Integrated Oil Field Development Plan - FDP. Criteria, strategy and process for an proper arctic offshore

Basic ofCriteria, Strategy, and Process for a Proper Arctic Offshore

Field Development Plan

G. MoriccaSenior Petroleum Engineer

[email protected]

March 2017 G. Moricca 2

Contents

1. Oil and gas resources in the Arctic 2. Safety and Environment3. Field Development Plan Guideline4. Uncertainties Management and Risk Mitigation5. Norwegian Petroleum Directorate FDP Guideline6. Technical Topics:

Reservoir Model for the FDP

Project Economic Evaluation

Hydrocarbon Recovery

Well Architecture

Offshore Drilling Systems for Arctic conditions

Production System for Arctic conditions


Contents





Well Architecture




Oil and gas resources in the Arctic are large


The Norwegian Perspective – Petroleum activities in the Norwegian Barents Sea

First exploration activities started in 1980

Snøhvit gas field in production

Goliat oil field in production

Johan Castberg oil under evaluation

Alta and Gotha oil under evaluation

Wisting oil ready to be developed

Several smaller gas discoveries made

ref. ENI 21.3.16


Petroleum activities in the Norwegian Barents Sea

Goliat First oil field in the Barents

Sea – ENI as operator

Production with offshore loading started in March 2016

One of the largest industrial projects undertaken in Northern Norway

Developed on the basis of comprehensive impact assessments


The Barents Sea – an emerging petroleum frontier

The Delimitation Agreement between Norway and Russia in force July 7, 2011

An area like the North Sea split 50/50

Impact assessment carried out formally opening the Norwegian part of the Barents Sea East

Norway applies its concession policy in the new area

Russia has awarded its “new” acreage to stated owned Rosneft


OMV (Norge), a wholly owned subsidiary of OMV Exploration, has discovered oil at wildcat well 7324/8-1, WistingCentral, in exploration license PL 537 in Norway.

OMV discovers oil at Wisting Central well, Barents Sea


Arctic offshore area has a great potential for future field developments projects, however they are characterized by:

1. High ecological risks

2. Challenging environment for operation and construction

3. Huge money investments


Arctic Challenges Severe environmental conditions

Difficult soil conditions

High environmental risks

Remoteness from the market

Ice and ice features

Icebergs

Ridges

Polar lows

Low temperatures

Darkness

Fog


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Well Architecture




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.


Hazard and operability studies -HAZOP

Techniques such as Hazard and operability studies (HAZOP) are used to design of plant layout and equipment.

This type of study is now commonly applied to new platform design and to the evaluation of refurbishment on existing platform.

This technique involves determining the potential hazard of an operation under normal and abnormal operating conditions, and considering the probability and consequences of an accident.


Innovations in Platform Design

Freefall lifeboats, launched from heat shielded slipways on offshore platforms;

Emergency shutdown valves installed on the seabed and topsides in incoming and outgoing pipelines, designed to isolate the platform from all sources of oil and gas in an emergency;

Fire resistant coating on structural members;

Computerized control and shutdown of process equipment.

Some example of innovations in platform design are:

Physical separation of accommodation modules from the drilling/process/compression modules - creating a pressurized “safe haven”. The areas are at the opposite ends of the platform, and ere separated by fire and blast walls;


Safety Management System

The SMS typically addresses the following areas:

Organization structure

Management personnel standards

Design procedures

Procedures for operations, maintenance, modifications and emergencies

Management of safety by contractors in respect of their work

The involvement of the workforce in safety

Accident and incident reporting, investigation and follow-up

Monitoring and auditing the operation of the system

Systematic reappraisal of the system.

Major oil companies have each developed their own specific safety management system (SMS) to suit local environments and modes of operation.


Environment Environmental standards have become a critical part of

any business.

Whilst individual companies tend to have their own specific environmental management system (EMS), global standards have been established, such as ISO 14001.

Since its principles are generic, they can be applied to almost any type of organization and many large oil and gas companies have adopted its framework.

Adherence to environmental standards is not only required to meet the legislative requirements in host countries, but is also viewed as good business because it is:- Cost effective- Providing a competitive edge- Essential to ensuring continued operations in an area- Helpful in gaining future operations in an area.


Environment Impact Assessment - EIA

The objective of an EIA is to document the potential physical, biological, social and health effect of a planned activity.

