insight to petroleum industry & operation .Itpo

1 © : Dr. Arko Prava Mukherjee

By: DR. ARKO PRAVA MUKHERJEE


An Introduction to the Petroleum Industry - Fagan, A

Petroleum Geoscience - Jon Gluyas

Geology & Geophysics in Oil Exploration – M. Sroor

Non-technical guide to Petroleum Geology, Exploration,

Drilling and Production – Norman J. Hyne

Handbook of Petroleum Analysis (for Chemical Engg) –

J.G. Speight

A first course in Petroleum Technology – D. A.T.

Donobue and K.R. Lang

Geology of Petroleum – A. I. Leverson

Refer : UPES E-resource link

\\10.2.1.161\UPES -Library

BOOKS


I

II

III

IV

V VI VII

Geology

Petroleum System

Surveys

Drilling

Production Storage Ref. & Distr. Introduction


Also known as the ENP or Exploration aNd Production sector.

The Upstream sector involves

• Searching the Oil/Gas resources (offshore and onshore

blocks)

• Drilling of exploratory and production wells,

• Development of the Oil field

• Subsequently Production operations to recover and bring

the petroleum crude oil and/or gas to the surface

economically

Skills sets

Reservoir Engineers, Drilling Engineers, Production Engineers

What is Upstream sector ?

Introduction


What is general stages in the Upstream sector ?

Introduction

Decision making?

Access phase – Explor. – Appraisal – Dev. planning – Production – Decomm.

Both in Mega – and Minor - Scale

Geologist

2 Petroleum Engineers

Geophysicist

HSE

Finance

Decision maker (Sr. Management)

Legal

?? + BD, PSCM


Present Scenario: Global Oil & Gas Industry

High fluctuations of crude prices In last 3-4 months has been

observed.

The WTI crude is currently prices around $97/barrel

The Brent crude is currently prices around $117/barrel

The E&P activity has increased all over the world.

GRAPH

Introduction


Present Scenario: Oil & Gas Industry in India

Crude oil consumption (2010) around 2.98 million barrels/day

Production is 752,000 barrels/day

India is importing around 75% of its oil needs

The exploitation activity for unconventional sources such as CBM has

geared up in India

The Indian government is planning to put up Shale Gas blocks on bid in

NELP rounds next year


Source: BP Statistical

review of world energy

2010

Introduction




2010

Introduction


FIELD LIFE CYCLE

Each activity is driven by a business need related to that particular phase. In

the later classes we will focus in more detail on individual elements of the

field life cycle

Fig: The field

life cycle and

typical

cumulative

cash flow.


FIELD LIFE CYCLE

Each activity is driven by a business need related to that particular phase. In

the later classes we will focus in more detail on individual elements of the

field life cycle

Fig: The field

life cycle and

a simplified

business

model.


FIELD LIFE CYCLE

Step 1 : GAINING ACCESS PHASE

The first step an oil company will undertake in hydrocarbon exploration and

production is to decide what regions of the world are of interest. This will

involve evaluating the technical, political, economic, social and

environmental aspects of regions under consideration.

Technical aspects will include the potential size of hydrocarbons to be found

and produced in the region, which will involve scouting studies using publicly

available information or commissioning regional reviews, and a consideration

of the technical challenges facing exploration and production, for example in

very deep offshore waters.

Political and economic considerations include political regime and

Government stability, the potential for nationalisation of the oil and gas

industry, current embargoes, fiscal stability and levels of taxation, onstraints

on repatriation of profits, personnel security, local costs, inflation and

exchange rate forecasts.

Intro: Access Phase


FIELD LIFE CYCLE

Contd ….Step 1 : GAINING ACCESS PHASE

Social considerations will include any threat of civil disorder, the availability

of local skilled workforce and local training required, the degree of effort

which will be required to set up a local presence and positively engage the

indigenous people.

Environmental considerations: The company will also consider the

precautions needed to protect the environment from harm during operations,

and any specific local legislation. There may also be a reputational issue to

consider when doing business in a country whose political or social regime

does not meet with the approval of the company‟s home Government or

shareholders.

Finally, an analysis of the competition will indicate whether the company has

any advantage. It may be that if the company has an existing presence in-

country from another business interest, such as downstream refining or

distribution, the experience from these areas could be leveraged

Intro: Access Phase


FIELD LIFE CYCLE


Some 90% of the world‟s oil and gas reserves are owned and operated by

National Oil Companies (NOCs), such as Saudi Aramco (Saudi Arabia),

Petronas (Malaysia), Pemex (Mexico). For an independent oil company to

take a direct share of exploration, development and production activities in a

country, it first needs to develop a suitable agreement with the Government,

often represented by the NOC.

The invitation to participate may be publicly announced, in the form of a

licensing round. Alternatively an arrangement for participation may be

privately agreed with the NOC. In order to gain an advantageous position on

this process, an oil company will expend effort to understand the local

conditions, often by setting up a small presence in-country through which

relationships are formed with key Government representatives such as the

Oil and Gas Ministry, Department of Environmental Affairs and local

authorities.

Intro: Access Phase


FIELD LIFE CYCLE


The investment made during the Gaining Access phase may be

considerable, especially in terms of time and the commitment of

representatives – it may take a decade of setting up the groundwork before

any tangible results are seen, but this is part of the investment process of

hydrocarbon exploration and production.

Intro: Access Phase


FIELD LIFE CYCLE

Step 2 : EXPLORATION PHASE

For more than a century petroleum geologists have been looking for oil.

During this period major discoveries have been made in many parts of the

world. However, it is becoming increasingly likely that most of the „giant‟

fields have already been discovered and that future finds are likely to be

smaller, more complex, fields.

Fortunately, the development of new exploration techniques has improved

geologists‟ understanding and increased the efficiency of exploration. So

although targets are getting smaller, exploration and appraisal wells can now

be sited more accurately and with greater chance of success.

Despite such improvements, exploration remains a high-risk activity. Many

international oil and gas companies have large portfolios of exploration

interests, each with their own geological and fiscal characteristics and with

differing probabilities of finding oil or gas. Managing such exploration assets

and associated operations in many countries represents a major task.

Intro: Exploration Phase




2010

Introduction


FIELD LIFE CYCLE

Contnd ….Step 2 : EXPLORATION PHASE

Traditionally, investments in exploration are made many years before there

is any opportunity of producing the oil (See Fig). In such situations

companies must have at least one scenario in which the potential rewards

from eventual production justify investment in exploration.


Fig: Phasing and

expenditure of a

typical exploration

programme.


FIELD LIFE CYCLE

Contnd ….Step 2 : EXPLORATION PHASE

It is common for a company to work for several years on a prospective area

before an exploration well is „spudded‟ – an industry term for starting to drill.

During this period the geological history of the area will be studied and the

likelihood of hydrocarbons being present quantified. Prior to spudding the

first well a work programme will have to be carried out. Field work, magnetic

surveys, gravity surveys and seismic surveys are the traditional tools

employed.



FIELD LIFE CYCLE

Step 3: APRAISAL PHASE

Once an exploration well has encountered hydrocarbons, considerable effort

will still be required to accurately assess the potential of the find. The amount

of data acquired so far does not yet provide a precise picture of the size,

shape and producibility of the accumulation.

Intro: Appraisal Phase


FIELD LIFE CYCLE

Contnd ….Step 3: APRAISAL PHASE

Four possible options have to be considered at this point:

• To proceed with development and thereby generate income within a relatively short

period of time. The risk is that the field turns out to be larger or smaller than envisaged,

the facilities will be over or undersized and the profitability of the project may suffer.

• To carry out an appraisal programme with the objective of optimising the technical

development. This will delay „first oil‟ to be produced from the field by several years and

may add to the initial investment required. However, the overall profitability of the project

may be improved.

• To sell the discovery, in which case a valuation will be required. Some companies

specialise in applying their exploration skills, with no intention of investing in the

development phase. They create value for their company by selling the discovery on,

and then move on with exploration of a new opportunity.

• To do nothing. This is always an option, although a weak one, and may lead to

frustration on behalf of the host nation‟s Government, who may force a relinquishment if

the oil company continues to delay action.



FIELD LIFE CYCLE

Contnd…..Step 3: APRAISAL PHASE

In the second case, the purpose of appraisal is therefore to reduce the

uncertainties, in particular those related to the producible volumes contained

within the structure.

Having defined and gathered data adequate for an initial reserves

estimation, the next step is to look at the various options to develop the field.

The objective of the feasibility study is to document various technical options,

of which at least one should be economically viable.

The study will contain the subsurface development options, the process

design, equipment sizes, the proposed locations (e.g. offshore platforms) and

the crude evacuation and export system. The cases considered will be

accompanied by a cost estimate and planning schedule. Such a document

gives a complete overview of all the requirements, opportunities, risks and

constraints.



FIELD LIFE CYCLE

Step 4: DEVELOPMENT PLANNING PHASE

Based on the results of the feasibility study, and assuming that at least one

option is economically viable, a field development plan (FDP) can now be

formulated and subsequently executed. The plan is a key document used for

achieving proper communication, discussion and agreement on the activities

required for the development of a new field, or extension to an existing

development.

The FDP‟s prime purpose is to serve as a conceptual project specification

for subsurface and surface facilities, and the operational and maintenance

philosophy required to support a proposal for the required investments

Intro: Development Phase


FIELD LIFE CYCLE

Contnd….Step 4: DEVELOPMENT PLANNING PHASE

The FDP should give management and shareholders confidence that all

aspects of the project have been identified, considered and discussed

between the relevant parties. In particular, it should include:

• objectives of the development

• petroleum engineering data

• operating and maintenance principles

• description of engineering facilities

• cost and manpower estimates

• project planning

• summary of project economics

• budget proposal.



FIELD LIFE CYCLE

Contnd….Step 4: DEVELOPMENT PLANNING PHASE

Once the FDP is approved, there follows a sequence of activities prior to the

first production from the field:

• FDP

• Detailed design of the facilities

• Procurement of the materials of construction

• Fabrication of the facilities

• Installation of the facilities

• Commissioning of all plant and equipment.



FIELD LIFE CYCLE

Step 5: PRODUCTION PHASE

The production phase commences with the first commercial quantities of

hydrocarbons (first oil) flowing through the wellhead. This marks the turning

point from a cash flow point of view, since from now on cash is generated

and can be used to pay back the prior investments, or may be made

available for new projects. Minimising the time between the start of an

exploration campaign and „first oil‟ is one of the most important goals in any

new venture.

Development planning and production are usually based on the expected

production profile which depends strongly on the mechanism providing the

driving force in the reservoir. The production profile will determine the

facilities required and the number and phasing of wells to be drilled.

Intro: Production Phase


FIELD LIFE CYCLE


The production profile is usually characterised by three phases:

1. Build-up period: During this period newly drilled producers are

progressively brought on stream.

2. Plateau period: Initially new wells may still be brought on stream but

the older wells start to decline. Production facilities are running at full

capacity, and a constant production rate is maintained. This period is

typically 2–5 years for an oil field, but longer for a gas field.

3. Decline period: During this final (and usually longest) period, all

producers will exhibit declining production.



FIELD LIFE CYCLE



Fig: The field

life cycle and

typical

cumulative

cash flow.


FIELD LIFE CYCLE

Step 6: DECOMMISSIONING PHASE

The economic lifetime of a project normally terminates once its net cash flow

turns permanently negative, at which moment the field is decommissioned.

Since towards the end of field life the capital spending and asset

depreciation are generally negligible, economic decommissioning can be

defined as the point at which gross income no longer covers operating costs

(and royalties). It is of course still technically possible to continue producing

the field, but at a financial loss.

Most companies have at least two ways in which to defer the

decommissioning of a field or installation

(a) reduce the operating costs, or

(b) increase hydrocarbon throughput

In some cases, where production is subject to high taxation, tax concessions

may be negotiated, but generally host Governments will expect all other

means to have been investigated first.

Intro: Decommissioning phase


FIELD LIFE CYCLE

Maintenance and operating costs represent the major expenditure late in field life. These costs will be closely related to the number of staff required to run a facility and the amount of hardware they operate to keep production going. As decommissioning approaches, enhanced recovery, for example chemical flooding processes are often considered as a means of recovering a proportion of the hydrocarbons that remain after primary production. The economic viability of such techniques is very sensitive to the oil price, and whilst some are used in onshore developments they can less often be justified offshore. When production from the reservoir can no longer sustain running costs but the technical operating life of the facility has not expired, opportunities may be available to develop nearby reserves through the existing infrastructure.



FIELD LIFE CYCLE

Ultimately, all economically recoverable reserves will be depleted and the

field will be decommissioned. Much thought is now going into

decommissioning planning to devise procedures which will minimise the

environmental effects without incurring excessive cost.

Steel platforms may be cut off to an agreed depth below sea level or toppled

over in deep waters, whereas concrete structures may be refloated, towed

away and sunk in the deep ocean. Pipelines may be flushed and left in place.

In shallow tropical waters opportunities may exist to use decommissioned

platforms and jackets as artificial reefs in a designated offshore area.



An Introduction to the Petroleum Industry - Fagan, A

Petroleum Geoscience - Jon Gluyas

Geology & Geophysics in Oil Exploration – M. Sroor

Non-technical guide to Petroleum Geology, Exploration,

Drilling and Production – Norman J. Hyne

Handbook of Petroleum Analysis (for Chemical Engg) –

J.G. Speight

A first course in Petroleum Technology – D. A.T.

Donobue and K.R. Lang

Geology of Petroleum – A. I. Leverson

Refer: many books are available in UPES E-resource link

\\10.2.1.161\UPES -Library

BOOKS



Introduction and Commercial Application: When the host government

notifies its intent to offer exploration acreage, the oil company has an

opportunity to gain access.

Two broad types of Petroleum Agreement exist: Licence Agreements and

Contract Agreements.

Petroleum Agreements and Bidding


In a Licence Agreement the Government issues exclusive rights to an oil

company to explore within a specific area. The operations are financed by

the licence holder who also sells all production, often paying a royalty on

production, and always paying taxes on profits. Such a fiscal regime is often

called a Tax and Royalty system. The Government may insist upon an

obligatory level of State participation.

In a Contract Agreement, the oil company obtains the rights to an area

through a contract with the Government or its representative NOC.

Essentially the company acts as a contractor to the Government, again

funding all operations. However, in this case, title to the produced

hydrocarbons is retained by the Government, and the oil company is

remunerated for its costs and provided a share of the profits either in cash or

in kind (i.e. a share of the produced hydrocarbons). The most common form

of this type of agreement is a production sharing contract (PSC), also known

as a production sharing agreement (PSA)



THE INVITATION TO BID

As mentioned earlier the majority of the remaining world hydrocarbon

reserves lie under the control of NOCs, and usually this will be developed by

the NOC. Exceptions to this may arise for a variety of reasons:

• The NOC may not have the local expertise required

• The host Government may not have sufficient funds or manpower

• or an asset may be unattractive to the NOC

In cases such as these, the host Government may invite third parties to

participate in the region. Such an opportunity may be posted in the

international press, trade journals or by specific invitation.






The geographic area of interest is divided up into a number of blocks by a

grid, which is usually orthogonal. The size of these blocks varies from

country to country and even from area to area in some cases. For example,

UK North Sea licence blocks are 1020 km, Norwegian blocks 2020 km, GoM

blocks 33 miles and deepwater Angola blocks approximately 10050km.

The Government will decide at its discretion what blocks it wishes to include

in any bidding round, but there is often a geographic progression, from say

shallow water areas into deeper water as time moves on.

The invitation to bid may come in several forms. For example, in the UK,

licensing rounds are announced periodically by the Department of Trade and

Industry (DTI) on behalf of the UK Government. In India it is NELP rounds

are announced by Directorate of Hydrocarbons (DGH)






The invitation to bid may not be for exploration acreage. For example, some

blocks offered by Sonatrach, representing the Algerian Government, were for

fields that had many years of production history. In this case, the equivalent

of an information memorandum (IM) was provided to prospective bidders.

This information includes both technical data for the fields, such as the

production history by well, and an outline of the commercial agreement that

would be expected for any participation by a foreign investor. Investors were

invited to submit a forward development plan to increase the recovery of the

field above the base case. The commercial terms offer a fraction of the

incremental production to the investor as the profit element of their

investment.



MOTIVATION AND FORM OF BID

In offering an exploration opportunity in a block, the motivation of the

Government is to encourage investment in form of exploration activities, such

as shooting seismic and exploration drilling, with a view to development if the

exploration is successful. A signature bonus may form part of the bid

package.

The invitation to bid may include an outline of the form of bid required along

with the fiscal terms applicable to any subsequent development. The bid may

require a minimum work programme consisting of seismic data to be

acquired and a minimum number of wells; for example 2000km of 2-D

seismic and four wells. The bidder is of course at liberty to commit to more

than the minimum, and a heavier commitment will improve the

competitiveness of the bid.



SUGNATURE BONUS AND COSTS

SIGNATURE BONUS: In many regions, especially those operating PSAs, it

is normal to add a signature bonus to the work programme offered. This is

the promise of a cash sum payable by the successful bidder to the

Government on award of the block. A minimum signature bonus may be

indicated in the invitation to bid, but this element of the bid package is again

a choice to be made by the bidder.

In the early phases of exploration in a basin, when the risks of exploration

failure are high, signature bonuses are usually tens of millions of dollars.

However, once the first discoveries have been made in the area, interest will

be heightened and signature bonuses offered for subsequent nearby blocks

can escalate to hundreds of millions of dollars. It is important to realise that

this signature bonus, once paid, is a sunk cost and should be considered as

part of the cost of exploration. It is not a tax-deductable cost against future

revenues.



MOTIVATION AND FORM OF BID

The offer will have a bid deadline, after which submitted bids will be opened

by the Government, or its NOC representative. This may be done in public or

more commonly behind the closed doors. The winning bids may be publicly

announced, or kept confidential, depending on the country. The criterion by

which the bids are then compared is normally the total value of the bid

package – the combination of the work programme plus signature bonus.

Of course, where the combined values of competitors are close, the

Government will need to decide on the relative weighting it places on work

programme versus cash offered in the signature bonus.

Other considerations that the Government will take into account will be the

bidders‟ technical competence, general reputation, any existing working

relationships and any strategic reasons the Government may have to

encourage particular entrants into the region



WINNER OF THE BID

The details of the winning bids may be publicly announced and published,

which is both a useful piece of information for future bids and an interesting

comparison for each bidder to make with their own offer. In some cases all

bids are announced, in which case the margin by which the winner

succeeded is clear – the winner of course hopes not to have outbid the next

nearest competitor by an embarrassing sum, thereby „leaving money on the

table‟.



