introduction to completion.pdf

7/22/2019 introduction to completion.pdf

1/20

INTRODUCTION TO COMPLETIONS

CONFIDENTIALITY

This manual section is a confidential document which must not be copied in whole or in part ordiscussed with anyone outside the Schlumberger organisation.

ContentsContents Page Page

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

Single Zone Completions .................. 8

Multiple Zone Completions ................ 9 Phases of Well Completion .......................... 9

Establish Objectives and DesignCriteria ............................................... 10

Constructing the Wellbore ................. 11

Perforation and ComponentInstallation .........................................17

Stimulation ......................................... 18Initiating 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 technologyhas evolved around the techniques and equipment devel-

oped for this purpose. Consequently, the selection ofmaterials, equipment and techniques should only be

made following a thorough investigation of the factors

which are specific to the reservoir, wellbore and produc-tion system under study.

This manual has been prepared to outline the planning

and execution processes involved in completing wells foroil 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 theSchlumberger organization or alliance partners. These

subjects are presented in greater detail to enable a clearerunderstanding of the technology and help identify poten-

tial applications of Schlumberger technology.

In support of the topics given a more general explanation,an extensive reference and further reading list is providedin Appendix I. Combining this manual with the reference

resources will enable engineers to obtain a working knowl-edge of most completion design and installation proce-

dures. However, developing familiarity and expertise withspecific completion technology often requires experience

within a particular operating environment.

There are three basic requirements of any completion (incommon with almost every oilfield product or service). A

completion system must provide a means of oil or gasproduction (or injection) which is;

Safe

Efficient

Economic

Current industry conditions may force operators to placeundue emphasis on the economic requirement of comple-

tions. However, as will be demonstrated later, a non-optimized completion system may compromise long-termcompany objectives. For example, if the company objec-

tive is to maximize the recoverable reserves of a reservoiror field, a poor or inappropriate completion design can

seriously jeopardize achievement of the objective as thereservoir becomes depleted. In short, it is the technical

efficiency of the entire completion system, viewed along-side the specific company objectives, which ultimatelydetermines the completion configuration and equipment

used.
http://../Index.pdf


2/20

CONFIDENTIALITY


1300 Marco Polo reports wells on shore of Caspian Sea

1814 First well to produce oil - 475 ft

1822 Rudimentary art of drilling established

1861 First recorded blowout

1863 Screwed casing joints developed

1880 Standardization of casing begins

1882 Straddle rubber wall packer developed

1890 First extensive casing program

1895 Henry Ford builds the first commercial automobile

1905 Casing cemented for the first time

1910 Drillpipe tooljoints introduced

1911 First gas lift device

1913 First dual completed well

1922 Simple hole-survey tools introduced

1925 API addresses tooljoint threads

1926 First electric submersible pump used

1927 First electric log run (Schlumberger)

1930 Well depths exceed 10,000 ft

1932 First gravel pack job

1933 First gun perforation job

1943 First subsea completion (Lake Eire, U.S.A.)

1958 Thru-tubing workover techniques developed

1958 Wireline retrievable SSSV developed (Camco)

1960 Cement bond log developed

1967 Computerized well data monitoring developed

1969 First coiled tubing job (Bowen)

HISTORY/EVOLUTION OF COMPLETIONS

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

Definition

Well completion processes extend far beyond the instal-

lation of wellbore tubulars and equipment. To highlightthis 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 technol-ogy requires:

The design, selection and installation of tubulars, tools

and equipment located in the wellbore for the purpose ofconveying, pumping or controlling production or injec-

tion fluids.

Under this definition, installing and cementing the produc-

tion casing or liner, as well as logging, perforating andtesting are part of the completion process. In addition,

complex wellhead equipment and processing or storagerequirements effect the production of a well so may have

some bearing on the design and configuration of thecompletion.


3/20

CONFIDENTIALITY


Completion History and Evolution

As the understanding of reservoir and production perfor-

mance has evolved, then so too have the systems andtechniques put in place as part of the completion process.

Early wells were drilled in very shallow reservoirs which

were sufficiently consolidated to prevent caving. As deeperwells were drilled, the problems associated with surface

water prompted the use of a casing or conductor to isolatewater and prevent caving of the wellbore. Further devel-opment of this process led to fully cased wellbores in

which the interval of interest is selectively perforated.

