6.2 Production optimization

6.2.1 Introduction

Petroleum production engineering is the series ofactivities concerned with the ability of a well toproduce or inject, often described through aproductivity or injectivity index (i.e. produced orinjected volumes per unit time per differential pressuredrop in the near wellbore region). As such, there is adifference between reservoir engineering, which dealswith the reservoir-at-large and, in particular, the extentand timeliness of hydrocarbon recovery. Production

engineering often deals with one or more wells at atime, and the delivery of oil and gas from the wellheadto the point-of-sales (Figs. 1 and 2). More important isthe frequent over-riding economic motivation toaccelerate the production by increasing the wellproduction or injection rate. Terms such as productionenhancement and well stimulation have been coinedand used extensively. At times, equally important, isthe reduction of the well drawdown, i.e. the differencebetween the driving, reservoir pressure, and theflowing bottomhole pressure.

6.2

Production optimization

725VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

gas

oilwater

separator

pipelineswell

choke

tubingoutflow

perforations

reservoir inflow

Fig. 1. Petroleum productionsystem: elements affectingwell productivity.

While on a superficial basis, the lower the flowingbottomhole pressure the larger the production ratewould be, this situation is not always desirable. Thereare many adverse effects associated with lower flowingbottomhole pressure such as scale, paraffin andasphaltene deposition, water and/or gas coning andsand production. Thus, it is essential that it isunderstood from the outset that stimulation and thepresumed increase in the productivity index should notautomatically translate into increasing the wellproduction rate but, instead, allocate the appropriateportion of the productivity index increase toproduction rate increase and/or drawdown decrease,depending on the needs of each individual well.Therefore, production optimization goal is to increaseproductivity and improve the overall asset value (in theshort-term) while satisfying all physical and financialconstraints.

An integrated productivity enhancementapproach, with reservoir management, balances theshort-term production optimization and the long-term reservoir engineering objectives, in order to

produce far more rational effects in the fielddevelopment.

Reservoir management is about making the bestpossible decisions that will enable a company tomeet specific objectives; and implementing thesedecisions. The ability to make the best possiblereservoir management decisions relies mainly onthe ability to predict the consequences ofimplementing these decisions. This, in turn,depends on the ability to model the expectedbehaviours of the reservoir system. The mostcommon objectives of reservoir management are:to decrease risk, to increase oil and gas production,to increase oil and gas reserves, to maximizerecovery, to minimize capital expenditures, tominimize operating costs and to optimizeprofitability. The understanding of reservoirmanagement has improved greatly over the last fewyears and a methodology is slowly emerging tofacilitate its routine implementation. Reservoirmanagement used to be identified with productionengineering, and then became synonymous with

726 ENCYCLOPAEDIA OF HYDROCARBONS

FIELD PRODUCTION PHASE

gas processing

compressed gasgas

gas

oil

water

producedfluids

injectionwater

injection gas

fuel gas

fuel gas

steam

oil and gas

tank farm storage

marketing

wellssteam plants water treatment

and compression

flow stationcompression

Fig. 2. Petroleum production system: from the wells to the point of sales.

numerical reservoir simulation. It is nowunderstood that it is an iterative process, of whichnumerical reservoir simulation and productionengineering are only two components.

Basics of petroleum production systemFig. 1 shows the different components of the

petroleum production system. An integrated, rathercomplex interaction of reservoir inflow, flow throughperforations and tubing outflow, well choke, surfacepipelines and separators, are the components of thepetroleum production system.

Flow rates The one-phase steady-state inflow performance

of a reservoir for the oil flow rate q (in STB/D,Stock Tank Barrel/Day) is given by Eq. [1], whichassumes under-saturated conditions (gas insolution), constant reservoir pressure, pe, at acertain border distance, re, and accounts for thepressure losses (basically permeability impairmentdue to drilling and completion damages) near thewellbore due to damage to the formation, known asa skin effect.

kh(pe�pwf)[1] q�1111111233333re141.2 Bm�ln �1��s�rw

where k (md) is the effective formation permeability,h (ft) the formation thickness, pwf (psi) the flowingbottomhole pressure, s the skin factor, rw (ft) thewellbore radius, B (RB/STB) the oil formationvolume factor. Assuming that reservoir and near-the-wellbore pressure remain above bubble point, theexpressions for the flow of oil qo and water qwshould be expanded to account for the relativepermeability reduction due to the effect of eachphase’s saturation, thus obtaining the followingrelations:

kkroh(pe�pwf)o[2] qo �1111111123333re141.2 Bo mo �ln �1��s�rw

kkrwh(pe�pwf)w[3] qw�1111111123333re141.2 Bw mw�ln �1��s�rw

where krw and kro are, respectively, the permeabilitywith respect to water and to oil in a two-phasereservoir. The larger the water saturation near thewellbore, the lower the oil flow.

Skin effectThis term accounts for the additional pressure drop

necessary to overcome the flow resistance of the

reduced permeability zone caused by drilling mudinvasion, the effect of partial penetration or the effectof the penetrating contact angle of the wellarchitecture. Fig. 3 shows the radius rs of the zonecharacterized by the skin with respect to the drainageradius. The skin factor s can be related to formationand damage permeability k, damage penetration ks andwell radius rw by s�(k/ks – 1)·ln(rs/rw).

Productivity index The productivity index J* (BOPD/psi) above the

bubble point pressure pb, when there is no waterproduction, is the ratio between the oil flow rate qb andthe pressure drawdown:

qb 7.08kh kro[4] J*�111�111�11�; for pwf�pbpe�pwf (pD�s) moBo

Above the bubble point pressure, with immobilewater and gas, oil saturation remains constant resultingin a constant productivity index, J*. If other phases arepresent in the wellbore, kro is reduced, and hence theproductivity index is also reduced. However, with noartificial support (e.g. water or gas flooding), reservoirpressure declines fast, since the only internal energy isprovided by the expansion of rock and water, which isvery small.

Inflow performance relationshipAn expression such as Eq. [1] is also called an

Inflow Performance Relationship (IPR) and a graph offlow rate vs. the flowing bottomhole pressure is a


PRODUCTION OPTIMIZATION

h

k

pwf

perw

rs

re

Fig. 3. Wellbore measurement of interest: for a given distance re, rw is the wellboreradius, rs is the skin radius, pe is the reservoir pressure,pwf is the flowing pressure, k is the real permeability of layer h.

standard construction in petroleum engineering,characterizing the well performance.