BLOCK AWARD

The successful bid will result in award of the block, giving the rights to

explore. Any signature bonus offered will be cashed by the Government.

There is often a prescribed sequence of events that dictate the timing of

carrying out the work programme and declaring a commercial interest in the

block – meaning that the company intends to progress beyond the

exploration stage and on to appraisal and possible development of a

discovery in the block. In this case, the company will need to convert the

exploration rights into development rights in the block.



BLOCK AWARD

The Figure below shows an example of the provisions in a PSA for

converting an exploration agreement into a production agreement.



BLOCK AWARD

The criteria for a commercial well would be based on production rate during

testing of a discovery well, whereas the declaration of a commercial

discovery (DCD) would depend on the oil company demonstrating that an

economic development can be justified – this will need to pass internal

economic screening criteria. In the example as shown in the previous Figure,

the Government is due a bonus payable at DCD, and a further bonus when

production from the development starts. Timeframes are typically imposed on

the events, shown above for a PSA between the oil company and the

Government.

In some cases there is a requirement to release only a fraction of the block if

commerciality has not been declared after a specified period of time.



BLOCK AWARD

The Figure below shows an example of drilling up a commitment of three

wells, and shooting 2-D seismic, whilst relinquishing fractions of the block

during this time.


Fig: Example of maturing of an exploration licence block.


FISCAL SYSTEM

The Petroleum Agreement will also include a description of the fiscal terms by which the Government will claim its share of revenues during the production period. This will fall broadly into four categories, as shown in the Table below. Within these broad categories, there are in excess of 120 different fiscal systems in place around the world. Some 50% of these are PSAs and 40% Tax and Royalty systems.



FARM-IN AND FARM-OUT

The participants in the block may change over time, for various reasons:

Firstly, in a PSA the Government may choose to award the block to several

companies, imposing a preferred split and a nominated operator. With the

approval of the Government, the incumbents may choose to trade the initial

splits. At any stage of the field life cycle, a company may choose to reduce its

share in a block by selling a fraction to another company – this is known as

„farming out‟. The company who accepts the share is said to have „farmed in‟.

The farm-out may be for cash or for a trade in another interest.

A company may choose to farm out if it is unable to raise the capital required

for development, or if it wishes to reduce its exposure in the project because

it considers its position to be too risky.

In fact, there is an active market in trading ownership of oil and gas properties

as companies adjust their portfolios to match their required risk profile or their

available budgets.



UNITISATION AND EQUITY DETERMINATION

We have seen how blocks are defined by a grid system. Unfortunately,

nature does not confine the hydrocarbon field size to the regularities of the

grids imposed, and commonly a field will span two or more blocks, often

owned by different groups. In the early days of field development, the

simplest way of defining the rights to exploration and development drilling

was to confine the drilling rig to the boundaries of the block.

Assuming wells were drilled vertically, the bottom hole location of the well

should be within the owner‟s block. Production from that well, however, could

be from the neighbouring block. It would therefore be in the interest of the

licence, block owner to site the production wells at the periphery of his block

and to produce aggressively, thus draining a neighbouring block without

concerns of reprisal from his neighbour. This gave rise to situations such as

that shown below at Spindletop, Texas in the early 1900s




Spindletop, Texas in the early 1900s




Apart from the obvious inequity of this arrangement, it also led to hugely

suboptimal field development costs and reservoir management.

To overcome this, most governments will insist that the field is „unitised‟ and

treated as one unit for development purposes. The owners of the field or the

Government will nominate an operator, and the development will be planned

based on the physical properties of the field, uninfluenced by ownership. The

split of the costs of development and the resulting net cash flow will be

determined by the „equities‟ held by the owners of the licence blocks which

the field straddles.

The basis for the equity determination is negotiated between the block

owners (Figure in next slide). This basis could be:

• areal extent of the accumulation, as mapped to the hydrocarbon–water

contact

• hydrocarbons initially in place

• moveable hydrocarbons initially in place

• recoverable hydrocarbons initially in place

• economically recoverable hydrocarbons initially in place.




Fig: Options for the basis of equity.




Moving toward the apex of Figure, the basis for equity becomes

progressively more complex and lengthier to determine. The extreme case of

economically recoverable reserves requires estimates of both the technical

development plan and all of the economic assumptions such as costs and

product prices, right through to the end of field life.

Prior to development, a „deemed equity‟ may be agreed between the equity

groups in order to set the proportional funding of the field development. This

will usually be reviewed close to first production when more information is

available from the development wells. Adjustments are then made to the

initial funding to ensure that the correct contributions to the development

costs have been made.

Once production has commenced and more information about the reservoir

becomes available, it may become apparent that the initial equity is incorrect.

If one of the equity groups feels that a revision to the equity is required, then

a „re-determination‟ may be called, and new equities agreed. Again, this can

be a costly exercise.


INTRODUCTION

1. What are the different stages of Oil field life cycle ? Write short

notes on each stage.

2. What are the different parameters a Oil company considers to

target a area of Interest? Write a short note on each parameter

3. What are the 4 possible options a Oil company has once it has

been successful in finding oil in the exploration phase?

4. What is FDP? Why it is important in the Development Planning

Phase.

5. Describe Decommissioning phase with examples?

© : Dr. Arko Prava Mukherjee 56

ACCESS PHASE

1. What are the different types of agreements in Access Phase?

2. Describe the process of bidding in Access Phase?

3. What is Signature Bonus? Describe its importance in Access

phase.

4. Describe with a diagram the different steps involved in

converting a exploration agreement into a production

agreement.

5. Describe Unitization and Equity determination process in

Access Phase?

© : Dr. Arko Prava Mukherjee 57



Before one tries to understand the Geological methods of exploration – one

must understand the concept of Petroleum System. This starts with the „Origin

of Petroleum‟.

When animals and plants die, they leave an organic residue composed of

carbon, hydrogen, nitrogen and oxygen. Most of this broken down by

bacteria. Some, however, is deposited in aquatic environments low in oxygen

– on the beds if inland seas, lagoons, lakes, or deltas – and is therefore

protected from the action of aerobic bacteria.

These residues are mixed with sediments (sand, clay, salt etc.), accumulate,

are compressed, and undergo a first transformation under the action of

anaerobic micro-organisms. This first stage of decomposition of the matter

gives rise to KEROGEN, the organic molecules of which are entrapped

within a clayey rock known as the SOURCE ROCK.

ORIGIN OF PETROLEUM


The mechanism of subsidence causes sediments to be entrained to great

depths , where they are exposed to high temperatures and pressures. The

KEROGEN is then transformed into hydrocarbons by thermal cracking: long

molecular chains are broken down, expelling the oxygen and nitrogen,

leaving molecules of carbon and hydrogen.

When temperatures exceed 50-70 deg C, kerogen is transformed into

Petroleum (or Oil). In range of 120-150 deg C the oil is subject to cracking, to

give WET gas, then DRY gas.

Higher the temperature and longer it is maintained, the shorter are the

resulting molecules, and therefore the lighter the hydrocarbons.

ORIGIN OF PETROLEUM


When temperatures exceed 50-70 deg C, kerogen is transformed into

Petroleum (or Oil). In range of 120-150 deg C the oil is subject to cracking, to

give WET gas, then DRY gas.

ORIGIN OF PETROLEUM


The term PETROLEUM SYSTEM refers to the combination of the main

geological attributes which have led to the accumulation of hydrocarbons.

Several conditions need to be satisfied for the existence of a hydrocarbon

(SEE FIGURE)

PETROLEUM SYSTEM

Generation, migration and trapping of hydrocarbons.


Conditions necessary for Hydrocarbon accumulations:

• Sedimentary Basin: an area in which a suitable sequence of rocks has

accumulated over the geological time.

• Source Rock: Within a sedimentary basin there needs to be a source rock

enriched in high content of organic matter

• Maturation: Through elevated temperatures and pressures these rocks must have reached maturation, the condition at which hydrocarbons are expelled from the source rock.

• Migration: Migration describes the process which has transported the generated hydrocarbons into a porous type of sediment, the reservoir rock.

• Reservoir Rock: A porous and permeable which contains the

hydrocarbon and allow them to accumulate.

• Trap: Lastly the reservoir must be surmounted by an impermeable layer

(or should be deformed in a favorable shape) such that it acts as a

natural barrier to the natural upward movement of fluids.


ASSIGNMENT: PETROLEUM SYSTEM

SUBMISSION TIME : ONE WEEK


INTRODUCTION

The objective of any exploration venture is to find new volumes of

hydrocarbons at a low cost and in a short period of time.

Once an area has been selected for exploration, the usual sequence of

technical activities starts with the definition of a basin.

The mapping of gravity anomalies and magnetic anomalies will be the first

two methods applied.

Next, a coarse two-dimensional (2D) seismic grid, covering a wide area, will be acquired in order to define leads, areas which show for instance a structure which potentially contains an accumulation (seismic methods will be discussed in more detail in the next section). A particular exploration concept, often the idea of an individual or a team will emerge next. Since at this point very few hard facts are available to judge the merit of these ideas they are often referred to as ‘play’.

Exploration


INTRODUCTION….contd

More detailed investigations will be integrated to define a ‘prospect’, a subsurface structure with a reasonable probability of containing all the elements of a petroleum accumulation, namely source rock, maturation, migration, reservoir rock and trap. Eventually, only the drilling of an exploration well will prove the validity of the concept. A ‘wildcat’ well is drilled in a region with no prior well control. Wells either result in discoveries of oil and gas, or they find the objective zone to be water-bearing in which case they are termed ‘dry’. Exploration activities are potentially damaging to the environment. The cutting down of trees in preparation for an onshore seismic survey may result in severe soil erosion in years to come. Offshore, fragile ecological systems such as reefs can be permanently damaged by spills of crude or mud chemicals. Responsible companies will therefore carry out an environmental impact assessment (EIA) prior to activity planning and draw up contingency plans should an accident occur (HSSE).

Exploration


GEOLOGICAL METHODS

There are four main branches of Geology relevant in exploration for

hydrocarbons:

• Sedimentology: i.e. the study of sedimentary rocks

• Stratigraphy: i.e. the study of the organization in time and space of

sedimentary rocks.

• Structural Geology: i.e. the study of structural deformation and fractures

of rocks

• Organic Geo-Chemistry: i.e. the study of the potential of rocks to

produce hydrocarbons.

The Geological and Tectonic history of the entire area is studied in details .

Exploration


GEOLOGICAL TOOLS….contd

When a site is relatively unexplored, prospectors first study the

TOPOGRAPHY and OUTCROPS in order to form a picture of the

characteristics of the subterranean formations and structures.

TRACES of hydrocarbon at the surface or in the subsoil can be a good

indication of the proximity of an accumulation.

Geologists drill small boreholes which allow them to take CORE samples for

chemical analysis by a laboratory. The results provide useful information on

whether there are traces of hydrocarbons present.

Particular efforts are made to gain a better understanding of the porosity and

permeability of potential reservoirs.

Geologists synthesize the information obtained into subsurface maps on

different scales, which may be extended over an entire basin or represent

just a single field.

Exploration



The most common Geological maps comprise of:

• Contours of equal thickness (ISOPACHS)

• Contours of equal depths (ISOBATHS)

• Physical properties of rocks (LITHOFACIES data)

Every time a new well drilled, additional data are obtained and added to

these subsurface maps.

These successive elaborations require a stratigraphic correlation

(SEQUENCE Stratigraphic) which involves identification of rocks of a similar

age by comparing fossils and well log data or from an outcrop with the data

from another well or outcrop in the light of the seismic results.

From the analysis of the data – if a major variation in thickness or in the type

of rock may provide an interesting geological clue.

Exploration



Exploration



Exploration



Exploration



Exploration



Exploration



Exploration



GEOPHYSICAL METHODS

There are various geophysical surveying methods that are routinely applied

in the search for potential hydrocarbon accumulations.

Geophysical methods respond to variations in physical properties of the

earth‟s subsurface including its rocks, fluids and voids. They locate

boundaries across which changes in properties occur.

These changes give rise to an anomaly relative to a background value; this

anomaly is the target which the methods are trying to detect.

The measurement of changes in signal strength along lines of a grid or

network, „profiling‟, allows anomalies to be mapped out spatially.

Care should be taken to avoid spatial „aliasing‟, the loss of fine detail

information as a result of gathering data at only a small number of measuring

stations

Exploration


GEOPHYSICAL METHODS

Care should be taken to avoid spatial „aliasing‟, the loss of fine detail

information as a result of gathering data at only a small number of measuring

stations.

Exploration

Loss of information due to limited number of measurement points.


GEOPHYSICAL METHODS

GRAVITY SURVEYS

The gravity method

measures small variations

of the earth‟s gravity field

caused by density

variations in geological

structures.

The measuring tool is a

sophisticated form of spring

balance designed to be

responsive over a wide

range of values.

Exploration

Principle of gravity surveying.


GEOPHYSICAL METHODS: GRAVITY SURVEYS

Fluctuations in the gravity field give rise to changes in the spring length

which are measured (relative to a base station value) at various stations

along the profile of a 2D network. The measurements are corrected for

latitudinal position and elevation of the recording station to define the

„Bouguer‟ anomaly.

The development of airborne gravity technology has allowed the surveying of

previously inaccessible areas and of much larger basins than is currently

practical with land-based measuring tools.

Exploration


GEOPHYSICAL METHODS

MAGNETIC SURVEYS

The magnetic method detects

changes in the earth‟s

magnetic field caused by

variations in the magnetic

properties of rocks.

In particular, basement and

igneous rocks are relatively

highly magnetic. If they are

located close to the surface

they give rise to anomalies

with a short wavelength and

high amplitude (see Figure).

Exploration

Source: http://www.ga.gov.au/ausgeonews/ausgeonews200712/productnews.jsp


GEOPHYSICAL METHODS

MAGNETIC SURVEYS

The method is airborne

(plane or satellite) which

permits rapid surveying and

mapping with good areal

coverage.

Like the gravity technique

this survey is often employed

at the beginning of an

exploration venture.

Exploration

Principle of magnetic surveying.


GEOPHYSICAL METHODS:

CSEM SEABED LOGGING

Controlled source electro-magnetic

(CSEM) surveying or seabed logging is

a remote sensing technique which uses

very low frequency electro-magnetic

signals emitted from a source near the

seabed.

Receivers are placed on the seabed at

regular intervals and register anomalies

and distortions in the electromagnetic

signal generated by resistive bodies,

such as reservoirs saturated with

hydrocarbons.

Exploration


Exploration

Fig: Principle of

CSEM seabed

logging.


GEOPHYSICAL METHODS:

CSEM SEABED LOGGING

CSEM works best in deep water (>500 m) in areas characterised by

relatively simple sand-shale sequences (clastic reservoirs); it is particularly

useful for surveying large traps (prospects) where other marine methods are

less practical or economical.

It is being increasingly used in conjunction with seismic data to verify likely

fluid fill within the reservoir rocks of a prospect, thus helping to reduce risk

and to improve the chance of success by allowing wells to be targeted in a

more sophisticated way.

Exploration


SEISMIC METHODS (Seismic Data Acquisition and Processing)

Introduction:

From being a predominantly exploration focused tool, seismic surveying has

progressed to become one of the most cost effective methods for optimizing

field production. In many cases, seismic data have allowed operators to

extend the life of „mature‟ fields by many years.

Seismic surveys involve generating sound waves which propagate through

the earth‟s rocks down to reservoir targets. The waves are reflected to the

surface, where they are registered in receivers, recorded and stored for

processing.

The resulting data make up an acoustic image of the subsurface which is

interpreted by geophysicists and geologists.

Geophysical methods of Exploration



Contd…..Introduction:

Seismic surveying is used in:

• exploration for delineating structural and stratigraphic traps

• field appraisal and development for estimating reserves and drawing up

FDPs

• production for reservoir surveillance such as observing the movement of

reservoir fluids in response to production.

Seismic acquisition techniques vary depending on the environment (onshore

or offshore) and the purpose of the survey. In an exploration area a seismic

survey may consist of a loose grid of 2D lines.

In contrast, in an area undergoing appraisal, a 3D seismic survey will be

shot. In some mature fields a permanent 3D acquisition network might be

installed on the seabed for regular (6–12 months) reservoir surveillance,

called ocean bottom stations (OBS) or ocean bottom cables (OBC).




Principles of Seismic Surveying

Sound waves are generated at the surface (onshore) or under water (offshore) and travel through the earth’s subsurface. The waves are reflected back to the surface at the interface between two rock units where there is an appreciable change in ‘acoustic impedance’ (AI) across that interface. AI is the product of the density of the rock formation and the velocity of the wave through that particular rock (seismic velocity).






Changes in acoustic impedance (AI) give rise to reflected seismic waves.




„Convolution‟ is the process by which a wave is modified as a result of

passing through a filter. The earth can be thought of as a filter which acts to

alter the waveform characteristics of the down-going wave (amplitude,

phase, frequency).

In schematic form (SEE Figure) the earth can be represented either as an AI

log in depth or as a series of spikes, called a reflection coefficient log or

reflectivity series represented in the time domain.

When the wave passes through the rocks its shape changes to produce a

wiggle trace that is a function of the original source wavelet and the earth‟s

properties.






Convolution of a reflected seismic wave.




Two attributes of the reflected signal are recorded:

• The reflection time, or travel time, is related to the depth of the interface or

„reflector‟ and the seismic velocity in the overburden.

• The amplitude is related to rock and fluid properties within the reflecting

interval and various extraneous influences that need to be removed during

processing.





Case a: When a seismic wave hits an interface at

normal incidence (see Figure-a), part of the energy

is reflected back to the surface and part of the

energy is transmitted.

Case b: In the case of oblique incidence the angle of

the incident wave equals the angle of the reflected

wave as shown in Figure-b. Again part of the energy

is transmitted to the following layer, but this time with

a changed angle of propagation.

Case c: A special case is shown in Figure-c where

an abrupt discontinuity, for example the edge of a

tilted fault block, gives rise to „diffractions‟, radial

scattering of the incident seismic energy. Such

artefacts can impede interpretation of the seismic

data but can be removed or suppressed during

processing (as outlined later in this section).





SEISMIC METHODS (Seismic Data Acquisition)


The time it takes for the wave to travel from the source S to a reflection point a at

depth z and up to a receiver R at an offset, or shot-receiver separation, x, is given by

the ratio of the travel path and the velocity (Figure a).

Time = Distance/Velocity (because Velocity = Distance/Time)

The acquisition system is arranged such that there are many shot-receiver pairs for

each reflection point in the subsurface, also called „common midpoint‟ or CMP.