Typically, the EIAs will be carried out for:- Seismic- Exploration and appraisal drilling- Development drilling and facilities installation- Production operations- Decommissioning and abandonment.

This will enable decision makers to determine whether an activity is acceptable and if not, identify possible alternatives.


The EIA Process The EIA process is a systematic process that examines the

environmental consequences of development action in advance.

The key stages in a EIA process includes:- Screening: undertaken to decide which project should be subject to

environmental assessment.- Scoping: identifies, at an early stage, the most significant issues to be

included in the EIA.- Consideration of alternatives: seeks to ensure that the proposer has

considered other feasible options including location, scales, process, layouts, operating conditions and ‘’no action’’ option.

- Project description: includes a clarification of the purpose and rationale of the project.

- EIA preparation: is the scientific and objective analysis of the scale, significance and importance of impacts identified.

- Public consultation and participation: aims to assure the quality, comprehensiveness and effectiveness of the EIA.


..... The EIA Process

The key stages in a EIA process includes:- EIA presentation: a vital step in the process, the documentation serves to

communicate the findings of EIA process to interested parties.- Review: involves a systematic appraisal by a government agency or

independent review panel.- Decision-making on the project involves a consideration by the relevant

authority of the EIA together with any material considerations.- Monitoring: is normally adopted as a mechanism to check that any

conditions imposed on the project are being enforced or to check the quality of the affected environment.

- Auditing: follows on from monitoring. Auditing is being developed to test the scientific accuracy of impact predictions and as a check on environmental management practices. It can involve comparing actual outcomes with predicted outcomes, and can be used to assess the quality of predictions and effectiveness of mitigation. It provides vital feedback into the EIA process.


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Well Architecture




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)


FDP Integrated TeamAn integrated, multidisciplinary team approach is required for a proper FDP definition. 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.


The life Cycle of a Petroleum ReservoirThe major phases are:

Exploration Survey to find a new reservoir in a known field or to extend the

limit of a known oil or gas reservoir.

Discovery

Appraisal to establish the limits of the reservoir, the productivity of wells in it

and the properties of the oil or gas)

Field Development Plan (FDP) definition: If appraisal wells show the

reservoir to be technically and commercially viable, the Oil Company will produce

a development plan which will be submitted to the relevant authorities.

Drilling and Completion (Field development)

Construction Production

De-commissioning

G. Moricca 25

EXPLORATION – SEISMIC SURVEY

EXPLORATION DRILLING &

APPRAISAL DRILLING

CONSTRUCTION PHASE -

Detailed Design, Procurement, Fabrication

CONSTRUCTION PHASE –

Transportation, Installation, Hook-up and

Commissioning.

PRODUCTION/PROCESSING/ EXPORTING

Decommissioning of offshore Facility:

Basic steps include:

- Engineering and Planning;

- Permits and Regulatory Compliance;

- Platform Preparation;

- Well Plugging and Abandonment;

- Conductor Removal;

- Mobilization of Decommissiong Vessel;

- Topsides Removal;

- Jacket Removal;

- Pipeline and Umbilicals Decommissioning;

- Materials Disposal;

- Site Clearance and Restoration.

CONSTRUCTION PHASE -

Subsea Pipeline to Onshore Refinery

From Exploration to Decommissioning

WHEN THE RESERVOIR IS DEPLETED, THE

FACILITIES MUST BE DECOMMISSIONED.

March 2017

CONCEPT - FEED


Clear 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 as a key tool to

determine the optimum

method of recovering the

hydrocarbons from the

reservoir.


Identification of a FDP Clear StrategyIdentify 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 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 ?


In choosing a development concept the following shall be taken into consideration:

Reservoir data

Crude oil characteristics

Type of Drilling and Completion

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


The following risk events should be considered in order to identify the most safety development option:

Change of reservoir information, well type and future growth

Damage to pipelines/umbilicals due to mooring lines or anchor failure

Equipment failure during commissioning and starting up

Infrastructure/pipelines failure during installation

Delay of infrastructure to start up

Problems during well construction

Control system failures during operation

Flow assurance problems/plug formation

Slug catcher flooding

Hurricanes


Process for FDP Definition

Sensitivity Analysis for Optimization

NPVROCE (NPV/ Capital)