Modern completions are now commonly undertaken indeep hot and difficult conditions.

With the simultaneous improvement in seismic interpreta-tion and drilling technology, wellbores can be precisely

placed to optimize production and enable effective reser-voir management. There are clear economic benefits to

be gained from reducing the number of wellbores requiredfor any reservoir development. However, fewer, but more

efficient wellbores require a greater emphasis to be placed

on the design, selection and installation of the completionequipment.

Horizontal wellbores, and the technology associated with

their completion are becoming common in many fields.Drilling extended reach wells often means that well servic-

ing and intervention options are severely restricted, fur-ther emphasizing the importance of correct design andinstallation of the initial completion equipment.

In all cases, achieving the completion objectives, and

subsequent production targets are a result of carefulplanning and preparation.

The introduction of key technologies and timing of eventsthat have significantly influenced oil and gas well comple-

tions are shown in Fig 1.

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

Mob

/Dem

ob

Casin

g

Drilli

ngRig

Drilli

ngFlui

ds

Completio

nTu

bular

s&Eq

uipm

ent

Logg

ing&

Per

forati

ng

Dire

ction

alSe

rvice

s

Bits

&Co

ring

Cem

entin

g

Supe

rvisi

on

S

itePre

para

tion

R

enta

lEqu

ipmen

t

Per

sonn

elLo

gistic

s

Othe

r

Cam

p100

200

300

400

Operational Phase/Cost Category

US$

x1000

500


4/20

CONFIDENTIALITY


The cost breakdown example shown in Fig. 2 was pre-pared 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, inthe example shown, "completion equipment" accounted

for approximately 10% of the total cost for the well.

Reservoir Drive Mechanisms

Reservoirs are generally classified by the type of drivemechanism. As hydrocarbons are formed and accumu-lated, energy is stored within the reservoir which, under

favorable conditions, enables the flow of oil and gas to thewellhead. Three basic types of drive mechanisms are

most commonly encountered.

Dissolved gas

Gas cap

Water drive

In practice, most reservoirs produce under a combination

of these primary drive mechanisms.

When the reservoir drive is unable to provide sufficientenergy to overcome the hydrostatic pressure exerted by

the fluid in the wellbore, artificial lift will be required to

sustain production.

Dissolved Gas Drive

In a dissolved gas drive reservoir, the oil contains dis-solved gas. A pressure drop, or drawdown, causes the

gas to escape from the oil, thereby forcing fluid throughthe reservoir toward the wellbore. In addition, the gasassists in lifting fluids to the surface (Fig. 3).

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.

Gas Cap Drive

Some reservoirs contain more gas than can be dissolvedin the oil under the reservoir pressure and temperature

conditions. The surplus gas, rises to the top of the reser-voir and forms a gas cap over the oil. The gas expands to

drive the oil toward the wellbore (Fig. 4).

Fig. 3. Dissolved gas drive reservoir.

Reservoir

Cap rock

Basement


5/20

CONFIDENTIALITY


Gas cap drive is more effective then dissolved gas drivetypically 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 watergenerally is present in surrounding parts of the same

formation. These vast quantities of water provide a storeof energy which can aid the production of oil and gas. Theenergy comes from the expansion of water as pressure in

the petroleum reservoir is reduced through the productionof oil and gas. Water is generally considered incompress-

ible, but will actually compress and expand about one partin 2500 per 100 psi change in pressure. When the enor-

mous quantities of water present are considered, thisexpansion results in a significant amount of energy whichcan aid the drive of reservoir fluids to surface. The water

also moves and displaces oil and gas in an upwarddirection out of the lower parts of the reservoir (Fig. 5).

Water drive is the most efficient primary drive mecha-nism, 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 thepressure 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 andgas lift. Each system having advantages/disadvantages

that are considered during a completion equipment selec-tion process.

Only gas lift is compatible with all of the reservoir drivemechanisms previously identified.

Fig. 4. Gas cap drive reservoir.

Gas cap

Cap rock

Reservoir

Basement


6/20

CONFIDENTIALITY


Fig. 5. Water drive reservoir.

Completion Classification

There are several ways of classifying or categorizing oiland gas well completions. The most common criteria for

classification include the following.

Wellbore/reservoir interface, i.e., open-hole or casedhole completion.