Reflection times are measured at different offsets (x1, x2, x3,… xn); the further away

shot and receiver are for a particular reflection point in the subsurface, the longer the

travel time.

The difference in travel time between the zero offset case (normal incidence) and the

non-zero offset case (oblique incidence) is called the normal move out (NMO) and is

dependent on the offset, velocity and depth to the reflector.




Source - receiver geometry for multiple offsets.




Collecting data from different offsets and also at different angles is important for

imaging the subsurface properly, for instance where intermediate layers or

structures impact on the amount of energy reaching the target (Figure b) or

where they give rise to variations in seismic velocity.

Seismic sources generate acoustic waves by the sudden release of energy.

There are various types of sources and they differ in:

• the amount of energy released: this determines the specific depth of

penetration of the wave

• the frequencies generated: this determines the specific „vertical resolution‟, or

ability to identify closely spaced reflectors as two separate events.

There is usually a trade-off between the two depending on the objectives of the

survey.

Studies of deep crustal structures require low frequency signals capable of

penetrating over 10 km into the earth, whereas a shallow geological survey

requires a very high frequency signal which is allowed to die out after only a few

hundred meters.




Typical sources for land surveys

are truck-mounted vibrating

sources or small dynamite charge

sources detonated in a shallow

hole. The most common marine

sources are pneumatic sources

such as air guns and water guns

that expel air or water into the

surrounding water column to

create an acoustic pulse.

There are also electrical devices

such as sparkers, boomers and

pingers that convert electrical

energy into acoustic energy.

Typically the latter produce less

energy and have a higher

frequency signal than pneumatic

sources.




Seismic detectors are devices that register a mechanical input (seismic

pulse) and transform it into an electrical output which is amplified before

being recorded to tape. On land the receivers are called geophones and they

are arranged in a spread on the ground or in shallow boreholes. At sea the

receivers are called hydrophones, often clustered in arrays, and they are

either towed in the water behind the boat or laid out on the sea floor in the

case of OBC




The acquisition geometry, or the configuration of source(s) and receivers

depends on the objectives of the survey, characteristics of the subsurface

geology and logistics.

Seismic surveys can be acquired along straight lines, zig-zag lines, in a

square loop and even in a circular pattern. Over the last few years multi-

azimuth surveys have become increasingly popular. Seismic data are

acquired along different azimuths (Figure) to allow structures to be imaged at

different angles thus enhancing the imaging of complex geology, such as

radial fault patterns and areas affected by salt.




Principle of multi-azimuth surveying.


SEISMIC METHODS : Borehole Seismic Surveying


In vertical seismic profiling (VSP) the seismic source is placed at the surface

and the receiver array is lowered down a borehole. In the case of borehole

tomography both source and receiver array are lowered into (different)

boreholes and the source is fired at different depths (Figure). Typically the

seismic sources use higher frequencies than in surface seismic surveys.

Advantages of borehole seismic techniques include improved resolution and

the ability to predict or more accurately model the velocity variations between

wells. Furthermore, the effects of the near-surface weathered layer are

removed or suppressed.

The result is that small-scale features and subtle variations in reservoir

continuity can be imaged better than using conventional surface seismic data

which has proved very powerful in field development and well planning.

More recently it has also been used to help characterize tight gas sands and

coal bed methane seams where very small features can have a dramatic

impact on resource distribution and recovery.


SEISMIC METHODS (Borehole Seismic Surveying)


Principles of borehole seismic surveying.


SEISMIC DATA PROCESSING


INTRODUCTION

The three main steps in seismic data processing are deconvolution, stacking

and migration. Additional processes are required to prepare or enhance the

seismic data before or after each of the main steps.

There are typically hundreds of traces in a 2D survey and thousands in a 3D

survey. Once they have been sorted, static corrections must be applied to

compensate for variations in topography, for example when seismic data are

acquired in an area covered by sand dunes. „Statics‟ also correct for

variations in seismic velocity in the near-surface, for example when a seismic

survey is acquired in a swampy area.




DECONVOLUTION

After static correction the next stage in processing is deconvolution. In

essence this is an inverse filtering procedure which removes or suppresses

unwanted signals. It aims to collapse the wavelet and make it as sharp as

possible so that it resembles a spike (Figure). In effect deconvolution tries to

remove the effects of the earth‟s filter by reproducing the geological

boundaries as a reflectivity series.




VELOCITY ANALYSIS AND NMO CORRECTION

It is clear that seismic velocity plays an important role in seismic surveying

and processing. It is the one parameter that allows the seismic image to be

converted into a geological depth section. There are several types of seismic

velocity, such as average, root mean square (RMS) and interval velocity.

The first two are statistical parameters only, whereas the interval velocity is

geologically more meaningful. In the case of normal incidence and horizontal

layers, it is simply the ratio of the interval thickness to the interval transit time

as illustrated in Figure




VELOCITY ANALYSIS AND NMO CORRECTION

As mentioned previously, there is a difference in travel time between the zero

offset case and the non-zero offset case for each CMP – this is known as

NMO. Viewing the traces side by side (Figure a), it is clear that the NMO for

each non-zero offset trace needs to be removed before the traces can be

summed. The stacking velocity is the seismic velocity which results in the

best correction for NMO (Figure b).




STACKING

All the reflections from the various offsets associated with a CMP are

summed, or „stacked‟ to give one trace for each CMP; this leads to an

improvement in the „signal-to-noise ratio‟.

Signals from spurious noise tend to vary between the different traces and

will, therefore, get cancelled out or at least suppressed. True geological

signals from the different traces tend to be similar and are thus boosted

during the stacking process.


SEISMIC DATA PROCESSING : MIGRATION


Ideally, after stacking the seismic data are in the correct position and have

the correct amplitudes. However, steeply dipping horizons cause reflections

to be recorded at surface positions which are different to their actual

subsurface position as shown in Figure. This also happens when large and

sudden variations occur in seismic velocity



HORIZONTAL REFLECTOR: The incident wave coming from the source at

S1 hits a point at position a and depth z and is reflected to the receiver at R1.

In the case of horizontal reflectors the travel time of the incident wave is the

same as the travel time of the reflected wave. Point a at depth z is recorded

at position a‟ at the surface and associated with depth z‟; both the position

and the depth are correct: a = a‟ and z = z‟.

STEEPLY DIPPING REFLECTOR: In the case of steeply dipping reflectors

the travel time of the incident wave is different to the travel time of the

reflected wave. In the picture the travel time of the reflected wave is much

smaller than the travel time of the incident wave. This leads to point a being

recorded updip of its true position with a shift in surface position (a ≠ a‟) and

a shift in depth (z ≠ z‟); the same occurs at point b and so on. The true dip (ø

true) of the reflector is imaged incorrectly and the apparent dip (ø app) is

shallower.

REMEDY: Migration is the process of repositioning reflected signals to show

an event (geological boundary or other structure) at its true position in the

subsurface and at its correct depth.



TYPES OF MIGRATION: There are two main types of migration: pre-stack

and post-stack migration. The first involves migrating the seismic data prior

to the stacking Sequence, the second after stacking has occurred.

If the geological layers are almost flat and the seismic velocities are uniform,

a simple post-stack time migration will give a good result. If the seismic

velocities vary only a little or the dips are small then a pre-stack time

migration will give a good solution.

In areas of complex geological structures, for example sub-salt or sub-basalt,

neither technique will image the events below the salt or basalt correctly and

pre-stack depth migration (PSDM) will need to be applied. PSDM requires

the processor to draw up a model of the seismic velocities of the subsurface,

this in itself can be quite challenging. The input model allows the reflectors to

be restored to their true position in the subsurface and corrects apparent dips

to true dips.

Although PSDM is an important tool in the imaging of complex structures it is

an expensive and time-consuming process. PSDM is often only applied

when other methods have failed to give a working solution.



SEISMIC OUTPUT:

A 2D seismic survey consists of a network of lines, usually arranged in an

orthogonal grid at regular spacing, for example 500 m. The processed result

is a series of seismic sections in time or depth (Figure) that tie at the nodes

or intersections of the lines. A single 2D line typically contains several

hundred traces.

A 3D seismic survey is acquired in a series of parallel swathes each

containing a large number of inlines (sail lines) and crosslines (perpendicular

to the sail lines) typically with a spacing between 12.5 and 50 m. The

processed result is a 3D „volume‟ or cube of data (Figure ) that can be

viewed along all three axes (line, trace, time/depth). These days the volumes

can also be sliced along an „arbitrary line‟ such as along the axis of a

meandering channel. A 3D seismic volume typically contains thousands of

traces.



SEISMIC OUTPUT:



SEISMIC OUTPUT:



SEISMIC OUTPUT:



SEISMIC OUTPUT:



SEISMIC OUTPUT:



Exercise:

Interpret the Seismic profile (data) and mark all the structural features like folds (anticline, syncline), unconformity, prominent bedding plan



Exercise:

Interpret the Seismic profile (data) and mark all the structural features like folds (anticline, syncline), unconformity, prominent bedding plan



Drilling Engineering

INTRODUCTION

Drilling operations are carried out during all stages of the project life cycle

and in all types of environments. The main objectives are the acquisition of

information and the safeguarding of production. Expenditure for drilling

represents a large fraction of the total project‟s capital expenditure (CAPEX)

(typically 20–60%), therefore an understanding of the techniques, equipment

and cost of drilling is important.

An initial successful exploration well will establish the presence of a working

petroleum system. In the following months, the data gathered in the first well

will be evaluated and the results documented. The next step will be the

appraisal of the accumulation requiring more wells. If the project is

subsequently moved forward, development wells will have to be engineered.



WELL PLANNING

The drilling of a well involves a major investment, ranging from a few million

US$ for an onshore well to 100 million US$ plus for a deepwater exploration

well.

Well engineering is aimed at maximizing the value of this investment by

employing the most appropriate technology and business processes, to drill

a „fit for purpose‟ well, at the minimum cost, without compromising safety or

environmental standards. Successful drilling engineering requires the

integration of many disciplines and skills.

Successful drilling projects will require extensive planning. Usually, wells are

drilled with one, or a combination, of the following objectives:

• to gather information

• to produce hydrocarbons

• to inject gas or water to maintain reservoir pressure or sweep out oil

• to dispose of water, drill cuttings or CO2 (sequestration).



WELL PLANNING

To optimize the design of a well it is desirable to have as accurate a picture

as possible of the subsurface. Therefore, a number of disciplines will have to

provide information prior to the design of the well trajectory and before a

drilling rig and specific equipment can be selected.

The subsurface team will define optimum locations for the planned wells to

penetrate the reservoir and in consultation with the well engineer agree on

the desired trajectory through the objective sequence. In discussions with

production and well engineers maximum hole inclination and required

wellbore diameter will be determined.

Wellhead locations, well design and trajectory are aimed at minimizing the

combined costs of well construction and seabed/surface facilities, whilst

maximizing production.

During exploration drilling and the early stages of field development

considerable uncertainty in subsurface data will prevail.



WELL PLANNING

It is important that the uncertainties are clearly spelled out and preferably

quantified. Potential risks and problems expected or already encountered in

offset wells (earlier wells drilled in the area) should be incorporated into the

design of the planned well. This is often achieved by using a decision tree

approach in the well planning phase. The optimum well design balances risk,

uncertainty and cost with overall project value.

The basis for the well design is captured in a comprehensive document. This

is then „translated‟ into a drilling programme.

In summary, the well engineer will be able to design and cost the well in

detail using the information obtained from the petroleum engineers,

geoscientists and production engineers. In particular, he will plan the setting

depth and ratings for the various casing strings, cementing programme, mud

weights and mud types required during drilling, and select an appropriate rig

and related hardware, for example drill bits.



RIG TYPES AND RIG SELECTION

The type of rig which will be selected depends upon a number of

parameters, in particular:

• cost and availability

• water depth of location (offshore)

• mobility/transportability (onshore)

• depth of target zone and expected formation pressures

• prevailing weather/metocean conditions in the area of operation

• experience of the drilling crew (in particular the safety record!).

PRESENTLY the following types of rig can be contracted for offshore drilling:

• Swamp barges

• Drilling jackets

• Jack-up rigs

• Semi-submersibles

• Drill ships

• Tender-assisted drilling



RIG TYPES

SWAMP BARGES : operate in very

shallow water (less than 20 ft). They can

be towed onto location and are then

ballasted so that they „sit on bottom‟. The

drilling unit is mounted onto the barge.

This type of unit is used in the swamp

areas of, for example Nigeria, Venezuela

and US Gulf Coast.

Source: http://www.deepwater.com/fw/main/Hibiscus-25C16.html?LayoutID=17



RIG TYPES

DRILLING JACKETS: are small steel

platform structures which are used in areas

of shallow and calm water. A number of

wells may be drilled from one jacket. If a

jacket is too small to accommodate a

drilling operation, a jack-up rig is usually

cantilevered over the jacket and the

operation carried out from there.

Once a viable development has been

proven, it is extremely cost-effective to build

and operate jackets in a shallow sea

environment. In particular, they allow a

flexible and step-wise progression of field

development activities.

Phased developments using jackets are

common in coastal waters, for example

South China Sea and the shelf GoM.



RIG TYPES

JACK-UP RIGS: are either towed to the

drilling location (or alongside a jacket) or

are equipped with a propulsion system.

The three or four legs of the rig are

lowered onto the seabed. After some

penetration the rig will lift itself to a

determined operating height above the

sea level.

If soft sediment is suspected at seabed,

large mud mats will be placed on the

seabed to allow a better distribution of

weight. All drilling and supporting

equipment are integrated into the overall

structure. Jack-up rigs are operational in

water depths up to about 450 ft and as

shallow as 15 ft. Globally, they are the

most common rig type, used for a wide

range of environments and all types of

wells.



RIG TYPES

SEMI-SUBMERSIBLES : are used for

exploration and appraisal in water depths too

great for a jack-up. A semi-submersible rig is

a movable offshore vessel consisting of a

large deck area built on columns of steel.

Attached to these heavy-duty columns are at

least two barge-shaped hulls called

pontoons.

Before operation commences on a specified

location, these pontoons are partially filled

with water and submersed in approximately

50 ft of water to give stability.

A combination of several anchors and

dynamic positioning (DP) equipment assists

in maintaining position. Relocation of the

semi-submersible vessel is made possible by

the utilization of tugboats and/or propulsion

machinery. E.g Deep water horizon



RIG TYPES

DRILLING SHIPS : are used for deep

and very deep water work. They can be

less stable in rough seas than semi-

submersibles. However, modern high-

specification drill ships such as

Discoverer Enterprise can remain

stable, and on target during 100 knot

winds using powerful thrusters

controlled by a DP system.

The thrusters counter the forces of

currents, wind and waves to keep the

vessel exactly on target, averaging less

than 2m off her mark, without an

anchor. Heavy-duty drill ships are

capable of operating in water depths up

to 3000m



RIG TYPES

DRILLING SHIPS :



RIG TYPES

TENDER-ASSISTED DRILLING :In some cases, oil and gas fields are

developed from a number of platforms. Some platforms will accommodate

production and processing facilities as well as living quarters. Alternatively,

these functions may be performed on separate platforms, typically in shallow

and calm water. On all offshore structures, however, the installation of

additional weight or space is costly. Drilling is only carried out during short

periods of time if compared to the overall field life span and it is desirable to

have a rig installed only when needed. This is the concept of tender-assisted

drilling operations.

In tender-assisted drilling, a derrick is assembled from a number of

segments transported to the platform by a barge. All the supporting functions

such as storage, mud tanks and living quarters are located on the tender,

which is a specially built spacious barge anchored alongside (Figure).

It is thus possible to service a whole field or even several fields using only

one or two tender-assisted derrick sets. In rough weather, barge type tenders

quickly become inoperable and unsafe since the platform is fixed whereas

the barge moves up and down with the waves.



RIG TYPES

TENDER-ASSISTED DRILLING :


Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS

ROTARY RIG: Whether onshore or offshore drilling is carried out, the basic

drilling system employed in both the cases will be the rotary rig (Figure ). The

parts of such a unit and the three basic functions carried out during rotary

drilling operations are as follows:

• Torque is transmitted from a power source at the surface through a drill

string to the drill bit.

• A drilling fluid is pumped from a storage unit down the drill string and up

through the annulus. This fluid will bring the cuttings created by the bit

action to the surface, hence clean the hole, cool the bit and lubricate the

drill string

• The subsurface pressures above and within the hydrocarbon-bearing

strata are controlled by the weight of the drilling fluid and by large seal

assemblies at the surface (BOPs).

However, in practice, onshore and offshore drilling units are often quite

different in terms of technology and degree of automatisation. This is largely

driven by rig availability, costs and safety considerations



DRILLING SYSTEMS AND EQUIPMENTS

ROTARY RIG:

The basic rotary rig



DRILLING SYSTEMS AND EQUIPMENTS DETAILS OF ROTARY RIG:



DRILLING SYSTEMS AND EQUIPMENTS

ROTARY RIG:

The basic rotary rig

http://www.globalpetrotech.com/rig-fleet/g-2.htm



ELEMENTS OF THE DRILLING SYSTEMS

We will now consider the rotary rig in operation, visiting all elements of the

system.

DRILL BITS

The most frequently used bit types are the roller cone or rock bit and the

polycrystalline diamond compact bit or PDC bit

Roller

cone bit

(left) and

PDC bit.



DRILL BITS

On a rock bit, the three cones are rotated and the attached teeth break or

crush the rock underneath into small chips (cuttings). The cutting action is

supported by powerful jets of drilling fluid which are discharged under high

pressure through nozzles located at the side of the bit.

After some hours of drilling (between 5 and 25 h depending on the formation

and bit type), the teeth will become dull and the bearings wear out. Later on

we will see how a new bit can be fitted to the drill string.

The location of the drilling fluid outlets is critical in the design of a bit that will

allow cuttings to be carried out from under the cutting surfaces.

The selection of bit type depends on the composition and hardness of the

formation to be drilled and the planned drilling parameters.



TYPES OF DRILL BITS

As mentioned THE DRILL BIT is the most critical component of the drill

stem. Bit technology has undergone more technological advancement than

any other element of the drill stem

Types of Bit include:

• Drag bits

• Rolling Cutter bits

• Diamond bits

• Special Purpose bits

DRAG BIT: The oldest of the rotary bits, the drag bit utilizes flat cutter blades

to scrap away the rock. These bits, though relatively simple and inexpensive,

and still used for drilling soft, shallow formations, have been largely replaced

by other types of bits.



TYPES OF DRILL BITS

ROLLING CUTTER BIT: The rolling cutter bit, which is also called a roller

cone bit, three-cone bit, or rock bit, is the most commonly used today and

comes in a variety of designs.

