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By: DR. ARKO PRAVA MUKHERJEE

© : Dr. Arko Prava Mukherjee

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BOOKS 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 © : Dr. Arko Prava Mukherjee

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Introduction

Production Drilling

II

V

Storage

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Ref. & Distr.

VII

IV

Surveys

Geology

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III Petroleum System © : Dr. Arko Prava Mukherjee

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Introduction

What is Upstream sector ? 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 © : Dr. Arko Prava Mukherjee

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Introduction

What is general stages in the Upstream sector ? Access phase – Explor. – Appraisal – Dev. planning – Production – Decomm.

Decision making?

Both in Mega – and Minor - Scale

Decision maker (Sr. Management)

Geophysicist

Geologist

HSE

2 Petroleum Engineers

Finance

Legal © : Dr. Arko Prava Mukherjee

?? + BD, PSCM

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Introduction

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.

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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

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Introduction

Source: BP Statistical review of world energy 2010

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Introduction

Source: BP Statistical review of world energy 2010

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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.

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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.

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Intro: Access Phase 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. © : Dr. Arko Prava Mukherjee 12

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 incountry from another business interest, such as downstream refining or distribution, the experience from areas could be leveraged © : Dr. these Arko Prava Mukherjee 13

Intro: Access Phase FIELD LIFE CYCLE Contd ….Step 1 : GAINING ACCESS PHASE 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. © : Dr. Arko Prava Mukherjee

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Intro: Access Phase FIELD LIFE CYCLE Contd ….Step 1 : GAINING ACCESS PHASE 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.

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Intro: Exploration 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 represents a major task. 16 : Dr. Arkocountries Prava Mukherjee

Introduction

Source: BP Statistical review of world energy 2010

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Intro: Exploration Phase 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.

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Intro: Exploration Phase 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.

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Intro: Appraisal Phase 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.

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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. : Dr. Arko Prava Mukherjee 21

Intro: Appraisal Phase 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. © : Dr. Arko Prava Mukherjee

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Intro: Development Phase 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

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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.

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Intro: Development Phase 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.

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Intro: Production Phase 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.

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Intro: Production Phase FIELD LIFE CYCLE Step 5: PRODUCTION PHASE 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.

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Intro: Production Phase FIELD LIFE CYCLE Step 5: PRODUCTION PHASE

Fig: The field life cycle and typical cumulative cash flow.

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Intro: Decommissioning phase 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. © : Dr. Arko Prava Mukherjee 29

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.

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Intro: Decommissioning phase 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.

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BOOKS

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

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© : Dr. Arko Prava Mukherjee

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Petroleum Agreements and Bidding

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.

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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)

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Petroleum Agreements and Bidding

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.

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Petroleum Agreements and Bidding

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Petroleum Agreements and Bidding

THE INVITATION TO BID 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)

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Petroleum Agreements and Bidding

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Petroleum Agreements and Bidding

THE INVITATION TO BID 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.

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Petroleum Agreements and Bidding

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.

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Petroleum Agreements and Bidding

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. © : Dr. Arko Prava Mukherjee

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Petroleum Agreements and Bidding

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 © : Dr. Arko Prava Mukherjee

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Petroleum Agreements and Bidding

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‟.

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Petroleum Agreements and Bidding

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.

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Petroleum Agreements and Bidding BLOCK AWARD The Figure below shows an example of the provisions in a PSA for converting an exploration agreement into a production agreement.

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Petroleum Agreements and Bidding

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.

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Petroleum Agreements and Bidding 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.

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Petroleum Agreements and Bidding 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.

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Petroleum Agreements and Bidding 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. © : Dr. Arko Prava Mukherjee

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Petroleum Agreements and Bidding 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

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Petroleum Agreements and Bidding UNITISATION AND EQUITY DETERMINATION Spindletop, Texas in the early 1900s

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Petroleum Agreements and Bidding UNITISATION AND EQUITY DETERMINATION 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. : Dr. Arko Prava Mukherjee 53

Petroleum Agreements and Bidding UNITISATION AND EQUITY DETERMINATION Fig: Options for the basis of equity.

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Petroleum Agreements and Bidding UNITISATION AND EQUITY DETERMINATION 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. © : Dr. Arko Prava Mukherjee 55

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?

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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?

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ORIGIN OF PETROLEUM 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.