Reservoir Geologic Setting

Volumes in Place

Hydrocarbon Properties

Driving Mechanism

Driving Mechanism Efficiency

Ultimate Recovery Factor

Today an Tomorrow Oil Price

Uncertainties

Type Surface Facilities

Diameter Export Pipeline

Type and Nr of Wells

Decisions


Field Development Plan Workflow

1• Development & Depletion Strategies

2• Environmental Considerations

3• Data Acquisition and Analyses

4• Geological and Numerical Model Studies

5• Reserves and Production Forecast

6• Facilities Requirements

7• Economic Optimization

8• Management Approval


Industrial accepted Offshore Field Development Pan Methodology

Phase 1: Conceptual Design - (Appraise)

Phase 2: Feasibility (FDP definition)

Phase 3: Detail Design (Finalize)

Phase 4: Material Procurement, Construction and Installation

Phase 5: Production Start-up


Project Phases and their Objectives Phase

Objective

Ability toImpact Results

CapitalExpenditures


Early Planning Creates the Greatest Value

• Developing a robust reservoir model and depletion plan

• Optimizing the drilling program (greatest recovery with fewest wells)

• Minimizing well performance uncertainty

• Selecting the right surface facility plan

The greatest value to a project is created in the Appraise and Select phases which involve:

The spend in these phases is generally a small percentage of total development spend but provides substantial added value to the project


Planning is a Collaborative Process

Objective is to select a development plan that satisfies an Operator’s commercial, strategic and risk objectives

It 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


Relative Influence on Cost

The “right” choice of the concept for the offshore field development is the first and major step for achieving profitable and technically safe offshore field exploitation.


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 of Development Strategy

Emphasis on:

Reduction of uncertainties

Reduction of influence of uncertainties


Proper Planning is Critical to Success


Feasibility

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?


Concept Selection

Which concept will have the highest NPV?

Constructability and install ability issues

Site conditions

Potential contracting constraints

Risk analysis


Front End Engineering Design – FEED

Strive for a fabrication friendly design

Strive for an installation friendly design

Identify risks and develop mitigation plans

Develop a manageable contracting strategy

Develop a realistic cost estimate and schedule


Engineering, Procurement, Construction, and Installation - EPCI Phase

Reflects pre-sanction planning Focus becomes ‘work the plan’ Inadequate planning leads to serious

problems Recovery is expensive


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Well Architecture




Discoveries are more complex in structure, divided by regional and local Faults into Blocks.

Reservoir & Fluid properties are difficult to predict.

Information acquired during exploration & appraisal period is not sufficient to plan a full field development.

Uncertainties Management


To reduce the risks of an improper FDP and avoid a financial catastrophe, the field can be developed in more than one single phase.

Risk Mitigation

An early production system tied back to a 2-3 years leased floating, production, storage and offloading vessel (FPSO) could be an valid alternative

For the first phase, facilities should be installed with low cost, but flexible to upgrade for future field development and production.


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Well Architecture




Norwegian Petroleum Directorate FDP Guideline

Source: Jan Bygdevoll

Discipline leader Reservoir Engineering

Norwegian Petroleum Directorate

February 2006





















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Well Architecture




Development and Depletion Strategy The input of all disciplines, mutual understanding and inter-discipline

communication is the key to developing a successful optimum plan.

In order to come up with an economically viable development and depletion strategy, the team need to address the following main questions:

1. Recovery scheme: - natural depletion or

- natural depletion

augmented by fluid

(water or gas)

injections

2. Well spacing –number of wells, platforms, reserves, and economics

3. Type of well: vertical, slanted, horizontal, multi-lateral


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 a 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 hydrocarbonsfrom 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


Major Tasks of the Reservoir Engineers How much oil and gas is originally in place?

What 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?

Data required to build a reservoir modelClassification Data

AcquisitionTiming

Responsibility

SeismicStructure, stratigraphy, faults, bed thickness, fluids, inter-well heterogeneity

Exploration Seismologists, Geophysicist

GeologicalDepositional environment, diagenesis, lithology, structure, faults, and fractures

Exploration, discovery & development

Exploration & development geologists

LoggingDepth, lithology, thickness, porosity, fluid saturation, gas/oil, water/oil and gas/water contacts, and well-to-well correlations

DrillingGeologists, petrohysicists, and engineers

Coring DrillingGeologists, drilling and reservoir engineers, and laboratory analysts

BasicDepth, lithology, thickness, porosity, permeability, and residual fluid saturation

SpecialRelative permeability, capillary pressure, pore compressibility, grain size, and pore size distribution

FluidFormation 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 & InjectionProduction and reservoir engineers


Data Acquisition and Analysis Multidisciplinary groups (i.e. geophysicists, geologists,

petrophysicists, drilling, reservoir, and production engineers) are involved in collecting various types of data throughout the exploration and appraisal phases.