The cones of this bit are designed to individually roll as the bits turn on the

bottom of the hole. While the cones distribute the weight of the drill collars,

their teeth bite into the rock, gouging and scraping away the cuttings, which

are then carried to the surface by the circulating mud.

According to the type and configuration of their teeth and types of bearing

used they are classified into TWO types:

• Steel tooth or Milled tooth

• Insert bit

Steel tooth or Milled tooth bits : have long widely spaced teeth for soft

formation models and shorter, closely teeth for harder formation types.



TYPES OF DRILL BITS

Contd ……ROLLING CUTTER BIT

Insert bits : The teeth of insert bits also vary in length depending on use, but

are made of extremely hard tungsten carbide, and inserted into the steel

cones.



TYPES OF DRILL BITS

DIAMOND BIT : Diamond bits operate similarly to drag bits, in that they have

no moving parts such as cones or bearings, but rely on industrial diamonds

to crack and abrade the formation.

The diamonds are set in a high strength steel matrix, with a pattern and

spacing optimally designed for the drilling conditions expected.

A relatively new type of diamond bit the polycrystalline diamond compact or

PDC bit. Here a layer of polycrystalline diamond is bonded to a layer of

Tungsten carbide to create a cutting surface with both high-wear and impact-

resistant properties.

The PDC surface is self-sharpening as it wears away, continually presenting

a fresh edge.

This type of bit is popular because of its much better rate of penetration

(ROP), longer lifetime and suitability for drilling with high revolutions per

minute (rpm), which makes it the preferred choice for turbine drilling.



TYPES OF DRILL BITS

DIAMOND BIT :



TYPES OF DRILL BITS

SPECIAL BIT : Other bit-type tools are designed for special purposes,

notably hold openers and under reamers. These tools are run above a bit to

maintain or enlarge the hole size.

Under-reamers have collapsible arms that are held open by the pressure of

mud circulating through the drill stem. These arms enable them to enlarge

the bottom of the hole and then be retrieved through the smaller diameter

upper portion of the hole.



DRILL STRING

Between the bit and the surface, where the

torque is generated, we find the drill string

(Figure).

Whilst primarily being a means for power

transmission, the DRILL STRING string

fulfils several other functions, and if we

move up from the bit we can see what

those are.



SECTIONS OF THE DRILL STRING

The DRILL COLLARS (DCs) are thick-

walled, heavy lengths of pipe. They keep the

drill string in tension (avoiding buckling) and

provide weight onto the bit.

STABILIZERS are added to the drill string at

intervals to hold, increase or decrease the

hole angle.

The BOTTOM HOLE ASSEMBLY (BHA)

described so far is suspended from the

DRILL PIPE, made up of 30 ft long sections

of steel pipe (joints) screwed together.




The drill string is connected to the kelly

SAVER SUB. A saver sub is basically a short

piece of connecting pipe with threads on

both ends. In cases where connections have

to be made up and broken frequently, the

sub „saves‟ the threads of the more

expensive equipment.

The KELLY is a six-sided piece of pipe that

fits tightly into the kelly bushing which is

fitted into the rotary table. By turning the

latter, torque is transmitted from the kelly

down the hole to the bit. It may take a

number of turns of the rotary table to initially

turn the bit thousands of meters down the

hole.




The kelly is hung from the travelling block.

Since the latter does not rotate, a bearing is

required between the block and the kelly.

This bearing is called a SWIVEL.

Turning the drill string in a deep reservoir

would be the dimensional equivalent to

transmitting torque through an everyday

drinking straw dangling from the edge of a

75-storey high-rise building! As a result, all

components of the drill string are made of

high-quality steels.



DRILLING OPERATION

The four basic drilling functions are:

1. Hoisting

2. Rotating

3. Circulating

4. Controlling

1. HOISTING (Derrick, Drawworks, Blocks and Hooks)

• The DERRICK, or mast, and the substructure it sits upon, support the weight

of the drill stem and allow vertical movement of the suspended drillpipe.

• The SUBSTRUCTURE also supports the rig floor equipment and provides

workspace for its operation.

• The DRILLSTRING is removed from time to time to allow fitting (connecting)

or disconnecting of DRILLPIPE sections. The length of the DRILL PIPE

section that can be disconnected and stacked to one side of the DERRICK is

determined by the height of the DERRICK.



DRILLING SYSTEMS AND EQUIPMENTS DETAILS OF ROTARY RIG:



DRILLING SYSTEMS AND EQUIPMENTS :



contd…..HOISTING (Derrick, Drawworks, Blocks and Hooks)

• A joint of DRILLPIPE is usually about 30 ft (9.1m) long, and a DERRICK that

will allow the pulling and stacking of pipe , in three-joints section (90ft or

27.4m), is about 140 ft (42.7m) high.

• The DRAWWORKS is a spool or drum upon which the heavy steel cable

(DRILLING LINE) is wrapped.

• From the DRAWWORKS, the line is threaded through the CROWN BLOCK

at the top of the DERRICK and then through the TRAVELLING BLOCK,

which hangs suspended from the crown block.

• By reeling in or letting out drill line from the drawworks drum, the travelling

block and the suspended drillstem can be raised or lowered.

• Hydraulic brakes are applied to safely control the movement of the heavy

TRAVELLING block and mechanical brakes are applied to bring it to a

complete stop.



contd…..HOISTING (Derrick, Drawworks, Blocks and Hooks)

• The DRAWWORK also features an auxiliary axle, or „CAT-SHAFT‟, with

rotating spools on each end called „CAT-HEADS‟. One Spinning CAT-HEAD

is used to provide power to tighten the DRILLPIPE JOINTS via a cable from

the cathead to the rotary tongs. The other CAT-HEAD is used for “Breaking

out” or loosening the pipe joints when the pipe is being withdrawn in

sections.

• The HOOK it is attached to the travelling block and is used to pick up the

DRILLSTEM via the SWIVEL and KELLY when drilling, or with elevators

when tripping into or out of the hole.



2. ROTATING (Swivel, Kelly, Rotary Table)

• The SWIVEL allows the drillstem to rotate while supporting the weight of the

drillstring in the hole and providing pressure-tight connection for the

circulation of the drilling fluid.

• The drilling fluid enters the SWIVEL by the way of the „GOOSENECK‟, a

curved pipe connected to a high-pressure hose.

• Connected to the SWIVEL is the KELLY, a three-, four – or six – sided 40 ft

(12.2m) length hollow steel, which is used to transmit the rotary movement of

the ROTARY TABLE to the drillstring.

• The term DRILLSTEM refers to the KELLY and attached DRILLPIPE, DRILL

COLLARS, and BIT. The DRILLSTRING refers to the DRILLPIPE and the

DRILLCOLLARS.

• The flat-sided KELLY fits through a corresponding opening in the KELLY

DRIVE BUSHING, which in turn fits into the MASTER BUSHING SET into

the ROTARY TABLE.



contd…..ROTATING (Swivel, Kelly, Rotary Table)

• The ROTARY TABLE is turned by the RIG‟s POWER SOURCE, the table

turns bushing and the KELLY BUSHING turns the KELLY, the KELLY in turn

turns the DRILLPIPE, and so on …. Down to the BIT.



3. CIRCULATING (Pumps, Standpipe, Return line, Solids control equipment)

• Circulation of a DRILLING FLUID to carry cuttings up the hole and cool the

bit is an important function of any rotary drilling rig.

• The heart of the CIRCULATION SYSTEM is the MUD PUMP (or Pumps),

which is (are) powered by the rig‟s prime power source, as are the rotary

table and drawworks.

• MUD PUMPS are positive displacement pumps that push a volume of

DRILLING MUD through the system with each stroke of its pistons. The

output of a mud pump can be determined from the piston and cylinder sizes,

the number of strokes per minute, and the type of piston arrangement.

• The MUDPUMPS pump the DRILLING FLUID from the MUD PITS or

TANKS up the STANDPIPE to a point on the DERRICK where the ROTARY

HOSE connects the STANDPIPE to the SWIVEL.

• The flexible, high-pressure HOSE allows the travelling block to move up and

down in the derrick while maintaining a pressure-tight system.







• The circulating drilling mud moves through the swivel, kelly, drillpipe, and

drillcollars, exiting through the bit at the bottom of the hole (or casing),

carrying the drilled rock pieces in suspension to the surface.

• At the surface , the mud leaves the hole through the RETURN LINE and falls

over a VIBRATING SCREEN called the SHALE SHAKER. This device

screens out the CUTTINGS and dumps some of them into a SAMPLE TRAP

and the rest into the RESERVE PIT.

• Once cleaned of large cuttings, the mud is returned to the MUD TANK, from

which it can be once again pumped down the hole.

• FINE PARTICLES are removed by centrifugal force by flowing the mud

through DESANDERS, DESILTERS or a CENTRIFUGE. A DEGASSER is

used to remove small amounts of gas picked up in the mud from the

subsurface formations.



4. CONTROLLING (Blowout preventers, Choke system)

• As mentioned earlier controlling the SUBSURFACE PRESSURES

encountered during drilling is an important part of the operation.

• One of the purpose of the DRILLING MUD is to provide a hydrostatic head of

fluid to counter balance the pore pressure of fluids in permeable formations.

• In spite of this, however, for variety of reasons, the well may „KICK‟; that is

formation fluids may flow into the wellbore, upsetting the balance of the

system, thus pushing mud out of the hole and exposing the upper part of the

hole and equipment to the higher pressure of the deep subsurface.

• If left uncontrolled, this can lead to a „BLOWOUT‟, with the formation fluids

forcefully erupting from the well, often igniting and endangering the crew, the

rig and the environment. For such extreme emergencies BLOWOUT

PREVENTERS or BOPs are installed.

• BOPs are a series of powerful sealing elements designed to close off the

annular space between the pipe and hole where the mud is normally

returning to the surface.




• The resulting choke from the BOPs allows the drilling crew to control the

pressure that reaches the surface and to follow the necessary steps for

„KILLING‟ the well and restoring a balanced system.

• Figure shows a typical

set of BLOWOUT

PREVENTERS,

including the annular

preventer, which has a

rubber sealing element

that is hydraulically

squeezed to conform

tightly to the drillpipe in

the hole.







• Also shown in the figure are RAM TYPE preventers, which grip the pipe with

rubber lined steel rams (pipe rams), or can shear the pipe in two with a

powerful hydraulic force to SEAL off the hole (Blind Rams or shear Rams).

• BOPs are opened and closed by hydraulic fluid stored under 1500 to 3000

psi (10,000 to 20,000 kPa) in an ACCUMULATOR.

• The CHOKE MANIFOLD houses the series of positive and/or adjustable

chokes that are usually controlled from a remote panel on the rig floor.

• Also, often a rig that is encountering a frequent gas kicks will also have a

mud-gas separator, which saves the drilling mud that is expelled along with a

large flow of formation gas, and separates from the gas for safe flaring at

some distance from the rig.



ENGINES

• Hoisting, Rotating and Circulating equipments is supplied with power from a

prime power source, usually diesel engines.

• Engine capacity may range from 500 to 6000 HP, and power may be

transmitted to the rig either mechanically or electrically.

• Mechanical drive rigs have a combination of Belts, Sprockets, Clutches, and

Pulleys, which transfer power from the diesel engines to the Drawworks,

pumps, and rotary table.

• The more modern diesel-electric rigs use their engines to drive generators

that produce electricity. This electricity in turn is sent through cables to a

switch and control house from which point it is relayed to power the

ELECTRIC MOTORS of each end user.


Drilling Engineering DRILLING FLUIDS

Drilling fluid technology has become increasingly sophisticated in the last two

decade. Whatever type of bit is used, all bits perform their job with the help of

the drilling fluid, which cools the cutting surfaces and circulates rock chips

from underneath.

Most wells are drilled with clear water for faster penetration rates, until a dept

is reached where hole conditions dictate a need for a fluid with special

properties.

The addition of clay and chemicals to the water permits the adjustment of

viscosity and, density, and other properties to improve hole cleaning and

prevent sloughing shale, lost circulation, formation flow and formation

damage.

In most cases, the circulating fluid utilized in a rotary drilling operation is a

water-based mixture of clays, suspended solids, and chemical additives. In

some cases oil is added to the fluid or the entire system is converted into a

oil based mixture.



A small percentage of wells are drilled with air or foam as the circulating fluid

for part of the drilling operation.

In any case the properties of the fluid must be such that it performs the

following functions:

• Control subsurface pressure

• Remove cutting from the hole

• Cool and lubricate the drill stem

• Aim formation evaluation and productivity

Control subsurface pressure: Subsurface pressure is controlled by adjusting

the density of the drilling fluid so that a balance is maintained between the

hydrostatic pressure imposed by the column of drilling fluid and the pore

pressure of the formation being drilled.



Control subsurface pressure: Subsurface pressure is controlled by adjusting

the density of the drilling fluid so that a balance is maintained between the

hydrostatic pressure imposed by the column of drilling fluid and the pore

pressure of the formation being drilled (FIGURE).

While the drilling fluid density allows it to

control pressures, other properties of

drilling mud allow it to form a protective

layer cake of clay particles on the wall of

the hole, preventing excess fluid loss

(filtrate) into permeable formations and

preventing sloughing or caving-in, of the

sides of the hole.

Mud density is measured by means of a

mud balance; a simple scale commonly

graduated in pounds per gallon (ppg) or

pounds per cubic feet (ppcf) increments.



Remove Cuttings from the Hole: Viscosity if the drilling fluid property which is

important when removing cuttings from the hole. Mud must have proper

viscosity to the lift the rock cuttings (chips) out from underneath the bit and

carry them up the annulus to the surface (FIGURE).

In addition the drilling fluid must exhibit sufficient gel strength to hold the

cuttings in suspension when circulation stops, and prevent from settling to

the bottom of the hole, collecting around the bit, making the pipe stick to the

hole.

The mud must also liquify, however, upon resumption of pumping, and must

release the cuttings easily at the surface.

Viscosity is usually determined with a Marsh funnel, which measures the

time it takes for a certain volume of mud to flow through a orifice. Gel

strength is a measured with a viscometer, which shears mud between metal

cylindrical surfaces.

The velocity at which the fluid is circulated is also important and is usually

100-200 ft/ min.



Remove Cuttings from the Hole: (FIGURE).



Cool and Lubricate the Drill stem: This function is performed primarily at the

bottom of the drillstem, where the bit is forced against the bottom of the hole

and rotated.

Force applied to the bit ranges from 10,000 to 100,000 lb (45 to 445 kN),

and rotating speed may range from 50 to 200 rpm. This combination of

weight and speed creates frictional heat within the bit that must be removed

by circulating fluid to prevent rapid wear.

Lubricants added the mud can help reduce the friction at the bit, between

the drill string and hole, and within the drillstring itself, where the frictional

pressure losses can require high pressures.

Air or foam drilling fluids are particularly efficient at performing this cooling

function.



Aid Formation Evaluation and Productivity: Drilling fluid properties should be

monitored to ensure that the interaction between mud and formation doesnot

prevent the formation from being easily evaluated or produced.

For e.g. Oil based muds make it difficult to evaluate potential of producing

horizons. In some cases the formation can be irreparably damaged by the

invasion of mud and mud filtrate.

Oil based mud in gas zones and fresh water-muds in zones containing water

sensitive clays, are examples of permeability damaging situations.

Density, viscosity, gel strength, lubricity, filter cake formation – all these

properties are important to the proper functioning of the drilling fluid. A wide

variety of chemical additives are available to help control these properties.

Some common examples are:

• Bentonite: clay added to fresh water to improve properties of a natural

mud resulting from native clays.

• Attapulgite: clay added to saltwater-based muds.

• Barite: used for giving added weight



Aid Formation Evaluation and Productivity….contd

• Chrome lignosulfates: mordern chemical thinners used to decrease

viscosity.

• Polymers: long chain molecules that act to increase viscosity

• Lost circulation materials: any of a variety of items that act to plug

fractures, including wall nut hulls, shredded cellophane, mica flakes and

vegetable fibres.


Drilling Engineering DRILLING PROGRESS

With the rig in the position and the conductor pipe in place, drilling can

begun. The largest bit is first to be run. The drilling program is designed so

that the initial bit will drill a hole large enough for casing that can

accommodate successively smaller bits and casing strings.

The number of casing strings necessary to reach the target depth will

determine the initial hole size. Attached to the drill bit are the first drill collars

and stabilizers, followed with joints of drill pipe.

Weight is applied to the bit by allowing the BHA to rest on the bottom

somewhat, and the rotary table begins to turn the Kelly. As the bit chews

away at the bottom of the hole, the mud pumps circulate the cuttings up the

annulus.

The Kelly slowly moves downward until the top of the kelly and the attached

swivel are near the drilling floor (after about 30 – 40 ft [9 to 12 m] has been

drilled).



DRILLING PROGRESS … contd

From now on, each time a kelly length has been drilled down, another joint of

drill pipe is added to the drill stem. The new joint of pipe will have been

hoisted into the “MOUSEHOLE” in preparation, waiting to be connected

(FIGURE).










The kelly and attached drillstring are lifted up in the derrick until the kelly

bushing has cleared the drill floor and the tool joint between kelly and

drillpipe is visible.

SLIPS (flexible, tooth wedges) are set in the rotary table to grip the drillstring

and allow it to hand motionless while the crew “breaks out” (UNSCREWS)

the kelly with the rotary tongs.

The ROTARY TONGS are nothing more than oversized pipe wrenches hung

from the derrick, over the drill floor, and pulled by a cable from the drawworks

(FIGURE).

So now the kelly is hanging freely fro the hook, and the crew can swing it

over to the pipe joint that is waiting, “BOX END UP” in the mousehole

(FIGURE). The Kelly is screwed into the new joint and both are lifted up into

the derrick and swung over the drillstring held by the slips.

into the box end of the waiting joint. The pipe is quickly screwed together and

tightened with the tongs







The driller lowers the assembly and carefully “STABS” the pin of the new

joint into the box end of the waiting joint. The pipe is then quickly screwed

together and tightened with the tongs before the slips are removed.

The entire assembly as then lowered back into the hole to drill another joint

length. After the kelly has been “DRILLED DOWN” 30-40 ft (9-12 m), the

connection process must be repeated, and is repeated joint after joint, as the

hole is deepened.

POOH (PULLING OUT OF HOLE) or Trip out

Sometimes it becomes necessary to pull out (“trip out”) of the hole or POOH;

perhaps to change the bit or to run casing. When making such a “trip”,

drillpipe is handled in stands, usually two or three joints each (about 60 or 90

ft, or 18 to 27 m).