Production method, i.e., natural flowing or pumpedproduction.

Producing zones, i.e., single zone or multiple zone

production.

Openhole or Barefoot Completions

Barefoot completions are only feasible in reservoirs with

sufficient formation strength to prevent caving or slough-ing. In such completions there exists no means of

selectively producing or isolating intervals within the res-ervoir or openhole section.

The production casing or liner is set and cemented in the

reservoir cap rock leaving the wellbore through the reser-voir 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 aban-doned except for a few low pressure formations and in

highly specialized conditions where formation damagefrom 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.

External gravel packs may also be used to control sand

production in poorly consolidated reservoirs. In suchcases, it is common to underream the interval of interest

(Fig. 6b)

Cap rock

Reservoir

Water drive


7/20

CONFIDENTIALITY


Fig. 7. Openhole completions.

Fig. 6. Openhole completions.

(a) Openhole

completion

(b) Gravel pack or

uncementedliner

(a) CementedCasing

(b) CementedLiner

Reservoir

Cap Rock

Cap Rock

Reservoir


8/20

CONFIDENTIALITY


Perforated Completions

The evolution and development of efficient and reliable

perforating tools and logging services has enabled com-plex completions to be designed with a high degree of

efficiency and confidence. Modern perforating chargesand techniques are designed to provide a clear perfora-

tion tunnel through the damaged zone surrounding thewellbore. This provides access to undamaged formation

allowing the reservoir to be produced to its full capability.

Cased and cemented wells generally require less com-

plex pressure control procedures during the early stagesof installing the completion components.

Efficient reservoir interpretation and appraisal techniques

combined with a high degree of depth control, enablesselective perforating. This helps ensure the successfulcompletion and production of modern-day oil and gas

wells by precisely defining which zones of the reservoirwill be opened for flow (Fig. 7).

Multiple zone completions are often used in reservoirs

with complex structures and unusual production charac-teristics. The ability to select and control the production (orinjection) of individual zones is often the key to ensuring

the most efficient production regime for the field or reser-voir. Consequently, modern multiple completions may be

complex but maintain a high degree of flexibility andcontrol of production.

Naturally Flowing Completions

Wells completed in reservoirs which are capable of pro-ducing without assistance are typically more economic to

produce. However, in high-temperature, high-pressureapplications, a great deal of highly specialized engineer-

ing and design will be required to ensure the safetyrequirements are met.

In general, naturally flowing wells require less complex

downhole components and equipment. In addition, thelong-term reliability and longevity of the downhole compo-nents 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 providedby artificial lift methods as the reservoir depletes. Such

considerations must be reviewed at the time of initialcompletion to avoid unnecessary expense and interrup-

tion to production.

Pumped Production Completions

All pumped or artificially lifted completions require the

placement of specialized downhole components. Suchcomponents are electrically or mechanically operated, or

are precision engineered devices. These features oftenmean the longevity or reliable working life of a pumpedcompletion is limited. In addition, the maintenance or

periodic workover requirements will generally be greaterthan that of naturally flowing completions.

Pumped or assisted lift production methods currently in

use include the following.

Rod pump

Gas lift

Electric submersible pump

Plunger lift

Jet pump

Single Zone Completion

In single zone completions, it is relatively straightforwardto produce and control the interval of interest with theminimum of specialized wellbore or surface equipment.

Since typically one conduit or tubing string is involved, thesafety, installation and production requirements can be

easily satisfied.

In most single zone completions, a packer (or isolationdevice) and tubing string is used. This provides protectionfor 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 require-ments and economic viability. Several contingency fea-tures may be installed at a relatively minor cost at the time

of initial installation. Consequently, close considerationmust be given to such options during the initial design

phase.


9/20

CONFIDENTIALITY


Multiple Zone Completions

Multiple zone completions are obviously designed to

produce more than one zone of interest. However, thereare many possible configurations of multiple zone comple-

tion, some of which allow for selective, rather than simul-taneous 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 multipletubing strings.

Produce several zones, commingled through a singleproduction string.

Drill and complete a separate well for each zone of

interest.

Selection of the most appropriate option must follow acareful study of the specific conditions encountered. Theequipment 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 determinedby operations and procedures executed during almostevery phase of a wells life, a continual review and moni-

toring process is required. In the majority of cases, asequential and logical approach to the design and execu-

tion process is required. Typically this can be summarizedas follows.

