introduction to completion.pdf

INTRODUCTION TO COMPLETIONS Contents

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Introduction .................................................. 1 Definition ...................................................... 2 Completion History and Evolution ................ 3 Reservoir Drive Mechanisms ....................... 4 Dissolved Gas Drive .......................... 4 Gas Cap Drive ................................... 4 Water Drive ........................................ 5 Artificial Lift ......................................... 5 Completion Classification ............................. 6 Openhole or Barefoot Completions .... 6 Perforated Completions ..................... 8 Naturally Flowing Completions .......... 8 Pumped Production Completions ...... 8

Contents

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Single Zone Completions .................. 8 Multiple Zone Completions ................ 9 Phases of Well Completion .......................... 9 Establish Objectives and Design Criteria ............................................... 10 Constructing the Wellbore ................. 11 Perforation and Component Installation ......................................... 17 Stimulation ......................................... 18 Initiating Production ........................... 20 Production Evaluation and Monitoring .......................................... 20 The DEE Cycle ............................................ 20

Introduction After a well has been drilled, it must be properly completed before it can be put into production. A complex technology has evolved around the techniques and equipment developed for this purpose. Consequently, the selection of materials, equipment and techniques should only be made following a thorough investigation of the factors which are specific to the reservoir, wellbore and production system under study.

There are three basic requirements of any completion (in common with almost every oilfield product or service). A completion system must provide a means of oil or gas production (or injection) which is;

This manual has been prepared to outline the planning and execution processes involved in completing wells for oil or gas production or injection. Several of the topics reviewed are included in, or are closely associated with, the range of services and products offered by the Schlumberger organization or alliance partners. These subjects are presented in greater detail to enable a clearer understanding of the technology and help identify potential applications of Schlumberger technology.

• Economic

In support of the topics given a more general explanation, an extensive reference and further reading list is provided in Appendix I. Combining this manual with the reference resources will enable engineers to obtain a working knowledge of most completion design and installation procedures. However, developing familiarity and expertise with specific completion technology often requires experience within a particular operating environment.

• Safe • Efficient

Current industry conditions may force operators to place undue emphasis on the economic requirement of completions. However, as will be demonstrated later, a nonoptimized completion system may compromise long-term company objectives. For example, if the company objective is to maximize the recoverable reserves of a reservoir or field, a poor or inappropriate completion design can seriously jeopardize achievement of the objective as the reservoir becomes depleted. In short, it is the technical efficiency of the entire completion system, viewed alongside the specific company objectives, which ultimately determines the completion configuration and equipment used.

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HISTORY/EVOLUTION OF COMPLETIONS

1300

Marco Polo reports wells on shore of Caspian Sea

1922

Simple hole-survey tools introduced

1814

First well to produce oil - 475 ft

1925

API addresses tooljoint threads

1822

Rudimentary art of drilling established

1926

First electric submersible pump used

1861

First recorded blowout

1927

First electric log run (Schlumberger)

1863

Screwed casing joints developed

1930

Well depths exceed 10,000 ft

1880

Standardization of casing begins

1932

First gravel pack job

1882

Straddle rubber wall packer developed

1933

First gun perforation job

1890

First extensive casing program

1943

First subsea completion (Lake Eire, U.S.A.)

1895

Henry Ford builds the first commercial automobile

1958

Thru-tubing workover techniques developed

1905

Casing cemented for the first time

1958

Wireline retrievable SSSV developed (Camco)

1910

Drillpipe tooljoints introduced

1960

Cement bond log developed

1911

First gas lift device

1967

Computerized well data monitoring developed

1913

First dual completed well

1969

First coiled tubing job (Bowen)

Fig. 1. Key events in the history and evolution of oil and gas well completions.

Definition Well completion processes extend far beyond the installation of wellbore tubulars and equipment. To highlight this fact, the following definitions are presented. To the majority of client organizations, completions are:

The methodology and technology required to produce recoverable reserves (reservoir to surface). The application of completion methodology and technology requires:

The design, selection and installation of tubulars, tools and equipment located in the wellbore for the purpose of conveying, pumping or controlling production or injection fluids. Under this definition, installing and cementing the production casing or liner, as well as logging, perforating and testing are part of the completion process. In addition, complex wellhead equipment and processing or storage requirements effect the production of a well so may have some bearing on the design and configuration of the completion.

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be gained from reducing the number of wellbores required for any reservoir development. However, fewer, but more efficient wellbores require a greater emphasis to be placed on the design, selection and installation of the completion equipment.

Completion History and Evolution As the understanding of reservoir and production performance has evolved, then so too have the systems and techniques put in place as part of the completion process.