An effective data acquisition and analysis program requires careful planning and well-coordinated team efforts.

Coring, logging, and initial reservoir fluid sampling should be made at appropriate times using the proper procedures and analyses


Reservoir model is an integrated modelling tool, prepared jointly by geoscientists and engineers.

Reservoir model building

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.


Reservoir Model Capabilities 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.


An example of iterative processes of use of the reservoir model for a field development project


Reserves 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 oil in place (OOIP) and then multiply OOIP by an estimated recovery factor.

The OOIP 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 or cores

Water saturation- Well logs or cores

Recovery efficiency- Analogy- Drive mechanism- Reservoir characteristics

… for reserves estimation by volumetric method the following data are required:


Calculating Oil in Place by the Volumetric Method

Oil in place by the volumetric method is given by:

Where:

N(t) = oil in place at time t, STB

Vb = 7758 A h = bulk reservoir volume, bbl

7758 = bbl/acre-ft

A = area, acres

h = thickness, ft

φ(p(t)) = porosity at reservoir pressure p, fraction

Sw(t) = water saturation at time t, fraction

Bo(p(t)) = oil formation volume factor at reservoir pressure p, bbl/STB

p(t) = reservoir pressure at time t, psia


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Well Architecture





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 / CommentExpected 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.

Commonly used criteria are reviewed, for our convenience, as follow:

1. Payout of Time2. Profit-to-Investment Ratio3. Present Worth Net Profit (PWNP)4. Investment Efficiency or Present Worth Index or Profitability

Index5. Discounted Cash Flow Return on Investment or Internal Rate

of Return.


Payout of Time

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

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.

Present Worth Net Profit (PWNP)


Investment Efficiency or Present Worth Index or Profitability Index

Investment Efficiency or Present Worth Index or Profitability 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


Discounted Cash Flow Return on Investment or Internal Rate of Return is the maximum discount rate that needs to be charged for the investment capital to produce a break-even.

Discounted Cash Flow Return on Investment or Internal Rate of Return.

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.


SomeEconomics Criteria

ofNorwegian Petroleum

Directorate




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Well Architecture




Impact of Hydrocarbon Recovery on FDP

The reservoir and well behavior under dynamic conditions are the key parameters in determining what fraction of the hydrocarbon initial in place (HCIIP) will be produced over the lifetime of the field.

This behavior will therefore dictate the revenue stream which the development will generate through sales of the hydrocarbons.

The reservoir and well performance are linked to the surface development plan, and cannot be considered in isolation; different subsurface development plans will demand different surface facilities.

The prediction of reservoir behavior are therefore crucial components of field development plan.

March 2017

The Driving Force for Production Reservoir fluids (oil, water, gas) and rock matrix are contained under high temperature and

pressures; they are compressed relative to their densities at standard temperature and pressure. Any reduction in pressure on the fluids or rock will results in an increasing volume, according to their compressibility.

As underground fluids are withdrawn (i.e. production occurs) any free gas present expands readily to replace the voidage, with a small drop in reservoir pressure. If only oil or water were present in the reservoir system, a much greater reduction in reservoir pressure would be experienced for the same amount of production.

The expansion of the reservoir fluids, which is function of their volume and compressibility. Act as a source of drive energy which can act to support primary production from the reservoir.

Initial ConditionsPinitial

After ProductionPactual << Pinitial

Primary production means using the natural energy stored in the reservoir as a drive mechanism for production.

March 2017

Enhancement Hydrocarbon Recovery Process

Waterflooding is one of the most widely used post-primary recovery method. Reservoir engineers are responsible for waterfooddesign, 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 93

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).


Waterflooding Waterflooding in an intensive investment activity and require a proper design. The design

includes: - Injection/producer pattern layouts - Injection-water sensitivity studies - Injection wells, injectivity, and allocation approaches, including well fracturing - Pilot waterflooding- Production wells - Surface facilities for injection water - Surface facilities for produced fluids

ProducersInjectors

Offshore Surface FacilitiesSeawater for Injection and sulfate reduction


In oil fields such as Wilmington (California, US) and Ekofisk (North Sea), voidage replacement also has been used to mitigate additional surface subsidence. In these cases, the high porosity of the unconsolidated sandstones of the Wilmington oil field’s reservoirs and of the soft chalk reservoir rock in the Ekofisk oil field had compacted significantly when the reservoir pressure was drawn down during primary production.