Establish objectives and design criteria

Constructing the wellbore

Installation of the completion components

Initiating production

Production evaluation and monitoring

Fig. 8. Multiple zone completion configuration

example.


10/20

CONFIDENTIALITY


As in all design and execution processes, the acquisitionof accurate or representative data is essential to the timely

achievement of the stated objectives. The level of accu-

racy required will vary with the data typefrom the as-sumption of essential reservoir formation and fluid prop-

erties to more general properties which can more easilybe 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 productionfacility parameters. This data is considered alongside

constraints and limitations which may be technical or nontechnical in nature, e.g., company policy.

Some flexibility may be required, especially in exploration

or development wells, where there are several unknownor uncertain parameters.

Fig. 9. Principal factors affecting a wells performance.

3 CompletionCan be controlled.

2 Reservoir properties

Can be measured.

1 Reservoir boundaryCan be estimated.

12

3


11/20

CONFIDENTIALITY


The principal factors affecting the performance of any wellrelate to the three areas illustrated in Figure 9. Of these,

many of the fluid and reservoir properties can be mea-

sured or inferred from measurements. However, in gen-eral they cannot be controlled. By contrast, almost all

elements of a completion can be controlled and appropri-ate selection will therefore affect well performance.

The objectives for which a completion system is designed

vary, however, the following points may be regarded asfundamental and will have some bearing in most applica-tions.

Ensure potential for optimum production (or injection).

Provide for adequate monitoring and servicing.

Provide some flexibility for changing conditions, applica-tions or contingency measures.

Contribute to efficient field/reservoir development and

production.

Ensure cost efficient installation and operation.

1.5.2 Constructing the Wellbore

The principal objectives associated with wellbore con-

struction will typically include:

Efficiently drill the formation while causing the minimumpracticable near wellbore damage.

Acquire wellbore survey and reservoir test data used toidentify completion design constraints.

Prepare the wellbore through the zone of interest for the

completion installation phase (run and cement produc-tion casing or liner and preparation for sand control orconsolidation services).

There are many issues which directly, or indirectly, influ-ence 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 notalways consistent. For example, in one case impaired

vertical permeability may constrain production. In anothercase, the same condition may be helpful in reducing gasor water coning.

Formation damage (fluid invasion)

Completion geometry (wellbore profile)

Fluid behavior (multiphase flow)

Geology (fractures and heterogeneity)

Only in very rare circumstances can a wellbore be

constructed (drilled and cemented) without any damageto the reservoir occurring. The completion and perforationprocess presents an opportunity for early damage to be

bypassed, however, poorly designed and executedoperations may result in even further damage being

caused.

Once in production, the wellbore conditions, reservoirparameters and the characteristics of reservoir fluids mayresult in the deposition of scale, wax or asphaltenes in or

near the wellbore, causing additional skin effect. Workoveroperations performed later in the life of a well, especially

applications requiring the well to be killed, also present arisk of damage. Consequently, the risk of reservoir damage

is present throughout the life of a well.

Drilling and Cementing

Filtrate damage - reduced permeability caused by

interaction of drilling fluid filtrate, the reservoir rock and/orthe 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 basedmuds.

Filter-cake formation - not generally a problem in perforated

wells, may effect open-hole or special gravel packcompletions.

Solids migration - Solids from the drilling fluid can plugvugs and natural fractures present in some reservoir

formations. If drilling losses have been controlled with

LCM (lost circulation material) the effect can be severeand the damage difficult to remove if the LCM is not acidsoluble.

Cement filtrate - as for drilling fluid, the effect of cement

filtrate can be damaging.

* Mark of Schlumberger


12/20

CONFIDENTIALITY


Washes and Spacers - fluids intended to remove thedrilling fluid filtercake to ensure adequate cement bonding

can, by their nature, be invasive and be ultimately damag-

ing.

Completion

Perforating - underbalanced perforating provides severaladvantages 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 toconclude 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 condi-tions (Fig. 11). Depending on the type of scale and

location of the scale, removal may vary from easy toimpossible. Scale avoidance or inhibition is typically the

preferred option.

Wax and Asphaltene - solids which precipitate in or near

the wellbore with changing temperature and pressureconditions.