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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. © : Dr. Arko Prava Mukherjee 60

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. © : Dr. Arko Prava Mukherjee

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PETROLEUM SYSTEM 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)

© : Dr.and Arkotrapping Prava Mukherjee Generation, migration of hydrocarbons.

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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 © : Dr.upward Arko Prava Mukherjee 63 natural barrier to the natural movement of fluids.

ASSIGNMENT:

PETROLEUM SYSTEM

SUBMISSION TIME :

ONE WEEK

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Exploration 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’. © : Dr. Arko Prava Mukherjee

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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). © : Dr. Arko Prava Mukherjee

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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 .

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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. © : Dr. Arko Prava Mukherjee

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Exploration GEOLOGICAL TOOLS….contd 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.

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Exploration GEOLOGICAL TOOLS….contd

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Exploration GEOLOGICAL TOOLS….contd

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Exploration GEOLOGICAL TOOLS….contd

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Exploration GEOLOGICAL TOOLS….contd

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Exploration GEOLOGICAL TOOLS….contd

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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 © : Dr. Arko Prava Mukherjee

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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.

Loss of information due to limited number of measurement points. © : Dr. Arko Prava Mukherjee

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Exploration 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.

Principle of gravity surveying. © : Dr. Arko Prava Mukherjee

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Exploration 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.

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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).

Source: http://www.ga.gov.au/ausgeonews/ausg eonews200712/productnews.jsp

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Exploration 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.

Principle of magnetic surveying. © : Dr. Arko Prava Mukherjee

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Exploration 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.

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Exploration

Fig: Principle of CSEM seabed logging.

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Exploration 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.

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Geophysical methods of 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.

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) 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). : Dr. Arko Prava Mukherjee 87

Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) 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). © : Dr. Arko Prava Mukherjee

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) Principles of Seismic Surveying

Changes in acoustic impedance (AI)Prava giveMukherjee rise to reflected seismic waves. © : Dr. Arko

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) Principles of Seismic Surveying

„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.

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) Principles of Seismic Surveying

Convolution of a reflected seismic wave. © : Dr. Arko Prava Mukherjee

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and Processing) Principles of Seismic Surveying

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.

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition and 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: Dr. this section). Arko Prava Mukherjee

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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 © and : Dr. Arko Pravato Mukherjee 95 dependent on the offset, velocity depth the reflector.

Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition)

Source - receiver geometry for multiple offsets. © : Dr. Arko Prava Mukherjee

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition) 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 © : Dr. Arko Prava Mukherjee 97 hundred meters.

Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition) 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 © : Dr. Arko Prava Mukherjee sources.

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition) 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

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition) 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 multiazimuth 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.

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Geophysical methods of Exploration SEISMIC METHODS (Seismic Data Acquisition)

Principle of multi-azimuth surveying.

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Geophysical methods of Exploration 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. © : Dr. Arko Prava Mukherjee

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Principles of borehole seismic surveying. © : Dr. Arko Prava Mukherjee

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Geophysical methods of Exploration 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.

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Geophysical methods of Exploration SEISMIC DATA PROCESSING 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.

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Geophysical methods of Exploration SEISMIC DATA PROCESSING 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

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Geophysical methods of Exploration SEISMIC DATA PROCESSING 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).

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Geophysical methods of Exploration SEISMIC DATA PROCESSING 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.

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Geophysical methods of Exploration 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

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Geophysical methods of Exploration 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. : Dr. Arko Prava Mukherjee 110

Geophysical methods of Exploration

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. © : Dr. Arko Prava Mukherjee 111

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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. © : Dr. Arko Prava Mukherjee

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SEISMIC OUTPUT:

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Geophysical methods of Exploration Exercise: Interpret the Seismic profile (data) and mark all the structural features like folds (anticline, syncline), unconformity, prominent bedding plan

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Geophysical methods of Exploration Exercise: Interpret the Seismic profile (data) and mark all the structural features like folds (anticline, syncline), unconformity, prominent bedding plan

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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.

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Drilling Engineering

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). © : Dr. Arko Prava Mukherjee

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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. © : Dr. Arko Prava Mukherjee

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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. © : Dr. Arko Prava Mukherjee

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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 © : Dr. Arko Prava Mukherjee

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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.

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Drilling Engineering 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 © : Dr. Arko Prava Mukherjee South China Sea and the shelf GoM.