Production below the bubble point pressure When reservoir pressure declines below the bubble

point pressure, gas bubbles will start to nucleate andcoalesce. After reaching critical gas saturation,bubbles are big enough to move through the porousspace, against water and oil.

For bottom-hole flows below the bubble pointpressure, Vogel, in 1968, introduced an empiricalrelationship for qo. The relationship, normalized forthe ideal absolute flow potential, is also known as theback-pressure equation:

qo pwf pwf[5] 1133�1�0.2�13��0.8�13�2

qo,max p� p�

where �p is the average reservoir pressure.For the same oil-gas system in which the

reservoir pressure is above the bubble point pressure,and yet the flowing bottom-hole pressure could bebelow the bubble point pressure, the so-called Vogelflow, qv, is related to the productivity index abovethe bubble point pressure by:

qo,b J*�p��pb� pb pb[6] 1133�113133 �1�0.2�1�2�0.8�1�2

qo,max qv p� p�

J*�p��pb�p�for pwf �pb⇒ qv�11111121113��p��2�0.2�pbp��0.8�pb �2

J*�p��pb�p� pb�J*11111132�113�p��0.8pb ��p��pb � 1.8

And the final Vogel’s relation for flow above andbelow bubble point is:

pwf pwf[7] qo�qb�qv�1�0.2�13��0.8�13�2�⇒ qo�t��p� p�

pb�J* pwf pwfJ*�p��pb��11 �1�0.2�13��0.8�13�2�1.8 pb pb

A similar expression for Vogel’s back-pressureequation was suggested by Fetkovich in 1973:

qopwf[8] 1133��1��13�2�n

qo,max p�

With the test information on two or more stabilizedflow rates, the unknowns qo,max and n can bedetermined. With n�1, Eq. 8 becomes:

J*[9] qo�t��J*�p��pb��11 �pb

2�p2wf �2�pb

There is little difference between Vogel’s IPR andFetkovich’s approximation (Fig. 4). However,Fetkovich’s correlation is said to better match field

data than Vogel’s but the latter is more useful forforecasting well performance since it does not requirea priori field data.

Flow through pipes and outflow performanceWhen a single-phase fluid flows through a pipe,

with diameter D, the pressure drop, dp, over a distancedL, can be obtained by solving the mechanical energyequation,

dp udu g 2ff u2dL[10] 1�132�1dz�1212�dWs�0r gc gc gcD

where r is the fluid density, u is the macroscopicvelocity, ff is the Fanning friction factor, dWs is theshaft work, g is the gravitational acceleration over dzand gc is the gravitational conversion constant (that isthe conversion factor to English engineering system of units).

Eq. [10] can be integrated to yield, assumingconstant density (incompressible fluid) and no shaftwork, dWs�0, the following:

g r 2ff u2dL[11] Dp�p1�p2�

1 rDz�12Du2�121gc 2gc gcD

The right hand side describes the potential energy,kinetic energy and the frictional contributions to theoverall pressure drop.

Assuming a compressible Newtonian fluid, forexample gas flow through pipes, the pressure drop canbe calculated from

ff �ZT13

qg�2

[12] p12�e�sp2�2.68510�3111333 �1�e�s�

sinq�D5



J*=0.48 STB/D/psia

pb=3,000 psia

5,000

4,000

3,000

2,000

1,000

flow

ing

bott

omho

le p

ress

ure

(psi

a)

00 500

flow rate (STB/D)1,000 1,500

Vogel (1968)

Fetkovich (1973)

qb=675 STB/D

Fig. 4. Two-phase inflow performancerelationships (after Vogel, 1968 and Fetkovich, 1973).

where s is given from the relation

�0.0375ggsinq�L[13] s�1111111

ZT323

where p1 is the upstream pressure and p2 is thedownstream pressure in psia; q is the inclination of thepipe with respect to the vertical; gg is the specific gasgravity; Z� and T� are the average gas deviation factorand temperature for the two pressure points; qg is thegas rate in MSCF/D (Millions Standard CubicFeet/Day).

Typically, multiphase flow will occur during theproducing life of a well. However, even if thebottomhole flowing pressure is above the bubblepoint, further pressure decrease will be needed todrive the reservoir fluid to the surface. In almost allcases, gas will come out of the solution and morethan one phase will coexist during the vertical lift.Free gas may help to lighten the liquid hydrostaticcolumn up to a certain point. For high gas-oil ratios,friction losses may actually impair the flow ability.In general, multiphase fluid flow deals with theconcurrent flow of oil, water and gas in vertical andinclined pipes. In more complex situations, sandand other solids (paraffines, waxes, andasphaltenes) may also compete in the multiphasevertical flow. In these cases, advanced strategiessuch as controlling reservoir drawdown,maintaining bottomhole and wellhead pressureabove flocculation, and injecting chemicals may benecessary to assure flow.

Several correlations calculate the pressure drop ingas-liquid two-phase flow in wells. The starting pointfor all the methods is the mechanical energy balance[Eq. 10]. Since flow properties (density andvelocities) may fluctuate appreciably along the pipe,the pressure gradient is calculated for small pipelengths or pressure increments. The overall pressuredrop is then obtained with a pressure traversecalculation, in which iteration over short length orpressure intervals may be necessary to matchproperties along the pipe.

The Hagedorn and Brown (1965) correlation usesthe mechanical energy equation to calculate thepressure gradient, dp, over a pipe length, dz,

um21

dp fm�2 D�2gc�

[14] 144223�r2

�1111111�r2

111

dz �7.4131010D5�r2 Dz

where r is the in situ average density, f is the frictionfactor, m� is the total mass flow rate (lbm/d), D is thepipe diameter (ft), um is the mixture velocity (ft/s), anddp/dz is in psi/ft.