Workover

Workover fluid losses - kill pills, containing pluggingmaterials, are frequently spotted to enable the well to be

killed (Fig. 12). Selection of an appropriate material whichenables subsequent clean-up or removal is essential.

Completion geometry

The geometry of the wellbore and the dimensions of thecompletion components have obvious compatibility re-

quirements. Similarly, the nature and configuration of the

reservoir will have some bearing on the optimal wellboreprofile. There are two basic means of providing options forreservoir/wellbore interface:

Designing the wellbore profile

Selecting the perforated interval

Fig. 10 Drilling fluid damage.

Fig. 11 Production damage (scale)

Fig. 12 Workover fluid invasion.

Kill pillresidues

Completionfluid loss

Scale inperforations

Scale in the

formation

Filtrate invadedzone

Filter cake

Spurt loss

Dynamic

fluid loss


13/20

CONFIDENTIALITY


Fig. 15 Horizontal wellbore.

Fig. 13 Vertical wellbore.

Fig. 14 Deviated wellbore.

Cap rock

Basement

Cap rock

Basement

Cap rock

Water zone

The completion geometry can have several effects on theperformance of a well.

Influence of completion geometry skin (Sc)

Susceptibility to coning and resultant gas or waterproduction

Influence of mechanical skin (Sm) on productivity

In the case of an isotropic reservoir

ht

Total skin = Sm

+ So

hp

where :

Sm

= mechanical skin

So

= completion skinh

t= reservoir height

hp

= perforated interval

Most wellbores can be described as being vertical, devi-ated or horizontal. Each category has associated advan-

tages and disadvantages. However, in the majority ofreservoirs currently being developed, horizontal wells

provide significant benefits and are becoming a preferredoption in many cases.

Vertical wellbore - provides limited intersection of thereservoir, especially on thin reservoirs. However, this

configuration provides improved predictability/controlon reservoirs which are to be stimulated by hydraulic

fracturing (Fig. 13).

Deviated wellbore - extends the reach of the well toaccess outlying reserves and improves productivity byincreasing 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 skinand reduced susceptibility to water and gas coning (Fig.

15).


14/20

CONFIDENTIALITY


Fully completed wells - higher initial production but withreduced 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

Control of gas and water is an important aspect ofcompletion design and operation. In addition to meeting

the initial reservoir requirements, there is often need forcontingency or remedial redesign work. Consequently,

the wellbore should, in ideal circumstances, be designedfor conditions anticipated over the lifetime of the well or

reservoir.

Unwanted gas production may originate from several

sources (Fig. 16), e.g.,

Poor cement bond on casing/liner

Gas coning

Preferential flow through high permeability streaks

Falling gas/oil contact due to reservoir depletion

Two phase fluid flow resulting from unwanted gas produc-

tion may present several problems. These are largelydependent on the quantity/ratio of gas and the location at

which the gas breakout occurs. Figure 17 shows gasbreakout occurring in the reservoir formation.

Similarly, in some gas wells condensate dropout may

occur when the pressure drops below the dewpoint. Inaddition to causing a loading effect on the wellbore, liquidsmay induce a positive skin factor. The increase in friction

pressure caused by two-phase fluid flow can result in asignificant pressure drop in such cases.

Unlike gas, water production is always undesirable. Water

only acts to reduce the productivity of a well and subse-quently requires special treatment and disposal when

produced to surface. Similar to gas, sources of waterproduction include the following (Fig. 18):

Poor cement bond on casing/liner

Water coning

Preferential flow through high permeability streaksFig. 16 Gas production.

Fig. 17 Gas break-out.

GOC Gas

Oil

Cement channel

Bubble point

Gas coning

Oil production rate

Bottomh

olepressu

re


15/20

CONFIDENTIALITY


Bubble

Point

Bubble

Point

GOC

OWG

Gravityslumping

High-perm

streak

Fig. 18 Water production.

Rising water/oil contact due to reservoir depletion

Injection water break-through

Break through of injection water may result from gravityslumping, a high permeability layer or viscous fingering

which may effect the reservoir at a significant distancefrom the injection wellbore.

Geology

Unlike the assumptions of many mathematical productionmodels and the simplicity of reservoir diagrams, very fewreservoirs are totally homogenous. The heterogenous

characteristics of a reservoir have bearing on severalparameters, e.g., productivity and unwanted water or gas

production.