Horizontal wellbores, and the technology associated with their completion are becoming common in many fields. Drilling extended reach wells often means that well servicing and intervention options are severely restricted, further emphasizing the importance of correct design and installation of the initial completion equipment.

Early wells were drilled in very shallow reservoirs which were sufficiently consolidated to prevent caving. As deeper wells were drilled, the problems associated with surface water prompted the use of a casing or conductor to isolate water and prevent caving of the wellbore. Further development of this process led to fully cased wellbores in which the interval of interest is selectively perforated.

In all cases, achieving the completion objectives, and subsequent production targets are a result of careful planning and preparation.

Modern completions are now commonly undertaken in deep hot and difficult conditions.

The introduction of key technologies and timing of events that have significantly influenced oil and gas well completions are shown in Fig 1.

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With the simultaneous improvement in seismic interpretation and drilling technology, wellbores can be precisely placed to optimize production and enable effective reservoir management. There are clear economic benefits to

Operational Phase/Cost Category

Fig. 2. Well cost breakdown example (10,000 ft land well).

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The cost breakdown example shown in Fig. 2 was prepared for a 10,000ft land well. Due to the variations in specific drilling and completion conditions and options, it is difficult to present data for a "typical well". However, in the example shown, "completion equipment" accounted for approximately 10% of the total cost for the well.

When the reservoir drive is unable to provide sufficient energy to overcome the hydrostatic pressure exerted by the fluid in the wellbore, artificial lift will be required to sustain production.

Reservoir Drive Mechanisms

In a dissolved gas drive reservoir, the oil contains dissolved gas. A pressure drop, or drawdown, causes the gas to escape from the oil, thereby forcing fluid through the reservoir toward the wellbore. In addition, the gas assists in lifting fluids to the surface (Fig. 3).

Reservoirs are generally classified by the type of drive mechanism. As hydrocarbons are formed and accumulated, energy is stored within the reservoir which, under favorable conditions, enables the flow of oil and gas to the wellhead. Three basic types of drive mechanisms are most commonly encountered.

Dissolved Gas Drive

Generally considered the least effective reservoir drive mechanism, dissolved gas drive typically yields only 15% to 25% of the oil originally contained in the reservoir.

• Dissolved gas Gas Cap Drive • Gas cap • Water drive In practice, most reservoirs produce under a combination of these primary drive mechanisms.

Some reservoirs contain more gas than can be dissolved in the oil under the reservoir pressure and temperature conditions. The surplus gas, rises to the top of the reservoir and forms a gas cap over the oil. The gas expands to drive the oil toward the wellbore (Fig. 4).

Cap rock

Reservoir

Basement

Fig. 3. Dissolved gas drive reservoir.

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Gas cap drive is more effective then dissolved gas drive typically yielding from 25% to 50% of the oil contained in the reservoir. Water Drive When the formation containing an oil reservoir is uniformly porous and is continuous over a large area, salt water generally is present in surrounding parts of the same formation. These vast quantities of water provide a store of energy which can aid the production of oil and gas. The energy comes from the expansion of water as pressure in the petroleum reservoir is reduced through the production of oil and gas. Water is generally considered incompressible, but will actually compress and expand about one part in 2500 per 100 psi change in pressure. When the enormous quantities of water present are considered, this expansion results in a significant amount of energy which can aid the drive of reservoir fluids to surface. The water also moves and displaces oil and gas in an upward direction out of the lower parts of the reservoir (Fig. 5).

Water drive is the most efficient primary drive mechanism, capable of yielding up to 85% of the original oil in place. This process is often supplemented by the injection of treated salt water into the reservoir to maintain the pressure and 'sweep' the oil toward the well bore. Artificial Lift When the reservoir does not, or can no longer, provide sufficient energy to produce fluid at an economical rate, some assistance through artificial lift may be required. There are four basic types of artificial lift (see Section 5), rod pump, hydraulic lump, electric submersible pump and gas lift. Each system having advantages/disadvantages that are considered during a completion equipment selection process. Only gas lift is compatible with all of the reservoir drive mechanisms previously identified.

Gas cap

Cap rock

Reservoir

Basement

Fig. 4. Gas cap drive reservoir.

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Cap rock

Reservoir

Water drive

Fig. 5. Water drive reservoir. Completion Classification There are several ways of classifying or categorizing oil and gas well completions. The most common criteria for classification include the following. • Wellbore/reservoir interface, i.e., open-hole or cased hole completion. • Production method, i.e., natural flowing or pumped production. • Producing zones, i.e., single zone or multiple zone production.