Fig. 5 illustrates the two-phase vertical flow of1,000 STB/D of 21oAPI crude oil, in a 2 7/8'' tubing,

with Gas/Liquid Ratio (GLR) of 500 and 1,000 SCF/STB, Water/Oil Ratio (WOR) of 0 and 1,using the modified Hagedorn and Brown correlation. For zero water production (WOR�0) andGLR�500 SCF/STB, the required bottomholeflowing pressure is 4,321 psia to achieve a tubingwellhead pressure of 125 psia; while for aGLR�1,000 SCF/STB, the required bottomholeflowing pressure is only 3,446 psia. Similarly, for 50% water production(WOR�1) and GLR�500 SCF/STB, the requiredbottomhole flowing pressure is 4,494 psia to achievea tubing wellhead pressure of 125 psia; while for aGLR�1,000 SCF/STB, the required bottomholeflowing pressure is only 3,787 psia. As shown in Fig. 5for the same GLR, the larger the water fraction inthe water/oil mixture, the larger the pressure lossesand hence the larger the bottomhole flowing pressurerequired to achieve a tubing wellhead pressure of 125 psia.

It is tentative to extrapolate that the larger theamount of GLR, the lower the pressure losses; whichis not necessarily true. It can be shown that forWOR�1 and GLR of 2,000 SCF/STB the bottomholeflowing pressure will go down to only 3,566 psia; andfor 5,000 SCF/STB the bottomhole flowing pressurewill in fact deteriorate to 4,272 psia. This is due to theincrease in friction losses due to slippage and high gasvelocities.

Well deliverabilityThis concept combines the reservoir inflow, as

exemplified by the well IPR, with the tubing



0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

dept

h (f

t)

pressure (psia)5,0004,0003,0002,0001,0000

1,000 STB/D @ 500 SCF/STB; WOR=11,000 STB/D @ 1,000 SCF/STB; WOR=11,000 STB/D @ 500 SCF/STB; WOR=01,000 STB/D @ 1,000 SCF/STB; WOR=0

Fig. 5. Pressure vs. depth for different GLRsand WORs using modified Hagedorn and Brown, 1965; generated in PPS Software, 2003.

performance curve, which essentially accountsfor all pressure drops associated with theplumbing of the well. This combination bringsthe components of the petroleum productionsystem together and can also be used for well diagnosis, analysis andidentification of malfunctioningor ill-functioning parts of the system, etc.This approach has been called well performanceanalysis or well-known trade marked termssuch as nodal analysis.

Well performance analysis is useful not just inidentifying a specific solution for a given well IPRand tubing performance. It can also be used toexperiment with a number of different options inIPR modification such as hydraulic fracturing,different perforation densities and even horizontaland complex wells. Also different well designs andoperational conditions such as tubing diameter,wellhead pressure, chokes and artificial lift methodscan be accounted for in the tubing performancecurve. All options, properly examined can lead to aneconomic optimization: incremental costs amongdesigns can be balanced against incremental wellperformance.

To calculate the well flow rate and the flowingbottom hole pressure, the well IPR (Fig. 6) isintersected with the well tubing performancecurve (see again Fig. 5), leading to a solution.

Given the reservoir pressure, only one IPRbehaviour is possible; for a given Tubing HeadPressure (THP) of 125 psia, and a given flowingbottomhole GLR and WOR, the well deliverabilityis the intersection between the IPR and therespective two-phase vertical lift tubingperformance curve. Consider the example in Fig. 6.The initial reservoir pressure is 11,000 psia; theabove bubble-point productivity index is about 16 STB/D/psia; there is no water production, theTHP is 125 psia, and the GLR is 500 SCF/STB.The 2 7/8'' tubing has no artificial lift and nochoke restrictions at the surface. From Fig. 6 thewell’s operating point will be about 12,500 STB/Dwith a bottomhole flowing pressure of 10,200 psia(point 1). If the water cut increases to 50%(WOR�1) then the same well will produce about5,300 STB/D at 10,800 psia flowing pressure(point 2 in Fig. 6). The increase of waterproduction in the tubing performance isdetrimental. For this particular example (Fig. 6),at current well’s operating point, furtheravailability of free gas in the wellbore, i.e. GLRgoing from 500 to 1,000 SCF/STB, do notimprove the well deliverability in any of the caseswhere WOR is 0 or 1 (points 3 and 4 in Fig. 6). Infact, the well deliverability worsened in thosecases where GLR was higher, for the same WOR.This is due to increased friction losses to excessgas presence in a limited-size tubing. In fact, atlow well rates, i.e. fluid flow less than 3,000STB/D at WOR�0, or fluid flow less than 2,000STB/D at WOR�1, the well deliverability couldbe improved at a higher GLR.

In all cases, further reservoir pressure declinealso would affect the well deliverability.Additionally, the well energy can be boosted byartificial methods such as electric submersiblepumps or artificial gas lift.

Production optimization At a certain point in the life of a well, recovery

may not satisfy physical or economic constraints andthe well will be shut. At this stage, a remediationaction or workover would be performed if thepreliminary analysis predicts additional economicvalue creation. The objectives of productionoptimization (Fig. 7) may be to enhance reservoirinflow performance or to reduce outflow performance.The results could be more production with lesspressure drawdown.

Usually, sand production, high water and low oilrates will indicate the need to revitalize thedownhole well environment. Cement squeezing,fracturing and acidizing are the most common tasks



IPR @ p= 7,000 psia

IPR @ p= 9,000 psia

IPR @ p= 11,000 psia

pwf (WOR=0, THP=125, GLR=500)

pwf (WOR=0, THP=125, GLR=1,000)

pwf (WOR=1, THP=125, GLR=500)

pwf (WOR=1, THP=125, GLR=1,000)

flow rate (STB/D)20,00016,00012,0008,0004,0000

4 2 3 110,000

6,000

8,000

4,000

2,000

0flow

ing

bott

omho

le p

ress

ure

(psi

a)

12,000

Fig. 6. Well deliverability from a two-phase IPR and different WORs and GLRs.

performed. Reservoir stimulation and/or wellintervention are necessary to improve the well-reservoir connectivity (increase perforation density,reduce mechanical damage, increase fracturelength) and/or boost vertical lift systemperformance (change tubing size, change artificiallift, remove bottlenecks).

There exist many possible solutions tomitigate the observed problems in the petroleumproduction system. The smarter productionengineer would balance an optimum combinationof analysis time effort and engineering designcalculation to decide proper actions as to maintainthe petroleum production system at an optimumpoint.

