving the goals or from obtaining the
optimum point of production. Constraints can be
either internal or external to the system;
a. Internal constraints are categorizes as
follow:
i. Limits of equipments, hours and
ability to produce
ii. Limits of people in skills, experience,
hours
iii. Written or unwritten policy that
prevent to get more production
b. External constraints when the system
can produce more than the market
demand. And when there is legislation
or contractual terms that limit
production.

10.7) Optimizing Production
Production optimization in petroleum upstream
industry is more appropriate to be analyzed by
petroleum production engineers because it uses
complicated technical formula of optimizing the
production and equipments which some of them
are
mentioned
in
the
below
link
http://www.elsevierdirect.com/v2/companion.jsp
?ISBN=9780750682701
But the production optimization concepts are the
same in any industry and we can cover it in
accounting or economical view. The production
is optimized by the following method
-

Liner programming and decision rule can
be used as optimization technique


Theory of Constraint is one of the most
famous and common technique, it focuses
on the following steps
1- Identify production process system
constraint
2- Decide how to use the constraints by
getting the most out of the constraint
3- Subordinate everything else to the
decision taken in step 2 above by
aligning whole system to support
decision made above.
4- Elevate system’s constraint by making
significant changes needed to increase
the capacity of constraint.
5- If a constraint is broken, engineer should
go to step 1 but should not allow to
cause new constraint.

10.8) Support Facilities Utilization and
Throughput accounting
In the presence of the constraints, Company can
maximize the profit by obtaining highest or
increasing the contribution margin per unit of

30


constraints measurement. Company should focus
on commodity that its contribution margin per
constraint measurement unit is higher than other.
We can use the throughput ratio instead of
contribution margin. Throughput is calculated as
the following formula:
Throughput = (Sales – Direct Materials cost)
Throughput accounting ration = Return per constraint
measurement unit ÷ Cost per constraint measurement unit.

To optimize the production company should
seek to increase the throughput, decrease the
investment and reduce operating expense, and
then consequently the net profit, return on
investment and productivity will be increased.
Net profit = Throughput – operating expense
Return on investment = net profit / investment
Productivity = Throughput / operating expense


31


Table 2: Drilling practices and Cost effect and management
Drilling
Techniques
Select Proper bit

Viscosity

Total Cost trend

Low
High
High
Low
High

Hardstone
Sandstone
Hardstone

Increase
Decrease
Decrease
Increase
Decrease

Low

Sandstone

Increase

Heavy weight

Low

Pressure in
Borehole is
greater than the
pressure onto the
bottom.

Increase

Light weight

Mud

Formation

Slow with light bit

Rotary speed

Characteristics
of drilling tools
HTC
PDC
Heavy weight
Light weight
High with heavy
bit

Penetration rate

High

Pressure in
Borehole is less
than the pressure
onto the bottom.

Decrease

High

Low

Poor Hole Cleanings and
stuck pipe
Tooling wears out faster
Will not hurt except if the
in case of very small drill
bits that very slower than
recommended RPM that
will be difficult to know
the
resistance
from
formation
and
very
difficult to penetrate it.
Fails to lift rock cuttings
to surface, resulting stuck
pipe
Excessive
high
mud
pressure can factures the
formation and cause lost
circulation or kill the well
Fails to lift rock cuttings
to surface, resulting stuck
pipe
Fails to keep high-pressure
formations under controls
and results in gas kicks or
blowouts
- Fluid which is too

Increase


Potential Risks

32


Drilling
Techniques

High

Short

N/A

N/A

Decrease

Long

Trip time

Characteristics
of drilling tools
Low

Penetration rate

Formation

Total Cost trend

Potential Risks

Decrease

viscous will wear out the
mud pump
- If the mud is very less
viscous, cuttings will not
be brought to the surface
and the stuck pipe can be
caused in the borehole
Increase safety risk but
this risk could be at the
minimum acceptable level
if it is done with trained,
high experienced and
efficient team.
Increase Non-productive
time

N/A

N/A

Increase

Table 3: Drilling Problems, risks, causes, signs, results and preventive control
Drilling
Problem
Lost
Circulation

Stuck Pipe

Causes

Results

Signs/Indicators

Prevention

Remedial Practices

- High Formation
Permeability
- Low Formation Pore
Pressure
- Poor Drilling Fluid
Characteristics
-Cave
-Keyseat - Crooked Hole
-Differential Pressure
Sticking
-Filter Cake

- Costly Mud usage
- Loss of Production
- Unproductive drill
time

- Flow out < Flow in
- Drop in mud
Return Rate
- Drop in Mud Pit
Volume

-Crew Education
-Good Mud
Program
-Study Wells in
Area

-Decrease Mud Weight
-Use Lost Circulation
Material as Mud Additive

-Fishing Operations
-Loss of Hole

-Cannot Pick Up
Pipe

-Use Minimum Mud
Weight Required to
Control Formation
Pressures.
-Use Special Drill

-Erode Mud Filter Cake - at
High Fluid Velocity (speed
up pumps)
-Spot Special Fluid; Oil,
Acid


33

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