Heterogeneities also make interpretation of test resultsmore difficult. Typically the vertical permeability (k

v) is less

than the horizontal permeability (kh), therefore k

v/k

h


16/20

CONFIDENTIALITY


Reduced tendency to coning

Decreased productivity in partially completed wellbores

On a smaller scale, i.e., over several inches, the effects

may be more variable and may effect the performance ofindividual perforations (Figure 21).

Wellbores which intersect natural fractures will typicallyhave improved productivity (Fig. 22). However, the frac-

ture may provide a conduit to unwanted water or gas

which is ultimately difficult to control. In such a fracturedformation, wellbores which do not intersect a fracture willhave reduce productivity and may display abnormally

high skin values (Fig. 23).

Formations containing low permeability layers or streaksmay have reduced productivity due to reduced vertical

permeability. However, the disadvantage of any loss ofproductivity may be counteracted by a reduced tendencyto coning. The presence of shale may impose significant

barriers to reservoir production, even if only present as acontinuous thin streak (Fig. 24). In such cases, reservoir

management can be complex since predicting productionprofiles and characteristics is difficult.

The production of sand and formation fines can cause

several problems which, in addition to constraining wellproductivity, effect the production facilities, completioncomponents, and reservoir stability.

Fig. 20 Layered formation (macro). Fig. 21 Layered formation (micro).

Fig. 22 Fracture intersected. Fig. 23 Fracture missed.

Not producing

Not producing

Low permeability layers reduce vertical flow

FracturingOil

Water


17/20

CONFIDENTIALITY


Fig. 26 Formation/casing collapse.

Fig. 25 Sand voids.

Sand control measures may be necessary to:

Prevent erosion of wellbore and production components

Minimize surface disposal requirements

Minimize wellbore fill

Prevent the formation of large void areas behind the

casing/liner that may be impossible to isolate

Severe, or long-term, sand production may result in voids

forming behind the casing or liner (Fig. 25). Furthererosion over an extended period and wellbore interval

may lead to subsidence around the wellbore which couldultimately lead to casing collapse (Fig. 26).

Common sand control measures include sandconsolidation, sand screens and gravel packing. The

most common method, gravel packing, requires designand selection processes to be carefully undertaken to

ensure that the gravel (sorted sand), screens and othercompletion equipment are compatible with the wellbore

and reservoir conditions. Incorrectly applied, gravel packingcan pose a greater constraint on production than theproblem it is intended to avoid.

Perforation and Component Installation

Wellbores that are cased and cemented are generally

stable and enable selective production (or subsequentisolation) to be achieved easily and reliably.

The productivity of most perforated completions can bemaximized by optimizing the following.

Perforation length

High-shot densities

Perforation phasing

Underbalanced perforating

In an ideal reservoir, it would be desirable to perforate theentire producing interval. However, there are few reser-

voirs in which this is advisable. The effects of water andgas coning, high permeability streaks etc. can be signifi-cantly reduced by selective, or controlled, perforating

Fig. 24 Shale streak.

Gas coning preventedby shale

Shale

Gas

Oil

Gas under-

running

Partial completionskin = 0

Loose sand

Sandvoid

Pluggedperforation


18/20

CONFIDENTIALITY


(Fig. 27 and 28 ). This results in a partial completion which,if properly designed, provides the best compromise of

productivity and control.

The proper selection and installation of completion com-ponents is an obvious requirement. Components may be

broadly categorized as follows.

Primary completion components - essential componentsnecessary for the completion to function safely, e.g.,packers.

Ancillary completion components - providing the comple-

tion system with increased flexibility and control, e.g.,sliding sleeve.

Fig. 27 Partial completion (lower).

Fig. 28 Partial completion (upper).

In general, the optimum completion configuration (andsystem) will provide a balance between flexibility and

simplicity.

Stimulation

Many reservoirs require some stimulation applied during,

or soon after, the completion process to achieve viableproduction rates. Such treatments can generally be

categorized as hydraulic fracturing or matrix treatments,selection being dependent on the characteristics of thereservoir rock, fluids and the nature of any damage which

is to be removed or bypassed.

Hydraulic fracturing

Propped Fracs - A fracture is initiated and propagated withspecially engineered fluid, pumped at high-rate and high-pressure to form a fracture radiating from the wellbore.

