Guidelines for field development plan

May 2017 G. Moricca 1
G. Moricca
Senior Petroleum Engineer
moricca.guiseppe@libero.it
Step-by-step Procedure for an
effective Field Development Plan
supported by the related Basic
Engineering Concepts

Integrated Field Development Plan
Content
 Oil and gas project plan refers to the unique
requirements of managing science, technology,
engineering aspects and economical topics of projects
in the upstream oil and gas industry.
 The purpose of this document is to provide the step-by-
step project management techniques procedures for an
effective Field Development Plan. For a better
understanding, the step-by-step procedures are
supported by a comprehensive statement outlining of
the related basic engineering concepts.

Project Management
The basic elements of any project are the same. The detailed attention required for
each element will vary, depending upon the project’s size and complexity. What is
required for an efficient Project Management is the preparation of the following
documents and their implementation on the project:
1. Project Plan — a document which fully describes the basis for undertaking the
project.
2. Organizational Structure — organization charts and position descriptions that
define the complete organization.
3. Project Control Schedule — includes the work breakdown structure (WBS),
work package description sheets, milestone charts and networks.
4. Project Control Budget — related to the WBS, properly coded, structured to
recognize the manner in which costs are actually collected and with a system for
tracking contingency.
5. Project Procedure Manual — a document which presents the exact
management work procedures to be used, work scopes, responsibilities,
authorities, interfaces and reporting methods.

The Project Plan
The project plan states and defines the following items:
- objectives of the project,
- its primary features,
- technical basis,
- project constraints,
- primary schedules,
- budget considerations,
- management approach,
- organization,
- procurement and contracting strategy and any other information
needed to do the project work.

Organization
Selecting the correct project organization is one of the most important and difficult
tasks. The organization must be selected to meet the specific requirements of each
project.
Factors influencing the selection of the organizational structure could include:
- What is the size of the project?
- Is the completion schedule critical?
- Is the engineering to be subcontracted or performed as part of the project group?
- If the engineering is subcontracted will all purchasing be performed by the
engineering subcontractor?
- If so, what controls are required over purchasing?
- How are construction contracts to be awarded?
Once the basic organizational structure has been selected, all positions should be
identified, coded and a personnel mobilization schedule selected.

Project Control Schedules
 Project control schedules and their supporting work
breakdown structures are needed as early as possible
for preparation of the project control budget and other
start-up work.
 A complete work breakdown structure is developed as
a first step to give the basis for all subsequent
scheduling and budgeting.

Project Milestones and Authorization Process
PDO = Plan for Development and Operation (Hydrocarbon withdrawal)
PIO = Plan for Installation and Operation (Pipeline & Surface Infrastructure)
 Project control schedules should include a master milestone bar-chart showing
major project milestones and project networks.
Time
Conceptual
Screening
Submission
PDO/PIO
Drilling
Start
Production
Start
Concept
Selection
PDO approval
Contract
Award
Facilities
Installation
Appraisal
Feasibility
Study
Field Development Activities

Project Control Budget
 Another important task during project start-up is the preparation of a
project control budget.
 The final control budget usually cannot be fully developed until
engineering design has progressed to a point allowing reasonable cost
estimation.
 It is still important to structure the entire project control budget, apply a
coding system and accomplish the costing as far as possible to enable
early completion of the control budget as design continues.
 Cost control can be no better than the project control budget with which
actual costs are compared.
 Sophisticated cost control techniques cannot correct the shortcomings of a
budget that is incomplete, not logically coded, employs poor cost data and
has inadequate contingency and escalation amounts.

Project Procedure Manual
Each project should have a project procedure manual which tells all project
participants what they have to do and how they should do it. The contents
of a typical Project Procedure Manual should include:
- Project objectives, including profitability and implementation
- Basic decision criteria, with focus on HSE, economy and technology
- Development solutions strategy
- Basic design criteria and relevant assumptions
- Reservoir development strategy
- Well completion strategy
- Production strategy
- Infrastructure: Tie-in to other fields or facilities expansion
- Uncertainty analyses for resource and technical solution
- Evaluation of risk elements for the concept(s) and implementation
- Evaluation of potential need to develop new technology and/or use
untraditional solutions

Peculiarities of the Upstream Oil and
Gas Industry
 The upstream industry is arguably the most complex of all the oil and gas business
sectors. As illustrated in the diagram, it is highly capital-intensive, highly risky,
and highly regulated. Upstream investments are high-risk, given that results of
every well drilled are unpredictable. Additional risk arises from safety and
environmental issues.
 Upstream is also
subject to global
forces of supply and
demand, economic
growth and
recessions, and
crude production
quotas.
High Risk - High Return
Highly Regulated
Impact by Global Politics
Technology Intensive

Oil or gas field life cycle
1
Discovery
2
Appraisal
3
Development
4
Production
5
Abandonment
Where
is the
field?
 Reservoir
structure
 Reservoir
connectivity
 Reserves
 Drilling
 Completion
 Flow Lines
 Facilities
 Production
 Injection
 Disposal
 Delivering
Decom
mission
ing
1-3 years 1-5 years 10-50 years
- Geologic structure
- No of Flow units
- Rock Properties
- Fluids Properties
- Driving Mechanism
- No Producing wells
- No of Injection wells
- Expected workovers
- Drilling & Completion
- Well Testing
- On line reservoir model
updating and fine-tuning
- Flow Lines
- Surface Facilities for
produced and injected
fluids: Separators,
Compressors, Pump
stations, Measuring System
- Production System Surveillance
- Downhole Data Acquisition
- Asset Management

Appraisal Phase
 It is the phase of petroleum operations that immediately follows
successful exploratory drilling.
 During appraisal, delineation wells might be drilled to determine the
size of the oil or gas field and collect cost-effective information
useful to decide if and how to develop it most efficiently.
SacOil Holdings Ltd

Field Appraisal Objective [1]
 The objective of performing appraisal activities on discovered
accumulation is to:
• Reduce the uncertainty in:
- Volume of hydrocarbon in place (OHIP)
- Description of the reservoir
• Provide information with which to make a decision on the nest
actions.
 The next action may be to:
- Undertake more appraisal
- Commence development
- Stop activities
- Sell the discovery

Field Appraisal Objective [2]
 Goal: Improving the quality of the data and reducing uncertainty.
 Outcome: Well fluid characteristics, OOIP, Recoverable oil, production
profile, with sufficient uncertainty.
 Method: More appraisal wells will be drilled, more measurements.
Tuning PDF ‐ CDFReservoir Model Production & Pressure

Making Good Decision [1]
 The decision to undertake more appraisal activity is a cost-effective information
inly if the value of outcome with the appraisal information is grater than value of
the outcome without the information.
 Supposing:
- Cost of appraisal information is $[A]
- The profit of the development without the appraisal information is $[B]
- The profit (net present value, NPV) of the development with the appraisal
information is $[C]
The appraisal activity is worthwhile only if [C - A] > [B]
Cost of appraisal
$[A]
Develop with appraisal
information
Develop without
appraisal information
NPV
($)
[B]
[C]

Making Good Decision [2]
 The make economic analysis to make decision ‘to do’ or
‘not to do’, it is necessary to assume outcomes of the
appraisal in order to estimate the value of the
development with these outcomes.
 The reliability of the economic analysis, and
consequently the reliability of the decision to make
decision ‘to do’ or ‘not to do’, is strictly correlated to
the technical capability and awareness of the field
development team as well as management decision.

Activities to reach the First Oil
 FDP time scheduling
 Installation of facilities
 Design of the
subsurface and surface
facilities
 Procurement of materials
 Fabrication of the facilities
 Commissioning of all plant and equipment's

1. Understand the environment
- Location
- Geotechnical
- Market
- Infrastructure
- Fiscal and political regime
- Production-sharing contract terms
2. Understand the reservoir and quantify
uncertainties
- Reserves
- Number of wells
- Well rate
- Produced fluid composition; flow assurance
- Reservoir management strategy
3. Understand the drilling
- Well Architecture
- Cost per well
- Number of drill centers required
- Intervention frequency and cost
- Wet vs. dry trees (pros and cons)
4. Propose options and examine
- Offshore
- Onshore
- Develop technical definition and cost estimate
for each
5. Commercial analysis
- Build economic model
- Use previous steps to examine various scenarios
- Understand risked economics and economic
drivers and sensitivities
The main topics to be faced for a proper oil
or gas field development project

Main Differences
Between
Onshore and Offshore
Field Development
Practices

Onshore vs Offshore Field Development
 One of the “fathers” of modern Petroleum Engineering
technology, L. P. Dake, states:
“A field is a field whether located beneath land or
water and the basic physics and mathematics
required in its description is naturally the same.
Where the main difference lies in the application of
reservoir engineering to field development is in
decision making: the nature, magnitude and timing
of decision being quite different in the offshore
environment.”

 Governmental regulations permitting and provided there are
production facilities in the locality, the well should be tied back to
the nearest block station and produced at high rate on a
continuous basis.
 An obvious advantage is that it provides a positive cash flow from
day one of the project but of greater benefit is that it permits the
reservoirs to viewed under dynamic conditions from the earliest
possible date.
Onshore
 Moreover, when each subsequent appraisal development well is
drilled, the conducting of drill-stem tests (DSTs) or, more
significantly, repeat formation tester (RFT) surveys will convey to
the engineer the degree of lateral and vertical pressure
communication: data that are indispensable in the planning of a
successful secondary recovery flood for water or gas injection.

 Following the discovery well on an accumulation a series of
appraisal wells is drilled to determine the volume of hydrocarbons
in place and assess the ease with which they can be produced: two
obvious requirements in deciding upon the commercial viability of
the project.
 Unfortunately, the appraisal wells, which may range in number
from one or two on a small accumulation to twenty or more on a
large, cannot usually be produced on a continuous basis from the
time of their drilling, since the offshore production and
hydrocarbon transportation facilities are not in existence at this
stage of the development.
Offshore
 In this environment the sequence of events in field developments
is much more compartmentalised than onshore.

Average Operational Costs
Economic component Onshore Offshore
Average Drilling Cost per well - $ million 3 to 6
50-100 up to
200
Average Completion Cost per well - $ million 1 to 2 10 to 20
Min suitable production rate - BOPD 100 - 250 2500 - 5000
Workover cost - $ million 1 to 2 5 to 10
Estimated break-even price @ 2015 $/bbl 25 - 30 50 - 70

Onshore vs Offshore Breakdown costs
- $/bbl - for regional oil production

Offshore vs Onshore Drilling Activities
 The basic equipment is similar for both onshore and offshore drilling. Both require
exploratory equipment, pumps, storage facilities and pipelines to drill and collect the oil.
One major difference for offshore drilling is the need for stability. Onshore drilling provides
natural stability in the form of the earth’s hard surface. Once anchored to the ground, the
rig remains stable and secure.
 Onshore drilling rigs are the more classic drilling equipment and come in different sizes
and strengths. They are generally classified by their maximum drilling depth and their
mobility. Conventional land rigs cannot be moved as a whole unit and are typically used in
the petroleum industry while mobile rigs are drilling systems that are mounted on wheeled
trucks and come in two different types, jackknife and portable mast.
 Offshore drilling presents much more of a challenge due to the shear depth of the water
just to reach the earth’s surface. The force the waves, especially in deep, rough waters,
presents major stability issues. This activity requires a manmade working surface to hold
the drilling equipment and facilities with some type of anchoring to the ocean floor.
 Time Frame - Offshore drilling often takes much longer to complete than onshore drilling.
An onshore well typically takes only a matter of days to drill, meaning production can begin
much faster. An offshore well can take months or years to build. This means an onshore
project is up and running much faster than offshore facilities.

Offshore vs Onshore Drilling Cost
 The costs for onshore versus offshore drilling are much different. Offshore drilling tends to
cost much more due to the increased difficulty of drilling in deep water. The specific cost
depends on a number of variables, including the specific location, any special
circumstances, well size, design and drilling depth.
 On average, an onshore oil well costs between $5.0 MM and $10.0 MM in total well
capital costs. Additional lease operating expenses between $1 MM and $3.5 MM may also
play into the cost over the life span of the well. The following breakdown shows a general
explanation of where those costs are dispersed:
- Drilling – 30 to 40% of costs: This category encompasses any tangible and intangible
costs associated with actually drilling the well.
- Completion - 55 to 70% of costs: The completion costs include both tangible and
intangible aspects of things like well perforations, fracking, water supply and disposal.
- Facilities - 7 to 8% of costs: Onshore drilling activities require storage and other facilities
and the associated expenses. This might include the equipment itself, site preparation
and road construction.
- Operations: The operations cost often come from the additional lease operation
expenses, which include well maintenance and delivery cost.

Offshore vs Onshore Drilling Rigs
 Offshore drilling rigs are classified differently, mainly based on their movability and how
deep the sea bed is. There are two types of offshore drilling rigs:
1. Bottom-supported units are rigs that have contact with the seafloor. There are
submersible bottom-supported units and also jack up units that are supported by
structured columns.
2. Floating units do not come in direct contact with the ocean floor and instead float
on the water. Some are partially submerged and anchored to the sea bed while
others are drilling ships which can drill at different water depths.
Diagram of different types of offshore drilling rigs.

Offshore vs Onshore Storage and Transport
 Storage and Transport Methods - Onshore drilling offers more options for storage and
transport of the oil after it is extracted from the well. The solid ground surrounding the
wells allows for additional processing facilities on site. The location also allows for easy
accessibility by trucks and other vehicles, so the oil can easily be transported to other
facilities for processing and distribution.
- Offshore oil drilling presents more of a challenge to the storage and transport
process. This is particularly true for deepwater drilling that takes place far off the
shore. The circumstances require special equipment and methods for processing the
oil and transporting it after extraction.
- Offshore projects close enough to the shore can use a system of pipelines to bring
the oil directly to shore.
- For deep wells and those far off the shoreline, barges or tankers process and store the
oil until it is taken ashore. These vessels are called Floating Production, Storage and
Offloading units, or FPSO for short.
- As the name suggestions, FPSO units can handle the initial processing of the oil while
out on the water. The ship is also designed to store the oil until it is offloaded onto a
tanker. Each of these vessels holds 2.5 million barrels of oil. Some of these vessels only
store and offload the oil. Large offshore production areas may use multiple FPSO units
to keep up with the demand of the project.

Offshore vs Onshore Cost Differences
 Offshore oil wells cost significantly more and depend on factors such as well depth, water
depth, productivity and distance to the infrastructure. In the Miocene area with shallower
water and well depths, the average cost for drilling and completion is $120 MM. In the
deepest Jurassic projects, costs can be as high as $230 MM. The breakdown of costs varies
somewhat for offshore drilling activities. Those categories include:
- Drilling – 60% of costs: Drilling takes up a much larger portion of the costs for offshore
drilling activities.
- Completion - 40% of costs: The completion activities take up the remaining costs, which
include well perforations, rig hiring, transportation and well head equipment.
- Facilities - 7 to 8% of costs: Onshore drilling activities require storage and other facilities
and the associated expenses. This might include the equipment itself, site preparation
and road construction.
- Operations: Like onshore drilling activities, the operation costs fall into the lease
operating expenses for the well.

Step-by-step Procedure
for an effective
Field Development Plan
according to the
Front-End-Loading (FEL)
Process

Front-End-Loading (FEL) Process [1]
 Front-end-loading (FEL) should be considered as a sound field development practice
that allows the optimum allocation of capital and human resources, reduces the
uncertainty of key information and ensures a holistic view to all field development plan
decisions.
 Front-end-loading methodology is a 3-step capital project planning process:
- FEL 1: The prefeasibility stage;
- FEL 2: The feasibility stage, and;
- FEL 3: The basic engineering and development stage.
SPE 167655 L. Saputelli et others - 2013
FEL-1 FEL-2 FEL-3

Front-End-Loading (FEL) Process [2]
 The FEL methodologies allow and actually force by process due diligence
the Oil & Gas companies to take better decisions during field
development planning process to improve the value of subsurface
resources while minimizing risk during field development execution
phase. The key advantages are:
- Ensure that the business objectives are aligned with the technical
objectives
- Human resources are better utilized
- Financial Risk is minimized
- Early production team participation
- Evaluate a large number of scenarios implies that some
opportunities
- Standard process for a well-defined decision making

Objectives and key activities of the phases
FEASEBILITY SELECT DEFINE EXECUTE OPERATE
FEL-1
Conceptual
Engineering
Clear frame
goal.
 Identify
opportunities.
 Preliminary
assessment of
uncertainties,
potential return,
and associated
risks.
 Plan for next
phase.
Cost accuracy
±40%
FEL-2
Preliminary
Engineering
Generate
alternatives.
 Reduce
uncertainty and
quantify
associated risks.
 Develop expected
value for selected
alternatives.
 Identify preferred
alternative(s).
 Plan for next
phase.
Cost accuracy
±25%
FEL-3
Eng. Design
Fully define
scope.
 Develop detailed
execution plans.
 Refine estimates
and economic
analysis to A/R
level.
 Confirm expected
value meets
business
objectives.
Cost accuracy
±15%
Detailed
Eng. Design
Implement
execution plan.
 Final design
 Implement
execution plan.
 Collect, analyze,
and share metrics
and lessons
learned.
Cost accuracy
±5%
Operations
Support
Monitor
performance.
 Final design
 Benchmark
performance
against objectives
and competitors.
 Share results and
lessons learned.
 Continue
performance
assessment and
identify
opportunities.
Field Development Planning
G
1
G
2
G
3
G Stage Gate – Decision to Proceed

 In the past decades, various initiatives have been put in place to organize
project management knowledge with an emphasis on methodologies
outlined by the Project Management Institute (PMI) and Independent
Project Analysis (IPA).
Front-end Loading Methodology
 The oil and gas industry has consistently used the combination of both
methodologies of the PMI and IPA in the development of major projects,
with particular attention on the front-end loading methodology (FEL), which
combines an approach of so-called "rolling wave planning", with a vision of
technical and cost integration in the light of the IPA's empirical tools.
 The FEL methodology is focused on the early stages of a project, aiming at
progressively increasing the level of maturity of technical information,
limiting investment in each phase, and ensuring that the decision-making
about the continuity of the project in each phase can be developed based on
both technical and financial documentation.