The understanding of reservoir inflow, wellbore vertical lift and surface facilities pressureconstraint is necessary to optimize the fieldproduction performance. Production optimizationrefers to the various activities of measuring,analysing, modelling, prioritizing andimplementing actions to enhance productivity of a field. Production optimization often refersto activities related to: a) well profilemanagement (coning, fingering, wellconformance management, etc.; see Chapter 4.3);b) near wellbore damage removal viaacidizing or fracturing; c) near wellboreand pipeline solid deposition prevention; d) well integrity (casing and cement failureprevention and remediation); e) field and welllevel artificial lift optimization; f) hydrocarbon(oil and gas) and other fluids transport efficiency;g) surface facilities design and total fluidhandling capacity; h) surface de-bottlenecking andcontinuous field-optimization.

Continuous (real time) oil field optimizationOpportunities for production optimization may

occur at different time-scales and at different corporatedecision levels. A number of new technologiesintroduced into oil fields over the last couple of

decades now provide the technology frameworkfor optimization of an oil field in a continuous rather than one-time fashion. Continuous FieldOptimization (CFO) requires computer integrationof field hardware (e.g., downhole sensors, remotely activated completions, surfacefacilities) for continuous decision making in afeedback fashion (data acquisition, data processing,and actuation).

One of the greatest worries of any oil/gasproducing operator is how long would the well be inproduction without necessary intervention. Wellintervention is costly, and may ruin any previouseconomic goal. Sometimes, it may be even moreeconomical to abandon the well, drill a new well orjust move to another area.

Smart well completions have been justifiedas a means to avoid rig intervention oncewater has appeared in a particular reservoir layer.With a simple remote actuation of downholevalves, an operator may improve the well’s lifewithout the need of a rig intervention. However,in the onset of this technology, only high interventioncost environments have been economicallyviable. Although there are some low-costsolutions available in the market, newtechnologies are being developed to furtherdrive down the costs.

Remotely activated (smart) completions shouldbe used to permit reservoir data collection byperforming persistent excitations, automaticallyregulate flow from particular zones to optimizewell’s deliverability and ultimately shut a particularwell’s offending layer as a result of exhaustedresources.

Planning a production optimization projectPetroleum production engineers perform an

analysis of the historical and actual productionsituation in order to determine the technologicalneeds and to identify the economic benefits thatwould make possible an additional expenditure.



Pres

less drawdown

Pres

more drawdown

dow

nhol

efl

owin

g pr

essu

re

productionincrease

reducedrestrictions

outflowperformance

liquid rate BPD

inflow performanceinflow performance

outflow performance

productivityenhancement

liquid rate BPDdo

wnh

ole

flow

ing

pres

sure

Fig. 7. Productionoptimization via outflowenhancement.

Production optimization projects cover differentareas or departments in a company, which meansthat project coordination is needed in order toensure the completion of the project and itsbenefits.

The optimization project could be affected for oneor more of the followings aspects:• Business case has to match problem-specific needs

and technology availability.• Business case has to demonstrate a clear value

addition to the value chain.• The asset may have many enhancement needs

which have not been prioritized.• The budget for expenditures is limited or unknown.• The time frame for execution is limited or

unknown.• The quality and quantity of data given is poor and

limited.It is also important to note that any production

optimization project should be planned in accordancewith the optimization’s objective function, whichcould be to reduce cost, to increase NPV (NetPresent Value) or to increase production.

Objective functions may not overlap. For example, if the objective function isto reduce cost this may mean the reduction inproduction, which is obvious. However, reduction in production may also increase thenet present value because some production maybe quite unprofitable. Therefore, operators, engineersor managers should agree on the project’s objectivefunction and avoid any operation or instruction thatcould be logical but against the true optimizationobjective function.

However, sometimes it is difficult to findopportunities for optimization due to several validreasons, such as:• The data are either low in quality or quantity or

taken too infrequently. Conversely, sometimes theclaim is that there are too many data and there areno proper systems to handle them.

• Softwares are not integrated in the system in theexpected way. Common data standards or a singleintegrated system would be the solution, whileexisting models do not mimic properly the physicsof the problem.

• The cost of the project would be to high.• Organization cannot handle changes in the man-

agement so that a system becomes soon out ofdate.

• There is a lack of formal education in petroleumproduction optimization engineering and littleexchange between disciplines involved.

• There is a lack of resources (time and financial) tofocus on production optimization.

Production optimization projects will have thefollowing phases: a) production data analysis,interpretation and clustering; b) opportunityidentification and generation of candidate; c) rankopportunities based on some predictable successcriteria; d) definition of the design componentsneeded to optimize the implementation; e) implementation, definition and monitoring of theresults; f ) feedback results and ongoing monitoringof the performances to find more candidates.

The generation of candidates for production optimization

The generation of candidates and opportunitiesidentification processes are directed to helppetroleum production engineers to better interpretand understand the available data, and to produceand implement valuable decisions and actions.Traditional petroleum production engineeringtechniques (well lithology and production loganalysis, interpretation of production tests, nodalanalysis, material balance, reservoir simulation,etc.), in conjunction with novel oil fieldinformation technologies (data integration,downhole sensing and remote control) andnumerical techniques (optimization, linear andnon-linear mappings, clustering techniques, whichcorresponds to the use of groups of curvesexpressing physical properties), conform thetechniques required for the generation ofcandidates for production optimization, also interms of identification and design.

Some of the approaches for generating candidatesfor production optimization are:

Stimulation candidate recognition for nearwellbore problems. Traditional productionengineering techniques can be used to determine theeconomic impact that an optimum stimulation designwould deliver. Opportunities should be ranked andscheduled for implementation following a sort ofmaster plan.

Integrated solution approach. An integrateproduction optimization approach (Fig. 8) is aworkflow series of processes which aim to identify,evaluate, rank and implement opportunities. Integralrefers to the principle that short-term productionoptimization goals are in agreement with the reservoirlong-term objectives.

Advanced production optimization techniques.Advance optimization models are created predict wellperformance on the basis of a series of modelledreservoir uncertainties together with well andexploitation scenarios. An optimization problem canbe set-up to find the best combination of candidatesthat deliver the optimum value at a minimum cost.