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Drilling Engineering 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 © : Dr. Arko Prava Mukherjee wells.

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Drilling Engineering 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 © : Dr. Arko Prava Mukherjee machinery. E.g Deep water horizon

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Drilling Engineering RIG TYPES DRILLING SHIPS : are used for deep and very deep water work. They can be less stable in rough seas than semisubmersibles. However, modern highspecification 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 © : Dr. Arko Prava Mukherjee

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Drilling Engineering RIG TYPES DRILLING SHIPS :

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering RIG TYPES TENDER-ASSISTED DRILLING :

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DRILLING SYSTEMS AND EQUIPMENTS

Drilling Engineering

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 safety considerations © : and Dr. Arko Prava Mukherjee 134

Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS ROTARY RIG:

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Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS

DETAILS OF ROTARY RIG:

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Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS ROTARY RIG:

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

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Drilling Engineering 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.

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Drilling Engineering 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.

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Drilling Engineering 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.

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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.

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Drilling Engineering 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 impactresistant 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering TYPES OF DRILL BITS DIAMOND BIT :

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Drilling Engineering 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.

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Drilling Engineering 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.

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Drilling Engineering SECTIONS OF THE DRILL STRING The DRILL COLLARS (DCs) are thickwalled, 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.

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Drilling Engineering SECTIONS OF THE DRILL STRING 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering SECTIONS OF THE DRILL STRING 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.

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS

DETAILS OF ROTARY RIG:

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Drilling Engineering DRILLING SYSTEMS AND EQUIPMENTS :

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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.

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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.

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Drilling Engineering 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. © : Dr. Arko Prava Mukherjee

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

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Drilling Engineering 3. CIRCULATING (Pumps, Standpipe, Return line, Solids control equipment) • 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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 © : Dr. Arko Prava Mukherjee 160 returning to the surface.

Drilling Engineering 4. CONTROLLING (Blowout preventers, Choke system) • 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.

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Drilling Engineering 4. CONTROLLING (Blowout preventers, Choke system)

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Drilling Engineering 4. CONTROLLING (Blowout preventers, Choke system) •

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.

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Drilling Engineering 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.

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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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering DRILLING FLUIDS

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.

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Drilling Engineering DRILLING FLUIDS 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering DRILLING FLUIDS 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 © : Dr. Arko Prava Mukherjee 168 100-200 ft/ min.

Drilling Engineering DRILLING FLUIDS Remove Cuttings from the Hole: (FIGURE).

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Drilling Engineering DRILLING FLUIDS 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.

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Drilling Engineering DRILLING FLUIDS 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 © : Dr. Arko Prava Mukherjee 171

Drilling Engineering DRILLING FLUIDS 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.

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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). © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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).

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Drilling Engineering DRILLING PROGRESS … contd

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Drilling Engineering DRILLING PROGRESS … contd

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Drilling Engineering DRILLING PROGRESS … contd 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 © : Dr. Arko Prava Mukherjee 177 tightened with the tongs

Drilling Engineering DRILLING PROGRESS … contd

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Drilling Engineering DRILLING PROGRESS … contd 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) © : Dr. Arko Prava Mukherjee

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Drilling Engineering DRILLING PROGRESS … contd POOH (PULLING OUT OF HOLE) or Trip out….contd

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Drilling Engineering DRILLING PROGRESS … contd POOH (PULLING OUT OF HOLE) or Trip out….contd

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Drilling Engineering DRILLING PROGRESS … contd 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering 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.

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Drilling Engineering DIRECTIONAL DRILLING Although some situations require „directional drilling‟ approach on land (FIGURE), it is most common in offshore regions.

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Drilling Engineering DIRECTIONAL DRILLING Directionally drilled wells will usually be drilled according to one of three basic hole patterns (FIGURE).

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Drilling Engineering DIRECTIONAL DRILLING 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 techniques:

several

• 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 : Dr. Arkoto Prava Mukherjee the hole. 187 conventional drillstem can be© used continue

Drilling Engineering DIRECTIONAL DRILLING DOWNHOLE MOTORS….contd

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Drilling Engineering DIRECTIONAL DRILLING 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.

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Drilling Engineering DIRECTIONAL DRILLING WITH JET BITS …. contd

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Drilling Engineering DIRECTIONAL DRILLING 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.