 FEL 1: Opportunity identification - This is the business assessment phase, where the
verification of strategic alignment with the company’s business plan and market
opportunities takes place. This step involves the definition of the scope and
objectives of the project, as well as an initial estimate of the amount of investment
required, by providing a range of variation in cost.
Front-end Loading phases for full
field development project
 FEL 2: Conceptual engineering - This is the stage of development that includes the
evaluation and selection of conceptual alternatives. The main focus of this phase is
the development of conceptual engineering for options listed in FEL 1, in order to
compare the options and define, through the results of the financial-economic
assessment of each option, which alternative will make it through to the next phase.
 FEL 3: Basic engineering - In this phase, the focus is the construction and the
preparation of the project for its corporate approval and future implementation. The
basic engineering of the selected option in FEL 2 is performed, allowing the
calculation of project capex with greater precision. The engineering solution
selected in FEL 2 is technically detailed and more value improving practices are
considered in the development of the basic engineering design.

Tasks to be accomplished for a reliable Field
Development Plan
Feasibility
Front End Loading (FEL-1)
 Identify opportunities.
 Preliminary assessment.
 Conceptual Engineering
1
• Set an Integrated FDP Team and Define a clear Target
2
• Data Acquisition, Data Storing and Data Validation
3
• Development of a robust Reservoir Model
4
• Conceptual FDP Scenario – Qualitative evaluation
5
• Field Development Strategy Identification
6
• Consolidation of FDP Scenario - Quantitative
6A
• Economic Evaluation
6B
• Uncertainty Analysis
6C
• Risk Analysis
6D
• Health, Safety and Environmental
6E
• Final Selection Field Development alternative
7
• Field Development Plan Approval
Selection
Front End Loading (FEL-2)
 Generate alternatives
 Identify preferred.
alternative.
 Preliminary Engineering.

Contents of final FDP document
Typical Contents of a Field Development Plan document:
1. Executive Summary
2. Introduction
3. Field History and Background
4. Reservoir Characterization & Geological Modelling
5. Reservoir Simulation & Performance Prediction
6. Techno-Economic Evaluation of Prediction Scenarios
7. Executive Prediction Scenario
8. Drilling & Completion Proposal
9. Project Scope of Work & Execution Schedule
10. Project Cost Estimation
11. Quality Management System
12. Health, Safety, and Environment
13. Governing Standards

May 2017 38
1
•Set an
Integrated FDP
Team and
Define a clear
Target
G. Moricca

May 2017
Identification and Assessment of Opportunities
FEL-1
Conceptual
Engineering
Clear frame
goal.
 Identify
opportunities.
 Preliminary
assessment of
uncertainties,
potential return,
and associated
risks.
 Plan for next
phase.
Cost accuracy
±40%
FEL-2
Preliminary
Engineering
Generate
alternatives.
 Reduce
uncertainty and
quantify
associated risks.
value for selected
alternatives.
alternative(s).
 Plan for next
phase.
Cost accuracy
±25%
FEL-3
Eng. Design
Fully define
scope.
execution plans.
and economic
analysis to A/R
level.
value meets
business
objectives.
Cost accuracy
±15%
Detailed
Eng. Design
Implement
execution plan.
 Final design
 Implement
execution plan.
and share metrics
and lessons
learned.
Cost accuracy
±5%
Operations
Support
Monitor
performance.
 Final design
 Benchmark
performance
against objectives
and competitors.
lessons learned.
 Continue
performance
assessment and
identify
opportunities.
G
1
G
2
G
3

Stage 1: Identification and Assessment
of Opportunities [1]
 The field development begins when the exploration phase ends:
when an exploration well has made a discovery.
 Only this well can provide the certainty about whether crude oil
or natural gas really does exist in the explored area after the
seismic measurements have been conducted.
 When evaluation of the well data and analysis of the drill cores
come to the clear conclusion that oil or gas has been found, this
means a potential development project has been identified. The
next phase, field development, can now begin.
 The aim of the assessment phase is to highlight the technical and
commercial feasibility of the project.

 To do so, it is necessary to find out as
much as possible about the reservoir and
to minimize the uncertainties. Actions that
help to do so dynamic reservoir models.
The reservoir engineers generate a 3D
model of the subsurface so that they can
estimate how much oil is hidden under the
surface.
 The engineers plan the entire production phase and address all sorts of
practical questions, such as: How many wells must be drilled and where?
Can the oil be recovered to the surface in an on-shore project with a
simple horse-head pump? Is the oil so corrosive that the pipes need a
special coating? How can the maximum production volume be achieved –
for example, by injecting water or gas into the reservoir? And when should
this procedure begin?
Stage 1: Identification and Assessment
of Opportunities [2]

Field Development Planning is the process of evaluating multiple
development options for a field and selecting the best option based
on assessing tradeoffs among multiple factors:
 Net present value, typically the key driver of decisions for
publicly-traded operators.
 Oil and gas recovery
 Operational flexibility and scalability
 Capital versus operating cost profiles
 Technical, operating and financial risks.
Field Development Planning (FDP)

 The task is to identify opportunities and perform all required
studies (Feasibility Study) to generate a development plan that
satisfies an Operator’s commercial, strategic and risk objectives.
 The execution of the Feasibility Study involves a continuous
interaction between key elements:
- Subsurface
- Surface
- Business
 The process requires
continuous and effective
collaboration and alignment
between reservoir, well
construction, surface facilities
and commercial teams
Sub
Surface
SurfaceBusiness
Feasibility Study

Outcomes of the Feasibility Study
 The main objective of Feasibility study is to
identify opportunities and provide consistent
and reliable answers to question like:
- Does the technology exist ?
- Is it technically feasible?
- Can it be built to the required size?
- Can it be installed?
- Do the risks appear manageable?

Feasibility Study Working Plan
During the execution of the feasibility study, the engineers will:
- Investigate the multiple technologies to be used
- Evaluate the costs of each solution, especially during the total life cycle of the
project including capital expenditure for the construction (CAPEX) and
operational expenditure (OPEX) to run the plant
- Estimate construction challenges versus benefits in operations and vice versa
- Measure the impact on the environment (foot print, water and energy
consumption, CO2 emissions, local acceptance, decommissioning and
restoration costs)
- Draft planning corresponding to each solution to identify critical items
- Identify potential risks on the project and hazards for personnel
- List all the required offsite and utilities
- Determine all the infrastructures needed to bring in the feedstock and to export
the production
- Include local constraints about regulation, taxations, employment, content

FDP Integrated Team
An integrated, multidisciplinary team approach is
required for a proper Feasibility study and the others
activities connected with the FDP. The team should
include the following professionals:
 Geologists responsible for geological and petrophysical works.
 Reservoirs engineers responsible for providing production forecast and
economical evaluation.
 Drilling engineers responsible for drilling offshore drilling systems selection
and drilling operations.
 Completion engineers responsible completion design and operations.
 Surface engineers responsible for designing/selection surface and
processing facilities.
 Other professionals, if needed, such as pipeline engineers, land manager,
etc.

FDP Integrated Team
Minimum
components/skills
for an integrated FDP
multidisciplinary
team
Reservoir
Engineer
Geologist &
Geophysicists
Drilling
Engineer
Completion
Engineer
Production
Engineer
Facilities
Engineer
HSE Engineer
Economic
Expert
FDP
Integrated
Team
Coordinator
An integrated team is a group composed of members with varied but
complimentary experience, qualifications, and skills that contribute
to the achievement of the organization's specific objectives.

Responsibility and Role of the Team
Coordinator
Role:
 Be custodian of the objectives of project
 Identify priorities
 Allocate the assigned human resources
 Promote and facilitate the correct integration of permanent and
part-time team components
 Avoid lack of communication among the team component and
management
Responsibility:
 To successfully deliver a FDP, within the allocated budget,
human resources and timeframe.

FDP Target Identification
 Identification of a clear target based on
the data collected during the field
appraisal and in line with company
strategy.
 Use the reservoir numerical model is a key
tool to determine the optimum technique
for recovering of the hydrocarbons from
the reservoir.
 Development plans are defined through simulation studies
considering either a probabilistic or a stochastic approach to
rank options using economic indicators, availability of injection
fluids (i.e., water and/or gas), and oil recovery and risk, among
other considerations.

Main causes of the Failure of FDP
 Reservoir related problems
have the largest and most
lingering effect on
production.
January 2018 G. Moricca 50
 Incomplete or poor quality reservoir data: contaminated fluid
samples, poor PVT analysis, incomplete pressure survey, partial
knowledge of the areal distribution of fluids saturation, poor
knowledge of the vertical and horizontal areal transmissibility, etc.
 This means that project
teams are forced to make
assumptions about missing
data or about remaining
risks in their production
forecasts.

 The success of oil and gas FDP is largely determined by the
reservoir: its size, complexity, productivity and the type and
quantity of fluid it contains. To optimize a FDP, the
characteristics of the reservoir must be well defined.
Unfortunately, in some cases, a level of information available
is significantly less than that required for an accurate
description of the reservoir and estimates of the real situation
need to be made.
Reservoir Model as the Standard Tool for FDP
 Reservoir numerical model is a standard tool in petroleum
engineering for solving a variety of fluid flow problems involved
in recovery of oil and gas from the porous media of reservoirs.
 Typical application of reservoir simulation is to predict future
performance of the reservoirs so that intelligent decisions can
be made to optimize the economic recovery of hydrocarbons
from the reservoir. Reservoir simulation can also be used to
obtain insights into the dynamic behavior of a recovery process
or mechanism.
Reservoir Model
Outcomes
dictate
Volumes
Rates
Well
Architecture
Well
Completion
Surface
Facilities

Typical Reservoir Study Contents
1. Reservoir Characterization
- Geological Setting
- Stratigraphic and Facies Analysis
- Petrophysical Analysis
- Reservoir Facies and Properties Maps
2. Reservoir Connectivity
- Reservoir Characterization and 3D Geologic Modeling
- Geological Inter-well Connectivity Evaluation
- Fluid and Saturation-Dependent Properties
- Initial Reservoir Pressure Estimation
- PVT Matching
- History Matching Reservoir Performance
3. Evaluation of Development Strategies
- Evaluation Recovery schemes: natural depletion;
natural depletion assisted by water (Water-flood),
gas injections, alternate water and gas injection, etc.
- Oil, Gas and Water Production Forecast
- Evaluation Infill Potential

- Original Hydrocarbon in place - OHIP
- Recoverable Hydrocarbons (Reserves and Reserves classification: Proven, Probable,
Possible)
- Oil, water and gas production profile (for field, well, flow units)
- Fluid Porosity map
- Permeability (vertical and horizontal) map
- Initial Static Pressure map
- Actual Static Pressure map (for brown fields)
- Fluids Saturation map
- Most probable reservoir drive mechanism and its strength
- Gas-Oil and the Oil-Water Contact depth
- Number of production wells to be drilled
- Duration of Natural Flow period for each well
- Identification of the most effective Secondary Hydrocarbon Recovery technique to be
adopted
- Number of injection wells to be drilled (if required)
- Number of disposal wells to be drilled (if required)
- Surface and downhole coordinates of planned wells to be drilled
- Water or Gas Injection profile (if required)
- Workover plan to sustain the hydrocarbon production during the field life cycle
Expected Reservoir Study Outcomes

May 2017 54
2
•Data Acquisition
and Analysis
G. Moricca

Data Acquisition
 All the available data coming from exploration, appraisal and
exploitation (in case of brown field) phases:
- Seismic
- Geologic
- Logging
- Coring
- Fluids
- Well Test
- Drilling History
- Completion History
- Production history (if available)
- Injection history (if available)
Should be collected in a Integrated Database to support the definition
of all activities (reservoir, drilling, completion, fluid transportation,
measuring devices selection, fluids processing) for a successful FDP.

The Integrated Database [from L. Cosentino 2001 Technimp]
 An Integrated database is a data repository system to interactively
store, retrieve and share E&P data, within a controlled and secure
environment.
 A Data Warehouse or Data Storage can be defined as an integrated,
non-volatile, time variant collection of data to support management
needs. From this viewpoint, it implies a reduced degree of interaction
with the end user.
 Data Management is the process of storing, organizing, retrieving and
delivering data/information from a database a Data Warehouse.
 The integrated database is one of the key issues in an integrated fiend
development team. The availability of high quality data, both static
and dynamic, and the rapidity of access to this data, is a crucial factor
for an successful a field development study.

Three Levels Database [from L. Cosentino 2001 Technip]
 Nowadays, in the E&P companies three levels of database are available:
- Corporate database
- Project database
- Application database
 Corporate database
- Corporate database stores the official data of the company.
- Data quality is high and the rate of change (volatility) is low.
- No new data is created within the Corporate database, and it does
not feed any application, except its own set of utilities for browsing,
selecting and exporting.
- Data are delivered in a format compatible with the Project database.
- Although the database can be accessed by anyone, changes in
content are controlled by an administrator.
- It usually resides in a mainframe and is characterized by the many
controls that are placed around it.

 Project database
- It contains data relevant to a particular project or asset.
- It is made up of information withdrawn from the Corporate database
and is accessed using software from different vendors.
- Its size is highly variable, from few to thousands of wells, and it may
contain multiple versions of the same data.
- All the professionals working on the team can access and modify the
database, so that the volatility is high.
- New data is generated through the interpretation stages.
- When the project has been completed, the interpreted data is
returned to the Corporate database and becomes the new reference
information.

 Application database
- It contains data relevant to a single application.
- It is normally accessed by any component of FDP integrated team,
working on a particular application and the information is therefore
highly volatile.
- Also, the information may not be easily shared with other
application databases, when vendors are different, unless a
dedicated interface software is available.
- When the interpretation is completed, the data is stored in the
Project database.

Database Structure and data QC
 All the data relevant to the active project should be
carefully revised and validated before being inserted
in the DB.
L. Cosentino - Technip 2001

Project Data Analysis and Lesson Learning
 All the data relevant to the active project
should be collected, revised and analysed.
 The documentation should maintain an
adequate level of confidentiality, but should
be accessible for the whole FDP team
components.
 A Lesson Learning Report should be
generated.