The production casing or liner is set and cemented in the reservoir cap rock leaving the wellbore through the reservoir open (Fig. 6a). Where possible, the final section through the pay zone is drilled using non-damaging fluids, or is drilled in an underbalanced condition. This completion technique is now almost entirely abandoned except for a few low pressure formations and in highly specialized conditions where formation damage from drilling fluids is severe. To prevent an unstable formation from collapsing and plugging the wellbore, slotted screen or perforated liners may be placed across the open hole sections.

Openhole or Barefoot Completions Barefoot completions are only feasible in reservoirs with sufficient formation strength to prevent caving or sloughing. In such completions there exists no means of selectively producing or isolating intervals within the reservoir or openhole section.

External gravel packs may also be used to control sand production in poorly consolidated reservoirs. In such cases, it is common to underream the interval of interest (Fig. 6b)

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Cap Rock

(a) Openhole completion

Reservoir

(b) Gravel pack or uncemented liner

Fig. 6. Openhole completions.

Cap Rock

(a) Cemented Casing

(b) Cemented Liner Reservoir

Fig. 7. Openhole completions.

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Perforated Completions The evolution and development of efficient and reliable perforating tools and logging services has enabled complex completions to be designed with a high degree of efficiency and confidence. Modern perforating charges and techniques are designed to provide a clear perforation tunnel through the damaged zone surrounding the wellbore. This provides access to undamaged formation allowing the reservoir to be produced to its full capability. Cased and cemented wells generally require less complex pressure control procedures during the early stages of installing the completion components.

considerations must be reviewed at the time of initial completion to avoid unnecessary expense and interruption to production. Pumped Production Completions All pumped or artificially lifted completions require the placement of specialized downhole components. Such components are electrically or mechanically operated, or are precision engineered devices. These features often mean the longevity or reliable working life of a pumped completion is limited. In addition, the maintenance or periodic workover requirements will generally be greater than that of naturally flowing completions.

Efficient reservoir interpretation and appraisal techniques combined with a high degree of depth control, enables selective perforating. This helps ensure the successful completion and production of modern-day oil and gas wells by precisely defining which zones of the reservoir will be opened for flow (Fig. 7).

Pumped or assisted lift production methods currently in use include the following.

Multiple zone completions are often used in reservoirs with complex structures and unusual production characteristics. The ability to select and control the production (or injection) of individual zones is often the key to ensuring the most efficient production regime for the field or reservoir. Consequently, modern multiple completions may be complex but maintain a high degree of flexibility and control of production.

• Electric submersible pump

Naturally Flowing Completions Wells completed in reservoirs which are capable of producing without assistance are typically more economic to produce. However, in high-temperature, high-pressure applications, a great deal of highly specialized engineering and design will be required to ensure the safety requirements are met. In general, naturally flowing wells require less complex downhole components and equipment. In addition, the long-term reliability and longevity of the downhole components is generally better than that of pumped completions. In many cases, wells may be flowed naturally during the initial phases of their life, with some assistance provided by artificial lift methods as the reservoir depletes. Such

• Rod pump • Gas lift

• Plunger lift • Jet pump Single Zone Completion In single zone completions, it is relatively straightforward to produce and control the interval of interest with the minimum of specialized wellbore or surface equipment. Since typically one conduit or tubing string is involved, the safety, installation and production requirements can be easily satisfied. In most single zone completions, a packer (or isolation device) and tubing string is used. This provides protection for the casing or liner strings and allows the use of flow control devices to control production. The complexity of the completion is determined by the functional requirements and economic viability. Several contingency features may be installed at a relatively minor cost at the time of initial installation. Consequently, close consideration must be given to such options during the initial design phase.

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Multiple Zone Completions Multiple zone completions are obviously designed to produce more than one zone of interest. However, there are many possible configurations of multiple zone completion, some of which allow for selective, rather than simultaneous production. For a reservoir having multiple pay zones there are four basic completion options. • Produce the zones sequentially through a single tubing string. • Produce several zones simultaneously through multiple tubing strings. • Produce several zones, commingled through a single production string. • Drill and complete a separate well for each zone of interest. Selection of the most appropriate option must follow a careful study of the specific conditions encountered. The equipment installed to allow the necessary flexibility and production options may be complex (Fig 8). Phases of Well Completion Since the ultimate efficiency of a completion is determined by operations and procedures executed during almost every phase of a wells life, a continual review and monitoring process is required. In the majority of cases, a sequential and logical approach to the design and execution process is required. Typically this can be summarized as follows. • Establish objectives and design criteria

Fig. 8. Multiple zone completion configuration example.