Waterflooding - Ekofisk Case Study

Sept. 2011


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Well Architecture




Well 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 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.


Well Shape Selection CriteriaThe well shape should be selected based on the geological target, maximization

of the hydrocarbon recovery, and operational constraints


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

J-shaped S-shaped Inclined well Horizontal well


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 bottomholeaccessibility.

Less expensive.


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.


Horizontal Well – CHEVRON Case study Horizontal Well Technology Applications for Improved Reservoir Depletion, Kern River Oil Field

Estimated to have over 3.5 billion barrels of original oil in place, the 114 year old Kern River Oil Field was a sleeping giant until the late 1960's when steam flooding began and oil production ramped up from 19,000 to over 142,000 BOPD by the mid 1980's.

In 2007 the cumulative production reached two billion barrels of heavy oil. With the introduction of convectional and shallow horizontal wells in 2007 the production decline curve that had been at approximately 6% began to flatten and today the decline rate is at 1 to 2%.




Multi-lateral Well Technologies have been developed to

drill multi-lateral wells. These wells have various shapes and offer the possibility of different types of completions to isolate and control production from different branches of multi-laterals.

Multi-lateral applications are common in heavy oil reservoirs (where wells are completed with slotted liners) and in carbonate reservoirs using open hole completions. A large scale of applications of multi-laterals is found in the heavy oil reservoirs in Canada and Venezuela and in the carbonate reservoirs in the Middle East.5,6Thin zones


Multilateral Well – ENI Case study The Zatchi B Heavy Oil Reservoir Development: The Unique Challenges of the TAML6 Multilateral Well

The Zatchi, located in the Lower Congo Basin offshore, is a shallow multi-layer reservoir (avg top @ -400 n TVDSS) .

The Zatchi B reservoir is 300m thik sand characterized by a large accumulation of heavy and viscous oil (15o API, 1000 cP).

Aquifer

- 406,5 m

- 419,5 m


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Well Architecture




The main problems for drilling in Arctic conditions would be a short ice-free period and ice loads on the drilling facility. Thus not every drilling facility is applicable for an Arctic Area.

Main traditional drilling solutions for offshore field development are described and their suitability for Arctic conditions is considered.

Drilling system for Arctic conditions


Drilling barges Drilling barges are big floating structures grounded on the bottom that need to

be tugged on the drilling point. They are ballasted to sink on the bottom before drilling. They are often used in shallow inner waters as bogs, lakes and other shallow

waters. However they are inappropriate for the wave condition characteristics for the

open waters in Arctic Area.


Grounded submersibledrilling platform Grounded submersible drilling rigs are grounded on the bottom and suitable for the

shallow waters. These drilling platforms consist of two blocks located one on another. Living quarters and

drilling rig are located in the upper block. The lower block works as an outer casing of a submarine - when the platform moves from one place to another, the lower block is filled by air which makes the platform to float. When such drilling platform is installed on the location, the air is bleed and the platform is grounded on the bottom.

The advantage of that platform is its mobility; however, its applicability is limited by shallow waters. This solution is applicable for ice-covered waters but not for year-round operations, for several months more than other platforms for ice-free waters.


Jack-up drilling rig A Jack-up drilling rig is a mobile drilling unit which can reach the drilling point

independently or by the help of tugs. The jack-up drilling rig is equipped with long legs, which seek the bottom, lifting the

drilling rig above the water. This type of drilling rig is suitable for operations in water depths up to150 m.

Jack-up drilling units are very popular solution for offshore drilling; however they are not appropriate permanent solutions for Arctic conditions because they can operate only in ice-free waters for about 45-90 days during the summer season.


Semisubmersible drilling rig The semisubmersible drilling rig is the most popular type of marine drilling structure

combining the advantages of submersible structures with ability to drill in deep waters. The operating principles are the same like for grounded submersible drilling rigs. The

exception is that semisubmersible platforms are moored either by heavy anchors more than 10 tones in weight or kept in position by dynamic positioning system.

Semisubmersible drilling rigs are applied for drilling in water depths from 600m to 2500m and more, depending on age, type and technical characteristics of the platform. They float away from the drilling point with the help of tugs or independently by thrusters. These platforms can withstand some ice loads and consequently extend drilling season in Arctic area.