Data required to build a reservoir model
Classification Data
Acquisition
Timing
Responsibility
Seismic
Structure, stratigraphy, faults, bed thickness, fluids, inter-well
heterogeneity
Exploration Seismologists, Geophysicist
Geological
Depositional environment, diagenesis, lithology, structure,
faults, and fractures
Exploration, discovery
& development
Exploration & development
geologists
Logging
Depth, lithology, thickness, porosity, fluid saturation, gas/oil,
water/oil and gas/water contacts, and well-to-well
correlations
Drilling
Geologists, petrohysicists, and
engineers
Coring Drilling
Geologists, drilling and
reservoir engineers, and
laboratory analysts
Basic
Depth, lithology, thickness, porosity, permeability, and residual
fluid saturation
Special
Relative permeability, capillary pressure, pore compressibility,
grain size, and pore size distribution
Fluid
Formation volume factors, compressibilities, viscosities,
chemical compositions, phase behavior, and specific gravities
Discovery, delineation,
development, and
production
Reservoir engineers and
laboratory analysts
Well Test
Reservoir pressure, effective permeability-thickness,
stratification, reservoir continuity, presence of fractures or
faults, productivity and injectivity index, and residual oil
saturation
Discovery, delineation,
development, and
production and
injection
Reservoir and production
engineers
Production &
Injection
Oil, water, and gas production rates, and cumulative
production, gas and water injection rates and cumulative
injections, and injection and production profiles
Production & Injection
Production and reservoir
engineers
From A. Satter & G. Thakur

May 2017 63
3
•Development
of a robust
Reservoir
Model
G. Moricca

Typical Application of the Reservoir Model
 The application of the reservoir model is varied and extensive.
The most typical are listed below.
Situation Expected Results
Pitfalls or Other
Considerations
New discoveries  Determine optimal number of
infilling wells
 Size and type of production facilities
 Decide whether to maximize
production rate or ultimate recovery
 Limited data, sometime from only a
single well
 Drive mechanism
 Terms of operating license or lease
Deepwater
exploration
 Prospect evaluation
 Scenario planning
 Limited data, no wells available
Mature fields  Answers to sudden production
problems
 Relatively inexpensive way to extract
maximum value from development
costs
Implementation of
secondary recovery
 Determine appropriate recovery
method
 Reservoirs to viewed under dynamic
conditions from the earliest possible
date
Decommissioning or
abandonment
 Determine future production
volumes
 Unanticipated future production
problems might reduce property
value

Major Tasks of the Reservoir Engineers
 How much oil and gas is originally in place?
 What supplementary data are needed to
answer these questions?
 What are the drive mechanisms for the reservoir?
 What are the trapping mechanisms for the
reservoir?
 What will the recovery factor be for the reservoir by primary
depletion?
 What will future production rates from the
reservoir be?
 How can the recovery be increased economically?

Why we need a Reservoir Simulation Model
From L. Cosentino 2001 Technip
 There are many reasons to perform a simulation study. Perhaps the most
important, from a commercial perspective, is the ability to generate oil
production profiles and hence cash flow predictions.
 In the framework of a reservoir study, the main objectives of numerical
simulation are generally related to the computation of hydrocarbon production
profiles under different exploitation options.
 In this context, there is little doubt that reservoir simulation is the only qualified
technique that allows for the achievement of such objectives. Simpler
techniques like material balance are particularly useful for evaluating the
reservoir mechanisms, but are not suited for reservoir forecasting.
 Reservoir simulation, on the other hand, offers the required flexibility to study
the performance of the field under defined production conditions. All
commercial simulators are provided with sophisticated well-management
routines that allow the engineer to specify the operating conditions at the levels
of producing interval, well, well group, reservoir and field.

Geological and Dynamic Reservoir Model
 The geological model defines the “geological units” and their continuity and
compartmentalization.
 The geological model
combined with the dynamic
model provides a means (the
reservoir model) of
understanding the current
performance and predicts the
future performance of the
reservoir under various “what
if” conditions so that better
reservoir exploitation
decisions can be made.

Geological Modelling Workflow

Info to be generated by Reservoir Study [1]
 Reservoir Characteristics
1. Areal and Vertical extent of production formation
2. Isopach map of gross and net pay
3. Correlation of layers and others zones
 Reservoir Rock Properties
1. Areal variation of average permeability, including directional
trends derived from geological interpretation.
2. Areal variation of porosity
3. Reservoir heterogeneity, particularly the variation of
permeability with thickness and zone
 Reservoir Fluid Properties
1. Gravity, FVF, and viscosity as a function of reservoir pressure

 Primary Producing Mechanism
1. Identification of producing mechanism, such as fluid expansion,
solution-gas drive, or water drive
2. Existence of gas cap or aquifers
3. Estimation of oil remaining to be produced under primary
operations
4. Pressure distribution in the reservoir
 Distribution of oil at beginning of waterfool
1. Trapped-gas saturation from solution-gas drive
2. Vertical variation of saturation as a result of gravity segregation
3. Presence of mobile connate water
4. Areas already waterflooded by natural water drive
Info to be generated by Reservoir Study [2]
 Rock/Fluid Properties
1. Relative permeability data for the reservoir rok

 Reservoir model is an integrated modelling tool, prepared jointly by
geoscientists and engineers.
Integrated Team for Reservoir modelling
 The integrated reservoir
model requires a thorough
knowledge of the geology,
rock and fluid properties.
 The geological model is
derived by extending
localized core and log
measurement to the full
reservoir using many
technologies such as
geophysics, mineralogy,
depositional environment,
and diagenesis.

Integrated planning for reservoir
studies
 To maximize team synergy and avoid delay, and integrated approach to
reservoir studies planning is recommended.
L. Cosentino - Technip 2001

May 2017 73
Basic Petroleum Engineering
Concepts for a consistent FDP
 Reservoir modelling
 Original Hydrocarbon in Place
 Reserves Estimation
 Reserves Classification
 Reservoir Depletion Strategy
 Water Injection Strategy
 Waterflooding Strategy
 Well Architecture Strategy
 Well Completion Strategy
G. Moricca

May 2017 74
Reservoir
Modelling
G. Moricca

Reservoir most common simplified
geological structures

Basic of Reservoir Modelling [1]
 Reservoir simulation is a technique in which a computer-based
mathematical representation of the reservoir is constructed and then
used to predict its dynamic behavior.
 The reservoir is gridded up into a number (thousands or millions) of grid
blocks.
 The reservoir rock properties (porosity, saturation and permeability), and
the fluid properties (viscosity and PVT properties) are specified for each
grid block.

 The driving force for the fluid flow is the pressure difference between
adjacent grid blocks.
 The calculation of fluid flow is repeatedly performed over short time
steps, and at the end of each time step the new fluid saturation and
pressure is calculated for every grid block.
 The reservoir simulation operates based on the principles of balancing
the three main forces acting upon the fluid particles (viscosity, gravity
and capillary forces), and calculating fluid flow from one grid block to the
next, based on Darcy’s law.
Basic of Reservoir Modelling [2]
From F. Jahn , M. Cook & M. Grahm - Elsevier 2008

 To initialize a reservoir simulation model, the initial oil, gas and water pressure
distribution and initial saturations must be defined in the reservoir model. Pressure data
are usually referenced to some datum depth. It is convenient to specify a pressure and
saturation at the datum depth and then to calculate phase pressures based on fluid
densities and depths
Basic of Reservoir Model Initialization
 The initialization of the reservoir simulation models is the process where the reservoir
simulation model is reviewed to make sure that all input data and volumetrics are
internally consistent with those in the geo-model. The reservoir simulation model should
normally be in dynamic equilibrium at the start of production, but there might be some
exceptions to that rule. Non-equilibrium at initial conditions may imply some data error
or the need to introduce pressure barriers (thresholds) between equilibrium regions.
 The initialisation phase allows for the calculation of the OOIP in the model, which is
then compared with the available volumetric figures.
 When the reservoir model (geological and dynamic) has been build, the model
Initialization is required to establish the initial pressure and saturation equilibrium
conditions.

 At this step, the main objective is to verify that the reservoir simulation model
accurately represents the structure and properties in the geologic model. The
following validation steps are recommended:
- Visualize reservoir simulation grid, each grid layer and each cross-section,
to ensure that simulation grid is constructed correctly and all gridblocks
are suitable for reservoir simulations.
- Compare reservoir simulation grid with the geological grid and make sure
that reservoir simulation grid layers and fault geometries are consistent
with the structural depth maps used.
- Visualize and compare reservoir simulation model properties (porosity,
permeability, net-to-gross ration and fluid saturation) with those in the
geological model.
- Compare reservoir simulation model gross-rock-volume, pore volume,
and hydrocarbon in-place volumes with the geological model volumes.
- Verify that the wells are consistently represented in the reservoir
simulation grid.
Basic of Reservoir Model Validation

May 2017 G. Moricca
 Is the reservoir model reliable enough to generate information
useful for business purpose ?
 If the production history is available (Brown field), the History Match
give a very reasonable answer to the question.
 If the production history is not available (Green field), we can judge
the “consistency” but not the “reliability” of the outcomes generated
by reservoir model simulation. In these circumstances, the skillfulness
of reservoir engineers is a key factor.
 The accuracy of the results is related to a correct problem statement
and to the quantity and quality of the available input data (garbage
in, garbage out). The experience and knowledge of the engineers
involved in the study represent another important factors.
80
Basic of History Match [1]

May 2017 G. Moricca
Basic of History Match [2]
 Basically, History Matching is a model validation procedure, which consists in
simulating the past performance of the reservoir and comparing the results
with actual historical data.
 If the production history is available (Brown field), perform the History Match.
 When differences are found, modifications are made to the input data in order
to improve the match.
 More generally, history matching is a way of checking sensitivity to variations in
the input parameters and eventually of understanding the representativeness
of the model. From this point of view, the history matching process can be
considered to be a valuable technique to improve the overall reliability of the
simulation model which, if it is properly performed, will highlight flaws and
inconsistencies in the existing reservoir description.
 The objective of history matching is to reproduce, as correctly as possible, the
historical field performance, in terms of measured rates and pressure. The
check should be always done both on a field and well basis.
81

May 2017 G. Moricca
Pressure and Saturation History Match
Workflow [L. Cosentino – Technip 2001]
82
[25] Toronyi RM, Saleri NG. Engineering control
on reservoir simulation. Part 2. SPE paper
17937.
[25] Toronyi RM, Saleri NG. Engineering control
on reservoir simulation. Part 2. SPE paper
17937.

May 2017 G. Moricca
History Match Example
Water Cut, Reservoir Pressure, Oil Rate and GOR history match
83

May 2017 84
OHIP Estimation
by Reservoir
Model
G. Moricca

 The determination of the Original Hydrocarbon In Place (OHIP) is typically
the concluding phase of the geological study, when the reservoir
description is completed.
 Even though the economic importance of a project is obviously much
more closely related to the reserves of a given field (i.e., the producible
part of the OHIP), the OHIP is the parameter that gives the dearest view
of the extension of the hydrocarbon accumulation and consequently of
the foreseeable exploitation projects.
 In the framework of an integrated reservoir study, the importance of an
accurate determination of the OHIP value is also related to the potential
reservoir energy that the hydrocarbon volume represents, which is
dependent on the compressibility of the oil and gas phases.
Original Hydrocarbon in Place (OHIP)
Estimation

 The volumetric computation of the OHIP can be
performed on a deterministic or probabilistic basis.
Original Hydrocarbon in Place
(OHIP) estimation
 Two technique are available for OHIP calculation:
- Volumetric computation (no production data are
required)
- Material balance techniques (production data are
required)

OHIP Estimation by Volumetric
Method - Deterministic Approach
 The deterministic evaluation is the technique that has
traditionally been applied for the computation of the
OHIP since the beginning of the oil industry.
 In this methodology, all the various input parameters
are calculated deterministically and no allowance is
given for any related uncertainty. In other words, the
distributions of the geological parameters are
considered free of error, even if this is obviously not
true.

OHIP Estimation by Volumetric Method
 At the very early stage, when the reservoir
model is not available yet, a preliminary project
evaluation can be made on the base of
reserves estimated by a volumetric calculation.
 The volumetric method for estimating
recoverable reserves consists of determining
the original hydrocarbon in place (OHIP) and
then multiply OHIP by an estimated recovery
factor.
 The OHIP is given by the bulk volume of the
reservoir, the porosity, the initial oil saturation,
and the oil formation volume factor.
 The bulk volume is determined from the
isopach map of the reservoir, average porosity
and oil saturation values from log and core
analysis data, and oil formation volume factor
from laboratory tests or correlations.

Areal Extent (productive limits of reservoir)
- Structure map
- Seismic
- Analogy
Net pay thickness
- Well logs
Porosity
- Well log and cores
Water saturation
- Well logs and/or cores
Recovery efficiency
- Analogy
- Drive mechanism
- Reservoir characteristics
Data required for Reserves Estimation
by Volumetric Method

 It is customary in the industry to describe this uncertainty in terms of a low and high
range.
OHIP Deterministic scenario
 When using the deterministic scenario method, typically there should also be low,
best, and high estimates, where such estimates are based on qualitative assessments
of relative uncertainty using consistent interpretation guidelines. Under the
deterministic incremental (risk-based) approach, quantities at each level of uncertainty
are estimated discretely and separately.

OHIP Estimation by Volumetric Method
Probabilistic (Stochastic) Approach
 The basic idea behind a probabilistic computation is to take into account
the uncertainties related to the various parameters involved in the
computation.
 The simplest approach is therefore to treat the variable of equation used
to calculate the OHIP [ A x h x ф x So ] in a probabilistic way, by assigning
them distribution functions, rather than a single, deterministic value.
 This is the so-called Monte Carlo approach. In its simplest, adimensional
application, it amounts to randomly sampling the input parameters
distributions, in order to generate a probability distribution function of
the variable of interest, the OHIP in this case.

 Using the deterministic approach, OOIP can be estimated by simply multiplying
the “best estimate” for each parameter involved in the algebraic equation. The
deterministic approach assumes that the most likely value of every input is
encountered simultaneously, which is generally unrealistic.
 The presence of uncertainty in reservoir
modeling parameters and the stochastic
nature of those parameters encourage the
use of Monte Carlos Simulation, which
provides for this uncertainty through
random sampling of parameters that
cannot be assigned a discrete value.
 The very well known equation giving the OHIP is:
OHIP = A x h x ф x So
Where: (A) is the reservoir area average, (h) is the net hydrocarbon thickness, (φ)
the average porosity and (So) the oil saturation.
How the Stochastic Models works [1]

How the Stochastic Models works [2]
 Monte Carlo Simulation approach can make use of independent probability
distribution to arrive at an overall probability distribution.
 Stochastic models (as Monte Carlo Simulation ) provide the average answer
(assuming that all input values represent the average input value) but tell us
nothing of the range or probability of possible answers.
A OOIPh ф So
x x x =
 Obviously, if the input parameters are incorrect or not representative of
real distribution (limited number of measurements) or the associated
sampling model is not appropriate, the output reflect the intrinsic error or
uncertainties.

 Probability distribution of the OHIP: no a single value, but a more
representative probabilistic distribution of the function (OHIP) of interest.
OHIP Estimation by Volumetric Method -
Stochastic Approach
Total Recoverable Oil (Millions BBL)
 The average expected oil reserve
is 12.4 million barrels
 The minimum expected oil
reserve is 5.26 million barrels
 The maximum expected oil
reserve is 26.24 million barrels
5.26
MMbbl
26.24
MMbbl
12.4 MMbbl

 It is customary in the industry to describe this uncertainty in terms of a low (P90) and
high (P10) range.
OHIP Stochastic Approach: P10 – P50 – P90
 The range of uncertainty of the recoverable and/or potentially recoverable volumes may
be represented by either deterministic scenarios or by a probability distribution. When
the range of uncertainty is represented by a probability distribution, a low, best, and
high estimate shall be provided such that:
- There should be at least a 90% probability (P90) that the quantities actually
recovered will equal or exceed the low estimate.
recovered will equal or exceed the best estimate.
recovered will equal or exceed the high estimate.
 For volume estimates, a low (P90) - high (P10) range is thus unambiguously defined by
statistics. The situation is more complex for a production forecast because the forecast
is a timeline and not a scalar. This has led to a variety of uncertainty definitions for the
forecast used in the industry, and has hampered progress in deriving the best methods,
tools and processes for deriving the forecast uncertainty range.

May 2017 96
OHIP Estimation
by Material Balance
Technique
G. Moricca

OHIP Estimation by Material Balance
Technique
 In all cases, the OHIP value determined from material balance computation
must be compared with the volumetric HOIP from the geological study.
The two estimations will never agree exactly and any difference greater
than, say, 10% should be investigated. When flaws in either technique are
ruled out and when robust material balance solution are available.
 Two cases may arise:
- The material balance gives lower OHIP than the volumetric
calculation. In this case, the inconsistency may be related to
differences in the reservoir volume being investigated, for example in
the presence of faulted reservoirs, where some of the fault blocks are
not in communication with the main producing part of the reservoir.
- The material balance gives higher OHIP than the volumetric
calculation. Since the material balance provides an estimation of what
Schilthuis called active oil, it is possible that too strong a cut-off has
been applied in the volumetric calculation and that some of the oil
trapped in the low porosity rocks actually contributes to the global
expansion.