Pipe is removed from the hole and placed on the floor. First the kelly, rotary

bushing, and swivel are towed in the “RATHOLE” (FIGURE)




POOH (PULLING OUT OF HOLE) or Trip out….contd









With to the Kelly and other equipments out of the way, the elevators, which

hand from the hook, can be latched around the pipe just below the tool joint

box and used to lift the pipe out of the hole.

When a stand of several joints has been pulled up into the derrick, the slips

are used once again to hang the drillstring in the rotary table while the

bottom tool joint is “broken” with the tongs and unscrewed with a spinning

wrench (FIGURE).

The stand of pipe is then swung to one side of the drill floor, where it is set

down and secured at the top by the derrickman. Free of their load, the hook

and elevators are lowered once again to grip another stand of pipe and

repeat the process until all the drillstem is racked in the derrick.

The bit is removed from the final stand of drill collars with a “bit breaker”, and

the rotary table is carefully covered to prevent any loose items from falling

into the hole. “TRIPPING IN” the hole is the reverse procedure of POOH.




DIRECTIONAL DRILLING

Because offshore operations are so expensive, a major means of cutting

costs is to drill several wells from a single platform – sometimes up to 20 or

more.

Obviously, since the well‟s surface locations are about the same, their

bottomhole locations will need to be widely spaced in order to effectively

drain the reservoirs they penetrate. This requires that the wells be

directionally drilled.




Although some situations require „directional drilling‟ approach on land

(FIGURE), it is most common in offshore regions.




Directionally drilled wells will usually be drilled according to one of three

basic hole patterns (FIGURE).




After making an initial deflection from vertical, the well may be drilled to the

target, or deflected once more to allow the bottom of the hole to be drilled

vertically (“double dogleg”).

The deviation begins when the hole is deflected using one of several

techniques:

• Downhole hydraulic motors with a “bent sub”

• Jet bits

• Whipstock

WITH DOWNHOLE MOTORS: Downhole motors are drilling tools that rely

on a turbine powered by drilling mud to turn the bit. The drilling system is not

rotated; there fore a rotary steerable system usually with a BENT SUB can

be used to point the bit toward the side of the hole (FIGURE).

With the tool positioned on bottom, the mud is circulated to operate the motor

and drill the hole at an angle for a short distance. Once the angle is formed, a

conventional drillstem can be used to continue the hole.




DOWNHOLE MOTORS….contd




WITH JET BITS: Jet bits are conventional tricone bits with one of their three

nozzles opened up and the other two openings closed off or reduced in size

(FIGURE).

In soft formations, the bit can be oriented at the bottom of the hole, and

drilling mud can be circulated at high velocity to wash out the side of the hole

(FIGURE). This washed out section is a path of least resistance, which the

bit will follow.




WITH JET BITS …. contd




WITH WHIPSTOCKS: Whipstocks are long, inverted, concave steel wedges

(FIGURE) with heavy steel collars through which the drillstem fits. The tools

deflect the rotating drillstem to the side of the hole and is then removed.




TRACKING THE TRAJECTORY: Of course , it is necessary, in a

directionally drilled hole, to be able to keep track of the deviated borehole

and ascertain exactly how far it has inclined from vertical and in what

direction.

Inclination and direction is usually obtained with a magnetic survey deviced.

When run inside the drillpipe and positioned inside a special non-magnetic

drill collars, this wireline tool records a compass reading on film. Upon

retrieval the film can be quickly developed and interpreted. In casedholes,

where magnetic interference is inescapable, a similar system is employed

using a gyroscope.

In situations where extremely precise and continuous drilling hole location

data is required, measurement while drilling, or MWD, tools may be used.

The MWD tools used a downhole mud motor to power instrumentation that

records hole data and transmits it to the surface as pulses in the drilling fluid.

A surface readout gives the position of the bit while it is drilling.




MUD Turbines and mud motors are also used for directional drilling.

Rotational movement of the drill string is restricted to the motor or turbine

section, whilst the rest of the drill string moves by „sliding‟ or being rotated at

a lower speed to ensure hole cleaning.

In the example of the turbine shown in (FIGURE), the mud is pumped

between the rotor and the stator section, inducing a rotational movement

which is transmitted onto the drill bit.

Nowadays, Motors and turbines are being replaced by the rotary steerable

system for cost and operational reasons. Their use is increasingly limited to

such applications as kicking off a sidetrack or where a sharp change in angle

is required in a short-radius horizontal well.




TRACKING THE TRAJECTORY …. Contd

Mud turbine





When a well is directionally drilled, the hole is maintained on course by

varying the type and position of the components in the bottomhole assembly,

by variation of weight-on-bit, and by adjustment of rotary speed and rate of

circulation.

When the hole is completed, a compilation of the survey data gives a plot of

the wellbore‟s path in both the vertical and horizontal planes (FIGURE).








CASING AND CEMENTATION

Imagine that a reservoir exists at a depth of 2500 m. We could attempt to

drill one straight hole all the way down to that depth.

That attempt would end either with the hole collapsing around the drill bit,

with the loss of drilling fluid into formations with low pressure or in the worst

case with the uncontrolled flow of gas or oil from the reservoir into

unprotected shallow formations or to the surface (blowout).

Hence, from time to time, the borehole needs to be stabilized and the drilling

progress safeguarded. And thus Casing is used.




When the surface hole has been drilled out of the conductor, as deep as

5000 ft (1524m) in some cases, the surface casing must be set before drilling

can continue further, This casing is set for several reasons:

• To protect shallow freshwater aquifers from contaminations

• To support the unconsolidated, low-pressure formations nearer the

surface and prevent the loss of drilling mud as it is weighted up to permit

deeper drilling

• To provide a base for well control equipment

After the pipe is tripped out (POOH), the casing crew moves in and runs the

casing in much the same manner as the drillpipe is run into the hole. Special

casing elevators, slips and tongs are required, however, to handle the large-

diameter pipe.




The casing design will usually start with a 23 in. conductor, then 18 5/8 in.

surface casing, 13 3/8 in. intermediate casing above reservoir, 9 5/8 in.

production casing across reservoir section and possibly 7 in. production

„liner‟ over a deeper reservoir section (FIGURE). A liner is a casing string

which is clamped with a packer into the bottom part of the previous casing; it

does not extend all the way to the surface, and thus saves cost.




Several items that are incorporated into

the casing string are described as

follows :

• GUIDE SHOE: A guide show

(FIGURE) is attached to the bottom of

the first joint casing lowered into the

hole. Its rounded nose facilitates the

movement of the casing down the

hole.




• FLOAT COLLAR: This component

is (FIGURE) placed several casing

lengths above the guide shoe, and

contains a one way valve. This

backpressure valve enables the

casing to “float” down the hole by

preventing the entry of drilling fluid

into the casing. The valve also

prevents a blowout through the

casing, should a kick occur during

the cementation operation, and

prevents backflow of cement after

pumping.




• CENTRALIZERS AND SCRATCHERS:

The first of these components hold the

casing away from the wall of the hole;

the second abrades the mudcake when

the casing string is reciprocated (moved

back and forth in the hole). This

procedure ensures a uniform distribution

of cement around the pipe, and good

bonding among pipe, cement, and the

formation (FIGURE).




Casing joints are available in different grades, depending on the expected

loads to which the string will be exposed during running, and the lifetime of

the well. The main criteria for casing selection are :

• Collapse load: originates from the hydrostatic pressure of drilling fluid,

cement slurry outside the casing and later on by „moving formations‟, for

example salt.

• Burst load: this is the internal pressure the casing will be exposed to during

operations.

• Tension load: caused by the string weight during running in; it will be

highest at the top joints.

• Corrosion service: carbon dioxide (CO2) or hydrogen sulphide (H2S) in

formation fluids will cause rapid corrosion of standard carbon steel and

therefore special steel may be required.

• Buckling resistance: the load exerted on the casing if under compression.




The CEMENTING procedure can vary in its

complexity, depending on the depth of the hole,

the number of stages required to fill the annular

space between casing and hole, and the

possible need for remedial cementing if the

first job is insufficient. The procedure for

conventional single-stage cementing is

illustrated in FIGURE.

PROCESS

• With the casing near the bottom, several

barrels of water “SPACERS” is pumped into

the casing, followed by a RUBBER PLUG that‟

seals against the inside wall of the casing as it

is pumped down the hole.




PROCESS …contd

• The plug serves to isolate the cement slurry, which

has been mixed at the surface and pumped

immediately behind the plug.

• When the amount of cement calculated to be

required to fill the space between the casing and

the hole has been pumped, another plug is

inserted into the casing.

• Drilling mud is then pumped behind the second

plug to push the progression of water, plug,

cement, and plug, down the casing.

• When the first PLUG reaches the FLOAT COLLAR,

a diaphragm in its core breaks under pressure, and

the cement slurry moves through the FLOAT

COLLAR VALVE, around the shoe and up the

annular space between the hole and the casing.




PROCESS…contd

• With the casing near the bottom, several

barrels of water “SPACERS” is pumped into

the casing, followed by a RUBBER PLUG that‟

seals against the inside wall of the casing as it

is pumped down the hole.

• When the second PLUG reaches the float

collar, all the cement has been displaced

around the casing, leaving only a small amount

inside the casing between float collars and

GUIDE SHOE. The second PLUG will not

rupture, and the increase in pump pressure at

the surface indicates that the job is almost

complete.




PROCESS…contd

• The volume of cement pumped must be

carefully calculated to ensure that it is sufficient

to fill the annulus between casing and hole,

• When the cement is “SET” sufficiently, the

drillpipe can be run back into the hole (with the

next SMALLER BIT , of course) and the entire

assembly of plugs, float collars, cement and

guide shoe can be drilled through as the hole

is deepened (These components are

constructed of materials that allow them to be

easily drilled through).

• With casing securely cemented in the hole, the

hole can safely deepened without fear of losing

circulation into the shallow, low pressure

formations.




PROCESS…contd

• As drilling continues, successive casing strings

will be run and cemented concentrically to

isolate and protect the intervals of openhole.

• After the hole is deepened from the surface

casing shoe, an intermediate casing string may

be set, possibly followed by a casing liner.

• A CASING LINER is a string of casing, set from

inside the intermediate casing extending

downward into the openhole, but not

necessarily “tied back” to the surface.

• This saves the cost of the entire hole length,

when safety concerns do not require it.




PROCESS…contd

• Finally, production casing is run to bottom

when total depth of the well has been reached.

This string protects the producing formation

and allows for the tubing to be easily installed.

• On most wells, sufficient depth is drilled to

ensure an adequate “SUMP” or “RATHOLE”

below the producing interval – the space in

which junk and debris may accumulate during

the completion procedure.



Drilling Engineering “DRILLING AHEAD”

• When not making a connection or tripping, the

driller is doing what we would expect –

“DRILLING AHEAD” ! Standing on the CONTROL

CONSOLE on the drilling floor, the driller monitors

and adjusts several important drilling parameters.

• WEIGHT ON BIT (WOB) is displayed on the

weight indicator and is adjusted by lowering and

raising the drillstem to allow more or less of its

weight to rest on the bit.

• The driller also monitors rotary speed to make

sure that the combination of rpm and WOB is

correct for efficient drilling.

• A MUD LEVEL RECORDER, TORQUE

INDICATOR, and pump pressure gauge allow the

driller to be quickly informed of any anomalous

situation that could indicate a potential problem.


Drilling Engineering “DRILLING AHEAD”

• An important device, often located in drilller‟s

“DOGHOUSE”, is the DRILLING RATE

RECORDER, which keeps a log of depth drilled

versus time. Both Geologists and Engineers use

this device to keep track of drilling depth versus

time.



Formation Evaluation

As the drilling target is approached, preparations for the evaluation of the

potentially productive formation will begin. Presently many methods are

available for evaluating the formation as described in the table below:


MUD LOGGING

• Mud Logging is an important procedure whereby samples of the drilling

cuttings are routinely collected and analyzed. The properties of the mud are

also monitored to determine if oil or gas formations have been penetrated.

• Based on cuttings, a mud logger prepares a lithological log of the hole

showing the types of rock and depth at which it was drilled. This information

is extremely helpful to the geologists and drilling engineers in anticipating the

conditions ahead of the bit.



CORING

• To gain an understanding of the composition of the reservoir rock, inter-

reservoir seals and the reservoir pore system, it is desirable to obtain an

undisturbed and continuous reservoir core sample.

• Cores are also used to establish physical rock properties by direct

measurements in a laboratory. They allow description of the depositional

environment, sedimentary features and the diagenetic history of the

sequence.

• In the pre-development stage, core samples can be used to test the

compatibility of injection fluids with the formation, to predict borehole stability

under various drilling conditions and to establish the probability of formation

failure and sand production.



CORING…contd

• Coring is performed in

between drilling operations. Once the formation for which a core is required has been identified on the mud log, the drilling assembly is pulled out of hole. For coring operations, a special assembly is run on drill pipe comprising a core bit and a core barrel (FIGURE)



CORING…contd

• Unlike a normal drill bit which breaks down the formation into small cuttings,

a core bit can be visualised as a hollow cylinder with an arrangement of

cutters on the outside. These cut a circular groove into the formation. Inside

the groove remains an intact cylinder of rock which moves into the inner core

barrel as the coring process progresses. Eventually, the core is cut free

(broken) and prevented from falling out of the barrel whilst being brought to

surface by an arrangement of steel fingers or „catchers‟.

• Core diameters vary typically from 3 to 7 in. and are usually about 90 ft long.

However, in favorable hole/formation conditions longer sections may be

achievable.

• Commonly, a fibre glass or aluminium sleeve is inserted into the steel inner

core barrel and the core is retrieved within the sleeve. At the surface the gap

(annulus) between the inner sleeve and core is injected with an inert

stabilizing material which „sets‟ to hold the core in place. The core is cut into

sections (typically 1 m) and shipped to the laboratory.



CORING…contd



CORING…contd

• In addition to a geological evaluation on a macroscopic and microscopic

scale, plugs (small cylinders of 3 cm diameter and 5 cm length) are cut from

the whole core, usually at about 30 cm intervals. Core analysis is carried out

on these samples.

• Routine core analysis of plugs will include determination of:

1. porosity

2. horizontal air permeability

3. fluid saturation

4. grain density.

• SCAL will include measurements of:

1. electrical tests (cementation and saturation exponents)

2. relative permeability

3. capillary pressure

4. strength tests.



CORING…contd

• Finally, the core will be sectioned (one third:two thirds) along its entire length

(slabbed) and photographed under normal and ultraviolet light (UV light will

reveal hydrocarbons not visible under normal light, as shown in FIGURE).


Photograph of

core (left = normal

light, right = UV).


SIDEWALL SAMPLING

• The sidewall sampling tool (SWS) can

be used to obtain small plugs (2 cm

diameter, 5 cm length, often less)

directly from the borehole wall. The tool

is run on wireline after the hole has

been drilled and logged.

• Some 20–30 individual bullets are fired

from each gun (FIGURE) at different

depths. The hollow bullet will penetrate

the formation and a rock sample will be

trapped inside the steel cylinder. By

pulling the tool upwards, wires

connected to the gun pull the bullet and

sample from the borehole wall.



SIDEWALL SAMPLING AND CORING

• Sidewall samples are useful to obtain direct indications of hydrocarbons

(under UV light) and to differentiate between oil and gas. The technique is applied extensively to sample microfossils and pollen for stratigraphic analysis (age dating, correlation, depositional environment). Qualitative inspection of porosity is possible, but very often the sampling process results in a severe crushing of the sample, thus obscuring the true porosity and permeability.

• In a more recent development a new wireline tool has been developed that actually drills a plug out of the borehole wall. With SIDE WALL CORING (FIGURE), some of the main disadvantages of the SWS tool are mitigated, in particular the crushing of the sample. Up to 20 samples can be individually cut and are stored in a container inside the tool.



SIDEWALL SAMPLING AND CORING


Sidewall coring tool



Formation Evaluation and Well Logging

WIRE LINE LOGGING

INTRODUCTION

• Wireline logs represent a major source of data for geoscientists and

engineers investigating subsurface rock formations. Logging tools are used

to look for reservoir quality rock, hydrocarbons and source rocks in

exploration wells, support volumetric estimates and geological/geophysical

modelling during field appraisal and development, and provide a means of

monitoring the distribution of remaining hydrocarbons during the production

lifetime.

• A large investment is made by oil and gas companies in acquiring openhole

log data. Logging activities can represent between 5 and 15% of total well

cost. It is important therefore to ensure that the cost of acquisition can be

justified by the value of information generated and that thereafter the

information is effectively managed.



WIRE LINE LOGGING

SETUP and WORKING : FIGURE

depicts the basic setup of a wireline

logging operation. A sonde is

lowered downhole after the drill

string has been removed. The

sonde is connected via an insulated

and reinforced electrical cable to a

winch unit at the surface. At a speed

of about 600 m/h the cable is

spooled upward and the sonde

continuously records formation

properties like natural GR radiation,

formation resistivity or formation

density. The measured data are

electrically transmitted through the

cable and are recorded and

processed in a sophisticated logging

unit at the surface.



WIRE LINE LOGGING

PRESSURE MEASURMENTS AND FLUID SAMPLING

• A common objective of a data gathering programme is the acquisition of fluid

samples. The detailed composition of oil, gas and water is to some degree

required by almost every discipline involved in field development and

production.

• One method of sampling reservoir fluids and taking formation pressures

under reservoir conditions in openhole is by using a wireline FPT. A number

of wireline logging companies provide such a tool under the names such as

RFT (repeat formation tester) and FMT (formation multitester), so called

because they can take a series of pressure samples in the same logging run.

Newer versions of the tool are called a modular dynamic tester or MDT

(Schlumberger tool), shown in FIGURE and reservoir characterisation

instrument or RCI.



PRESSURE MEASURMENTS AND FLUID

SAMPLING…Contd

• The tool is positioned across the objective formation and

set against the side of the borehole by either two packers or by up to three probes (the configuration used will depend on the test requirements). The probes are pushed through the mudcake and against the formation. A pressure drawdown can now be created at one probe and the drawdown be observed in the two observation probes. This will enable an estimate of vertical and horizontal permeability and hence indicate reservoir heterogeneities as well as recording a pore pressure.

• Alternatively fluids can be sampled. In this case, a built-in resistivity tool will determine when uninvaded formation fluid (hydrocarbons or formation water) is entering the sample module. The flow can be diverted back into the wellbore until only the desired fluid is flowing, thus providing fluid samples uncontaminated with mud.



PRESSURE MEASURMENTS AND FLUID SAMPLING…Contd

MDT tool

configuration for

permeability

measurement.