Drilling ships Drilling ships are self-moving rigs, usually with high net load capacity. They can transport a lot of expendables and equipment for the drilling in remote

locations. Drilling ships are also widely used for deep water drilling. These ships do not require towing on the drilling point and they are very popular for

ice-free waters. However in Arctic Area they could be considered only for summer period.


Drilling rigon the production platform Drilling rig could be installed on the production platforms and used for drilling and

workover operations. The total amount of wells that could be drilled from one platform varies depending on

well and reservoir conditions, but is usually limited to 40-50 wells. Usually the drilling rig is installed stationary but it could be removed and replaced by a workover system when all the planned wells are drilled and completed.

For drilling in Pechora Sea (Arctic area) Gazprom constructed the Prirazlomnaya platform with drilling rig installed on the platform. It is announced that the platform is capable to perform year-round drilling in ice-covered waters of Pechora Sea.


Artificial island Artificial islands for offshore well drilling are used in water depths up to 20 m. They

allow for year round drilling. Artificial islands are widely used in ice-covered shallow waters of the Beaufort Sea. Big

experience gathered for many years of using them in Alaska region ensure safety and reliable solution for operation in Arctic waters.


Grounded ice island An ice sheet that is used as a base

for drilling consists of natural and artificial ice with thickness up to 3 m. The drilling rig is installed on this base with a set of drilling and well control equipment, which in case of an accident (significant lateral moving or ice loosening) allows the operator to perform a quick disconnection of the conductor.

Grounded ice islands provide relatively inexpensive and environmentally friendly technology.

It is possible to perform year-round drilling from ice islands.


Therefore analysis of drilling systems shows that in the Arctic area during the ice-free period it is possible to use the following solutions:

Grounded submersible drilling platforms Grounded caisson drilling platforms Jack-up drilling rigs Semisubmersible drilling rigs Drilling ships Drilling rigs on production platforms Artificial islands

However for ice-covered waters only few solutions are relevant: Drilling rigs on gravity based production platforms Artificial islands Grounded ice islands Submersible gravity based drilling platforms (but not year-round, several months

more than other platforms for ice-free waters

Therefore it is common practice for Arctic fields’ development to plan drilling only during ice-free period from traditional drilling systems, such as jack-ups, semi submersibles and drilling ships.

Summary


Contents





Well Architecture




Production System for Arctic

The production system or production facility is the main part of an offshore field development concept since it accommodates not only production equipment but often drilling and process systems also.

In the Arctic Area the production system is the guarantee for safe and successful operations and therefore it is even more important in the Arctic to choose the “right” production system.

The main production facilities that used for offshore fields are described with comments regarding their usage in Arctic areas.


Steel stationary platform (Jacket) Typical fixed steel platforms consist of large legs and tubular steel cross bracing that

form a «jacket». The jacket is supported by piles driven into the seafloor to transmit wave, wind, current or ice forces into the ground.

They typically support a deck that contains a drilling rig, living quarters and production facilities. Jackets are usually used in shallow to medium water depths and are intended for long-term use.

Steel jacket platforms can operate in up to 450m of water depth and withstand hurricanes and winter storms.

They are typically not the best solution for severe arctic areas with large ice-ridges and multi-year ice. However jacket oil platforms with legs equipped by cones are successfully used in shallow waters of Bohai Bay with first year ice conditions. Traditional jackets could be used in year round ice-free waters of Arctic like in the West Barents Sea for example.


Jack-up platform Self-elevating platforms (jack-up) can be used for hydrocarbon production as well as for drilling. Especially they are well suitable for shallow waters but have limitations in water depths.Main advantages of the jack-up platform are simple marine operations, possibility of onshore equipment assembly and possibility to install subsurface storage tanks. The mobility of the jack-up platform is also one of its characteristics. However these structures cannot operate in multiyear ice waters in Arctic Area. There is possibility that reinforced structures can withstand light first year ice.


Gravity basedstructures (GBS) These platforms take advantage of their large size and heavy mass to support large facilities. They can also be designed to resist severe arctic conditions, such as multi-year ice and icebergs. A GBS can be made of steel or concrete, and provide support for heavy drilling rigs and production equipment. This type of structure can have a storage tanks for oil or liquid gas.These structures are known as the most suitable solution for ice-covered Arctic waters. But the depth of water in such conditions for gravity based structures is typically limited by 80m; in case of weak soils it is even limited by 60m.