OHIP estimation by Material Balance Method
 The Material Balance OHIP estimation is performed by the Havlena and Odeh techniques.
Energy Plot
Campbell Plot
Analytical Plot
This is a plot of tank pressure against cumulative
phase produced (in this case oil). The data points are
the historical pressure and cumulative rate data.
Campbell plot (graphical diagnostic plot) re-arrange the material balance
equation such that a plot of the ratio of net produced volumes (Prod –
Aquifer Influx and /or injection) divided by expansion terms yields a
horizontal line with an intercept equal to initial volumes in place.
The Energy plot shows the contribution of various
drive mechanisms tower production with time.
The WD plot shows the dimensionless aquifer function versus type
curves. This plot indicates the location of the history data points in
dimensionless coordinates.
WD Function Plot

May 2017 99
Recoverable oil
(Reserves) Estimation
when reservoir model is
not available
G. Moricca

Estimating recoverable volume of oil or
gas if reservoir model is not available
 Recoverable oil or gas depends on reservoir quality and
reservoir drive.
Recoverable oil or gas = OHIP x RF
 If reservoir model is not available, reservoir analogs help
narrow the range of values for variables that determine
recovery factor (RF). Use the equation below to estimate
the recoverable oil or gas in a reservoir:

Estimating recovery factor
 Drive mechanism has the greatest geological impact on recovery factor.
Narrowing the range in recovery factor is a matter of estimating how
much difference pore type and reservoir heterogeneity impact the
efficiency of the drive mechanism. To estimate the recovery factor, use
the procedure below:
1. Decide which drive mechanism is most likely from the geology of
the prospective reservoir system and by comparing it with reservoir
systems of nearby analog fields or analog fields in other basins.
2. Multiply OOIP or OGIP by the recovery factor for the expected
drive.
3. Narrow the recovery factor range by predicting the thickness of
the reservoir by port type. Port type affects recovery rate. For
example, in a reservoir with strong water drive and macroporosity,
recovery will be up to 60%, mesoporosity recovery will be up to
20%, and microporosity recovery will be 0%.

Recovery factors for different drive
types mechanism
 The table below shows recovery factor percentages for different drive
mechanisms for oil vs. gas reservoirs.
Reservoir drive
mechanism
Percent ultimate recovery [%]
Gas Oil
Strong water 30–40 45–60
Partial water 40–50 30–45
Gas expansion 50–70 20–30
Solution gas N/A 15–25
Rock 60–80 10–60
Gravity drainage N/A 50–70

May 2017 103
Reserves
Classification
G. Moricca

Proven Reserves [1]
 Proved reserves are those quantities of petroleum which, by
analysis of geological and engineering data, can be estimated with
reasonable certainty to be commercially recoverable, from a given
date forward, from known reservoirs and under current economic
conditions, operating methods, and government regulations.
Proved reserves can be categorized as developed or undeveloped.
 If deterministic methods are
used, the term reasonable
certainty is intended to express
a high degree of confidence
that the quantities will be
recovered. If probabilistic
methods are used, there
should be at least a 90%
probability that the quantities
actually recovered will equal or
exceed the estimate.

Proven Reserves [2]
 In general, reserves are considered proved if the commercial
producibility of the reservoir is supported by actual production or
formation tests. In this context, the term proved refers to the
actual quantities of petroleum reserves and not just the
productivity of the well or reservoir.
 In certain cases, proved
reserves may be assigned
on the basis of well logs
and/or core analysis that
indicate the subject
reservoir is hydrocarbon
bearing and is analogous to
reservoirs in the same area
that are producing or have
demonstrated the ability to
produce on formation tests.

Proven Reserves [3]
 The area of the reservoir considered as proved includes (1) the area
delineated by drilling and defined by fluid contacts, if any, and (2)
the undrilled portions of the reservoir that can reasonably be
judged as commercially productive on the basis of available
geological and engineering data.
 In the absence of data
on fluid contacts, the
lowest known
occurrence of
hydrocarbons controls
the proved limit
unless otherwise
indicated by definitive
geological,
engineering or
performance data.

Proven Undeveloped Reserves
 Reserves in undeveloped locations may be classified as proved
undeveloped provided (1) the locations are direct offsets to wells
that have indicated commercial production in the objective
formation, (2) it is reasonably certain such locations are within the
known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where
applicable, and (4) it is reasonably certain the locations will be
developed.
 Reserves from other locations are categorized as proved
undeveloped only where interpretations of geological and
engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains
commercially recoverable petroleum at locations beyond direct
offsets.

Production Forecast
Prediction Cases

 Once the base case prediction run has been calibrated for the prevalent
or observed field conditions, a complete forecast simulation is performed.
The results of this run should be carefully checked for the presence of
errors, oversight and numerical instabilities. In addition, a check should be
made that the well management/drilling scheme has been correctly
implemented and that no unexpected departures are observed in the
resulting profiles.
Production Forecast
 As far as the results are concerned, the analysis of a production forecast
can be made in a variety of ways, the most typical being tables and plots
of oil rates and cumulative oil production vs. time.
 A comparison of the results of the various cases will show at a glance the
most interesting (technical) exploitation options

Reservoir
Development Strategy

Field Flow Production Profile
 The decline of field flow rate can be against by appropriate depletion strategy involving a proper
pressure support according to the reservoir characteristics.
 An oilfield typically exhibits the production profile seen in figure below. Some fields have short plateau
periods (reservoir with no pressure support = Natural Flow) , more resembling a single peak, while
others (reservoir with strong pressures support due to the presence of a strong active aquifer or
efficient pressure support by injection of water or gas according to the specific reservoir
characteristics) may keep production relatively constant for many years. But, at some point, all fields
will reach the onset of decline and begin to experience decreasing production.
No pressure
support

Reservoir Drive Mechanisms
 Four type of driving mechanism are
possible:
1. Depletion or Solution gas drive
2. Gas cap drive
3. Water drive
4. Combination drive

Solutions Gas Drive
Reservoir Behavior
and Development
Strategy

 Solution drive occurs on a reservoir which contain no initial gas cap
or underlying active aquifer to support the pressure and therefore
oil is produced by the driving force due to the expansion of oil and
connate water, plus any compaction drive.
 The
contribution to
drive energy
from
compaction and
connate water
is small, so the
oil
compressibility
initially
dominates the
drive energy.
Development Strategy for Depletion or
Solution Gas Drive Reservoirs [1]
Solution Gas Drive
Reservoir

May 2017 115
 Because the oil compressibility itself is low, pressure drops rapidly as
production takes place, until the pressure reach the bubble point.
 Once the bubble point is reached, solution gas starts to become liberated
from the oil, and since the liberated gas has a high compressibility, the
rate of decline of pressure per unit of production slow down.
Development Strategy for Solution
Gas Drive Reservoirs [2]
G. Moricca
F. Jahn , M. Cook & M. Grahm 2008

 Once the liberated gas has overcome a critical gas saturation in the
pores, below which it is immobile in the reservoir, it can either
migrate to the crest of the reservoir under the influence of
buoyancy forces, or move toward the producing wells under the
influence of the hydrodynamic forces caused by the low pressure
created at the producing well.
 In order to make use of the high compressibility of the gas, it is
preferable that the gas forms a secondary gas cap and contributes
to the driving energy.
 This can be encouraged by reducing the pressure sink at the
producing wells (which means less production per well) and by
locating the producing wells away from the crest of the field.
Development Strategy for Solution
Gas Drive Reservoirs [3]

Development Strategy for Solution Gas
Drive Reservoirs [4]
 In a steeply dipping field,
wells would be located
down-dip. However, in a
field with low dip, the
wells must be perforated
as low as possible to
keep away from a
secondary gas cap.
 There are three distinct
production phases,
defined by looking at the
oil production rate.

 After the first production date, there is a build-up period, during
which the development wells are being drilled and brought on
stream, and its shape is dependent on the drilling schedule.
 Once the plateau is reached, the facilities are filled and any extra
production potential from the wells is choked back.
 The facilities are usually designed for a plateau rate which
provides an optimum offtake from the field, where the optimum is
a balance between producing oil as early as possible and avoiding
unfavorable displacement in the reservoir, caused by producing too
fast, and thereby losing ultimate recovery (UR).
 Typical production rates during the plateau period vary between
2and 5% of STOIHP per year.

 Once the well potential can no longer sustain the plateau oil rate,
the decline period begins and continues until the abandonment
rate is reached.
 In the solution gas drive reservoirs, the producing GOR starts at the
initial solution GOR (Rsi), decreases until the critical gas saturation
is reached, and then increases rapidly as the liberated gas is
produced into the wells.
 Commonly the water cut remains small in solution gas drive
reservoirs, assuming that there is little pressure support provided
by the underlying aquifer.
 The producing GOR may decline in later years as the remaining
volume of gas in the reservoir diminishes.

 The typical Recovery Factor (RF) from a reservoir development by
solution gas drive is in the range 5-30%, depending largely on the
absolute reservoir pressure, the solution GOR of the crude, the
abandonment conditions and the reservoir dip.
 The upper end of this range may be achieved by a high dip
reservoir (allowing segregation of the secondary gas cap and the
oil), with high GOR, light crude and a high initial reservoir
pressure.
 Abandonment conditions are caused by high producing GORs and
lack of reservoir pressure to sustain production.
 The low RF may be boosted by implementing secondary recovery
techniques, particularly water injection, or gas injection, with the
aim of maintain reservoir pressure and prolonging plateau and
decline periods.

 The decision to implement these techniques is both technical and
economical.
 Technical considerations
would be the external
supply of gas, and the
feasibility of injecting
the fluids into the
reservoir.
 Multiple reservoir
simulation runs,
combined with an
adequate economic
analysis, are require to
define the problem and
identify a proper
optimized solution.

Solution Gas Drive
Reservoirs Performance
 Pressure (P), gas saturation (Sg).
producing GOR (R), and
cumulative producing GOR (Rps)
as a function of OOIP recovered
for a solution gas drive, black oil
reservoir.
 Pressure and producing GOR as a
function of OOIP recovered for a
Louisiana volatile-oil reservoir.

Gas Cap Drive
Reservoir Behavior
and Development
Strategy

Development Strategy for Gas Cap Drive
Reservoir [1]
 The initial condition for gas cap drive is an initial gas cap. The high
compressibility of gas provide drive energy for production, and
the larger the gas cap, the more energy is available
Gas Cap Drive Reservoir

Reservoir [1]
 The well position follow the same reasoning as for solution gas
drive; the objective being to locate the producing wells an their
perforations as far away from the gas cap (which will expand with
time) as possible but not so close to the OWC to allow significant
water production via coning.

Reservoir [2]
 Compared to the solution gas drive case, the typical production
profile for gas cap drive shows a much slower decline in reservoir
pressure, due to the energy provided by the highly compressible
gas cap, resulting in amore prolonged plateau and a slower
decline.

May 2017 G, Moricca 127
Reservoir [3]
 Typical RFs for gas cap drive are in the range 20-60% influenced by
the field dip and the gas cap size.
 Abandonment conditions are caused by very high producing
GORs, or lack of reservoir pressure to maintain production, and
can be postponed by reducing the production from high GOR
wells, or by recompleting these wells to produce further away
from the gas cap.
 Natural gas cap drive may be supplemented by reinjection of
produced gas, with the possible addition of make-up gas from an
external source.
 The producing GOR increase as the expanding gas cap
approaches the producing wells, and gas is coned or cusped into
the producer. Supposing a negligible aquifer movement, the water
cut remains low.

Reservoir [4]
 The gas injection well
would be located in the
crest of the structure,
injecting into the existing
gas cap.
simulation runs, combined
with an adequate
economic analysis, are
require to define the
problem and identify a
proper optimized solution.

Gas Cap Drive Reservoir Characteristics
 Broadly, gas caps
are classified as
segregating or
non-segregating.
 The table
summarizes the
distinguishing
characteristics of
each.
PetroWiki

Segregating Gas Caps Reservoir
 Distribution of water, oil, and gas and position of gas/oil contact (GOC) in a
segregating-gas-cap reservoir: (a) before production and (b) during depletion.
 Segregating gas caps are gas caps that grow and form an enlarged gas cap zone.
 The segregation-drive mechanisms can be augmented by crestal gas injection.

Non-Segregating Gas Caps Reservoir
 Distribution of water, oil, and gas in a non-segregating-gas-cap reservoir: (a) at
discovery and (b) during depletion.
 Non-segregating gas caps do not form an enlarged gas-cap zone, and their GOC
appears stationary.
 The gas-cap gas expands but the displacement efficiency is so poor that the
expanding gas appears to merely diffuse into the oil column.

May 2017 132
Gas Cap Drive Reservoir
Performance
The effect of dimenstionless gas cap
size (m) on final primary oil recovery
and peak producing GOR for a west
Texas black oil reservoir. Recoveries
reported as percent of oil-leg OOIP.
G. Moricca

Water Drive
Reservoir Behavior
and Development
Strategy

Development Strategy for Water Drive
Reservoir [1]
 Neural water drive occurs when the underlying aquifer is both large
(typically greater than ten times of the oil volume) and the water is
able to flow into the oil column, that is it has a communication path
and sufficiently permeable.
 If these conditions are
satisfied, then once
production from the
oil column creates a
pressure drop the
aquifer respond by
expanding, and water
moves into the oil
column to replace the
voidage created by
production.
Water Drive Reservoir

Reservoir [2]
 Since the water is compressibility is low, the volume of water must be
large to make this process effective, hence the need for the large
connected aquifer. In this context, “large” would be 10 to 100 x the
volume of oil in place.
 The prediction of
the size and
permeability of the
aquifer is usually
difficult, since there
is typically little data
collected in the
water column.

Reservoir [3]
 Hence the prediction of aquifer response often remain a major
uncertainty during reservoir development planning.
 In order to see the reaction of an aquifer, it is necessary to
produce from the oil column, and measure the response in
terms of reservoir pressure and fluid contact movement.
 Use is made of the material balance technique to determine the
contribution to pressure support made by the aquifer. Typically 5%
of STOIIP must be produced to measure the response. This may
take a number of years.

Reservoir [4]
 According to the location of the
aquifer relative to the reservoir,
they are classified as :
- Peripheral waterdrive -- the
aquifer areally encircles the
reservoir, either partially or
wholly
- Edgewater drive -- the aquifer
exclusively feeds one side or
flank of the reservoir
- Bottomwater drive -- the
aquifer underlays the
reservoir and feeds it from
beneath
Edgewater drive aquifer
Bottomwater drive aquifer

Reservoir [5]
 Water drive may be imposed by water injection into the reservoir,
preferably by injecting into the water column to avoid by-passing
down-dip oil.
simulation runs,
combined with an
adequate
economic analysis,
are require to
define the
problem and
identify a proper
optimized
solution. F. Jahn , M. Cook & M. Grahm 2008

Reservoir [6]
 If the permeability in the water leg is significantly reduced due to
compaction or diagenesis, it may be necessary to inject into the
oil column.
 A common solution is to initially produce the reservoir using
natural depletion, and to install water injection facilities in the
event of little aquifer support.
 The aquifer response (or impact of the water injection wells) may
maintain the reservoir pressure close to the initial pressure,
providing a long plateau period and slow decline of oil
production.
 The producing GOR may remain approximately at the solution
GOR if the reservoir pressure is maintained above the bubble
point.

Reservoir [7]
 The outstanding
feature of the
production
profile is the
large increase
in water cut
over the life of
the field, which
is usually the
main reason for
abandonment. F. Jahn , M. Cook & M. Grahm 2008

Waterflooding

Waterflooding
 Waterflooding is a process used to inject
water into an oil-bearing reservoir for pressure
maintenance as well as for displacing and
producing incremental oil. Since waterflooding
usually follows “primary” production, it is often
called a “secondary” recovery technique.

May 2017
Basic of Waterflooding Process
 Waterflooding is one of the most widely used
post-primary recovery method. Reservoir
engineers are responsible for waterfood
design, performance prediction, and reserves
estimation. They share responsibilities with
production engineers for the
implementation, operation.
 Waterfooding is the injection of water into a wellbore to push, or “drive” oil to another
well where it can be produced. The principal reason for waterflooding an oil reservoir is to
increase the oil-production rate and, ultimately, the oil recovery.
William M. Cobb & Associates, Inc.
G. Moricca 143
 This is accomplished by "voidage replacement"—injection of water to increase the
reservoir pressure to its initial level and maintain it near that pressure.
 The water displaces oil from the pore spaces,
but the efficiency of such displacement
depends on many factors (e.g., oil viscosity
and rock characteristics).

May 2017
Immiscible displacement
 In the processes of immiscible displacement, the composition of the
displacement fluid (e.g. water) and the displaced fluid (oil) remains unaltered
and a separation interface is maintained throughout the entire process; water
and oil constitute two completely distinct fluid phases.
G. Moricca 144
 A process of immiscible displacement can occur naturally where an active aquifer
is present, or can be induced by injecting water as the displacement fluid, as is
usually the case, or a dry gas.