Automated tools for candidate recognition. The useof unsupervised learning techniques, neural networks(self-organizing maps and radial basis function) andadvanced statistics (partial least squares and principalcomponent analysis) permits the extraction of keyinformation that delivers the best candidate forproduction optimization. Starting from the 1990s, thenumber of artificial intelligence techniques hasincreased noticeably.

Economic evaluation. It is paramount tounderstand the economic impact (implementation costvs. additional revenues) of each opportunity. It isrecommended to plot the project added value vs. thecost chart, or the added value vs. the effort required,etc. Selection may involve further reservoir impactstudies in order to evaluate long-term effects in thereservoir.

These techniques are not a solution by themselvesand do not work alone; instead they work together, e.g.for any production enhancement proposal, it ispossible that after a geologically optimized welllocation, an integral solution technique is executed fordrainage evaluation, and then an economic analysis iscompleted.

Table 1 shows a number of petroleum productionsystem problems, the data manifestationsand the many possible solutions to overcomethe problems.

6.2.2 Workovers to eliminateundesired water and/or gasproduction

Various options to reduce lifting and/or water handlingcosts are available for wells that produce largeamounts of water or gas. These include water shut-offtreatments using gelled polymers, lifting costsreduction, power options to reduce electrical costs, andseparation techniques. Not all wells imply the use ofany or all of these techniques, but under the rightcircumstances, major economic benefits can berealized.

Water and gas conformance analysisComplex water and gas conformance problems

may involve one or more of the following situations:injection induced or natural reservoir fractures;



1- integral reservoir analysis

2- well analysis and nodal analysis

rock and fluidproperty maps

4- integral solution portfolio economicanalysis tight to reservoir exploitation plan

5- execute action plan

6- monitoring and review plan

projectmanagement

watercontrol

fracturing

gascontrol

sandcontrol

acidstimulation

re-perforating

solidcontrol

artificiallift

surfacenetwork

costmanagement

action planrecommendation

riskanalysis

economicanalysis

reviewobjectives

reviewportfolio

revised action planrecommendation

acquiredata

optimizeplan

preliminaryopportunity

identification

pressuremaintenance

&conformance

project

open n-zonestimulation

re-perforationfrac & pack

polymer, gels,emulsions, silicates,particles, hoz. wells,

change zones,squeeze jobs

changelines,bottle-

necking,optimize

changemethod,optimize

&combine

removesolids,changetubing

wellfile

builduptests

wellcompletion

injectionproduction

reserverevision

productionlogging

welllogs

optimal conditionsfor well and completion

preliminarycandidate

selection plan

operationalautomation &

reliability analysis

productiongraphs

surface capacityanalysis

crosssection

reserves anddecline curves

3- well and drainage area analysis

select integral solution to optimize productivity

reservoirperformance

drainage area& completion

water & gas controlinjection/production

tubingperform

artificiallift

surfacenetwork

A B

Fig. 8. Integrated production optimization approach.

significant permeability area and vertical variation;open hole completions.

Water shut-off treatments using gelled polymersThe majority of polymer treatments to control

water production in producing wells are performed infractured carbonate/dolomite formations associatedwith a natural water drive. Gelled polymers are createdwhen dry polymer is mixed in water and crosslinkedwith a metal ion (usually chromium triacetate oraluminium citrate). Gelation is controllable, rangingfrom a few hours to weeks. Slower gelation timeallows for more volume and deeper placement.Different polymer systems are available from differentservice providers.

Creating a pressure response during treatment isthe single most important indicator of a potentiallysuccessful water control project. A slow, steadypressure increase over a period of time duringpumping will tell the operator one of two things: theformation is reaching fill-up of polymer into theproblem zone; or the reservoir temperature is causingthe polymer to crosslink and build viscosity. Pressureresponse is a product of polymer volume, injectionrate and gel strength. Altering any or all of thesefactors can improve the success of the treatment ifreservoir resistance is not seen as the gelant is beingpumped. Increasing polymer volume is typically thefirst step recommend if the Hall plot indicates only aslight increase of pressure near the end of thetreatment. The advantage of pumping a larger volume

is that greater in-depth reservoir penetration canimprove the longevity and effectiveness of thetreatment. The disadvantage of more volume isincreased treatment costs due to longer pump timesand additional chemicals.

Usually injection rates are increased at thebeginning of the treatment in order to determinehow easily the formation can accept a viscousfluid. Recent research and field experience haveshown that higher pump rates can improve the effectiveness of treatments in carbonates thatexhibit secondary permeability and porosityfeatures. Increasing the injection rate also reducesthe service company field time, which translatesinto a cost reduction for the operator.

Increasing gel strength or gel viscosity is the thirdmethod for achieving a pressure response. Thismethod is typically used at the midpoint of a treatmentwhen the Hall plot shows no increase in slope or afterseveral treatments in a particular field indicate theneed for such action. The improvement gel strengthcan be achieved by accelerating the crosslinking,increasing the polymer loading of the gelant, or usinga higher molecular-weight polyacrylamide.

Candidate selectionBest candidates are shut-in wells or wells

producing at or near their economic limit. These wellsgreatly benefit from a successful treatment and little,other than the treatment cost, is at risk if the treatmentfails. Other selection criteria include significant



Table 1. General petroleum production system problems, manifestation and remadiation practices

General petroleum production system problems

Low productivity wells or field Accelerated production declineIncreasing operation and maintenance costs Well production is zero, or production losses are high

Multiple manifestations and multiple data evidence

Historic and current production is below target Liquid build up in pipelines and equipment is presentWater cut is high or increasing Well liquid level build/up is present and increasingGOR is high or increasing Abnormal distributed temperature profilesTubing head pressure is low or decreasing Permeability to oil is low or decreasing with timeBottom hole pressure is high or increasing Production losses and deferrement is high or increasingSkin effect (nearwellbore damage) is high or increasing Field subsidence rate is high or increasingPressure drop across tubing is high or increasing Equipment downtime is high or increasingUneven fractional flow across different zones Equipment uptime is low or decreasingCorrective maintenance is high or increasing Safety and environment incidents are high or increasingPressure drop from surface pipeline is increasing Cement bond and other prodcution logging tools

failure indicationsIntermitent or slug flow Resistivity profile indicating water presencePump rod load or motor current are abnormal Pump or compressor vibration/lubricant oil pressure

are abnormalSand production is high or increasing Acoustic response indicating water/gas sequence

remaining mobile oil in place, high water-oil ratio,high producing fluid level, high initial productivity,wells associated with active natural water drive,structural position and high permeability contrastbetween oil and water-saturated rock (i.e., vuggyand/or fractured reservoirs). Successful treatments

have been conducted in both cased and open holecompletions.