• Constructing the wellbore • Installation of the completion components • Initiating production • Production evaluation and monitoring

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As in all design and execution processes, the acquisition of accurate or representative data is essential to the timely achievement of the stated objectives. The level of accuracy required will vary with the data type–from the assumption of essential reservoir formation and fluid properties to more general properties which can more easily be measured (Fig 9).

1.5.1 Establish Objectives and Design Criteria This initial phase may be summarized as the collection of data pertaining to the reservoir, wellbore and production facility parameters. This data is considered alongside constraints and limitations which may be technical or non technical in nature, e.g., company policy. Some flexibility may be required, especially in exploration or development wells, where there are several unknown or uncertain parameters.

3 Completion– Can be controlled.

3

2 Reservoir properties– Can be measured.

2

1

1 Reservoir boundary– Can be estimated.

Fig. 9. Principal factors affecting a wells performance.

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The principal factors affecting the performance of any well relate to the three areas illustrated in Figure 9. Of these, many of the fluid and reservoir properties can be measured or inferred from measurements. However, in general they cannot be controlled. By contrast, almost all elements of a completion can be controlled and appropriate selection will therefore affect well performance.

• Formation damage (fluid invasion)

The objectives for which a completion system is designed vary, however, the following points may be regarded as fundamental and will have some bearing in most applications.

Only in very rare circumstances can a wellbore be constructed (drilled and cemented) without any damage to the reservoir occurring. The completion and perforation process presents an opportunity for early damage to be bypassed, however, poorly designed and executed operations may result in even further damage being caused.

• Ensure potential for optimum production (or injection).

• Completion geometry (wellbore profile) • Fluid behavior (multiphase flow) • Geology (fractures and heterogeneity)

• Provide for adequate monitoring and servicing.

• Ensure cost efficient installation and operation.

Once in production, the wellbore conditions, reservoir parameters and the characteristics of reservoir fluids may result in the deposition of scale, wax or asphaltenes in or near the wellbore, causing additional skin effect. Workover operations performed later in the life of a well, especially applications requiring the well to be killed, also present a risk of damage. Consequently, the risk of reservoir damage is present throughout the life of a well.

1.5.2 Constructing the Wellbore

Drilling and Cementing

The principal objectives associated with wellbore construction will typically include:

Filtrate damage - reduced permeability caused by interaction of drilling fluid filtrate, the reservoir rock and/or the fluids within it (Fig. 10). Risk of damage is reduced by careful fluid selection or treatment of base fluid, e.g., freshwater muds tend to be more damaging than oil based muds.

• Provide some flexibility for changing conditions, applications or contingency measures. • Contribute to efficient field/reservoir development and production.

• Efficiently drill the formation while causing the minimum practicable near wellbore damage. • Acquire wellbore survey and reservoir test data used to identify completion design constraints. • Prepare the wellbore through the zone of interest for the completion installation phase (run and cement production casing or liner and preparation for sand control or consolidation services). There are many issues which directly, or indirectly, influence the process of wellbore design and construction. The examples provided below can have significant effect on the productivity of a well. In addition, the effects are not always consistent. For example, in one case impaired vertical permeability may constrain production. In another case, the same condition may be helpful in reducing gas or water coning.

Filter-cake formation - not generally a problem in perforated wells, may effect open-hole or special gravel pack completions. Solids migration - Solids from the drilling fluid can plug vugs and natural fractures present in some reservoir formations. If drilling losses have been controlled with LCM (lost circulation material) the effect can be severe and the damage difficult to remove if the LCM is not acid soluble. Cement filtrate - as for drilling fluid, the effect of cement filtrate can be damaging.

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Dynamic fluid loss

Filtrate invaded zone

Washes and Spacers - fluids intended to remove the drilling fluid filtercake to ensure adequate cement bonding can, by their nature, be invasive and be ultimately damaging.

Completion Filter cake Spurt loss

Fig. 10 Drilling fluid damage.

Perforating - underbalanced perforating provides several advantages in removing or avoiding damage, especially if the well can be placed directly on production (no well kill) after perforating. Completion fluid losses - if the well must be killed to conclude the completion process, it may be difficult to prevent or control completion fluid losses.

Production Scale - deposited following reaction of water soluble materials to changing temperature and pressure conditions (Fig. 11). Depending on the type of scale and location of the scale, removal may vary from easy to impossible. Scale avoidance or inhibition is typically the preferred option.

Scale in the formation Scale in perforations

Wax and Asphaltene - solids which precipitate in or near the wellbore with changing temperature and pressure conditions.