May 2017
Microscopic displacement efficiency
 Microscopic Displacement Efficiency (MDE) reflects the residual oil saturation
value, that is, the oil left behind in the formation after the passage of the
displacing fluid.
G. Moricca 145
 Oil saturation refers to the fraction of the rock’s pore volume filled with oil, and
is dependent on the shape and dimensions of the pores, the properties of the oil,
and the interaction between the rock and the fluids governed by interfacial
tensions and wettability (the tendency of a fluid to stick to the rock’s surface.

May 2017
Wettability, Absolute Permeability, Relative
Permeability and Critical Saturation
G. Moricca 146
 Wettability is a fundamental property, being that it influences the fluid
saturations and relative permeability.
 The relative permeability to a fluid is defined as the ratio between the effective
permeability to that fluid and the absolute permeability of the rock. Absolute
permeability is an intrinsic property of reservoir rock, and defines the ease with
which a fluid can flow through the interconnected pore spaces when the rock is
saturated in a single fluid, whereas effective permeability defines a fluid’s ability
to do the same in the presence of other fluids (water, gas, oil).
 Therefore, relative permeability is a property that is dependent on the fractions
or saturation degree of the different fluids present in the porous medium, and
by definition can vary between zero and one. The greater the percentage of fluid
present in the porous medium, the higher its relative permeability will be.
 On the other hand, every fluid has a saturation point, referred to as critical
saturation; below this point, the fluid is no longer mobile, though still present
within the porous medium; at that point the relative permeability becomes
zero.

May 2017
Relative Permeability Curve
 During the viscous displacement flood the water saturation increases from its
irreducible value ( Swc ), at which it is immobile, to the maximum or flood-out
saturation ( Sw = 1 – Sorw ) at which the oil ceases to flow.
G. Moricca 147
1
 Sorw , is the residual oil
saturation representing the
unconnected oil droplets
trapped in each pore space
by surface tension forces at
the end of the waterflood.
 This occurs in any flood in
which the fluids are
immiscible, that is they do not
physically or chemically mix.
 Consequently the maximum amount of oil than can be displaced (recovered)
during a waterflood is: MOV = PV (1 - Sorw - Swc)

May 2017
Relative Permeability Laboratory
Measurements [1]
 The so-called rock relative permeability curves are measured in one-dimensional
core flooding experiments. After cleaning the core plug and flooding it with oil,
so that at initial conditions it contains oil and irreducible water, one of two
types of experiment is usually performed.
G. Moricca 148
 The major difference in unsteady state techniques is that saturation equilibrium
is not achieved during the test.
 The most common is the viscous displacement of oil by injected water
(unsteady-state type) and the second is the steady-state type of experiment in
which both oil and water are simultaneously injected into the plug at a
succession of different volume ratios (water flow rate increasing, oil rate
decreasing).
 Since steady state is not reached, Darcy’s Law is not applicable. The Buckley-
Leverett equation for linear fluid displacement is the basis for all calculations of
relative permeability.

May 2017
Relative Permeability Laboratory
Measurements [2]
 There are essentially five means by which relative permeability data can be
obtained:
- Direct measurement in the laboratory by a steady state fluid flow process
- Direct measurement in the laboratory by an unsteady state fluid flow
process
- Calculation of relative permeability data from capillary pressure data
- Calculation from field performance data
- Theoretical/empirical correlations
G. Moricca 149
 Values obtained through laboratory measurements are usually preferred for
engineering calculations, since they are directly measured rather than estimated.
Steady state implies just that, values are not measured until the tested sample
has reached an agreed upon level of steady-state behavior. Subsequently,
unsteady-state measurements are taken while the system is still changing over
time. Unsteady state tests are popular because they require much less time and
money than steady state tests to operate.

May 2017
Relative Permeability: Unsteady State
Techniques
G. Moricca 150

Factors governing the
waterflooding process
Three are the factors governing the oil recovery
efficiency achievable by the waterflooding
process. They are:
-Mobility ratio
-Heterogeneity
-Gravity

Mobility
ratio
𝑴 =
𝑲 𝒓𝒘
𝝁 𝒘
/
𝑲 𝒓𝒐
𝝁 𝒐

Mobility ratio M
𝑴 =
𝒎𝒂𝒙𝒊𝒎𝒖𝒎 𝒗𝒆𝒍𝒐𝒄𝒊𝒕𝒚 𝒐𝒇 𝒕𝒉𝒆 𝒅𝒊𝒔𝒑𝒍𝒂𝒄𝒊𝒏𝒈 𝒑𝒉𝒂𝒔𝒆 (𝒗𝒂𝒕𝒆𝒓)
𝒎𝒂𝒙𝒊𝒎𝒖𝒎 𝒗𝒆𝒍𝒐𝒄𝒊𝒕𝒚 𝒐𝒇 𝒕𝒉𝒆 𝒅𝒊𝒔𝒑𝒍𝒂𝒄𝒆𝒅 𝒑𝒉𝒂𝒔𝒆 (𝒐𝒊𝒍)
𝑴 =
𝑲 𝒓𝒘
𝝁 𝒘
/
𝑲 𝒓𝒐
𝝁 𝒐
Krw = end point water relative permeability (dimensionless)
Kro = end point oil relative permeability (dimensionless)
µw = water viscosity (cp)
µo = oil viscosity (cp)
M ≤ 1 means that the injected water cannot travel faster than the
oil and therefor displaces the oil in perfect piston-like manner.
M ≤ 1 Stable displacement (piston-like displacement)
M > 1 Unstable displacement (water fingering, poor oil recovery)

Mobility ratio M
𝑴 =
𝑲 𝒓𝒘
𝝁 𝒘
/
𝑲 𝒓𝒐
𝝁 𝒐
= 0.6
Krw = end point water relative permeability (dimensionless) = 0.3
Kro = end point oil relative permeability (dimensionless) = 1
µw = water viscosity (cp) = 0.4
µo = oil viscosity (cp) = 0.8
M ≤ 1 means that the injected water cannot travel faster than
the oil and therefor displaces the oil in perfect piston-
like manner, stable displacement , good oil recovery.
Using typical parameters for North Sea fields:

Mobility ratio M
M ≤ 1 resulting from low oil viscosity, the
displacement is piston-like and highly efficient
such that all the movable oil is recovered by the
injection of an equivalent volume of water.
M > 1 Alternatively, if the oil is viscous so that M > 1,
the flood is inefficient and it can take the
circulation of many MOVs of water to recover
the single MOV of oil.

Mobility ratio [M] impact on Sweep Efficiency
Good ‘piston
like’ flooding
 Good sweep efficiency
 No by-passed oil
Water
M ≤ 1 Oil
Bad flooding
‘water fingering’
Water
 Poor sweep efficiency
 Early water breakthrough
 By-passed oil
M > 1
Oil

Reservoir
Heterogeneity

Reservoir Heterogeneity
 Matrix permeability variation in the vertical direction causes
displacing fluid to advance faster in zones of higher permeability and
results in earlier breakthrough in such layers.
 All oil reservoirs are heterogeneous rock formations. The primary
geological consideration in waterflooding evaluation is to determine
the nature and degree of heterogeneities that exist in a particular
oil field.
 To achieve a good recovery factor, the displacement fluid, whether of
natural origin or induced by injection, must efficiently sweep the
hydrocarbons in the pore spaces and must also come into contact
with the greatest possible volume of the reservoir.
 The macroscopic displacement efficiency, in turn, is the product of
two elements: areal sweep efficiency and vertical invasion
efficiency.

Reservoir Heterogeneity
 Vertical sweep efficiency. Vertical sweep efficiency is a parameter that
expresses the degree of displacement of the oil by the displacement fluid
along a vertical section of the reservoir at a specific moment in its
productive life.
 Areal sweep efficiency. Areal sweep efficiency, is defined as the ratio
between the area of the reservoir with which the displacement fluid comes
into contact and the reservoir’s total area

Heterogeneity Unfavorable for Waterflooding
 Reservoir heterogeneities can take many forms, including
- Shale, anhydrite, or other impermeable layers that partly or completely separate the
porous and permeable reservoir layers.
- Interbedded hydrocarbon-bearing layers that have significantly different rock qualities —
sandstones or carbonates.
- Varying continuity, interconnection, and areal extent of porous and permeable layers
throughout the reservoir that can induces poor waterflooding efficiency.
- Directional permeability trends that are caused by the depositional environment or by
diagenetic changes that can induce poor sweep efficiency.
- Fractures or high permeability channels, that induce a channeling flow and a consequent
premature water breakthrough.
- Fault trends that affect the connection of one part of an oil reservoir to adjacent areas,
either because they are flow barriers or because they are open conduits that allow
unlimited flow along the fault plane, and consequently very poor waterflooding
efficiency.

Impact of Permeability Heterogeneity
on Oil Displacement Efficiency [1]
 The effect of different permeability distributions across a continuous reservoir
section can be illustrated considering three cases as follow.
Case (a): Coarsening upwards in permeability.
This case represents what might be described as the "super homogeneous"
reservoir.
At the injection well, the bulk of the water enters the top of the section. But
the viscous, driving force from the injection pumping decreases logarithmically
in the radial direction and before the water has travelled far into the formation
it diminishes to the extent that gravity takes over and dominates.
The water, which is continually replenished at the top of the formation, then
slumps to the base and the overall effect is the development of a sharp front
and perfect, piston-like displacement across the macroscopic section.

Case (b): The permeability increase with depth.
The majority of the injected water enters at the base of the
section at the injection wellbore and being heavier it stays there.
This leads to premature breakthrough and the circulation of large
volumes of water to recover all the oil trapped at the top of the
section.

Case (c) is intermediate between the two.
There is piston-like displacement across the lower part of the
section but a slow recovery of oil from the top.
This leads to premature breakthrough and the circulation of large
volumes of water to recover all the oil trapped at the top of the
section.

Impact of Permeability distribution across a continuous
reservoir section on Displacement Efficiency [From L. P. Dake – 2001]
]
Gravity segregation
Gravity segregation
The Practice of Reservoir Engineering – L. P. Dake - 2001

Recipe for evaluating vertical sweep efficiency in
heterogeneous reservoirs - The Practice of Reservoir Engineering – L. P. Dake
No matter what the nature of the vertical heterogeneity, the following
recipe is applied to assess the sweep efficiency in edge waterdrive
reservoirs.
- Divide the section in to N layers, each characterised by the following
parameters: hi , Ki , φi , Swci , Sori , K’rw , K’ro (the subscript “ i “
relates to the ith layer).
- Decide whether there is vertical pressure communication between the
layers or not.
- Decide upon the flooding order of the N layers and generate pseudo-
relative permeabilities to reduce the description of the macroscopic
displacement to one dimension.
- Use the pseudos to generate a fractional flow relationship which is
used in the Welge equation to calculate the oil recovery, Npd (PV), as a
function of cumulative .water influx, Wid (PV).
- Convert the oil volume to a fractional oil recovery, Np/N , and relate
this to the surface watercut, fws .

Recipe for evaluating vertical sweep efficiency in
heterogeneous reservoirs - The Practice of Reservoir Engineering – L. P. Dake
were:
- fws = fractional flow of water (dimensionless)
- hi = formation thickness ith layer (ft)
- Ki = permeability ith layer (mD)
- K’rw = end point relative water permeability ith layer (dimensionless)
- φi = porosity ith layer (fraction)
- Np = cumulative oil recovery (stb)
- Npd = dimensionless cumulative oil recovery (PV)
- Swci = connate water saturation ith layer (PV)
- Sori = residual oil saturation ith layer (PV)
- Wid = dimensionless cumulative water injected ith layer (PV)
- PV = pore volume

Gravity
Segregation
Water tongue

Vertical Equilibrium and Effect of
Gravity Forces
 The distribution of fluids is dictated by gravity/capillary
equilibrium for a waterflood. When a reservoir is produced at low
rates and there is a large density difference between injected and
produced fluids, gravity forces dominate over viscous forces.
 The importance of gravity segregation of fluids can be determined
by the viscous-gravity time ratio, shown by:
 Gravity effects always are present because for any potential
waterflood project, oil always is less dense than water, even more
so after the gas is included that is dissolved in the oil at reservoir
conditions.

 Gravitational forces can be a major factor in oil recovery if the
reservoir has sufficient vertical relief and vertical permeability.
 The effectiveness of gravitational forces will be limited by the rate
at which fluids are withdrawn from the reservoir.
 If the rate of withdrawal is appreciably greater than the rate of
fluid segregation, then the effects of gravitational forces will be
minimized.
 In all reservoirs, even those with close well spacing, the horizontal
distance between an injector well and a producer well is very long
relative to the vertical thickness of the reservoir pay interval.
 This means that gravity plays an important role in the water/oil-
displacement process, given that the fluids can move vertically
within the pay interval.
Vertical Equilibrium and Effect of
Gravity Forces

Vertical Displacement [From PetroWiki]
 To describe the Vertical Displacement in a waterflood,
three distinct situations should be considered:
- Stratified systems with non communicating
layers for various mobility ratios.
- Homogeneous systems with gravity (including
dipping beds).
- Stratified systems with communicating layers
and assumed vertical fluid equilibrium.

May 2017 G. Moricca
Stepwise Waterflooding Project
 The uncertainties of a waterflooding design coming from the
reservoir characteristics uncertainties that can be the source for a
very poor waterflooding efficiency and consequently technical
unsuccessful and economic disaster..
 Unfortunately, the waterflooding design has to be carryout when, in
many cases, we have limited information on reservoir
characteristics.
 The only way to face the problem is to:
- Perform an in deep analysis of the available information
- Adopt an phase approach for waterflooding project
implementation.
171

Well
Architecture

Well Architecture
 Today, thanks to the advanced drilling technologies it is possible to drill wells
having different shapes:
- Vertical
- Slanted
- S-shape
- Horizontal
- Multilateral
 This gives us the
flexibility to select
the most
appropriate,
according to the
production target
and the subsurface
formation
characteristics.
Well Type by Shape

Well Drilling and Completion Planning
 The drilling of a well involves a major investment ranging from a few million US$ for
onshore well to 100 million US$ for a deepwater exploration well.
 Well engineering is aimed at maximizing the value of this investment by employing
the most appropriate technology and business process, to drill a ‘’fit for purpose”
well, at the minimum cost, without compromising safety or environmental standards.
 The subsurface team will define
optimum location and well
architecture for the planned wells to
penetrate the trajectory through the
objective sequence.
 To optimize the design of a well it is desirable to have as accurate a picture as
possible of the subsurface: identification of boundaries, heterogeneities, and
anisotropies.
 Completion engineering, as part of is
that part FDP integrated team, is
responsible of well completion design
aimed to maximize production (or
injection) in a cost-effective manner.
M. J. Economides -A. D. Hill – C. Ehlig-Economides – D. Zhu
Copyright © 2013 Pearson Education, Inc.

Well Architecture and Completion
Strategy
Petroleum Production System involves three distinct connected
systems:
1. Reservoir, which is a porous medium with unique storage and
flow characteristics
2. Subsurface artificial structures, which include the well, bottom
hole completion, reservoir completion and wellhead
assemblies connected with
3. Surface artificial structures, which include the surface gathering,
separation, and storage facilities.

Completion is the interface between reservoir
and surface production.
Well Architecture makes reference to the well
shape (Vertical, Slanted, Horizontal, Multilateral,
Extended Reach) design to reach the target
(reservoir) in the most efficient and effective way.
Well Architecture and Completion
Strategy

Vertical Well
 Vertical well is the ideal
solution to produce from
a single flow unit having a
large net pay or multiple
flow units can be
produced commingled.
 Easy to be drilled.
 Very good bottom hole
accessibility.
 Less expensive.

J-shape wells are made up of a vertical
section, a deep kick off and a build up
to target. They are also called Deep
Kick off wells or J Profile wells (as they
are J - shaped).
The well is deflected at the kickoff
point, and inclination is continually
built through the target interval (Build).
The inclinations are usually high and
the horizontal departure low.
This type of well is generally used for
multiple sand zones, fault drilling, salt
dome drilling, and stratigraphic tests.
J-shape

Horizontal Well
 Disadvantages of horizontal wells
are:
- High cost as compared to a
vertical well.
- Generally only one zone at a time
can be produced using a
horizontal well.
- If the reservoir has multiple pay-
zones, especially with large
differences in vertical depth, or
large differences in permeability,
it is not easy to drain all the layers
using a single horizontal well..
Horizontal wells have been employed in a variety of reservoir applications:
- Thin zones
- Naturally fractured reservoirs,
- Reservoirs with water and gas coning problems
- Low permeability reservoirs
- Gas reservoirs
- Heavy oil reservoirs
- Waterflooding
- EOR applications.