Treatment sizingOnly empirical methods exist at this time for sizing

treatments. Experience in a particular formation is



Table 1 (cont’d).

Diagnosed problem or cause Possible recommended remediating actions

Low reservoir pressure support Debottleneck (relax) surface pressure constraintsReview/change well tubing and/or completionImplement/review secondary recovery projectImplement/review artificial lift system & compressor

capacityImplement/review downhole water separators

(Near) wellbore collapse and instability Change drawdonw strategy (reduce flow)Implement fracture and pack of nearwellbore areaHorizontal and multilateral wellsInstall gravel packsReview direction of preferencial stress for drilling

Water or gas breakthoug Implement bacteria or gel injection to control offending zones

Implement near wellbor acid stimulationCement squeeze to shut in zonesRe-perforate and change sleeve positionZonal or well choke controlling settings (optimize total flow)Implement/review enhanced oil recoveryImplement fracture and pack of nearwellbore area

Crossflow Zonal or well choke control settings (optimize total flow)Re-perforate and change sleeve positionChange drawdown strategy (reduce flow)

Solid precipitation Relax surface pressure constraintsChange well tubing and/or completionImplement/review artificial lift systemsInstall wellbore or tubing head chemical injectionChange drawdonw strategy (reduce flow)Implement fracture and pack of nearwellbore areaHorizontal and multilateral wells

Surface Pipeline and vales failures Repair/change pipeline and valvesInstall filters and monitoring equipmentChange/review pipeline facilities desing practices

Casing, cement, tubing, rod and motors failures Cement squeeze to shut in zonesRepare casing, tubing, rod and motors are requiredChange/review casing, tubing, rod and morots

desing practice & limits

Surface bottlenecking Debottleneck (relax) surface pressure constraintsImplement/review periodic steady state surface

optimizationImplement/review advance process control

and identificationImplement/review artificial lift system & compress

capacityImplement/review reliability centered

operations & maintenanceChange/review surface facilities desing practices

most beneficial. However, in many instances largervolume treatments appear to decrease water productionfor longer periods of time and recover moreincremental oil. Some rules of thumb include two timesthe well’s daily production rate as the minimumpolymer volume or using the daily production capacityof the well at maximum drawdown (i.e., what the wellwould be capable of producing if it were pumped off)as the treatment volume. In lower fluid level wells thedaily production rate is sometimes used as theminimum polymer volume.

Preparation prior to pumpingThe wellbore needs to be clean, acidized if

necessary (typically 350-500 gal 15% acid, pumpaway with water). A maximum treating pressure mustbe established; a step rate test to determine partingpressure needs to be run if necessary. An acceptablesource of water to blend and pump the treatmentmust be selected. The water’s compatibility to formthe desired gels needs to be tested. A polymer-compatible biocide for the mix water (typically 5-10gallons per 500 barrels of mix water) must beselected. Tubing and packer above the zone to betreated need to be set.

Placing treatmentStages of increasing polymer concentration must

be used. It is necessary to inject treatment at a ratesimilar to the normal producing rate. Treatmentpressure must be kept below reservoirparting/fracture pressure. Changing conditions duringtreatment may warrant design changes duringpumping. The treatment should be over-displacedwith water or oil. In some instances, a rapid pressureresponse early in the treatment is a sign that thetreatment may not be successful.

Water shut-off using cementWhen a producing zone has been fully (or almost)

watered out, one recommended technique is to forcecement slurry through the perforations to shut-off thatoffending layer. Alternatively, cementing operationsmay be undertaken to set a plug in an existing wellfrom which to plug a well horizon so that it may beabandoned due to high water-cut or excessive gasproduction.

6.2.3 Reservoir stimulation: matrix acidizingand hydraulic fracturing

The general common objective of well stimulation viamatrix acidizing or hydraulic fracturing is to reduce

pressure restrictions around wellbore and the increaseflow rate.

Matrix acidizingThe purpose of matrix acidizing is to dissolve rock

material and remove drilling mud and clay creatingnew flow paths and increasing permeability in nearwellbore area. Acid is used to remove damage fromcarbonate and sandstone formations and to stimulateproduction and injectivity in carbonates. Acid is usedfor both matrix and fracture treatments in carbonates.Matrix acid candidates have permeability greater than10 md in oil wells and 1 md in gas wells. Acid fraccandidates have permeabilities less than 10 md in oilwells and 1 md in gas wells. Matrix acidizing isperformed below the fracturing rate and pressure ofthe formation, where acid travels through existingpores and natural fractures. Fracture acidizing isperformed above the fracturing rate and pressure of theformation, where the rock is cracked and an etchedfracture is created.

Matrix acid treatments are commonly used toincrease injectivity in disposal and injection wells. Ifacidizing injection and disposal wells is needed on aregular basis to maintain injection rates, water qualityshould be examined.

Carbonate rocks, mainly conformed by limestone(CaCO3) and dolomite (CaMg(CO3)2), rapidly dissolvein HCl and create reaction products, calcium chloride(CaCl2), magnesium chloride (MgCl2), carbon dioxide(CO2) and water (H2O), that occur under the followingbalanced equations:calcare ⇒ CaCO3�2HCl → CaCl2�CO2�H2Odolomia ⇒ CaMg(CO3)2�4HCl → CaCl2�MgCl2�CO2�H2O

In carbonates, the rate of dissolution is limitedmainly by the speed with which acid can bedelivered to the rock surface. This results in rapidgeneration of irregularly shaped channels, calledwormholes. The acid increases production bycreating bypasses around the damage rather thandirectly removing it.