WIRE LINE LOGGING : TYPES OF LOGGING TOOLS

ELECTRICAL LOGS: measure the voltage generated naturally by alternating

types of rock beds (Spontaneous Potential Log or SP Log), and the resistivity

and conductivity of the rocks and their saturating fluids to an electric current

(electric survey log, induction log, dual induction log etc. )



WIRE LINE LOGGING

ELECTRICAL LOGS (LATERALLOG)

The most common method for measuring

formation resistivity and hence determining

hydrocarbon saturation is by logging with a

resistivity tool such as the laterolog.

The tool is designed to force electrical

current through the formation adjacent to

the borehole and measure the potential

difference across the volume investigated.

With this information the formation

resistivity can be calculated and output

every foot as a resistivity log



WIRE LINE LOGGING

ELECTRICAL LOGS (INDUCTION

TOOL)

The laterolog tool needs a conductive

environment to operate. Therefore, in oil

based mud (OBM) other types of tools

are used. The most common is the

INDUCTION LOG TOOL, based upon the

principles of mine detection. A

transmitting coil induces currents in the

formation which in turn induce a current

in the receiver coil.



WIRE LINE LOGGING

SP LOG EXAMPLE




RADIOACTIVE LOGS: measure the natural radioactivity of different rock

formations, or else the response of those different formations to

bombardment by neutron or gamma rays (neutron log, gamma ray or GR log

etc. )




RADIOACTIVE LOGS: GAMMA RAY LOG

• Non-productive layers such as shales can be differentiated

from clean (non-shaly) formation by measuring and

comparing natural radioactivity levels (Gamma ray

emission) along the borehole.

• Shales contain small amounts of radioactivity elements

such as thorium, potassium and uranium which are not

normally present in clean reservoir rock, therefore high

levels of natural radioactivity indicate the presence of

shale, and by inference non-productive formation layers.

• The thickness of productive (net) reservoir rock within the

total (gross) reservoir thickness is termed the net to gross

or N/G ratio. The most common method of determining the

N/G ratio is by using wireline GR logs.




RADIOACTIVE LOGS: GAMMA RAY LOG



WIRE LINE LOGGING :

GAMMA RAY LOG

EXAMPLE




ACOUSTICAL LOGS: measure the time it takes for a sonic pulse to travel

through a formation (Sonic log etc).

The sonic tool works by sending a sound pulse into the formation and

measuring the time taken for the sound wave to return to a receiver located

further up (or down) the tool.

The transit time in tight (nonporous) sandstone or limestone is short; while in

porous formations it is longer and in mudstone it is longer still. For Coal it is

very slow.

Its main use is in the evaluation of porosity in liquid filled holes.




ACOUSTICAL LOG EXAMPLE

Sonic log responses in a

sandstone and mudstone

sequence:

In the sandstones have a

lower sonic velocity than

the shales (mudstones).


Types of Well Logging Tools

A vast

variety of

logging tools

are in

existence


Well Logging Tools

SUMMARY:

In usual practice many types logs and different combination of the log data is

used to evaluate the formation and finally all this data is used to determine the

thickness, porosity and hydrocarbon saturation of the rock formations.


Well Logging Tools

LOGGING/MEASURMENT WHILE DRILLING (LWD / MWD TOOL):

Basic MWD technology was first introduced in the 1980s by drilling

companies, and was initially restricted to retrievable inserts for directional

measurements and then natural GR logs. These developments were quickly

followed by logging tools integrated into drill collars (DCs) (LWD).

Recently, LWD development has progressed to the stage where most of the

conventional wireline logging tools can be effectively replaced by a LWD

equivalent.

Early LWD technology was often considered to be inferior to wireline.

However, recent mergers between wireline and drilling companies has

resulted in technology-transfer in R&D which has led to a significant

improvement in LWD log quality.

A lazy use of terminology within the industry means that LWD and MWD can

be considered as synonymous. A more appropriate term for today‟s

sophisticated devices is formation evaluation while drilling (FEWD).


Well Logging Tools


Perhaps the greatest stimulus for the development of such tools has been

the proliferation of high-angle wells in which deviation surveys are difficult

and wireline logging services are impossible (without some sort of pipe

conveyance system), and where LWD logging can minimize formation

damage by reducing openhole exposure times.

Whilst providing deviation and logging options in high-angle wells is a

considerable benefit, the greatest advantage offered by LWD technology, in

either conventional or high-angle wells, is the acquisition of REAL TIME data

at surface.

Most of the LWD applications which are now considered standard, exploit

this feature in some way, and include:

• real time correlation for picking coring and casing points

• real time overpressure detection in exploration wells

• real time logging to minimise „out of target‟ sections (geosteering)

• real time formation evaluation to facilitate „stop drilling‟ decisions.


Well Logging Tools


Schlumberger geosteering tool with LWD.


Well Logging Tools


BakerHughes Inteq „Pentacombo‟ tool.


Well Logging Tools


Data transmission may be within the downhole assembly from the sensors

to a memory device or from the sensors to surface. The latter is usually

achieved by mud pulse telemetry, a method by which data are transmitted

from the tool in real time, that is as data are being acquired.

Electrical power is supplied to LWD tools either from batteries run in the

down hole assembly or from an alternator coupled to a turbine set in the

mudstream.



Perforation and Well Activation

BASIC WELL COMPLETION TECHNOLOGY

Each drilled wellbore awaiting completion is unique. Even nearby wells

drilled to the same reservoir can have different depths, formation

characteristics, and hole sizes.

It follows, then, that a wide variety of equipment designs and procedures

have been developed to provide safe, efficient conduits from subsurface

reservoirs to the surface in different situations.

In each case, the ideal completion design minimizes initial completion and

operation costs, while providing for the most profitable operation of an oil or

gas well over its entire life.

Thus in the following slides we will concentrate on the typical rig-site

procedure involved in well completions, rather than attempting to cover the

enormous number of specific completion designs practically possible.




Types of completion:

• the openhole completion - in which the producing formation is not isolated

by the casing, which extends only to the top of the producing interval




Contd….. Types of completion:

• the liner completion - which is not cemented and not "tied back" to the

surface




Contd …..Types of completion:

• the cased and perforated completion - which involves cementing the

production casing across the productive interval and then perforating the

casing for production. When a liner is cemented and perforated it could be

considered a cased and perforated completion.




One of these configurations will be the basis for the completion design,

which may incorporate one or multiple strings of tubing and a variety of

tubing components to facilitate production from one or multiple zones.

A cased and perforated well with a single tubing string will serve to illustrate

the typical completion procedure.

COMPLETION PROCEDURE

After the contract casing crew runs the final casing, cementing follows the

usual procedure, although stage cementing may be necessary to cement an

extremely long string. The production string has been hauled out to the

location and the inside diameter checked to make sure that imperfections

will not prevent the subsequent running in of tubing and packers after the

string is set.



Contd…..COMPLETION PROCEDURE

Special care must be taken to prevent the possibility of future leaks. If stage

cementing is necessary, the bottom section is first cemented in place and

then a series of plugs are pumped down the casing to open ports that allow

the upper end of the annulus to receive cement.

After the cement has set, the inside of the casing must be drilled out and

flushed clean of cement and other debris to a depth below that of the

proposed completion.




It is important that the inside diameter of the

production casing be clean and smooth. It is also

important that the cement form a competent seal

between the casing and borehole over the entire

openhole interval.

To ensure this, an acoustic cement bond log is

sometimes run on electric line to determine if

voids exist between casing and hole because

cement has bypassed the drilling fluid (figure). If

the bond is poor in an area, particularly if the

area is between productive formations, a cement

squeeze will be required. This technique

involves selectively perforating the casing and

pumping cement into the empty spaces.




Often the cement bond log is run in conjunction with a gamma ray log and a

casing collar log. The drilling engineers can correlate this gamma ray log

with the logs run earlier during formation logging. This correlation is

important because as we zero in on the target-the productive formation-the

need to locate tools precisely relative to that formation is critical.

At this point, many operators move the drilling rig off location and replace it

with a less expensive, and often less powerful, completion rig. This gives the

operator time to design the rest of the completion, provide for a sales

contract, and order equipment.

Whichever rig is used, the next step in the completion is to measure the

tubing while running it into the hole. A careful count must be kept of the

exact number of tubing joints run into the hole and their total length.

With the tubing in the hole, the BOP stack, which is now attached above the

tubing head where the tubing will hang, may be tested.




The casing may also be pressure tested, and a filtered completion fluid may

be circulated into the well to displace the drilling mud prior to perforating.

This fluid is usually a heavy brine, which provides the hydrostatic pressure

needed to control the well; but does not contain solids that can plug the

perforations and damage the formation.

If perforating is to be done at this point, the tubing is removed and the

perforating gun is lowered and positioned according to the correlation log

and casing collars. It is critical that the gun be placed precisely; once

inaccurate perforations are made, they can only be plugged off with a costly

cement "squeeze."




If perforating is to be done at this point, the tubing is removed and the

perforating gun is lowered and positioned according to the correlation log

and casing collars. It is critical that the gun be placed precisely; once

inaccurate perforations are made, they can only be plugged off with a costly

cement "squeeze."




With the well perforated, it may now be time to stimulate the well by either

acidizing or hydraulically fracturing the formation. Acid can be used to

dissolve formation-damaging particles left by the drilling mud or to eat away

portions of the rock itself, increasing the size of flow passages.

Hydraulic fracturing involves the high pressure pumping of fluid into the

formation to split the rock apart and to increase the flow capacity of tight

formations.

Normally, the next step is to run and set a completion packer, either

incorporated into the tubing string or set independently on electric wireline. The packer is pressure tested to ensure its sealing ability. (Many shallow, low pressure wells, however, do not require a packer to isolate the casing from produced fluids.)




The tubing must then be "spaced out." This requires that a length of tubing

be removed from the upper end so that it can be "landed" in the tubing head,

which is some distance below the rotary table.

Once the tubing has been landed in the tubing head, a temporary plug can

be set inside the tubing while the BOP stack is removed and the surface flow

control equipment ("Christmas tree") installed. This plug is then removed

through the Christmas tree, and the well is completed.

The rig will often be moved off location at this point, allowing the well to be

"brought in." On an offshore platform, the rig may be skidded to the next well

slot.

If a rod pump is required on the well, it may be installed at this time and the

necessary rods and downhole pumping mechanism run into the tubing. If

gas lift valves have been incorporated into the tubing string, gas may be

used to blow the completion fluid out of the tubing and permit the well to flow

on its own.




In some cases, the well will be "swabbed in" at this point, by running a

close-fitting plunger into the tubing on wireline and pulling it back up, thereby

displacing the completion fluid in the tubing and allowing the formation to

flow. After an initial well test, which may be conducted with temporary test

facilities, the flow line needed to produce the well on a continuous basis will

be connected.



COMPLETION PROCEDURE : PERFORATION

The use of cemented steel casing to line the wellbore and isolate producing

zones is only practical when a method for easily reopening those zones for

production exists.

Jet perforating is the procedure whereby an explosive charge is used to

selectively open passages to the formation through the casing and cement

sheath. This method is the most widely used today, because of its versatility

and power.

Having evolved from the same technology that produced the military

bazooka, the jet perforator relies on a conical-shaped charge of explosives

to produce a high pressure stream of particles. Bullet perforators, on the

other hand, fire metal projectiles at the inside of the casing to penetrate

casing, cement, and rock.




Jet perforating guns consist of a carrier with a series

of explosive charges linked together by a detonating

cord.

A variety of gun designs exist; they vary according

to:

• whether the gun is to be run on an electric

conductor line or attached to the bottom of the

tubing;

• whether the gun is to be run through the casing on

electric line or tubing, or is to be lowered through

the tubing on electric line;

• whether the gun is retrievable following detonation

or is expendable (meaning it is destroyed when the

gun is fired);

•the diameter and length of the perforation desired.




Wider, longer perforations require larger, stronger

jet charges, and, accordingly, larger guns to hold

them. The charge itself is held in a metal case

(FIGURE) that is linked to similarly shaped charges

by a detonating cord ending in an electric detonator.

When the gun is fired, an electric current from the

surface sets off the blasting cap detonator, which

secondarily ignites the detonating cord leading to

the main explosive charges.




When a charge is fired (FIGURE), the metallic liner

collapses to form a stream of high-pressure, high-

velocity jet particles. Traveling at 30,000 ft/sec

(9100 m/sec), the jet stream strikes the casing at 15

x 106 psi (100 x 106 kPa) a fraction of a second

after detonation, displacing the metal, cement, and

rock to form a perforation.



COMPLETION PROCEDURE :

PERFORATION

Retrievable hollow carrier guns have

cylindrical steel bodies with closed

ports opposite each jet charge

(FIGURE a).

Fully expendable guns enclose the

charges in a frangible aluminum or

ceramic case that disintegrates on

firing (FIGURE b),

whereas semiexpendable guns consist

of wire or metal strip' carriers that are

retrieved after firing (FIGURE c).




Through-casing and through-tubing guns of these types differ primarily in the

diameter of the gun (3 to 5 in [7.6 to 12.7 cm] for casing guns, 1 to 2 in [2.5

to 5.1 cm] for tubing guns) and in the size of the jet charges.

After firing, the gun component' of the tubing is released with a wireline

shifting tool to allow full flow into the tubing.

In addition to perforation diameter and length, two important considerations

in all types of perforating are the shot density and phasing of the

perforations. The shot density, or shots per foot, is usually 2, 4, 8, 12, or 16

holes in each foot of perforated interval.




GUN PHASING: Phasing pertains to the direction of each successive shot

relative to its neighbors; if each charge is pointed 90 deg away from the

next, we have 90 deg phasing.

In the case of 180 deg phasing, each shot points directly opposite from the

next one in the carrier. Gun phasing can be particularly important when

perforating a fractured well, a highly deviated well, or a multiple completion,

where the gun must be oriented to avoid perforating an adjacent tubing

string.

The decision about the interval to be perforated is often made by the

geologist or by the engineer and geologist responsible for the area in which

the well is drilled.

Consideration will be given to maximizing flow rate and minimizing

production problems such as produced sand, water coning, or excessive gas

production in an oil well.




Contd….. GUN PHASING:

The decision is often made after careful review of the log and core data back

at the company office. The geologist„s input concerning net pay, sidewall

core descriptions, and the areal extent of sand intervals can be crucial in

determining the best interval to be perforated.



COMPLETION PROCEDURE : WELL STIMULATION

Well stimulation techniques like Acidizing or Fracturing is a routine part of

the completion program. Either type of stimulation may also be applied soon

after a well has been completed and has tested at lower production rates

than expected.

Stimulation may also be part of a remedial or "workover" program designed

to improve productivity following a decline in production. Stimulation will

often follow a formation pressure buildup test that was run to determine if the

cause of low productivity was i) permeability reduction near the wellbore, ii)

low permeability throughout the reservoir, or iii) low reservoir pressure.

Acid stimulation can improve the first condition, whereas fracturing is

necessary to significantly improve the second condition. Of course, the third

condition can only be helped by pressure maintenance through injection of

water or gas.




Both acidizing and fracturing pumping of fluids down the tubing or drillpipe

and into the formation.

In fracturing, the objective is to apply enough pressure to actually split the

formation apart, creating flow channels to the wellbore where either none or

few previously existed.

In most acidizing procedures, the objective is to squeeze the acid into the

existing pore spaces of the rock matrix, where it can react to enlarge the flow

channels and improve permeability.

Acid-fracturing treatments create fractures that are simultaneously widened

by acid dissolution.









COMPLETION PROCEDURE : SAND CONTROL

A certain amount of sediment will always be produced along with formation

fluids. Sand control is the technology and practice of preventing sand flow

from unconsolidated sandstone formations.

Such a problem is often found in Tertiary sediments, at shallow depths, and

in areas such as Nigeria, Indonesia, Trinidad, Venezuela, Canada, the U.S.

Gulf Coast, and the Los Angeles Basin (Patton and Abbott 1982).

Sand production leads to any or all of the following problems:

• casing collapse

• abrasion of downhole and surface equipment

• reduced productivity

• completely plugged ("sanded-up") wells




Methods for controlling sand production have generally involved one of two

approaches:

• a metal screen and sand grain barrier that screens out the formation sand

but does not inhibit fluid flow into the well bore; or

• an epoxy resin that can be injected into the formation near the well bore and

allowed to harden; this cements the sand grains together and by

consolidating them prevents their movement (sand consolidation).




Metal wire-wrapped screens and gravel packs work

in a manner analogous to a large crowd of people

trying to leave a theatre through a small door. Each

could pass through the door individually, but when

several try at once they form a "bridge" that

prevents those at the rear of the pack from moving

at all. In sand control, bridging methods employ

wire-wrapped screens or slotted casing, both of

which have carefully sized openings that allow the

formation sand to be deposited against them. In the

case of gravel packs, carefully sized clean sand is

placed outside the screen to retain the formation

sand at its outer edge (FIGURE).




Correct sizing of both the gravel pack sand and the

gravel pack screen requires knowledge of the

information about formation grain size distribution

that had been obtained from cores.

Guidelines have been developed to select sand and

screen sizes that will prevent formation sand

movement but not inhibit formation fluid flow.



Production Engineering

INTRODUCTION

Up to this point, describing the static geologic structure has been a basic

part of the exploration and development process. Wells are drilled and

logged, maps are revised, and the reservoir begins to take shape as a

volume having certain dimensions – stochastic model

But once production begins, the reservoir is only a part of a larger system

that includes the reservoir, wellbore, tubing string, artificial lift equipment,

surface control devices, gathering lines, separators, treaters, tanks, and

metering devices. All of these elements behave according to their own

specific performance relationships, but each, in turn, also depends upon and

influences the other elements.

PRODUCTION ENGINEERS are thus concerned with the interaction of

these performance relationships as production occurs over time, anticipating

performance changes and designing the system to maximize recovery of oil

and gas economically. Understanding this dynamic production system as

well as the static geologic structure is a practical objective for everyone

involved in the exploration an production effort – DYNAMIC MODELLING



COMPLETION COMPONENTS

The basis for any completion is the heavy steel pipe lining the wellbore-the

casing. Together with the cement sheath holding it in place, the casing

performs several important functions:

• supporting the sides of the hole;

• preventing communication of fluids and pressures between shallow and

deep formations;

• allowing for control of pressures; and

• providing a base for surface and subsurface equipment.




A cross section of a typical casing installation is

shown in FIGURE. The number of concentric

"strings“, their relative sizes and strengths, the

setting depths, and cementing techniques will vary

according to the depth and drilling program for the

well.