May 2017 J. Bellarby – ELSEVIER 2009 180
Multilateral well
 A multilateral is a well with more
than one branch (lateral).
 Multilaterals find wide
applications:
- Compartmentalized reservoirs
- Stacked intervals
- Increased reservoir drainage
- Reducing drawdown
- Slot constrained platforms or
pads.
 A multilateral is well always carry
more risk than a single well. Risks
for multilateral should be
assessed in term of drilling,
completing, productivity,
operability and well intervention.

Well
Completion

Well Completion Strategy [1]
 Although
completion
expenditure is a
limited portion of
the total capital
costs of the field,
completion have
a huge effect on
revenues and
future operating
cost. Some of
basic economic
considerations
are shown in the
figure here
reported. J. Bellarby – ELSEVIER 2009

Well Completion Strategy [2]
 This does not necessarily mean that completions have to survive for the entire
field life. It may be optimum to design for tubing replacement or artificial lift
installation when the flow conditions (BHP, WC, GOR) change.
 The choice to spend more money on corrosion-resistant completion for the
initial completion or to install a cheaper completion to be replaced if failure will
occur is an economical matter.

Completion Planning
 Completion planning of a producer, involves:
- Defining the well architecture
- Defining the mode of formation fluid production: Natural flow or assisted
flow by Artificial Lift system.
- Choosing the equipment to be used
- Selecting materials
- Defining operational guidelines
 Wells to be completed can be producers or injectors.
- A producer can be an oil or gas producer well.
- An injector can be an water, gas (hydrocarbon gas or waste products such as
carbon dioxide, Sulphur, hydrogen sulphide, etc.), steam well injector or
disposal well.
 The completion planning for the injector is the same of the producer but
considering that the is in of “hydraulic injection flow condition” only.
 The completion design mast take into account the evolution of the
production/injection characteristics (BHFP, WC, GOR) of the well along the field
life time, according to the production/injection forecast.

Single Completion [1]
 Single zone completion is one of the
types of upper completion which allows
producing only one zone. Production
tubing is a flow path for fluid from a
reservoir to flow to the surface so it
protects the casing from corrosion and
maximizes the efficiency of the flow.
 In a single tubing string completion,
typically a packer is set on top of a
reservoir so the reservoir fluid can flow
up into the production tubing. Types of
packers are based on several factors as
temperature, pressure, reservoir fluid,
etc. Additionally, complexity of tubing and
packer installation is driven by objectives.

Single Completion [2]
 Features of a Single String
Completion are listed below:
- Through tubing perforation
can be performed.
- Packer can be set with x-mas
tree in place.
- Reservoir can be isolated and
workover operation can be
done.
- Downhole measurements can
be effectively conducted.
- Artificial lift methods as gas
lift, ESP, etc. can be deployed.

Multiple zone completion
Multiple zone completion is one type of
completion which allows operators to
selectively produce or comingle
reservoir fluid from different zones into
one well.
It is also possible to workover the upper
part of completion string without
removing the next interval completion.
Additionally, through tubing perforation
is can performed at the bottom zone.
A multiple zone completion can be
divided into two parts, which are single
string completion and multiple string
completion.

Single Multiple Zone Completion [1]
 A multiple-string configuration
consists of two or more
completion strings in one well.
 This is more expensive and
complicated to install than a
single-string configuration.
However, it has some advantages
such as the ability to
simultaneous produce or inject
into different zones in
commingled.

Dual Multi zone Completion [2]
 A multiple-string configuration
consists of two or more
completion strings in one well.
 This is more expensive and
complicated to install than a
single-string configuration.
However, it has some advantages
such as the ability to
simultaneous produce and inject
into different zones and has a
more accurate production
allocation than a single string
type.

Dual Completion
 The complexity of dual completions is their main drawback:
- Difficult to perforate the upper interval. Option include
oriented guns run through the short string, perforating prior to
running the completion and side-string perforating.
- Limited access to the upper interval (e.g. water shut-off within
the interval is near impossible).
- Complex artificial lift (e.g. gas lift requires tubing pressure
operated valves).
- Difficult (but not impossible) to integrate with sand control
reservoir.
 The completion is usually installed with both strings at the same
time.

Horizontal well typical Completion

 Multilateral technology can be used in a variety of scenarios including:
- The development of in fill field programs with limited slots.
- The extension of field life by accessing new reserves.
- The development of deepwater plays.
Multilateral Completion
 Design concepts
In a multilateral completion, a unique system may mechanically connect directional and
horizontal laterals to a parent well bore, allowing production from the individual laterals to
be selectively produced or commingled.
 Generally, multilaterals can be
divided into two categories:
- Re-entry - Where an existing well
is re-entered and multiple
branches are drilled off of the
existing well bore.
- New development -Where a new
well is designed and drilled,
utilizing multiple branches and
various completion types as
required.
1996

March 2017 G. Moricca 193
Offshore Wells
Completion

 For the dry tree system, trees are located on or close to the platform,
whereas wet trees can be anywhere in a field in terms of cluster, template,
or tie-back methods.
 Globally, more than 70% of the wells in deepwater developments that are
either in service or committed are wet tree systems.

Wet tree systems
 Subsea cluster wells gathers the production in the most efficient and
cost-effective way from nearby subsea wells, or from a remote
/distant subsea tie-back to an already existing infrastructure based on
either a FPSO or a FPU

Vertical Monobore
Subsea Tree
Systems

Subsea manifold

May 2017 199
4
• Conceptual
Definition of
the Field
Development
Scenario
G. Moricca

 The Conceptual Field Development Scenario for new field
development is identified based on data obtained from during the
exploration and appraisal phases such as:
- Reservoir geological setting
- Reservoir driving mechanism
- Rock properties (porosity, permeability, saturation, capillary
forces, heterogeneity, etc.)
- Fluid properties
- Hydrocarbon in place
Conceptual definition of the Field
Development Scenario [1]

May 2017 201G. Moricca
 The decision to make investment for the field develop is
made based on the information provided by the reservoir
study: expected reserves and production profiles.
 The main scope of the task is to:
- Take decision ‘to do’ or ‘not to do’, and
- Select the Field Development Scenario
 The investment will be done if:
- The Project is supported by a positive economic and
- Reliable technology to produce the reservoir
resources are available.

 The base case is derived by using the “most trustable” reservoir
parameter associate with P50 Proved Reserves.
 If the project is judged as feasible, this task provide the following main
outcomes:
- The base case production profile
- The high potential case
- The conservative case
- A preliminary cost (Opex and Capex) estimation for each production
profile (cost accuracy ±40%).
 The high potential case is derived by using the “highest reservoir
potential”, associated with P30 Proved Reserves.
 The conservative case is derived by using the “most trustable” reservoir
parameter associated with P90 Proved Reserves.

Field Development Scenario Workflow
Cost accuracy
±40%

 Each phase ends with a gate review, which works as a clear transition
point, where the project, after being examined, is either allowed to move
to the next phase, return for a better definition or canceled.
Gate 1 – Is the project feasible?
 The conceptual engineering of the
identified opportunities will be
performed to compare the options
and identify which alternative is the
most feasible from technical and
economical view point (assessment
stage).
 At the end of the feasibility study, the project (identified possible business
opportunity) will be submitted to the management for approval [Gate 1]. If
the feasibility study is approved, the conceptual engineering of the
identified options will be performed.

May 2017 205
5
•Setting the
Field
Development
Strategy
G. Moricca

May 2017
Analyze Alternatives for field Development
FEL-1
Conceptual
Engineering
Clear frame
goal.
 Identify
opportunities.
 Preliminary
assessment of
uncertainties,
potential return,
and associated
risks.
 Plan for next
phase.
Cost accuracy
±40%
FEL-2
Preliminary
Engineering
Generate
alternatives.
 Reduce
uncertainty and
quantify
associated risks.
value for selected
alternatives.
alternative(s).
 Plan for next
phase.
Cost accuracy
±25%
FEL-3
Eng. Design
Fully define
scope.
execution plans.
and economic
analysis to A/R
level.
value meets
business
objectives.
Cost accuracy
±15%
Detailed
Eng. Design
Implement
execution plan.
 Final design
 Implement
execution plan.
and share metrics
and lessons
learned.
Cost accuracy
±5%
Operations
Support
Monitor
performance.
 Final design
 Benchmark
performance
against objectives
and competitors.
lessons learned.
 Continue
performance
assessment and
identify
opportunities.
G
1
G
2
G
3

Stage 2: Select among the possible
development scenario
 The project team evaluates all the development scenario using
criteria such as the production volumes expected, the
necessary investments, operating costs, economic feasibility,
HSE and the time needed until completion. Then the company
management chooses the most suitable concept based on
these criteria and makes the decision to develop this concept
further.
 There are many possibilities for developing a crude oil or
natural gas field. For instance, we could select between a
stand-alone platform, a subsea tie-back with an FPSO (Floating
Production, Storage and Offloading) or a subsea tie-back that is
linked to already existing host platforms. Eventually we will
have to choose one.

May 2017 208
Depletion
Strategy
Natural Depletion followed by Water/Gas Inj. for Pressure Maintenance
Natural Depletion followed by Water flooding for Secondary Recovery
Natural Depletion
Ultimate
Recovery
[UR]
Typical Scenario to be investigatedStrategy Outcomes
Production
Strategy Short plateau rate
Long plateau rate
Pre-drilling - Starting production at plateau rate Consolidated
Production
Profile
Lifting
Strategy
Artificial lifting flow
Artificial lifting flow providing some extra surface blustering pressure
Natural flow at minimum wellhead flowing pressure
Lifting
System to be
adopted
Well Architecture
Strategy
Horizontal
Multilateral
Vertical / Deviated
Cost-effective
way for fluids
withdrawal
Perforating
Strategy
Commingled Flow Units
Single Flow Unit
Partial Penetration
Effective
reservoir
management
Completion
Strategy Dual Completion onshore – Subsea Completion offshore
Single Completion onshore - Dry Completion offshore Cost-effective
way for fluids
withdrawal
Surface Facilities
Strategy Dedicated in-situ Facilities (onshore or offshore)
Crude to be sent to pre-existing onshore Facilities Cost-effective
way for fluids
treatment

Objective of Field Development Planning
 The main objective of field development planning is the selection of plan that
satisfies an operator’s commercial, strategic and risk requirements, subjected to
regional and site constraints, through a continuous and effective collaboration
and alignment amongst main stakeholders: Subsurface, Well Construction,
Surface Facility, Operation and Commercial Teams.
Subsurface
Characterization
Drilling
Completion
Surface
Facilities
Project
Objective

Items to be considered to define a
proper Field Development Strategy [1]
 A proper development strategies is strictly dependent from
reservoir characteristics and fluid behavior.
 The main questions to be addressed are:
- Hydrocarbon recovery scheme
- Primary and subsequently secondary and tertiary
hydrocarbon recovery technique
- Well spacing (Number of wells)
- Well Architecture
- Well Completion type
- Fluid transportation
- Fluid treatment

 For offshore development, the main question to be addressed are:
- Stand-alone development or subsea tie-in to existing
platform(s)
- Platform or subsea-to-land solution
- Platform concepts (e.g. floating or fixed, with and without
drilling facilities)
- Integration with existing platform(s) or infrastructure
- Transport solution for oil: pipeline transport or offshore
loading
- Transport solution for gas (compression demand, processing
requirements)
- Design for easy decommissioning and removal
Items to be considered to define a
proper Field Development Strategy [2]

FDP items and their impacts
 Reservoir Geometry and Geology (greatest impact)
- Recovery factor and flow rates.
- Well count, location and construction.
- Secondary recovery methods.
 Fluid Properties
- Subsea and topside design.
- Operation and maintenance( hydrate, wax and deposits,
corrosion).
 Drilling and Completion
- Well management and well intervention frequency.

 Regional Considerations and Regulations
- Block size
- Infrastructure
- Contract
 Site Characteristics (offshore field)
- Water depth
- Metocean condition
- Bathymetry
FDP items and their effects

 Reservoir data
 Crude oil properties
 Drilling and Completion technologies to be adopted
 Risk of pollution
 Geographic location
 Water depth
 Distance from Shore Base and/or Terminal
 Environmental conditions
 Soil criteria
 Functional and operational requirements
 Governing Codes of Practice
 Special or unusual Design Codes
In choosing a development concept
the following shall be taken into
consideration:

Identification of a FDP Clear Strategy
Identify the most effective strategy to reach the predefined Company Target
finding a proper answer to the questions like the following:
 Reservoir hydrocarbon withdrawal strategy:
- natural depletion ?
- water injection?
- gas injection ?
- water and/or gas injection ?
 Optimum wells location and spacing ?
 Optimum plateau rate ?
 Stand-alone development or subsea tie-in to existing platform(s) ?
 Platform or subsea-to-land solution ?
 Platform concepts (e.g. floating or fixed, with and without drilling facilities) ?
 Integration with existing platform(s) or infrastructure ?
 Transport solution for oil: pipeline transport or offshore loading ?
 Transport solution for gas (compression demand, processing requirements) ?
 Design for easy decommissioning and removal ?

Focus on
 To avoid uneconomic development
 To ensure safety for Person, Environment
 To ensure adequate economic return
 To derive maximum benefit from available data sets
 To improve reservoir recovery
Focus and Emphasis of Development
Strategy
Emphasis on
 Reduction of uncertainties
 Reduction of influence of uncertainties

Gate 2 – Is it the best scenario?
 Among the proposed solutions,
the company management
chooses the most suitable
development plan to be further
define from technical and
economics view point.

May 2017 218
6
•Consolidation
of the
Reservoir
Development
Scenario
G. Moricca

Consolidation of the Field Development
Scenario - Selection phase [1]
The main scope of consolidation task is analyze all the possible
alternative relevant to :
1. Depletion Strategy
- Natural Depletion
- Natural Depletion followed by Water/Gas Injection for Pressure Maintenance
- Natural Depletion followed by Waterflooding for Secondary Recovery
2. Production Srategy: Different Production Profile for the same UR
- Pre-drilling - Starting production at plateau rate
- Short plateau rate
- Long plateau rate
3. Lifting Strategy
- Natural flow at minimum wellhead flowing pressure
- Artificial lifting flow
- Artificial lifting flow providing some extra surface blustering pressure

Consolidation of the Field Development Scenario -
Selection phase [2]
4. Well Architecture Strategy
- Vertical
- Deviated
- Horizontal
- Multilateral
5. Perforation Strategy
- Single Flow Unit
- Commingled Flow Units
- Partial Penetration
6. Completion Strategy
- Single Completion onshore - Dry Completion offshore
- Dual Completion onshore – Subsea Completion offshore
7. Surface Facilities Strategy
- Crude to be sent to pre-existing onshore Facilities
- Dedicated in-situ Facilities (onshore or offshore)

Consolidation of the Field Development Scenario
Workflow - Case without production history [1]
Step 1 – Define a Depletion Strategy
Primary Recovery
Thermal
Natural Flow Artificial Lift
Water Flooding Pressure Maintenance
Gas Injection Chemical Other
Tertiary Recovery
Secondary Recovery
Conventional
Recovery
Enhanced
Recovery
Steam
Hot Water
In-situ Combustion
CO2
Hydrocarbon
Nitrogen
Alkali
Surfactant
Polymer
Microbial
Acoustic
Electromagnetic

Step 2 - Define a provision (to be confirmed or changed after analysis)
subsurface development scheme:
- Well location
- Well architecture
- Sand face completion
Step 3 – Run reservoir model (sensitivity) to assess the minimum well number
required to produce the reservoir economically, as well as the optimal well
location and well type (e.g. vertical, slant, horizontal, multilateral, etc.).
Step 4 – Make the economic analysis of “minimum well number” development
scenario to be used as a reference.

Step 5 – Simulate different well-spacing and calculate rates and volumes.

Step 6 – Make the economic analysis for each well–spacing configuration and
identify the most cost-effective Ultimate Recover development scheme.
Profitability analysis for different well–spacing configuration A, B, C
 Development Cost [A]
 Ultimate Recover [X]
 Development Cost [B]
 Ultimate Recover [Y]
 Development Cost [C]
 Ultimate Recover [Z]
NPV
Higher
NPV
Medium
NPV
Lower

May 2017
225G. Moricca
Step 7 – Make the Uncertainties-Risk analysis to:
- Identify reservoir characteristic uncertainties (extension, structure,
rock properties, fluid saturation)
- Define a preliminary drilling schedule combining the development
activities with data acquisition to reduce uncertainties
Step 8 – Consolidate a preliminary drilling schedule (No of wells to be drilled and
sequence) combining the field development activities with data
acquiring to reduce the uncertainties:
- Geological uncertainties and
- Engineering uncertainties (e.g. well performance, recovery factor)
Step 9 – Re-run the economic analysis to maintain under control the profitability
of the project.