Silicate matrix acidizing is different fromcarbonates. Sandstone, mainly conformed by silicondioxide (SiO2), reacts with hydrofluoric acid (HF) toproduce silicon tetrafluoride (SiF4). As a secondaryreaction, silicon tetrafluoride (SiF4) will react withmore hydrofluoric acid (HF) to produce siliconhexafluoride (SiF6

2�). Hydrochloric acid does not reactwith silicate materials. SiO2 and HF reactions occurunder the following balanced equation:

4HF�SiO2 → SiF4�2H2O

SiF4�2F� → SiF62�



By comparison, the reaction rate betweenHF and sandstones is much slower than HCl. Mud acidizing seeks to unblock existing pathways for production by dissolving wellboredamage and minerals filling the interstitial pore space, rather than creating new pathways.The HF reacts mainly with the associatedminerals of sandstones, rather than the quartz.The acid reactions caused by the associatedminerals (clays, feldspars and micas) can createprecipitants that can cause plugging. Much of the sandstone acid’s purpose is to preventthis possibility. A considerable improvementin the success rate of sandstone matrixacidizing was achieved by monitoring,in real time on the field, the evolution of skineffect and damage removal. Such monitoringevaluates whether the fluids are adequate withregards to their composition and volume.It also assesses the required modification forthe treatment or for future improvementsin other treatments.

Another challenge that must be faced ineither lithology is how to direct the acid flow.As acid is pumped, it flows preferentiallyalong the most permeable path into theformation. The acid opens these paths up evenmore, and less permeable, damage zones arealmost guaranteed not to receive adequate treatment.A technique to divert the treatment fluid towardsdamage formations or damage perforations istherefore mandatory.

There is a variety of diversion techniques.Treatment fluid can be directed exclusively towardsa low permeability zone using drill-pipe or coiledtubing conveyed tools, equipped with mechanicalpackers. The diversion of treatment fluids can alsobe achieved by bullheading acid at maximuminjection rate below the fracture pressure. Thismaximum injection rate maintains a sustaineddifferential pressure in the near wellbore area to betreated. Alternatively, flow can be blocked atindividual perforations.

In carbonates, bridging agents such as benzoic acidparticles or salt can be used to create a filter cakeinside wormholes, encouraging the acid to goelsewhere. In sandstones, microscopic agents such asoil-soluble resins can create a filter cake on the sandface. Chemical diverters such as viscous gels andfoams created with nitrogen are used to block high-permeability pathways.

The requirements on any diverting agent arestringent. The agent must have limited solubilityin the carrying fluid, so it reaches the bottomof the hole intact. It must not react adversely

with formation fluids; it must divert the acid.Finally, it must clean up rapidly so as notto impede later production. Ball sealers dropin the rat hole as soon as injection halts or,if they are of the buoyant variety, they arecaught in ball catchers at the surface.Benzoic acid particles dissolve inhydrocarbons. Oil-soluble resins are expelledor dissolved during the ensuing hydrocarbonproduction. Gels and foams break downwith time.

Hydraulic fracturingHydraulic fracturing is used to create high

permeability flow conduit in tight rocks, increasingthe area of flow to wellbore. It is also used in highlypermeable rocks as sand control, liquid dropoutprevention or turbulent flow control technique bydecreasing pressure drop around the wellbore. Theinitiation of a hydraulic fracture in a well is thetensile failure, or breakdown, of the surroundingrock caused by the injection of fluid (Economides etal., 1994, 1998; Dusterhoft and Chapman, 1994;Economides and Nolte, 2000; Fan and Economides,1995; Mukherjee, 1999). Fracture propagation fromthe well into the reservoir is extended as fluid athigh rate continues to be injected. The pressureneeded to initiate the fracture is often considerablygreater than the pressure required to propagate thefracture. Commonly, at an appropriate instant duringinjection, proppant is added to the fracturing fluid tokeep the fracture open. Thus, a conductive pathwayis created for fluid flow from the reservoir to thewellbore.

In the past, hydraulic fracturing has been usedalmost entirely to stimulate the productionor injection of wells in low-permeability reservoirs(Economides et al., 1994, 1998; Mukherjee, 1999;Economides and Nolte, 2000). Such a hydraulicfracture invariably results in a high-conductivitypathway, and thus, for low-permeabilityreservoirs the intention has always been togenerate a long fracture allowing considerablepenetration of the reservoir by such a high-conductivity path. This goal is convenientlyaccomplished in unrestricted fracturing. However, inhigh-permeability reservoirs, the incrementalconductivity obtained under normal circumstancesfrom a traditional fracture treatment would be verysmall, leading to a low-conductivity fracture. Lowconductivity would also lead to a large pressure dropalong the fracture during production. This would meanwasteful over-treatment because much of the fracturelength would not contribute effectively to wellproduction.



Some readers may find part of the logicof the paragraph above difficult to comprehend.It should be stressed that conductivity is ameasurement of the contrast betweenthe ease with which fluids flow in the createdfracture compared to the alternative, i.e.,no fracture. In low-permeability formationseven a bad treatment can produce ahigh-conductivity fracture. Narrow and lengthyfractures are needed. Frequently, this notionescapes even practitioners in the field.It is not a great accomplishment to pump a largeamount of proppant and pack a fracture ina low-permeability formation. Pumping very smallproppant slurry concentrations for very longperiods of time is often what is guaranteed.

In contrast, in higher-permeability reservoirs, theresulting fracture conductivity is of paramountimportance while the fracture length is secondary.This physical demand in the fracturing of high-permeability reservoirs was aided greatly by theintroduction of the Tip-Screen-Out technique (TSO;Smith et al., 1987). This is the arrest of the lateralgrowth of the fracture, which is subsequentlyinflated. The result is a relatively short, large-widthfracture with much higher fracture conductivitycompared to what unrestricted fracturing couldyield. Furthermore, a small fracture length limits thefracture fluid leak-off into the formation (which issevere in high-permeability reservoirs) and hence,contributes to the success of the treatment. Thus, inthe last few years, high-permeability reservoirs havealso become attractive candidates for hydraulicfracturing.

Objectives of high-permeability fracturingThe general objective is to stimulate the

production or injection rate of a well. Beyond theobvious motivation, there are several other objectivesin the fracturing of a high-permeability formation,described below.