Proppant carried by the fracturing fluid remains in place asthe pressure is bled off and the fracture close. The

resulting high permeability fracture provides a highproductivity conduit to the wellbore (Fig. 29).

Acid Fracs - This technique applies to carbonate reservoirsand involves pumping acid in stages with the fracture fluid.

The acid reacts with the carbonate reservoir to formetched surfaces on the fracture, thereby preventing com-

plete closure following bleed-off of the fracture fluid (Fig.30).

Fig. 29 Hydraulic fracturing.

Water coning

Waterflow

ingthrough

high-perm

streak

Propanttrapped infracture

Wellbore


19/20

CONFIDENTIALITY


Fig. 30 Acid fracturing.

In all fracturing treatments care must be taken during thedesign and execution phases to minimize the risk of

fracturing into undesirable water or gas producing areas(Fig. 31).

Matrix Treatments - Designed to remove or bypass near

wellbore damage, the treatment is performed below theformation fracture pressure. The resulting interconnectedwormholes provide higher conductivity near the wellbore

(Fig. 32).

Appreciable productivity increases following matrix treat-ment will generally only occur if significant damage is

present.

Fig. 32 Matrix treatment (carbonates).

The treatment mechanism is dependent on the type ofreservoir rock. Most carbonate reservoirs are treatable

with hydrochloric acid (HCl). The acid bypasses damageand links vugs and natural fractures to create a highly

permeable path. In sandstone reservoirs, a mud acidtreatment (hydrofluoric acid - HF/HCl) is typically used.

This acid formulation can dissolve siliceous materials, sois capable of removing the damage rather than bypassingthe damage, as in carbonate reservoirs.

To be fully effective, any treatment should be properly

applied through the treatment interval. For near wellboretreatments, such as acidizing, incomplete treatments due

to variable perforation performance can be a problem(Fig. 33).

Fig. 31 Fracture design.

Fig. 33 Incomplete treatment.

Acid etched

wormholes

Fracture has growninto water zone

Stimulated area

Perforation plugged(e.g., with CaCO3)

Acid etchedfracture andworm holes

Wellbore

Water

Oil

Gas

Oil

Gas

Wellbore


20/20

CONFIDENTIALITY

Initiating Production

In most cases, this phase of the completion process is

further subdivided into the following three stages.

Initiating flow to establish communication between thereservoir and the wellbore.

Defining an appropriate clean up program to enable the

ultimate production rate to be achieved safely andwithout damage to the reservoir, completion compo-nents or surface production facilities.

Design of any initial stimulation treatment which may be

necessary to enable the restoration of permeability inthe near wellbore area.

Production Evaluation and Monitoring

An initial production evaluation is necessary to confirmthat the completion system achieves the production capa-

bilities required by the design objectives. Subsequentevaluation and monitoring exercises will provide the fol-

lowing production information on the reservoir, well andcompletion system.

Statistics relating to the reliability and longevity of comple-tion components.

Verification that assumptions made during the design

process were accurate or representative.

Trends or statistical departures which may provide early

indication of completion problems or the need for inter-vention or workover.

Periodic monitoring of reservoir parameters provides

useful data for the completion and production of offsetwells or recompletion as required by reservoir depletion.

The DEE Cycle

The previous five phases have, in effect, outlined aDESIGN, EXECUTE and EVALUATE* cycle for comple-

tion activities. They represent a logical and structuredapproach to a process which may be complex and require

the involvement of several departments and engineeringdisciplines.

Even by this short introduction to oil and gas well comple-tion, several conclusions quickly become apparent. These

should be borne in mind as the completion design process

is further investigated.

The safe, efficient and economic completion of an oil orgas well is a complex process.

A structured approach to defining the design criteria of

a well is essential. Critical to this effort is a comprehen-sive formation evaluation program.

The design of well completions is a dynamic process -taking into account data gathered on the performance of

previous completions. However, no two wells are ex-actly alike!

A degree of flexibility should be built into the design andconfiguration of completions to allow for anomalies and

uncertainties.

All completions comprise a variety of tubular and special-ized components. The total number of components will

directly effect the complexity, inherent reliability andlongevity of a successful completion system.

* Mark of Schlumberger

introduction to completion.pdf

Documents