Step 10 – Production build-up period and the duration of production plateau
optimization by adoption of appropriate drilling-time schedule.
-Profile [A] illustrates a gradual increase of production as the
producing wells are drilled and brought on stream; the duration of
the production build-up period is strictly related to the drilling
schedule.
-Profile [C] is characterized by a plateau production rate longer
than for case A and B. The vantage of profile C is that it requires
smaller facilities and probably less wells to produce the same
UR. One additional advantage of profile Cis that the lower
production rate, and therefore slower displacement in the
reservoir, may improve the UR.
-Profile [B], in which
some wells have been
pre-drilled starts
production at plateau
rate. The vantage of
pre-drilling is to
advantage the
production of oil, which
improves the
production cashflow,
but the disadvantage
are that the cost of
drilling has been
advantaged, and that
the opportunity has
been lost to gather
early production
information from the
first few wells, which
may influence the
location of subsequent
wells. Economic criteria
are used to decide
whether to pre-drill.
F. Jahn – M. Cook & M. Grahm
ELSEVIER 2008

Step 11 – Make the economic and risk analysis for each production profile
Oil recovery for the three Production profiles scheme A, B, C
NPV [A] NPV [B] NPV [C]
Risk analysis [A] Risk analysis [B] Risk analysis [C]

Step 12 – Select the drilling time-schedule, and consequently the expected
production profile taking into consideration:
-The project profitability
- The Stakeholders strategy

May 2017 229
6A
•Economic
Evaluation
G. Moricca

Project Economic Evaluation
3. Collecting operation and
economic data (see the
dedicated Tab).
4. Making economic calculations.
Engineers and geologists are
primarily responsible.
5. Making risk analysis and
choosing optimum project.
Both engineers and geologists
are primarily responsible for
analysis. Engineers, geologists,
operations staff, and
management work together to
decide on the optimum
project.
The task in project economic analysis require team efforts consisting of:
1. Setting an economic objective based on the company’s economic criteria. Reservoir
engineers are responsible for developing justification with the input from management.
2. Formulating scenarios for project development. Engineers and geologists are the primary
contributors with management guidance.

Input Data for the Project
Economic Evaluation
Data Source / Comment
Expected oil and gas production Reservoir engineers
Rates vs. time Reservoir and production engineers
Oil and gas price Finance and economics professionals
Capital investment(tangible, intangible) and
operating costs
Facilities, operations and engineering
professional
Royalty/production sharing Unique to each project
Discount and inflation rate Finance and economics professionals
State and local taxes (production,
severance, ad valorem, etc.)
Accountants
Income taxes, depletion, and amortization
schedules
Accountants

Economic Evaluation Criteria
 Each company has its own economic evaluation criteria with
required minimum values to fit its strategy for doing business
profitability.
 Acceptance or rejection of individual proposals are largely governed
by the company’s economic criteria.
 The Key Economic Parameters commonly used are:
1. Payout of Time
2. Profit-to-Investment Ratio
3. Present Worth Net Profit (PWNP)
4. Investment Efficiency or Present Worth Index or Profitability
Index
5. Discounted Cash Flow Return on Investment or Internal Rate
of Return.

Key Economic Parameters [1]
 Payout of time is the time needed to recovery the investment.
- It is the time when the cumulative undiscounted or discounted
cash flow (CF = revenue – capital investment – operating
expenses) is equal zero.
- The shorter the payout time (2 to 5 years), the more attractive
the project.
- Although it is an easy and simple criterion, it does not give the
ultimate lifetime profitability of the project, and it should not
used solely for assessing the economic viability of project.

 Profit-to-Investment Ratio is the undiscounted cash flow
without capital investment divided by the total investment.
Unlike the payout time, it reflects total profitability; however, it
does not recognize the tine value of money.
 Present Worth Net Profit (PWNP) is the present value of the
entire cash flow discounted at a specified discount rate.
 Profitability Index or Investment Efficiency or Present Worth
Index is the total discounted cash flow divided by the total
discounted investment. The value of this parameter in the range of
0.5 to 0.75 is considered favorable.

 Internal Rate of Return or Discounted Cash Flow Return on
Investment is the maximum discount rate that needs to be
charged for the investment capital to produce a break-even. This
can be also expressed as the discount rate at which the total
discounted cash flow, excluding investments, is equal to the
discounted investments over the life of the project.

Selection of the Business Cases
based on Economic Analysis
 For each cases make an economic evaluation of the
profitability of the project based on revenue and
expenditure items.
Revenue Items
 Gross revenues
from sales of
hydrocarbon
 Payment for
farming out a
project or part of a
project
Expenditure Items
 Capital expenditure (CAPEX), e.g. platform,
wells, surface facilities
 Operating costs (OPEX), e.g. maintenance,
salaries, insurance, tariff paid
 Government take, e.g. royalty, tax, social
contributions

Basic Economic Evaluation Procedure
1. Calculate annual revenues using oil and gas sales from productions and unit
sales prices.
2. Calculate year-by-year total costs including capital, drilling, completion,
operating, and production taxes.
3. Calculate annual undiscounted cash flow by subtracting total costs from the
total revenues.
4. Calculate annual discounted cash flow by multiplying the undiscounted cash
flow by the discounted factor at a specified discount rate.

Project Economic Evaluation Example [1]
[1]x[2]/1000 [4]x[5]/1000 [3]+[6]
[1] [2] [3] [4] [5] [6] [7] [8]
Time
(period)
Oil
Prod.
Oil
Price
Oil
Revenue
Gas
Prod.
Gas
Price
Gas
Revenue
Total
Revenue
Capital
Cost
Year Year (MSTB) ($/BBL) ($MM) (MMSCF) ($/MSCF) ($MM) ($MM) ($MM)
2018 1 0 50.0 0.0 0 1.5 0.0 0.0 5.7
2019 2 0 50.0 0.0 0 1.5 0.0 0.0 64.7
2020 3 5,405 50.0 270.3 3,276 1.5 4.9 275.2 244.0
2021 4 8,079 50.0 404.0 5,934 1.5 8.9 412.9 74.2
2022 5 9,024 50.0 451.2 7,208 1.5 10.8 462.0 0.0
2023 6 9,068 50.0 453.4 5,848 1.5 8.8 462.2 0.0
2024 7 7,021 50.0 351.0 2,968 1.5 4.5 355.5 0.0
2025 8 4,004 50.0 200.2 2,031 1.5 3.0 203.3 0.0
2026 9 2,511 50.0 125.6 2,179 1.5 3.3 128.8 0.0
2027 10 1,803 50.0 90.2 3,469 1.5 5.2 95.4 0.0
2028 11 1,306 50.0 65.3 4,763 1.5 7.1 72.5 0.0
2029 12 972 50.0 48.6 3,364 1.5 5.0 53.6 0.0
2030 13 685 50.0 34.3 2,200 1.5 3.3 37.6 0.0
2031 14 620 50.0 31.0 1,087 1.5 1.6 32.6 6.4
2032 15 500 50.0 25.0 1,087 1.5 1.6 26.6 6.4
Total 51,000 2,550.0 45,415.3 68.1 2,618.1 401.3

Project Net Cash Flow @ 12% = 698.5 million
[8]+[9]+[10] [7]-[11] [12]x[13] [12]x[15] [12]x[17]
[9] [10] [11] [12] [13] [14] [15] [16] [17] [18]
Operating
Cost
Prod.
Tax
Total
Cost
Undiscaunted
Cash Flow
Discaunt
Factor
@12%
Discaunted
Cash Flow
@ 12%
Discaunt
Factor
@ 20%
Discaunted
Cash Flow
@ 20%
Discaunt
Factor
@ 30%
Discaunted
Cash Flow
@ 30%
Year ($MM) ($MM) ($MM) ($MM) Fraction ($MM) Fraction ($MM) Fraction ($MM)
2018 0.0 0.0 5.7 -5.7 0.9449 -5.4 0.9129 -5.2 0.8771 -5.0
2019 0.0 0.0 64.7 -64.7 0.8437 -54.6 0.7607 -49.2 0.6747 -43.6
2020 21.6 55.0 320.6 -45.5 0.7533 -34.2 0.6339 -28.8 0.5190 -23.6
2021 32.3 82.6 189.1 223.8 0.6726 150.5 0.5283 118.2 0.3992 89.3
2022 36.1 92.4 128.5 333.5 0.6005 200.3 0.4402 146.8 0.3071 102.4
2023 36.3 92.4 128.7 333.5 0.5362 178.8 0.3669 122.3 0.2362 78.8
2024 28.1 71.1 99.2 256.3 0.4787 122.7 0.3057 78.4 0.1817 46.6
2025 16.0 40.7 56.7 146.6 0.4274 62.7 0.2548 37.3 0.1398 20.5
2026 16.0 25.8 41.8 87.0 0.3816 33.2 0.2123 18.5 0.1075 9.4
2027 16.0 19.1 35.1 60.3 0.3407 20.5 0.1769 10.7 0.0827 5.0
2028 16.0 14.5 30.5 42.0 0.3042 12.8 0.1474 6.2 0.0636 2.7
2029 16.0 10.7 26.7 26.9 0.2716 7.3 0.1229 3.3 0.0489 1.3
2030 16.0 7.5 23.5 14.0 0.2425 3.4 0.1024 1.4 0.0376 0.5
2031 16.0 6.5 28.9 3.7 0.2165 0.8 0.0853 0.3 0.0290 0.1
2032 16.0 5.3 27.7 -1.1 0.1933 -0.2 0.0711 -0.1 0.0223 0.0
Total 282.5 523.6 1,207.5 1,410.6 698.5 460.2 284.3
Project Economic Evaluation Example [2]

Project Cash Flow at different discount rate (oil price 50 $/BBL)
-60.0
-40.0
-20.0
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
220.0
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Discaunted
Cash Flow
@ 12%
Discaunted
Cash Flow
@ 20%
Cum
Discaunted
Cash Flow
@ 30%
NetCashFlow($million)
 Payout Time 2.7 year
 Project Net Cash Flow @ 12% = 698.5 million

Project Cash Flow at Oil price: 25 to 75 $/BBL
-125.0
-100.0
-75.0
-50.0
-25.0
0.0
25.0
50.0
75.0
100.0
125.0
150.0
175.0
200.0
225.0
250.0
275.0
300.0
325.0
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Discaunted
Cash Flow
@ 12%
25 $BBL
Discaunted
Cash Flow
@ 12%
30 $BBL
Discaunted
Cash Flow
@ 12%
40 $BBL
Discaunted
Cash Flow
@ 12%
50 $BBL
Discaunted
Cash Flow
@ 12%
60 $BBL
Discaunted
Cash Flow
@ 12%
65 $BBL
Discaunted
Cash Flow
@ 12%
70 $BBL
Discaunted
Cash Flow
@ 12%
75 $BBL
 The project is profitable also at 25 $/BBL
 Project NPV @ 12% 148,7 $million
 Payout Time 2.1 year @ 75 $/BBL
 Payout Time 3.2 year @ 25 $/BBL

 Pessimistic scenario: Oil price: 25 $/BBL – Uncertainty in UR
 At 25 $/BBL, the project remain profitable if the recovered oil is higher
than 70% of the estimated oil reserves.
-160
-120
-80
-40
0
40
80
120
160
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Discaunted
Cash Flow @ 12%
Oil 25.5 MMBBL
- 50%
Discaunted
Cash Flow @ 12%
Oil 30.9 MMBBL
- 40%
Discaunted
Cash Flow @ 12%
Oil 35.7 MMBBL
- 30%
Discaunted
Cash Flow @ 12%
Oil 43.35 MMBBL
- 15%
Discaunted
Cash Flow @ 12%
Oil 51.0 MMBBL
Discaunted
Cash Flow @ 12%
Oil 56.1 MMBBL
+10%
Discaunted
Cash Flow @ 12%
Oil 61.2 MMBBL
+20%
Discaunted
Cash Flow @ 12%
Oil 66.3 MMBBL
+30%
 Recovered oil -50% Project NPV @ 12% = -74,4 $million
 Recovered oil -25% Project NPV @ 12% = - 8.9 $million
 Recovered oil -30% Project NPV @ 12% = 13.6 $million
 Recovered oil -15% Project NPV @ 12% = 81.2 $million
 Recovered oil +10% Project NPV @ 12% = 193.8 $million

May 2017 243
6B
•Uncertainty
Analysis
G. Moricca

Uncertainties vs Risk
Cambridge Dictionary definition:
 Uncertainty: a situation in which something
is not known.
 Risk: a risk is a danger, or the possibility of
danger, defeat, or loss; a risk is also someone
or something that could cause a problem or
loss.
Uncertainties can generate risks!

Uncertainties vs Risk
Uncertainty
Risk
Risk Uncertainty
Uncertainty Risk
All risks are uncertainties,
however, not all
uncertainties are risks

 Petroleum exploration and production are inherently
risky activities. Decisions regarding those activities
depend on the forecast of the future hydrocarbon
production revenue.
Typical Uncertainties in Upstream
Oil Industry
 Such uncertainties involve all activities required to define
a comprehensive FDP and, just for a better
understanding, can be differentiated in:
 Technical uncertainties
 Economical uncertainties

 Typical technical uncertainties can include, but not only:
- Reservoir geometry and the spatial distribution of petro-
physical properties (porosity, permeability, net pay, fluids
saturation, capillary pressure, etc.)
- Reservoir compartmentalization
- Vertical and horizontal hydraulic communication
- Presence of fault and its sealing characteristics
- Reservoir fluid properties (Bo, Pb, Rs, Viscosity, etc.)
- Reservoir fluids drive mechanism(s) and its strength
- Modeling limitations
- Measurement errors
- Evaluation of the environmental impact
Typical Technical uncertainties

 Typical technical uncertainties can include, but not only:
- Future hydrocarbon price
- Future maintenance services cost
- Future capital cost
Typical Economical uncertainties

Quantifying Uncertainty
 The uncertainty can be quantified by a set of possible states or
outcomes where probabilities are assigned to each possible state
or outcome. Mathematically, the uncertainty his expressed by a
probability density function.
Uncertainty Measurement
Probability Density Function
 In probability theory, a probability density function (PDF) is a
function, whose value at any given sample (or point) in the sample
space (the set of possible values taken by the random variable) can
be interpreted as providing a relative likelihood that the value of
the random variable would equal that sample.

Mathematical definition
Probability Density Function (PDF)
Let x be a continuous variable (e.g. porosity). Then a probability
distribution or probability density function (PDF) of x is a function f (x)
such that for any two numbers a and b with a ≤ b,
PDF ( a < x < b ) = 𝑎
𝑏
𝑓 𝑥 𝑑𝑥
PDF ( 60 < x < 70 )

An practical example: Supposing that a certain number of experimental porosity measurements
are available, the plot reported below can be generated
Probability Density Function
 Few points (10) are characterised by low
porosity (12%) – Low PDF
 As well as, few points (10) are
characterised by high porosity (34%) –
Low PDF
 The largest number (120) of
measurement are characterised by
porosity 24% - Highest PDF
 Among the 620 measured points, the
majority (500) are characterised by: 18 <
Porosity > 28%
 If the values of x-axis is a continuous
rather than discrete values, a continuous
PDF is obtained.
Groups of core plug
samples having the
same porosity
 The probability density function (PDF) allows to calculate the probability of x value in an
interval (a, b). The probability is precisely the area under its PDF in the interval (a, b).

 Cumulative Probability curve refers to the probability that a random
variable is less than or equal to a specified value.
Cumulative Probability
 The Cumulative probability is derived
from the Probability Density Function as
following:
- There is 100% of probability
(cumulative probability = 1) that
porosity is higher than x min
- Equally, there is 0% of probability
(cumulative probability = 0) that
porosity is higher than x max
- From the continuous PDF one would
estimate that approximately 70% core
plug have a permeability higher than
x1
- The Cumulative Permeability is also as
the Expectation Curve

 The shape of the Cumulative Probability Curve provides very useful information:
Cumulative Probability
- Case [A] - Very well defined
case since the range of
uncertainty in STOIIP values
is small (less than 100
MMstb).
- Case [B] – represents a
poorly defined discovery,
with much broader range of
uncertainty in STIIOP
definition.
- To reduce the uncertainty
of case [B] more appraisal
activity should be done
before committing to a
development plan.

Quantifying Uncertainty related to
the Reservoir Model Outcomes
 Monte Carlo Simulation model is a very popular technique used
to assess the overall uncertainties (coming from the specific
uncertainty of each parameter required for the evaluation)
related to the reserves estimation and the associated production
profiles.
 This is done by generating a number of simulations varying some
of the input parameters, by considering for each one a
‘reference’, a ‘pessimistic’, and an ‘optimistic’ value.
 To be statistically significant, the uncertainties assessment
requires large number of simulation runs, especially if the
analysis is related to an undeveloped field (new field) without
historical history match.