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Drilling Engineering DIRECTIONAL DRILLING 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering DIRECTIONAL 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.

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Drilling Engineering DIRECTIONAL DRILLING TRACKING THE TRAJECTORY …. Contd Mud turbine

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Drilling Engineering DIRECTIONAL DRILLING TRACKING THE TRAJECTORY …. Contd 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).

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Drilling Engineering DIRECTIONAL DRILLING TRACKING THE TRAJECTORY …. Contd

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Drilling Engineering 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.

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Drilling Engineering CASING AND CEMENTATION 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 largediameter pipe.

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Drilling Engineering CASING AND CEMENTATION 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.

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Drilling Engineering CASING AND CEMENTATION 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.

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Drilling Engineering CASING AND CEMENTATION •

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.

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Drilling Engineering CASING AND CEMENTATION •

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).

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Drilling Engineering CASING AND CEMENTATION 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 :

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Collapse load: originates from the hydrostatic pressure of drilling fluid, cement slurry outside the casing and later on by „moving formations‟, for example salt.

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

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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.

•

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Drilling Engineering CASING AND CEMENTATION 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.

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Drilling Engineering CASING AND CEMENTATION 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 © : Dr. and Arko Prava annular space between the hole theMukherjee casing.

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Drilling Engineering CASING AND CEMENTATION 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.

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Drilling Engineering CASING AND CEMENTATION 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 © : Dr. Arko Prava Mukherjee formations.

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Drilling Engineering CASING AND CEMENTATION 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. © : Dr. Arko Prava Mukherjee

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Drilling Engineering CASING AND CEMENTATION 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.

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“DRILLING AHEAD”

Drilling Engineering

• 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. : Dr. Arko Prava Mukherjee

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“DRILLING AHEAD”

Drilling Engineering

• 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.

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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:

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Formation Evaluation 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.

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Formation Evaluation CORING • To gain an understanding of the composition of the reservoir rock, interreservoir 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.

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Formation Evaluation

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)

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Formation Evaluation

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. © : Dr. Arko Prava Mukherjee

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Formation Evaluation

CORING…contd

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Formation Evaluation

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. © : Dr. Arko Prava Mukherjee

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Formation Evaluation

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).

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Formation Evaluation

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.

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Formation Evaluation

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.

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Formation Evaluation

SIDEWALL SAMPLING AND CORING

Sidewall coring tool

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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.

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Formation Evaluation and Well Logging 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. © : Dr. Arko Prava Mukherjee

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Formation Evaluation and Well Logging 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.

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Formation Evaluation and Well Logging PRESSURE MEASURMENTS SAMPLING…Contd

AND

FLUID

•

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. © : Dr. Arko Prava Mukherjee

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Formation Evaluation and Well Logging PRESSURE MEASURMENTS AND FLUID SAMPLING…Contd

MDT tool configuration for permeability measurement.

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Formation Evaluation and Well Logging 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. )

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Formation Evaluation and Well Logging 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

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Formation Evaluation and Well Logging WIRE LINE LOGGING ELECTRICAL TOOL)

LOGS

(INDUCTION

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.

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Formation Evaluation and Well Logging WIRE LINE LOGGING SP LOG EXAMPLE

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Formation Evaluation and Well Logging WIRE LINE LOGGING

: TYPES OF LOGGING TOOLS

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. )

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Formation Evaluation and Well Logging WIRE LINE LOGGING

: TYPES OF LOGGING TOOLS

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. © : Dr. Arko Prava Mukherjee

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Formation Evaluation and Well Logging WIRE LINE LOGGING

: TYPES OF LOGGING TOOLS

RADIOACTIVE LOGS: GAMMA RAY LOG

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Formation Evaluation and Well Logging WIRE LINE LOGGING : GAMMA RAY LOG EXAMPLE

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Formation Evaluation and Well Logging WIRE LINE LOGGING

: TYPES OF LOGGING TOOLS

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.

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Formation Evaluation and Well Logging WIRE LINE LOGGING

: TYPES OF LOGGING TOOLS

ACOUSTICAL LOG EXAMPLE

Sonic log responses in a sandstone and mudstone sequence: In the sandstones have a lower sonic velocity than the shales (mudstones).

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Types of Well Logging Tools

A vast variety of logging tools are in existence

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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.