The conductor casing prevents the surface hole

from caving and it also prevents lost circulation. In

offshore situations, the drive pipe is hammered into

the mud to provide a conduit from below the

seafloor to the production deck, and the conductor

casing is set inside the drive pipe.




There may be intermediate casing strings

between surface and production casing if the

depth of the well requires it. Each casing string is

cemented in place and the production string is

perforated across the productive zone.



COMPLETION COMPONENTS : TUBING

The central downhole component of a completed well is

the production tubing (FIGURE). There are four primary

reasons for utilizing production tubing as a conduit for

producing fluids:

• It is relatively easy to remove if problems develop.

• It isolates producing fluids from the casing and makes

control of the fluids easier.

• It facilitates circulation of heavy fluids into the wellbore

to control the well.

• Its smaller diameter allows for safety devices and

artificial lift equipment to be included in the completion

design. It allows for more efficient producing rates from

lower productivity wells.




Tubing is suspended from a tubing hanger within the

wellhead at the surface, and the producing zone(s) may

be isolated by production packers in the tubing string.

A well may be completed with several strings of tubing

(dual completion, triple completion, etc.), each carrying

production from a different zone.

Some extremely productive wells produce through

casing without tubing, or through both tubing and the

casing-tubing annulus.



COMPLETION COMPONENTS : TUBING COMPONENTS

The design of a particular completion depends on:

• the number and type of productive zones;

• the expected pressures and flow rates;

• the need to control sand production;

• the need for artificial lift or stimulation; and

• the regulations governing operations in the area.



TUBING

COMPONENTS

FIGURE shows

schematic

examples of a

number of typical

completions. In

addition, the

following

definitions and

associated figures

describe the most

common

components of

those completion

examples.



TUBING

COMPONENTS

FIGURE shows

schematic

examples of a

number of typical

completions. In

addition, the

following

definitions and

associated figures

describe the most

common

components of

those completion

examples.




COMPONENTS

A) PACKERS:

The packer seals the casing-tubing annulus

with a rubber packing element, thus preventing

flow and pressure communication between

tubing and annulus.

Packers are designed either to remain in the

well permanently (FIGURE) or to be retrieved if

future downhole work is required (FIGURE).



COMPLETION COMPONENTS :

TUBING COMPONENTS

A) PACKERS: Retrievable packers




A) PACKERS:

Mechanically set packers rely on tubing or drillpipe movement to force

grooved "slips" to grip the casing and to expand the sealing element during

the setting procedure.

Hydraulically set packers are engaged by fluid pressure. Some packers can

also be set with an explosive charge triggered from the surface by an

electrical cable (electric line), or wireline.

There are a wide variety of packers available to meet the requirements of

specific completion designs.




COMPONENTS

OTHER COMPONENTS

Multistring Packer (FIGURE): The multistring

packer seals the casing-tubing annulus where

more than one tubing string is involved. Up to

five-string packers are available, but more than

a triple completion is rare because of the

difficulty of retrieval if problems develop.




COMPONENTS

Sliding Sleeve : The sliding sleeve component is

a wireline-operated sleeve, which will open or

close ports in the tubing to allow fluid in or out.

This feature is useful for circulating annular fluid

out of the hole after a packer is set, or for opening

a selective completion at a future date. This type

of component is also called a circulating sleeve.




COMPONENTS

Tubing Anchor : The tubing anchor is

essentially a packer without the sealing element

and is designed to prevent tubing but not fluid

movement. It also allows partial removal of the

tubing string.




COMPONENTS

Blast Joint : A blast joint is a section of heavy duty

tubing located opposite production perforations in a

multistring completion. It prevents erosion of the tubing

by high-velocity flow (especially with sand production).




COMPONENTS

Safety Joint : The safety joint allows for the parting of

an auxiliary tubing string beneath a multiple string

packer when the packer is being retrieved. Usually it

consists of a sleeve-type arrangement with shear pins

that part after a certain tension is reached.




COMPONENTS

Landing Nipple: Landing nipples are a variety

of short tubing components with interior profiles

that allow for the wireline setting of plugs,

safety valves, chokes, pressure gauges, etc.,

within the tubing by using the appropriate

locking device. Using a wireline to set and

retrieve production tubing equipment is

common practice in areas where pulling the

entire tubing string is difficult or expensive, for

example, offshore.

A flow coupling is a short, heavy-duty tubing

joint run above and below tubing restrictions

(safety valves, chokes, etc.) that minimize

abrasive effects of turbulent flow caused by the

restrictions.




COMPONENTS

Gas-Lift Mandrels: A gas-lift mandrel is a

tubing component that holds a gas-lift valve

which, in turn, allows the passage of gas-lift

gas between annulus and tubing. Side-

pocket mandrels allow for wireline

placement and retrieval of gas-lift valves

within the tubing string.




TUBING COMPONENTS

Subsurface Safety Valve: This component is a

valve assembly within the tubing string, which is

designed to close in case of emergency. The

valve can be an integral part of the tubing string

(tubing retrievable) or set inside the tubing with

wireline (wireline retrievable). These valves can

be surface controlled by means of hydraulic

pressure or designed to close at a certain

predetermined flow rate.

.




TUBING COMPONENTS

PACKERS:

Subsurface Safety Valve:

.




Tubing string components are expensive, and so is the cost of pulling the string

out of the hole should future problems arise.

A good completion design anticipates future performance problems and

provides the flexibility to handle them, while balancing completion costs

against the risk of future remedial work.



COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS

The valves and connections at the top of the well are often referred to

collectively as the "wellhead" or "christmas tree.“

The primary purpose of this equipment is to safely control the flow of fluids

under pressure. Other functions are sealing the annular openings between

concentric casing and tubing strings, and providing a base for blowout

control equipment during drilling operations.




The design of the entire arrangement depends on several factors:

• the expected maximum and operating pressures;

• the number and sizes of casing strings;

• the number and sizes of tubing strings;

• the need for auxiliary equipment, such as subsurface safety valves,

electrical conduits for submersible pumps, and chemical injection

equipment;

• the outside environment-onshore, offshore, or subsea;

• the inside environment: CO2 and H2S content of produced fluids or

corrosive formation water;

• the operator's safety policy and the prevailing safety regulations; and

• the operator's equipment inventory and preference for a given

manufacturer.



COMPLETION COMPONENTS : SURFACE

FLOW CONTROL EQUIPMENTS

The FIGURE shows a typical surface flow

control installation for a multiple casing string,

single tubing string, flowing well.




SURFACE FLOW CONTROL

EQUIPMENTS

The casinghead is screwed or welded to

the outermost casing stub.

The inside of the casinghead provides a

shouldered sealing surface for the casing

hanger, which grips the hanging casing

and usually allows the weight of the

casing string to provide the force

necessary to seal off the annulus

between the outer and inner casing

strings.





A casing packoff, or similar sealing

element, is sometimes used to provide

additional pressure sealing for the annulus.

Casing spools allow for additional casing

strings to be hung and sealed off above the

casinghead. During the drilling operation,

the inside of the casinghead or spool, is

protected with a temporary bushing to

prevent damage from drillpipe rotation.

Normally, the casinghead and casing

spools have at least one additional

connection designed to allow fluid access

and pressure monitoring of the concentric

annular spaces during production.




SURFACE FLOW CONTROL

EQUIPMENTS

The TUBING HEAD performs a function

similar to the casinghead, in that it

accommodates a tubing hanger

(FIGURE), which usually screws onto the

top of the tubing string(s) and seals off

the casing-tubing annulus with metal-to-

metal and/or rubber sealing elements.

Often the tubing hanger is further

secured by a series of set screws. An

adapter (also called a tubing "bonnet")

provides a transition from the tubing

head to the arrangement of valves and

fittings above the casing and tubing

head, used to control flow (the

"Christmas tree").





In the Christmas tree, the bottom valve often

called the master valve, is the primary means

for completely shutting in the well. This and

other valves used in the tree are normally gate

valves that operate by moving a metal barrier

to block the flow stream (FIGURE).

Often, safety regulations require that one valve

be pressure-actuated to automatically shut off

flow in case of operating problem or natural

disasters. Offshore wells usually require a

downhole safety valve in addition to this

surface safety system.





The tree allows for vertical entry into the tubing

by removal of the top adapter. A "tee" - type

fitting allows for redirection of the vertical flow

stream to a horizontal flow line.

The produced fluids in the flowing well, before

entering the surface flow line, must pass

through the smallest restriction in the surface

flow equipment- the choke.

Chokes, located in the Christmas tree, provide

a means for controlling production rate by

restricting the area available for flow. This

restriction is normally a bean or orifice of a

specified diameter, and must be inserted into

the choke body.




FIGURES below show examples of surface flow control equipment for a variety of completions.




While most manufacturers make components with bolted flange

connections, some companies also manufacture wellhead and Christmas

tree equipment with clamp connections to allow speedy assembly.

Wellhead and Christmas tree components are available for all types of

specific design situations. Most equipment can be adapted to allow that

different manufacturers' components be combined in a single installation.



SURFACE PRODUCTION FACILITIES: INTRODUCTION

The fluid produced from a well is usually a mixture of oil, gas, water, and

sediment at elevated temperatures and pressures. The oil alone is a

complex mixture of many hydrocarbon compounds, and oils from different

reservoirs have different physical and chemical characteristics.

All crude oils have a certain amount of gas dissolved in them. A gas phase

may exist in the production stream, having come out of solution with the drop

in pressure up the tubing, or it may exist in and be produced from the

reservoir as free gas. In some cases, the only hydrocarbons found in a

reservoir exist as a gas and, thus, we have a dry gas reservoir.

Formation water may be carried in the gas state as vapor, emulsified as a

liquid with the oil, or produced as free water. Sand, silt, and clay from the

formation can be carried by the produced fluids into the wellbore and be

produced along with scale and corrosion products from the casing or tubing.

Various contaminants can be present in the oil, gas, and water. These

include CO2, H2S,and dissolved salts.



SURFACE PRODUCTION FACILITIES

INTRODUCTION

Surface production facilities are designed to turn this mixture into separate

streams of clean, dehydrated oil and gas, and safely disposable water. Only

then can the oil and gas be metered and sold, or sent for further processing

to a plant or refinery.

Of course, the diversity of well fluid mixtures has led to the development of

an assortment of vessels to clean and separate these mixtures at various

pressures and temperatures.

Now to start with lets discuss the production stream of oil well



SURFACE PRODUCTION FACILITIES: SEPARATION

The produced fluids leave the Christmas tree via a flow line-usually a 2- or

3-in (5- to 8-cm) pipe, which may be below or above ground at onshore

installations, or perhaps on the seafloor for a subsea completion.

Subsea completions are often equipped with TFL or through-flow-line

connections (FIGURE) whereby the flow line connects to the Christmas tree

in a smooth loop. This arrangement allows for production devices (plugs,

etc.) to actually be pumped through the flow line and into the tubing, thus

eliminating the need to disconnect any Christmas tree fittings. (A valuable

consideration if your wellhead is in 300 ft of water!)

The flow line (gathering line) generally travels by the shortest route to the

surface production facilities. If the production facilities are shared by a group

of wells, as is often the case, the flow line will probably connect to a

production manifold. This is an assembly of valves that allows each well's

flow stream to be shut in or diverted to a particular portion of the production

facilities.




Normally, a separator is the first piece of production processing equipment

the fluid stream encounters. Separators are usually classified by physical

shape. FIGURE shows the Vertical, horizontal, and spherical separator

configurations.

A conventional separator divides the produced fluid stream into oil and gas,

or liquid and gas, and is known as a gas-oil separator or gas-liquid

separator.



SURFACE PRODUCTION FACILITIES:

SEPARATION

Sometimes separators are also called

"traps." Conventional separators can be

two-phase or three-phase depending on

whether they separate oil and gas, or oil,

gas and water.

WORKING PRINCIPLE:

The FIGURE shows two-phase, gas-liquid

separator.

The oil-gas-water mixture enters through

an inlet on the side of the tank-shaped

vessel.




SEPARATION

Contd….WORKING PRINCIPLE:

The fluid stream immediately strikes a

metal plate, which diverts the flow around

the inner surface of the cylindrical

separator, imparting a centrifugal motion.

This motion throws the liquid to the outer

edge of the cylinder and allows the gas to

remain near its center.

The lighter gas portion of the fluid stream,

now separated, rises through the center of

the vessel while the liquid falls. Some

separators have an arrangement of metal

fins at the inlet, which abruptly changes the

fluids flow direction and velocity.




SEPARATION


In this case, the liquid's higher inertia

carries it way from the gas and downward,

while the gas rises to the top of the

separator.

Still another feature of some separators is

the presence of a system of baffles, which

spread the liquid out as it drops to the

bottom of the vessel. This allows any gas

bubbles, carried in the liquid, to easily

escape.




SEPARATION


The amount of time the oil is allowed to

settle in the separator prior to being

dumped at the outlet is termed retention

time. Normal retention time is usually 30 to

90 seconds. For a given liquid flow rate

through the separator, an increase in

retention time will require an increase in

vessel size or liquid depth.

The added cast of a larger separator may

not be justified by the additional separation

of gas that a longer retention time allows.

Our surface design, then, must be based

an economical considerations as well as

system performance.



SURFACE PRODUCTION

FACILITIES: SEPARATION


The gas phase, which is directed to

the upper portion of the vessel, is

usually passed through a mist

extractor (FIGURE) to remove

minute liquid droplets entrained in

the gas. Here, three processes act

to separate liquid from the gas: flow

velocity changes; direction

changes; and impingement, e

adherence and coalescence of

liquid mist an a surface.




SEPARATION


A combination of these three processes is

incorporated into a coalescing pack-type

mist extractor (FIGURE) made of knitted

wire mesh or layers of inert particles with

shapes designed far maximum surface

area.




SEPARATION


Centrifugal-type mist extractors

(FIGURE) used in vertical separators

have a set of vanes that cause the

circular motion of gas, throwing the

heavier liquid droplets to the wall of

the vessel to drain to the bottom. Its

efficiency increases as the velocity of

the gas stream increases.





The gas flow rate through the separator is controlled by a backpressure

valve, which maintains the desired pressure in the vessel. A liquid level

controller causes oil to be discharged from the separator when the

appropriate level is reached, and prevents gas from escaping through the

liquid outlet,.

The control is usually pneumatic (gas pressure-operated), but in low-

pressure applications, an internal, float-operated lever valve is employed.





Separators are sized according to the expected oil and gas production rates,

the necessary operating pressure and temperature, and the oil and gas

properties.

For example, a vertical separator about 2 ft (.61 m) in diameter and 10 ft

(3.05 m) high, with a retention time of one minute, will handle about 1300

bbl/D (207 m3/d) of typical crude oil.

A single barrel horizontal separator 2 ft (.61 m) in diameter and 10 ft (3.05 m)

long will handle about 2000 bbl/D (318 m3/d) and a 3 ft (.91 m) diameter

spherical separator about 1100 bbl/D (175 m3/d). For comparison, 100 to

200 bbl/D (16 to 32 m3/d) is about the output of a normal garden hose.




SEPARATION

SEPARATOR TYPES:

VERTICAL: Vertical separators are

often used an low to intermediate gas-

liquid ratio well streams. They are more

readily cleaned if sand - paraffin are

produced, and occupy less floor space

an offshore platforms.

However, a vertical separator can be

mare expensive than a horizontal

separator with the same separation

capacity.




SEPARATION : SEPARATOR TYPES:

HORIZONTAL: Horizontal separators, therefore , are usually more cost

efficient, especially far high to medium gas-liquid ratio streams, for liquid-

liquid separation, and in applications where foaming oil is a problem.

Horizontal separators (fig. a) often have closely spaced horizontal baffle

plates that extract liquids. A double barrel horizontal separator (fig. b) has a

higher liquid capacity because incoming free liquid is immediately drained

away from the upper section into the lower. This allows a higher velocity gas

flow through the upper baffled-section.













SPHERICAL SEPARATORS:

Spherical separators are much more common than vertical or horizontal

types. They tend to have lower installation and maintenance costs. They are

more compact, but lack the capacity for high gas rates or liquid surges.




OIL TREATMENT

In many oil fields, following the initial gas-oil separation process, the oil must

be treated to remove water, salt, or H2S. Most pipeline quality oil must have

its water content reduced to the 0.2% to 2% by volume range.

Because salt water is generally associated with oil in the reservoir, its

production along with the oil is not unusual. Almost all well streams contain

water droplets of various sizes. If, because of their higher density, they

collect together and settle out within a reasonably short time they are called

free water.



SURFACE PRODUCTION FACILITIES: SEPARATION :

OIL TREATMENT

The water cut measured on one or several samples of the well stream

normally refers to free water, and is expressed as the volume of water

relative to the total volume of liquid.

The sample is assumed to be representative. A free-water knockout (figure)

is a simple separation vessel located along the flow stream at a point of

minimum turbulence, where the oil and water mixture is allowed sufficient

time for its density differences to act to separate the phases.





OIL TREATMENT




OIL TREATMENT

A more difficult separation problem arises when the oil and water are

produced as an emulsion. Most oilfield emulsions are the water-in-oil type,

where individual water particles are dispersed in a continuous body of oil

(figure).




SEPARATION :

OIL TREATMENT

An inverted, or oil-in-water, emulsion can also occur, especially when the

ratio of water to oil is very high. Two things are necessary to produce an

emulsion of water and oil: agitation and an emulsifying agent.

As well fluids move through the formation, through the perforations and

completion equipment, up the tubing and through a choke, turbulence and

mechanical mixing provide the agitation necessary to disperse the droplets

of water throughout the oil phase, or droplets of oil throughout the water

phase.

Many crude oils also contain carbonates, sulfates, and finely divided solids,

which may act as emulsifying agents. These agents increase the stability of

the interfacial films separating the dispersed and continuous phases.




SEPARATION :

OIL TREATMENT

In order to "break" the emulsion and separate the oil from the water, a

variety of processes have been developed.

Treating vessels, which utilize more than one treating process to attack

particularly stable or "tight” emulsions, are common.

Chemical treatment uses chemical action to rupture the tough film

surrounding the dispersed droplets. The selection of the most effective

chemical demulsifier for a given crude oil-water emulsion is usually a trial-

and-error process.

Chemicals are normally added continuously to the produced fluids, as far

upstream from the treating or separation facilities as possible. Heat

treatment to reduce the viscosity of the emulsion and promote gravity

segregation is also used in treating emulsions.




SEPARATION :

OIL TREATMENT : DIRECT HEATERS

In direct heaters, the crude oil

emulsion is passed through a coil of

pipe that is exposed to a direct flame.

In indirect heaters the pipe carrying

the emulsion passes through a water

bath, which obtains its heat from a

fire-tube. Sometimes an internal

heater is used in a "gunbarrel"

treater-an older but still useful treating

method shown in FIGURE.