Quantifying Uncertainty by a
Stochastic approach
 Monte Carlo Simulation model is extensively used for oil in place assessment,
based on the associated geological attributes uncertainties.

Uncertainty generates Risk and Opportunity
 Risk is an undesirable consequence of uncertainty, but the upside
potential of uncertainty is an “opportunity ” if it is captured (e.g.
higher OOIP than expected).
Possible consequences
of uncertainty
Risk
- Possibility of loss or injury
- A dangerous element or factor
- The probability of loss
Opportunity
- Possibility of exceeding expectation
- Upside potential
- An attractive element or factor

Benefice of performing the Uncertainty
Assessment
 Integrate all subsurface uncertainties and understand
how they impact reservoir management decisions.
 Identify the most important reservoir parameters, so we
can focus team resources on relevant issues and
maintain the right level of technical detail, saving time
and money.
 Efficiently investigation of the alternatives through a
combination of scenarios and stochastic simulations.
 Identify potential opportunities.

May 2017 258
6C
•Risk
Analysis
G. Moricca

Reservoir Development Decision Tree
The operational context and the competitive environment in which companies do business nowadays impose a
level of certainty in our decisions as never before. In spite of the level of effort to reduce the downside risk and
maximize the upside risk in our enterprises, bad decisions eventually are made. Bad decisions can erode our
financial performance and competitive position, adversely impact our projects, programs and portfolios, and
eventually jeopardize our survivability. From here, the importance of implementing a decision making process
(DMP) that systematically and consistently addresses the different key drivers that affect the outcome in terms
of upside and downside risk.
Figure 2 represents an overview of the overall field
development concept selection process. The first
steps
involve collecting, documenting and validating all
assumptions, premises, requirements and
objectives of the
proposed development; identifying and clearly
defining the
different concepts to be evaluated; and in some
cases, depending on the number of eva luated
concepts or “family
concepts”, performing a pre-screening process
Management 2013, 3(3): 142-151

 Project risk is defined as “…an uncertain event or
condition that, if it occurs, has a positive or negative
effect on one or more project objectives such as scope,
schedule, cost, and quality”
 The aim of project risk management is to identify and
minimize the impact that risks have on a project. The
challenge with risk management is that risks are
uncertain events
 In the management of projects, organizations attempt to
reduce their exposure to these uncertain events through
risk management.
Project Risk Management
(Project Management Institute, 2013).

 Petroleum exploration and production are inherently technical and
commercial risky activities.
 At field development stage major investment decision are taking in
the anticipation of future return over along period of time. So it is
important that careful technical and commercial risk analysis is
performed.
 Project Risk Management is usually done through a formal
management process which consists of the following steps:
1. Plan risk management,
2. Identify risks
3. Perform qualitative risk analysis
4. Perform quantitative risk analysis
5. Plan risk responses (risk mitigation)
6. Control risks
Project Risk Management
(Project Management Institute, 2019).

 Possible risk events associated to the operations:
- Negative HSE events
- Delay in well location preparation
- Delay due to unexpected operational (drilling, completion,
installation) problems
- Equipment failure during commissioning or starting up
- Infrastructure/pipelines failure during installation
- Control system failures during operation
- Flow assurance problems
Possible Risks
 Possible economic risk events:
- Profit loss
 The risk analysis should includes also the identification
positive aspect as the up-side potential of the project.

Quantitative Risk Assessment [QRA]
 Quantitative Risk Assessment is defined as:
Risk = Impact x Probability
and expressed in monetary terms.
 Quantitative risk management in project management
is the process of converting the impact of risk on the
project into numerical terms. This numerical
information is frequently used to determine the cost and
time contingencies of the project.

Project Risk Matrix
 Technical and non-technical team components brainstorming is a valuable
approach to identify risks and opportunities, and build the Project Risk
Matrix. Some of the most original ides can come from non-discipline team
members.
 The dimension of the risk is evaluated in monetary terms.
 Design a dedicated Risk Matrix for the specific project-stage, and, if
required, for sub-stage: e.g. field development strategy, well architecture,
well completion, surface facilities, etc.

Risk Analysis Step-by-Step Procedure
1. Perform the risk analysis at several stages and at any time it is
required.
2. Identify the potential risks for the selected stage as well as the
risks which each option could occur.
3. Design a dedicated Risk Matrix for the specific purpose.
4. Perform qualitative risk analysis based on:
- Occurrence probability
- Impact time schedule
- Impact on Budget Rating --> Very Low Low Moderate High Very High
Cost Impact of
Risk
Insignificant
cost increase
< 5% cost
increase
5-10% cost
increase
10-20% cost
increase
> 20% cost
increase
Cost Impact of
Opportunity
Insignificant
cost reduction
< 1% cost
decrease
1-3% cost
decrease
3-5% cost
decrease
> 5% cost
decrease
Time Schedule
Impact of Risk
Insignificant
slippage
<1 month
slippage
1-3 months
slippage
3-6 months
slippage
> 6 months
slippage
Time Schedule
Impact of
Opportunity
Insignificant
improvement
< 1 month
improvement
1-2 months
improvement
2-3 months
improvement
> 3 months
improvement
Probability 1–9% 10–19% 20–39% 40–59% 60–99%
Impact Definitions

5. Perform the risk scoring combining the:
- Severity of the risk
- Occurrence
- Impact
5 - Very High 5 10 20 35 50
4 - High 4 8 16 28 40
3 - Moderate 3 6 12 21 30
2 - Low 2 4 8 14 20
1 - Very Low 1 2 4 7 10
Very Low Low Moderate High Very High
1 2 4 7 10
Risk Matrix
Probability
Rating
Impact Rating
Quantitative Risk Assessment
Risk = Impact x Probability

6. Perform quantitative risk analysis in monetary terms based on:
- Cost impact– will the project be completed within the
allocated budget?
- Time impact – will the project be completed within the
planned timeframe?
- Performance impact – will the output from the project
satisfy the business and technical goals of the project?
The risks should be quantified in monetary terms to enable the
project team to develop effective mitigation strategies for the
risks, or to include appropriate contingencies in the project
estimate.
7. Register the main item on the Risk Register and detail the item
by discipline, and include actions for risk mitigation and define
the responsible party who will follow-up on each item.

Risk Register
The Risk Register aims to do the following:
 Identify and record all risks related to a project.
 Gather relevant information on each of the risks.
 Capture derived information based on analysis and prioritization of
the risks.
 Capture mitigation strategies planned for the risks.
 Track the status of each of the risks.
Occurence
Impact
time
schedule
Impact
on
Budget
Probability
Rating
1 to 5
Impact
Rating
1 to 10
Risk
Rating
Prob x Imp
Gross
Value
$
NPV
$
R1 Management
R2 Financial
R3 Operational
R4 Technology
Risk
Quantitative
EvaluationRef
No
Risk Register
Action
Owner
Risk
Mitigation
Actions
Last
Revie
w
Current
Status
Quantitative Risk Assessment
[QRA]
Date
Logged
Risk
Type
Risk
Descripion
Worst Case
Scenario
Description
Risk
Qualitative Evaluation

Risks
Mitigation

Risks Mitigation
Definition: Risk mitigation planning is the process of developing options and actions
to enhance opportunities and reduce threats to project objectives.
[Project Management Institute, Inc.].
[Project Management Institute, Inc.]

Risk mitigation strategies for negative risks or threats include:
 Assume/Accept: Acknowledge the existence of a particular risk,
and make a deliberate decision to accept it without engaging in
special efforts to control it. Approval of project or program
leaders is required.
 Avoid: Adjust program requirements or constraints to eliminate
or reduce the risk. This adjustment could be accommodated by a
change in funding, schedule, or technical requirements.
 Control: Implement actions to minimize the impact or likelihood
of the risk.
 Transfer: Reassign organizational accountability, responsibility,
and authority to another stakeholder willing to accept the risk.
 Watch/Monitor: Monitor the environment for changes that
affect the nature and/or the impact of the risk.
Risks Mitigation Strategy

Risks Mitigation Strategy
Avoid Mitigate
Accept Transfer
Risk
Eliminate cause of risk Reduce probability or impact of risk
(impact or the probability is high)
Contingency plan for (risk is low in
terms of probability and impact)
To be included in a watch list
Third party (insurance) take on
responsibility (risk impact is high but
the probability is low)

Going in parallel order to the explanation of the four risk strategies of negative
risks above, you have:
Accept / Reject: If the probability of an opportunity is low and the impact on the
project would be low, then you should not actively pursue it because that would
be waste of resources, but rather watch out for it and take advantage of it if it
occurs.
Exploit: If the probability of an opportunity is high and the positive impact on the
project would be high as well, then you should identify and maximize the
probability of occurrence of those events that which would trigger an opportunity
in order to exploit it.
Share: If you have an opportunity that has low probability of occurring, but would
have a high positive impact on the project, you would share the opportunity with
a third party that could best capture the opportunity in order to benefit the
project. Examples of this include forming risk-sharing partnerships, teams,
special-purpose companies or joint ventures.
Enhance: If there is an opportunity that has low probability of occurring, then it
might be worthwhile to add resources to increase the probability of its occurring.
Strategies for positive risks or Opportunities

Exploit Enhance
Accept Share
Opport
unity
Make sure opportunity occurs Only If it is highly probable (the
opportunity is real) and has good
impact
Allocate resource for further
investigation
If good impact but low probable to
occur, give third party ownership of
probability
Strategies for positive risks or Opportunities

Methods and Strategies to reduce
Uncertainty
 There are several methods and strategies to reduce uncertainty. There is a
trade off between capital cost and uncertainty.
 Methods:
- Drill stem test.
- More appraisal wells.
- Extended well test.
- Early production.
- Staged development.
 Application depends on:
- Reservoir size and Char.
- Operator Strategy
- Available Technology.

Summary of Risks, Uncertainties and
Mitigations actions
Reservoir Geology
Reservoir Performance
Rock
Properties
Fluid
Properties
Drive
Mechanism
Technical
Commercial
HSE
Organisational
Risk
Uncertainty
Mitigation
actions
Geological uncertainties could be
mitigated by the data acquired during the
project implementation phase
Can be preliminarily
assessed by analogy.
Good reservoir
monitoring plan is
mandatory.
The HSE risks can
be strongly
mitigated by the
adoption of best
practices
Only consolidated
technologies should
selected
- Limited resources
- Lack of communication
- Lack of analysis
To be avoided
Dynamic reservoir
performance can be
assessed by robust
reservoir simulator
Crude oil sampling
and consistent PVT
analysis are crucial
Good formation
evaluation during the
appraisal and
exploitation phase
Stringent economic
analysis considering
market volatility

May 2017 277
6D
•Health, Safety
and
Environmental
G. Moricca

 In developing and subsequently operating a field,
safety and environmental consideration has to be
included.
 Regulatory agency constrain s will also to be satisfied.
 The most common HSE rules will mentioned on the
coming snapshots and some emphasis to the Arctic
environment will be dedicated.
Health Safety and Environmental
(HSE) Considerations

 Work according to applicable laws, codes and regulations
 Comply with approved procedures, rules and instructions
 Provide all necessary information, instruction and supervision
 Use trained and competent people for the tasks they are expected to
complete
 Provide Safe Systems of Work (SSOW) facilitated by efficient
planning, robust risk assessment and effective management of
change
 All incidents must be reported and investigated and remedial actions
assigned and completed
 Clear objectives to be settled
 Documentation to be reviewed in accordance with a scheduled
program or after a significant change
HSE common principles

Safety and Environment
 Safety and Environment have become important elements of
all part of field life cycle, and involve all of the technical and
support functions in the oil company.
 The Piper Alpha disaster in North Sea in 1988 triggered a
major change in the approach to management of safety within
the industry.
 Companies recognize that good safety and environmental
management make economic sense and are essential to
guaranteeing long-term presence in the market.
 Stakeholders, be they governments, non-government
organizations (NGOs) or financing entities will scrutinize the
HSE (health, safety and environment) performance of an
operator on a continuous basis.
 Many techniques have been developed for the safety and
environmental impact of operations.

Safety Performance Standards
 Safety Performance is measured by companies in many
different ways. To benchmark safety performance on an
industry wide scale, globally recognized standard are
required.
 A commonly used method is the recording of the number of
accidents, or lost time incidents (LTI).
 An LTI is an incident which causes a person to stay away from
work for one ore more days.
 Recordable injury frequency (RIF) is the number of injuries
that require medical treatment per 100 employee.

Gate 2 – Work quality and
economics ok?
 At the end of project selection phase, based on
production volumes expected, the necessary
investments, operating costs, economic feasibility, HSE
and the time needed until completion criteria, the
company management chooses the most suitable
concept and makes the decision to develop this
concept further.

May 2017 283
6E
•Final Selection
of preferred
alternative for
the Field
Development
G. Moricca

May 2017
Feasibility Study
FEL-1
Conceptual
Engineering
Clear frame
goal.
 Identify
opportunities.
 Preliminary
assessment of
uncertainties,
potential return,
and associated
risks.
 Plan for next
phase.
Cost accuracy
±40%
FEL-2
Preliminary
Engineering
Generate
alternatives.
 Reduce
uncertainty and
quantify
associated risks.
value for selected
alternatives.
alternative(s).
 Plan for next
phase.
Cost accuracy
±25%
FEL-3
Eng. Design
Fully define
scope.
execution plans.
and economic
analysis to A/R
level.
value meets
business
objectives.
Cost accuracy
±15%
Detailed
Eng. Design
Implement
execution plan.
 Final design
 Implement
execution plan.
and share metrics
and lessons
learned.
Cost accuracy
±5%
Operations
Support
Monitor
performance.
 Final design
 Benchmark
performance
against objectives
and competitors.
lessons learned.
 Continue
performance
assessment and
identify
opportunities.
G
1
G
2
G
3

Stage 3: DEFINE
 Once the field development concept has been
selected, the engineers take over the detailed field
development and prepare the so-called Front End
Engineering & Design (FEED).
 They now elaborate on the concept to include every
last detail. Using simulations and construction
programs, they draw up precise plans for the
production wells that will recover the hydrocarbons,
the production plants and the other infrastructure
requirements, of the oil and gas produced.

Define Project details of
the Oil Recovery Scheme
Primary Recovery
Thermal
Natural Flow Artificial Lift
Water Flooding Pressure Maintenance
Gas Injection Chemical Other
Tertiary Recovery
Secondary Recovery
Conventional
Recovery
Enhanced
Recovery
Steam
Hot Water
In-situ Combustion
CO2
Hydrocarbon
Nitrogen
Alkali
Surfactant
Polymer
Microbial
Acoustic
Electromagnetic

Identification of most cost-effective UR
 Define a Business Cases
Scenario based on:
- Oil in Place
- Oil Recovery Scheme
- Preliminary estimation of the No
of required wells for the field
development (preliminary Well
Spacing)
- Preliminary Costs estimation for
the field development
 Select the base case based on
economic criteria and risk
analysis considerations.
Oil in Place
Oil recovery scheme A, B, C
Developm
ent Cost s
A
Developm
ent Costs
B
Developm
ent Cost s
C
NPV
A
Higher
NPV
B
Medium
NPV
C
Lower

Production build-up period and the duration
of Production Plateau optimization
 Three scenarios can be taken into
consideration:
- Short production plateau [A]
- Pre-drilling - Starting production
at plateau rate [B]
- Long production plateau rate [C]
Oil in Place
Oil recovery scheme A, B, C
Developm
ent Cost
A
Developm
ent Cost
B
Developm
ent Cost
C
NPV
A
Higher
NPV
B
Medium
NPV
C
Lower
Production Profile A, B, C
NPV
A
Higher
NPV
B
Medium
NPV
C
Lower
 Select the base case based on
economic criteria, as well as
reservoir management
optimization and risk analysis
considerations.

May 2017 289
7
•Project
Approval
G. Moricca

Management Project approval
The FDP final approval is typically is made
based on economic evaluation of the
profitability of the project.
Revenue Items
 Gross revenues
from sales of
hydrocarbon
 Payment for
farming out a
project or part of a
project
Expenditure Items
 Capital expenditure (CAPEX), e.g. platform,
wells, surface facilities
 Operating costs (OPEX), e.g. maintenance,
salaries, insurance, tariff paid
 Government take, e.g. royalty, tax, social
contributions

Target
FDP
Organization
Infrastructures
and Constraints
Knowledge
Strategy
Field Development Roadmap
to reach the project target

Dear Reader,
I get bored to enjoy my beautiful garden,
so, I am looking to come back in the real game to help E&P
Companies in daily attempt to generate value.
Thank you for your attention
Giuseppe Moricca
If you are interested in receiving my services, please contact me at
moricca.giuseppe@libero.it

Guidelines for field development plan

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