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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). © : Dr. Arko Prava Mukherjee

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Well Logging Tools LOGGING/MEASURMENT WHILE DRILLING (LWD / MWD TOOL): 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. © : Dr. Arko Prava Mukherjee

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Well Logging Tools LOGGING/MEASURMENT WHILE DRILLING (LWD / MWD TOOL):

Schlumberger geosteering tool with LWD.

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Well Logging Tools LOGGING/MEASURMENT WHILE DRILLING (LWD / MWD TOOL):

BakerHughes Inteq „Pentacombo‟ tool. © : Dr. Arko Prava Mukherjee

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Well Logging Tools LOGGING/MEASURMENT WHILE DRILLING (LWD / MWD TOOL): 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.

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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.

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Perforation and Well Activation BASIC WELL COMPLETION TECHNOLOGY 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

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Perforation and Well Activation BASIC WELL COMPLETION TECHNOLOGY Contd….. Types of completion: •

the liner completion - which is not cemented and not "tied back" to the surface

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Perforation and Well Activation BASIC WELL COMPLETION TECHNOLOGY 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.

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Perforation and Well Activation BASIC WELL COMPLETION TECHNOLOGY 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. © : Dr. Arko Prava Mukherjee

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Perforation and Well Activation 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.

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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.

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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. © : Dr. Arko Prava Mukherjee

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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."

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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."

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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.)

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Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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 © : Dr. Arko Prava Mukherjee 261 on its own.

Perforation and Well Activation Contd…..COMPLETION PROCEDURE 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.

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Perforation and Well Activation 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.

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION 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. © : Dr. Arko Prava Mukherjee

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION 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.

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION When a charge is fired (FIGURE), the metallic liner collapses to form a stream of high-pressure, highvelocity 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.

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Perforation and Well Activation 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).

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION 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.

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION 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. © : Dr. Arko Prava Mukherjee

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Perforation and Well Activation COMPLETION PROCEDURE : PERFORATION 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.

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Perforation and Well Activation 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. © : Dr. Arko Prava Mukherjee

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Perforation and Well Activation COMPLETION PROCEDURE : WELL STIMULATION 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.

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Perforation and Well Activation COMPLETION PROCEDURE : WELL STIMULATION

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Perforation and Well Activation COMPLETION PROCEDURE : WELL STIMULATION

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Perforation and Well Activation 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

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Perforation and Well Activation COMPLETION PROCEDURE : SAND CONTROL 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).

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Perforation and Well Activation COMPLETION PROCEDURE : SAND CONTROL

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).

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Perforation and Well Activation COMPLETION PROCEDURE : SAND CONTROL 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.

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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 © : Dr. Arko Prava Mukherjee 280 involved in the exploration an production effort – DYNAMIC MODELLING

Production Engineering 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.

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Production Engineering COMPLETION COMPONENTS 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.

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Production Engineering COMPLETION COMPONENTS

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.

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS : TUBING 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.

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Production Engineering 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.

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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).

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Production Engineering COMPLETION COMPONENTS TUBING COMPONENTS

:

A) PACKERS: Retrievable packers

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Production Engineering COMPLETION COMPONENTS : TUBING COMPONENTS 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.

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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.

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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.

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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.

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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).

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Production Engineering COMPLETION COMPONENTS COMPONENTS

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TUBING

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.

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Production Engineering COMPLETION COMPONENTS COMPONENTS

:

TUBING

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. © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS : TUBING 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. Sidepocket mandrels allow for wireline placement and retrieval of gas-lift valves within the tubing string.

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Production Engineering COMPLETION COMPONENTS : 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. .

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Production Engineering COMPLETION COMPONENTS : TUBING COMPONENTS PACKERS: Subsurface Safety Valve: .

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Production Engineering COMPLETION COMPONENTS : TUBING COMPONENTS

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.

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Production Engineering 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.

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS 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.

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Production Engineering COMPLETION COMPONENTS : FLOW CONTROL EQUIPMENTS

SURFACE

The FIGURE shows a typical surface flow control installation for a multiple casing string, single tubing string, flowing well.

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Production Engineering COMPLETION COMPONENTS : 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.

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS 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. © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS : 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-tometal 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"). © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS

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.

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS

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. © : Dr. Arko Prava Mukherjee

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS FIGURES below show examples of surface flow control equipment for a variety of completions.

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Production Engineering COMPLETION COMPONENTS : SURFACE FLOW CONTROL EQUIPMENTS 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.