Workover Fig. 11 Production damage (scale) Completion fluid loss

Workover fluid losses - kill pills, containing plugging materials, are frequently spotted to enable the well to be killed (Fig. 12). Selection of an appropriate material which enables subsequent clean-up or removal is essential.

Completion geometry

Kill pill residues

The geometry of the wellbore and the dimensions of the completion components have obvious compatibility requirements. Similarly, the nature and configuration of the reservoir will have some bearing on the optimal wellbore profile. There are two basic means of providing options for reservoir/wellbore interface: • Designing the wellbore profile • Selecting the perforated interval

Fig. 12 Workover fluid invasion.

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The completion geometry can have several effects on the performance of a well. • Influence of completion geometry skin (Sc)

Cap rock

• Susceptibility to coning and resultant gas or water production • Influence of mechanical skin (Sm) on productivity Basement

In the case of an isotropic reservoir

Total skin =

ht ––– Sm + So hp

Fig. 13 Vertical wellbore. where : Sm So ht hp

= mechanical skin = completion skin = reservoir height = perforated interval

Cap rock

Most wellbores can be described as being vertical, deviated or horizontal. Each category has associated advantages and disadvantages. However, in the majority of reservoirs currently being developed, horizontal wells provide significant benefits and are becoming a preferred option in many cases. • Vertical wellbore - provides limited intersection of the reservoir, especially on thin reservoirs. However, this configuration provides improved predictability/control on reservoirs which are to be stimulated by hydraulic fracturing (Fig. 13).

Basement

Fig. 14 Deviated wellbore.

Cap rock

• Deviated wellbore - extends the reach of the well to access outlying reserves and improves productivity by increasing reservoir contact, especially in thin reservoirs. (Fig. 14). In wellbores deviated greater than 45°, significant productivity gains can be realized. • Horizontal wellbore - significant increase in productivity, especially in thin reservoirs. Reduced influence of skin and reduced susceptibility to water and gas coning (Fig. 15).

Water zone

Fig. 15 Horizontal wellbore.

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• Fully completed wells - higher initial production but with reduced control or contingency for unwanted water or gas. • Partial completion - reduced production but improved control of coning or unwanted water/gas production. Effect of skin also increased.

Multiphase flow

Unwanted gas production may originate from several sources (Fig. 16), e.g., • Poor cement bond on casing/liner

Bubble point Bottom hole pressure

Control of gas and water is an important aspect of completion design and operation. In addition to meeting the initial reservoir requirements, there is often need for contingency or remedial redesign work. Consequently, the wellbore should, in ideal circumstances, be designed for conditions anticipated over the lifetime of the well or reservoir.

• Gas coning Oil production rate • Preferential flow through high permeability streaks

Fig. 17 Gas break-out. • Falling gas/oil contact due to reservoir depletion Two phase fluid flow resulting from unwanted gas production may present several problems. These are largely dependent on the quantity/ratio of gas and the location at

GOC

Gas

which the gas breakout occurs. Figure 17 shows gas breakout occurring in the reservoir formation. Similarly, in some gas wells condensate dropout may occur when the pressure drops below the dewpoint. In addition to causing a loading effect on the wellbore, liquids may induce a positive skin factor. The increase in friction pressure caused by two-phase fluid flow can result in a significant pressure drop in such cases.

Oil Gas coning Cement channel

Unlike gas, water production is always undesirable. Water only acts to reduce the productivity of a well and subsequently requires special treatment and disposal when produced to surface. Similar to gas, sources of water production include the following (Fig. 18): • Poor cement bond on casing/liner • Water coning

Fig. 16 Gas production.

• Preferential flow through high permeability streaks

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GOC

High-perm streak

Water injection well

Gravity slumping

OWG High-perm streak

Bubble Point

Bubble Fig. 18 Water production. Point • Rising water/oil contact due to reservoir depletion • Injection water break-through Break through of injection water may result from gravity slumping, a high permeability layer or viscous fingering which may effect the reservoir at a significant distance from the injection wellbore.

Geology

• Response to acid or chemical treatments, e.g., effected by rock mineralogy. • Susceptibility to reservoir damage, e.g., effected by mineral type and distribution. On a large scale, i.e., heterogeneities present over several feet, can be seen as layering (Fig. 20) which may have the following influences

Unlike the assumptions of many mathematical production models and the simplicity of reservoir diagrams, very few reservoirs are totally homogenous. The heterogenous characteristics of a reservoir have bearing on several parameters, e.g., productivity and unwanted water or gas production. Heterogeneities also make interpretation of test results more difficult. Typically the vertical permeability (kv) is less than the horizontal permeability (kh), therefore kv/kh