Here the emulsion flows into the

central flume and enters the tank at

the bottom, rising through a water

layer heated by internal coils.




SEPARATION :

OIL TREATMENT : HEATER TREATERS

Heater-treaters (figure) heat the emulsion

and separate the oil and water in the same

processing vessel.

The raw emulsion is preheated by the

warm, clean oil leaving the vessel, and the

water level is controlled by a siphon.

Collision and coalescence of dispersed

water droplets in an emulsion can be

accomplished by inducing electrical

charges in the particles through the

application of an electric field.




OIL TREATMENT : ELECTROSTATIC TREATERS

Electrostatic treaters are normally horizontal vessels, such as those shown

in FIGURE. The emulsion enters this form of treater and passes through an

initial separating section where it is heated and must pass upward through a

water layer. Any emulsion not yet broken then rises through an electrically

charged grid. The salt water droplets then become dipoles with oppositely

charged ends.

The droplets are attracted to one another. They collide, coalesce, and form

larger drops until they are heavy enough to settle to the water section of the

vessel and be drained. Electrostatic forces can be hundreds of times greater

than the gravitational forces acting to separate oil and water in a

conventional treater.





OIL TREATMENT : ELECTROSTATIC TREATERS




OIL TREATMENT :

Most produced oil still contains small amounts of emulsified water with solids

dispersed within it even after separation and treatment. Contract

specifications require that this BS&W (Basic Sediment and Water) be

reduced to a small percentage before sale. Even such small amounts of

water can still cause problems, particularly if the salinity is high.



SURFACE PRODUCTION FACILITIES: OIL METERING

Crude oil metering can be classified as either the automatic or manual

measurement of the produced oil volume.

The types of automatic measurement devices can be subdivided into four

classes: positive volume, positive displacement, turbine, and mass flow

meters.

Manual "gauging" of oil production involves a hand measurement of oil

level in a storage tank before and after oil is removed to the sales line.

Appropriate samples are taken from the tanks to ensure the oil is of pipeline

quality. This approach is still used in some areas but most measurement

techniques utilized in large fields, offshore, or in recently developed areas,

involve automatic measurement.




POSITIVE VOLUME METERING involves the filling of a predetermined

volume, the automatic discharge of that volume by liquid level-actuated

valves, and the recording of the discharge by some type of counter.

Positive volume meters may be found in metering separators and heater-

treaters, dump tank meters, and weir tanks. Some separators and treaters

are equipped with liquid level controlled valves, which periodically release

volumes of oil or liquid and record the action.

When several wells produce to a central tank battery, this type of vessel may

be used for individual well tests, but the final metering of commingled oil is

often accomplished by using a series of tanks as shown in FIGURE






SURFACE PRODUCTION FACILITIES: OIL

METERING

At least two tanks are required-one to

collect the surge of production, and one to

act as a measuring volume to be filled

and emptied in to the pipeline. If

continuous rather than intermittent flow to

the sales pipeline is required, additional

tanks may be needed to allow for

alternate filling and discharge, and to

provide a full sump tank from which oil

can be pumped to the sales line.

Sometimes these functions can be

combined in a single vessel where an

enclosed tank (figure) is filled and

emptied to another portion of the vessel

for transfer. There are several versions of

this system available.




POSITIVE DISPLACEMENT METERS are highly efficient fluid motors used

for measuring oil volumes. They consist of a measuring chamber and a

sealing section between the inlet and outlet connections (FIGURE) .These

rneters are operated by fluid pressure. The fluid stream is divided into

segments within the meter and the movement of these segments through

the meter is registered on a counter.




ELECTRIC METERING : For electric metering, the movement of the counter

transmits an electrical pulse or signal. Because each pulse represents a

discrete volume, the total number of pulses, integrated over time, represents

the volume metered. The signals are amplified, then converted and

displayed as totalized flow via electronic instrumentation.

-----------------

LEGAL PROCESSES: When oil or gas is delivered into a sales line at a

metering point, a legal custody transfer takes place. In many cases this is

accomplished before the oil or gas leaves the lease on which it is produced.

In offshore situations, the produced fluids may travel quite some distance to

shore before being separated, metered, and transferred to the sales line.

Lease Automatic Custody Transfer (LACT) refers to a system designed to

provide continuous unattended transfer of crude oil from the producer to the

pipeline. This approach is particularly useful where large numbers of wells

are located in a remote area. In addition to accurately metering the liquid,

the unit must also monitor the quality (BS&W) of the production, or obtain a

representative sample at line conditions.




Contd……LEGAL PROCESSES:

LACT units utilize positive displacement-type oil meters, and some

incorporate a capacitance probe, which determines the BS&W content of the

oil by measuring the dielectric constant of the passing fluid. If the crude is

not of pipeline quality, it is automatically diverted for reprocessing.







SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT

Introduction

If the producing bottomhole pressure becomes so low that it will not allow

the well to produce at a desired flow rate (or perhaps any flow rate!), some

sort of artificial energy supply will be needed to lift or help lift the fluid out of

the wellbore.

Energy can be supplied indirectly by injecting water or gas into the reservoir

to maintain reservoir pressure, or through a variety of artificial lift methods

that are applied at the producing well itself.

There are many artificial lift methods, however, all are variations or

combinations of three basic processes:

1. lightening of the fluid column by gas injection (gas lift);

2. Subsurface pumping (beam pumps, hydraulic pumps, electric

submersible centrifugal pumps); and

3. Piston like displacement of liquid slugs (plunger lift).




ARTIFICIAL LIFT

Introduction

The relative usage of the common artificial

lift methods in the United States is shown in

FIGURE.

Sucker rod or beam pumping is the most

common method (85%), with gas lift

second (10%), and then electrical

submersible and hydraulic pumping

about equal (2%) in usage. Plunger lift and

several variations of all these processes are

in limited use.




Introduction

The prominence of sucker rod pumping is due, in part, to the large number

of shallow, low productivity wells in the midwestern and western United

States, which are pumped with beam pumps.

If stripper well production is removed from consideration, the relative

percentages of artificial lift usages are 27% for beam pumping, 53% for gas

lift, and about 10% each for electrical submersible and hydraulic pumping.

Remember, this distribution does not always hold in specific areas. For

example, gas lift is used almost exclusively offshore where space and

operating costs are major considerations.

Also, submersible pumps are gaining in popularity in onshore areas of the

United States. Beam pumping is seldom used in parts of the world where

wells produce at high production rates.



SURFACE PRODUCTION FACILITIES: ARTIFICIAL

LIFT

Gas lift

Gas lift provides artificial lifting energy by the injection

of gas into or beneath the fluid column. The gas

decreases the fluid density of the column and lowers

the bottomhole pressure, allowing the formation

pressure to move more fluid into the wellbore.

Note the effect of decreasing the bottomhole pressure

on production rate in FIGURE. Injected gas bubbles

also expand as they rise in the tubing above their

injection point, pushing oil ahead of them up the

tubing. The degree to which each of these

mechanisms affects the well's production rate depends

on the type of gas lift method applied: continuous flow

or intermittent flow.




LIFT

Gas lift

Continuous flow gas lift relies on the constant

injection of gas-lift gas into the production stream

through a downhole valve (FIGURE). The installation

can be designed to allow for injection from the

casing/tubing annulus into the tubing (most common),

for injection into a smaller concentric tubing string

within the production tubing ("macaroni" string), or for

injection from the tubing into the casing/tubing annulus

(annular flow installation).

The fluid column above the injection point is lightened

by the aeration caused by the relatively low density

gas. The resulting drop in bottornhole pressure causes

an increase in production rate.




LIFT

Gas lift

Intermittent gas lift (FIGURE) allows for the huildup

of a liquid column of produced fluids at the bottom of

the wellbore. At the appropriate time, a finite volume of

gas is injected below the liquid and propels it as a slug

to the surface. The propelling gas may be injected at a

single point below the liquid slug or may be

supplemented by multipoint injection as the slug

moves past successive valves.

An intermitter at the surface controls the timing of

each injection-production cycle. Intermittent gas lift is

used on wells with low fluid volumes, a high

productivity index, and low bottornhole pressure, or a

low productivity index and high bottomhole pressure.

Gas lift is a very flexible artificial lift method. A properly

designed installation can produce efficiently at a rate

as high as 1000 bbl/D (159 m3/d) or as low as 50

bbl/D (7.9 m3/d).




LIFT

Gas lift valves

There are a number of gas-lift valves that are used in

gas-lift operations. They are distinguished by their

sensitivity to the casing and/or tubing pressures

needed to open and close them (FIGURE).

The casing pressure operated valve (also called a

pressure valve) requires a buildup in casing pressure

to open and a reduction in casing pressure to close.

Fluid-operated valves require a buildup in tubing

pressure to open and a reduction in tubing pressure to

close.

A throttling pressure valve is sensitive to tubing

pressure in the open position, and once opened by

casing pressure buildup, requires a reduction in tubing

or casing pressure to close.




LIFT : Gas lift valves

For a specific gas-lift design, the valves will be

located at appropriate intervals in the tubing string.

The type of valve and its location will depend on the

expected flow characteristics of the well over its

lifetime, whether continuous or intermittent gas lift is

to be used, and whether the upper valves are to be

used for simply unloading the fluid in the annulus or

for multipoint injection.

Conventional gas-lift valves are attached to gas-lift

mandrels and wireline retrievable gas-lift valves are

set in side-pocket mandrels (figure). For

conventional valves to be changed or serviced, the

entire tubing string must be pulled, while retrievable

valves can be latched and set through tubing with a

wireline unit.




Rod Pumping

Subsurface pumping can be achieved by various methods. The most

common is sucker rod pumping, where the pumping motion is transmitted

from the surface to the pump by means of a string of narrow jointed rods

placed within the tubing.




ARTIFICIAL LIFT : Rod Pumping

Rod pumping systems (figure) consist

essentially of five components:

• the subsurface pump, which displaces

the fluid at the bottom of the well and

thereby reduces bottomhole pressure;

• the rod string, which transmits power to

the pump from the surface;

• the surface unit, which transfers rotating

motion to a linear oscillation of the rod

string; and,

• the gear reducer, which controls the

speed of the motor or engine that is the

prime mover.



SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping

The subsurface pump (figure) is essentially a plunger and valve

arrangement within a tube or barrel. When the close-fitting plunger is lifted

within the barrel, it creates a low-pressure region below the plunger, which is

filled by fluid from the formation.

Simultaneously, the plunger and rods lift fluid up the tubing. The valves are

designed to open and close so that they allow fluids to enter the pump on

the upstroke and be displaced above the traveling valve on the downstroke

the fluid above the traveling valve moves one full stroke upward on the

upstroke. There is a wide variety of pumps designed for many different

applications.




The subsurface pump (figure)




The different types of API pump designations are given in the next figure.

The API (American Petroleum Institute) has designed a classification system

using the criteria listed in the following:

• tubing size

• pump bore size

• rod or tubing pump

• barrel-type

• plunger-type

• pump seating assembly location

• traveling or stationary barrel

• type of seating assembly

• barrel length

• plunger length

• extensions




The

different

types of

API pumps



SURFACE PRODUCTION

FACILITIES:

ARTIFICIAL LIFT :

Rod Pumping

The sucker rods are usually

about 25 ft (7.62 m) long and are

connected with threaded

couplings. In deep wells, a

tapered string of rods,

decreasing in diameter with

depth, can be run to maximize

strength at the point of maximum

load-the top of the string (figure).





The surface unit also varies in design and size. Typical designs are the

conventional (Class I) and the Mark II or air balanced units (Class III units)

(figure) . Unit sizes are designated by torque rating, peak load, and stroke

length.

They can range from a unit with a 16-in (.406-m) stroke and a maximum load

of 3200 lb (1451 kg), to one with a 300-in (7.62-m) stroke and a maximum

load of 47,000 lb (21,319 kg). The torque rating for the gear reducer of these

two units varies by a factor of 570.

Rod pumping meets a wide range of artificial lift needs with typical producing

rates from 5 to 600 bbl/D (.795 to 95.4 m3/d).








ARTIFICIAL LIFT : Rodless Pumping

The majority of rodless subsurface pumps fall into two categories: hydraulic

and electrical submersible centrifugal.

Hydraulic pumps rely on the use of a high-pressure power fluid pumped

from the surface to operate a downhole fluid engine. The engine, in turn,

drives a piston to pump formation fluid and spent power fluid to the surface

(figure).





Most engine/pump units can be circulated

in and out of the well for maintenance.

The power fluid system can be either

open (OPF) or closed (CPF) depending

on whether the power fluid is commingled

with the produced fluids or is returned to

the surface in a closed conduit.

In addition to the downhole equipment,

this type of pumping system requires a

surface power fluid pump and a power

fluid reservoir. The power fluid is normally

crude oil or water. Hydraulic pumps have

a fairly wide range of production rate

applications, typically 135 to 15,000 bbl/D

(21.5 to 2385 m3/d)





Electrical submersible centrifugal pumps are a second type of rodless

pumping system. In figure, we see a typical system layout. Electrical power

is supplied via a bank of transformers that convert primary line voltage to

system voltage.

A switchboard provides

instrumentation for control and

overload protection. The junction

box acts as a vent to prevent gas,

which may have migrated up the

power cable, from reaching the

electrical switchboard.

Power is transmitted through the

power cable to an electric motor

at the bottom of the tubing string.

The motor is isolated from well

fluids by a protector.





Electrical submersible centrifugal pumps…contd

Above that is a gas separator and the motor driven

pump, which normally is a multistage centrifugal

pump (figure). These pumps can handle a wide range

of rates-from 200 to 60,000 bbl/D (31.8 to 9540

m3/d).

----------------------------------

Rod and rodless pumping systems achieve a

reduction in bottornhole pressure by mechanical

displacement of fluid up the tubing.




ARTIFICIAL LIFT : Plunger lift

A third artificial lift process involves the use of gas to power a plunger the

length of the tubing string-in effect, a gas-lift powered pump that utilizes the

entire tubing string as the barrel.

Plunger lift is typically an intermediate artificial lift method for wells that

ultimately must be pumped but have a low productivity index (PI) and a high

enough gas-oil ratio to operate the plunger.

------------------------

Several variations on the methods mentioned have been proposed and

tested by producers and service companies. These include: jet pumping, a

hydraulic pump, which uses a nozzle to transfer power fluid momentum

directly to the produced fluid; chamber lift, a gas-lift installation, which allows

for production from low PI wells without the backpressure from injected gas;

and modified rod pumping unit designs, such as the winch- or pneumatic-

type pumping unit.




ARTIFICIAL LIFT : Summary

There are a variety of artificial lift methods available to the production

engineer. The particular method chosen for a given well will depend on

factors such as the pressures, fluid types, space limitations, power

requirements, well depth, and operation experience.

While gas lift is the major method employed offshore, rod pumping is the

most widely used artificial lift method onshore, an in general.



Refining, Transportation and Distribution

REFINING

BACKGROUND

B

A


CASE ‘B’ = OIL WELL:

As mentioned earlier in the „separator‟ section – As the gas and liquid enter

the larger space, the "beer bottle" effect happens. The pressure drops

further and light gases that were dissolved in the crude oil vaporize and

bubble out.

Just like the fizz in a beer when you pop the top. Natural gas is drawn off the

top of the separator, and crude oil from the side. Almost every reservoir also

has water vapor entrained in the oil and gas, and almost all of that separates

in the field separator and is drawn off the bottom. The crude oil comes out off

above the water.

The natural gas coming from this well is called associated gas.



CASE ‘A’ = GAS WELL:

The production from this well is called nonassociated gas or gas well gas.

In most cases, some oil is dissolved in the gas.

When the gas from the wellhead goes through a field separator, the heaviest

hydrocarbons drop out in the form of liquids called condensate, which are

like a very light crude oil.

Sometimes the gas production has almost no hydrocarbons heavier than

butane, in which case it is referred to as dry gas.




The production from this well is called nonassociated gas or gas well gas.

In most cases, some oil is dissolved in the gas.

When the gas from the wellhead goes through a field separator, the heaviest

hydrocarbons drop out in the form of liquids called condensate, which are

like a very light crude oil.

Sometimes the gas production has almost no hydrocarbons heavier than

butane, in which case it is referred to as dry gas.

The distinction between associated and non associated gas is not important chemically, but only from a management point of view. Natural gas consumption varies with seasonal change or may have limited market access, especially if the well is in a remote location (then called stranded gas).




Producers may have a ready market for the crude oil but not the gas. The

penalty for shutting in the gas is huge because the oil would have to be shut

in as well.

Historically, in every part of the world, unmarketable gas was flared, or

burned on site. Nowadays, in the case of stranded gas, it is more likely re-

injected into the reservoir, saving it for later production and meanwhile

enhancing the produce ability of the crude oil.

The basic constituent of natural gas is methane, but despite the fact that the natural gas has gone through a field separator, some hydrocarbons heavier than methane (but not as heavy as condensate) may still remain in the vapor stream. The natural gas may be processed in a gas processing plant, or simply gas plant (fig), for the removal of these natural gas liquids (NGLs).




Producers may have a ready market for the crude oil but not the gas. The

penalty for shutting in the gas is huge because the oil would have to be shut

in as well.

Historically, in every part of the world, unmarketable gas was flared, or

burned on site. Nowadays, in the case of stranded gas, it is more likely re-

injected into the reservoir, saving it for later production and meanwhile

enhancing the produce ability of the crude oil.

The basic constituent of natural gas is methane, but despite the fact that the

natural gas has gone through a field separator, some hydrocarbons heavier

than methane (but not as heavy as condensate) may still remain in the vapor

stream. The natural gas may be processed in a gas processing plant, or

simply gas plant (fig), for the removal of these natural gas liquids (NGLs).



GAS Plants

The NGLs consist of ethane, propane, butanes, and natural gasoline. The

first three are volatile and gaseous at room temperature. By itself natural

gasoline is liquid at room temperature, but it can remain gaseous when

mixed with enough natural gas.

Sometimes the natural gasoline and the butanes content can be large

enough, perhaps 10%or more, that during cold winter months they can

condense (liquefy) in a natural gas transmission line. The buildup of the

liquid in low spots in the line can reduce the capacity of the pipeline or, more

seriously, droplets can damage the turbines that push the gas through the

pipeline system. For that reason, some gas streams must be processed in

gas plants to remove these components.

Besides these operational aspects of removing butane and natural gasoline,

there is often an economic incentive to remove them, as well as the propane

and the ethane, at the gas plant. These streams may be worth more in other

markets than being sold as constituents of natural gas.