Tension leg platforms These floating platforms can

support a drilling rig and production facilities.

The TLPs are similar to fixed platforms except they use a floating hull tethered to seafloor by a mooring system made of tension legs. These steel “tendors” limit vertical movements from wind and sea forces and keep the TLP in position.

Many TLPs are built with a four-column design that supports the deck section. Below the water, a ring of pontoons connects the columns, much like a semisubmersible drilling vessel. TLPs can be used in up to 1800m of water.


Platform with vertical cylindrical caisson (SPAR) Much like the TLP, SPARs are moored to the seafloor,

but with a more conventional lateral mooring anchoring system instead of tension legs.

They are supported by a floating, hollow cylinder containing extra weight in the bottom, similar to a huge buoy.

About 90 percent of the structure is underwater, so it has great stability in very deep waters – as much as 3000m.

As other floating structures this solution is not considered as technically feasible for ice-covered waters in Arctic.


Semisubmersible platform A semisubmersible production platform consists of a deck supported by four columns

connected by four pontoons. Similar to TLPs, semisubmersibles can support living quarters and production equipment. Unlike TLPs, their floating hull uses a conventional lateral mooring system of steel cables or dynamic positioning system to keep the platform in position and is connected to subsea wells via flow lines.

The subsea wells are drilled by mobile offshore drilling units since typically there is not a drill rig on a semisubmersible production platform. These platforms are widely used in water depths up to 2500m.

A floating semisubmersible platform is also not considered as a suitable solution for multiyear ice waters but could be a good decision for Arctic ice-free waters in the West Barents Sea or Bering Sea.


Floating production vessels (FPSO, FPSDO, FSU) Floating production storage and offloading units (FPSOs) can operate in water depths up

to 3000m and are best suited for milder climates or where there are limited pipeline systems to transport oil to shore. These ship-like vessels can process all of the oil or gas produced from a reservoir, separating the oil and gas and storing the oil until it can be offloaded to tankers for transportation.

The storage capacity of the FPSO allows oil to be stored and then periodically offloaded to a tanker so that the tanker does not need to be on standby for long periods while waiting to receive production. Subsea wells lift production to the FPSO through risers. Most vessels use mooring systems connected to a “turret”. The turret is mounted to the hull and allows the vessel to rotate freely.

Floating vessels as other floating structures are not suitable for multiyear ice waters but could be a good solution for ice-free Arctic waters with icebergs existing. The example of such FPSO application is Shtokman field in the Barents Sea where probability of icebergs existing is very high. In such case the disconnection capability of an FPSO is used to prevent collision with iceberg.


Subsea production systems Subsea production systems are composed of wells, manifolds and flowlines lying directly

on the seafloor. Wells for semisubmersible platforms and FPSOs are subsea wells drilled from the Mobile Offshore Drilling Unit. Additionally subsea wells can be connected to other systems, like SPARS, FPSOs or platforms to extend a reach to nearby reservoirs.

Oil and gas from subsea wells flow in flowlines to processing platforms or to shore that may be in distance up to 160 km. The recent years’ tend is to extract the oil and gas by subsea equipment only. This technology is successfully applied on the Ormen Lange and Snohvit fields.

But there are some potential problems for subsea equipment that are specific for the Arctic. There is a possibility of ice keel scouring and it is necessary to heat subsea pipelines in shallow Arctic waters.


Artificial Island Man-made gravel islands may be

used year-round in water depths of up to 20m and can support large drilling rigs and production equipment. Large amounts of gravel are placed on the seafloor to create the island. When production is completed the islands may be left to erode naturally or dredged to a depth that allows for vessel navigation. Gravel islands typically may be strengthened with concrete, rock or steel sheet piles to resist the impact of ice.

Artificial islands have been successfully used for oil production in ice-covered waters of Beaufort Sea for decades. The gathered experience has shown this production system as being suitable for Arctic shallow waters.


Analysis of the existing types of production systems showed that there are only few technically feasible solutions for ice-covered waters in Arctic area: Gravity Based Structures Artificial island Subsea production system (with a lot of challenges)

For ice-free waters all of the illustrated solutions are suitable taking into account water depths limitations.

Summary

Thank Youfor

Your attention Giuseppe Moricca

Senior Petroleum [email protected]

Mob. +39 347 7573167