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering 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

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION SEPARATION

FACILITIES:

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.

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Production Engineering SURFACE PRODUCTION SEPARATION

FACILITIES:

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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION SEPARATION

FACILITIES:

Contd….WORKING PRINCIPLE: 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.

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Production Engineering SURFACE PRODUCTION SEPARATION

FACILITIES:

Contd….WORKING PRINCIPLE: 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION Contd….WORKING PRINCIPLE: 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.

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Production Engineering SURFACE PRODUCTION SEPARATION

FACILITIES:

Contd….WORKING PRINCIPLE: 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION Contd….WORKING PRINCIPLE: 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION Contd….WORKING PRINCIPLE: 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 lowpressure applications, an internal, float-operated lever valve is employed.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION Contd….WORKING PRINCIPLE: 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION SEPARATOR TYPES: VERTICAL: Vertical separators are often used an low to intermediate gasliquid 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES: HORIZONTAL: Horizontal separators, therefore , are usually more cost efficient, especially far high to medium gas-liquid ratio streams, for liquidliquid 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES:

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES:

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES: 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION 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.

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Production Engineering 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES: OIL TREATMENT

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Production Engineering SURFACE PRODUCTION FACILITIES: SEPARATION : 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).

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Production Engineering SURFACE PRODUCTION FACILITIES: 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: 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 trialand-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 © : Dr. Arko emulsions. Prava Mukherjee 335

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SURFACE PRODUCTION FACILITIES: 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. © : Dr. Arko Prava Mukherjee

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SURFACE PRODUCTION FACILITIES: 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.

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SURFACE PRODUCTION FACILITIES: SEPARATION : 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.

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Production Engineering

SURFACE PRODUCTION FACILITIES: SEPARATION : SEPARATOR TYPES: OIL TREATMENT : ELECTROSTATIC TREATERS

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Production Engineering

SURFACE PRODUCTION FACILITIES: SEPARATION : 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.

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Production Engineering

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.

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Production Engineering

SURFACE PRODUCTION FACILITIES: OIL METERING 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 heatertreaters, 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

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SURFACE PRODUCTION FACILITIES: OIL METERING

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Production Engineering

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. © : Dr. Arko Prava Mukherjee

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SURFACE PRODUCTION FACILITIES: OIL METERING 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.

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SURFACE PRODUCTION FACILITIES: OIL METERING 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. Dr. Arko Prava Mukherjee 346

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SURFACE PRODUCTION FACILITIES: OIL METERING 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.

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SURFACE PRODUCTION FACILITIES: OIL METERING

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Production Engineering

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). © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION ARTIFICIAL LIFT

FACILITIES:

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.

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT 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. © : Dr. Arko Prava Mukherjee

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Production Engineering 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL 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 © : Dr. Arko Prava Mukherjee bbl/D (7.9 m3/d).

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL 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. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: 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.

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Production Engineering 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.

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping The subsurface pump (figure)

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping

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 © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping

The different types of API pumps

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Production Engineering SURFACE FACILITIES:

PRODUCTION

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).

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping 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).

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rod Pumping

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Production Engineering SURFACE PRODUCTION FACILITIES: 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).

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rodless Pumping 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) © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rodless Pumping 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 © : Dr. Arko Prava Mukherjee fluids by a protector.

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Production Engineering SURFACE PRODUCTION FACILITIES: ARTIFICIAL LIFT : Rodless Pumping 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).

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Rod and rodless pumping systems achieve a reduction in bottornhole pressure by mechanical displacement of fluid up the tubing. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: 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 pneumatictype pumping unit. © : Dr. Arko Prava Mukherjee

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Production Engineering SURFACE PRODUCTION FACILITIES: 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.

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Refining, Transportation and Distribution REFINING BACKGROUND

A

B

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Refining, Transportation and Distribution 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.

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Refining, Transportation and Distribution 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.

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Refining, Transportation and Distribution 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 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). © : Dr. Arko Prava Mukherjee

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Refining, Transportation and Distribution CASE ‘A’

= GAS WELL:

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 reinjected 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).

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Refining, Transportation and Distribution CASE ‘A’

= GAS WELL:

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 reinjected 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).

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Refining, Transportation and Distribution 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. © : Dr. Arko Prava Mukherjee

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