Bypassing formation damage. A fracturethat penetrates beyond the near-wellboredamage region effectively bypasses and nullifiesthe effects of this damage zone. These effects,left unchallenged, would result in impairedproductivity and invariably unwanted largerpressure drawdown. Often, matrixsimulation to remove the near-wellboredamage is either partially effective or totallyineffective.

Reduction of near-wellbore drawdown duringproduction. Pressure drawdown, which is equal tothe reservoir pressure minus the flowing bottomholepressure, is the sole driving force for flow from the

reservoir to the wellbore. As drawdownincreases it may affect the formation stability.Formation instability may cause fines andsand to migrate into the wellbore region.A short and wide fracture can overcome thisproblem by reducing pressure losses andvelocities in the reservoir sand near the wellbore.

Improving communication between reservoirlayers and the wellbore. In multiple laminatedsand/shale sequences, the thin laminated sand layer may not communicate efficiently withthe wellbore until a fracture is performedto provide a continuous, vertically penetrating,connection to the perforations.

Reducing the effect of non-Darcy flow in most dry gas and/or gas condensate reservoirs. Generally,for reservoir permeabilities below 5 md thereis little effect from non-Darcy flow. In higher-permeability reservoirs, the non-Darcyterm becomes increasingly important and could significantly reduce the well productionrate. A hydraulic fracture provides further conductivity and the flow velocities fromthe reservoir can be reduced enough so that non-Darcy effects are either eliminated or markedlyreduced (Settari et al., 1998).

Candidate well selection for high-permeabilityfracturing. To determine which well is suitablefor high-permeability fracturing and, ofeven greater importance, the size and typeof fracture treatment, candidates are classified intotwo major categories depending on whatis expected from the well. For productionenhancement these are:• Formations where matrix acidizing is not possible

due to mineralogy or because the penetration ofdamage is too deep or too severe to be removed bymatrix stimulation.

• Multiple pay zones in laminated sand/shalesequences, in which the laminated layers could notcommunicate with the wellbore unless a fractureprovides the connection.

• Gas wells in high-permeability reservoirs in whichproduction is impeded because of non-Darcy flow.A fracture can greatly reduce the non-Darcyeffects. According to Settari et al. (1998), for anyreservoir permeability, as the reservoir pressureincreases, the fracture becomes less effective inreducing reservoir turbulence and a longer fractureis needed.For near-wellbore drawdown related problems the

following are suitable:• Poorly consolidated formations in which

fracturing may act as a substitute to gravelpack without the associated plugging,



which almost always appears in gravelpacks resulting in large positive skins. The mainmechanism that favours high-permeabilityfracturing over gravel packs in poorlyconsolidated formations is the reductionin the fluid flux at a desired flow ratebecause of the substantial increase in thearea of contact with the reservoir. Thisincrease in area prevents the de-consolidationof sand and its migration towards the well.All wells that are candidates for gravelpacking, especially wells in which gravelpacks might reduce the near wellborepermeability, are generally even bettercandidates for high-permeability fracturing.

• Low-bottomhole-pressure wells in which formationcould not afford the required drawdown forsatisfactory radial flow production.

Procedure for candidate recognition for high-permeability fracturing

It is, first of all, important to determineand confirm that the well is under-performing. Well production rate alone, which may be below one’s fond expectations, may not meanthat the well is a candidate for stimulation.This notion implies that the production engineermust know the well, the actual geology, thereservoir pressure and its depletion, the realdrainage and, of course, the all importantreservoir permeability.

Furthermore, ignorance of the reservoirpermeability and the associated well skineffect may lead to substantial errors, not onlyin selecting the appropriate stimulationtreatment (i.e. matrix stimulation or hydraulicfracturing). As it will also be shown later in thischapter the value of the reservoirpermeability is crucial to the sizing of thehydraulic fracture. It is not enough justto decide that fracturing is appropriate.A pressure transient test, to delineate betweenthe controlling influences on production(permeability vs. skin) is strongly recommended,especially in high-permeability reservoirs.

A large pre-treatment skin effect maynot necessarily mean damage, let aloneacid-removable damage. Other factors mayprovide large skin effects such as phase behaviourand turbulence. The latter is particularlyimportant in high-permeability gas or two-phasewells. It is essential for well performance analysisand identification of production impediments to bethorough both for the design and the subsequentevaluation phase of the stimulation treatment.

The reservoir rock and fluid chemistry musttherefore be well understood especiallyconsidering the potential unpleasant sideeffects of matrix stimulation treatments. In thepast, when only low-permeability fracturingwas possible, there were no choices: permeability less than 1 md meant fracturing;permeability substantially large meant matrixstimulation. If undesirable side effectswere unavoidable, the engineer had only onechoice: perform the treatment and take thepenalty or not do it at all. Today, withhigh-permeability fracturing, bypassingdamage is a very legitimate alternative inany-permeability reservoir. Intelligent andeconomic-motivated choices are now possible.

Finally, there is no question that reservoirswith sand production are particularly attractivefor high-permeability fracturing. In this respectthe verdict is unambiguous. In almost all cases,wells with sand production problems are farmore likely to benefit from fracturing than anyother sand exclusion technique such as gravelpacking.

Key issues in high-permeability fracturingTaken as a continuum, high-permeability fracturing

does not differ from low-permeability fracturing. Theoptimum dimensionless fracture conductivity that canbe achieved is 1.6 for any proppant volume in aninfinite acting reservoir (Prats, 1961). Thedimensionless fracture conductivity, introduced byCinco-Ley et al. (1978) is:

kfw[15] CfD�11kxf

where CfD is dimensionless fracture conductivity,kf (mD) is the proppant pack permeability, w (ft)is the average fracture width, k (mD) is theformation permeability and xf (ft) is the fracturehalf length. The fracture conductivity and thefracture length are combined in the estimationof a skin effect, sf , which acts as an ‘accounting’procedure for the stimulation effects ofa hydraulic fracture. Added to the dimensionlesspressure term describing the reservoirbehaviour, this skin effect functions at radialand pseudo-radial flow exactly as anyother skin effect.

In high-permeability fracturing the demandis for a much higher fracture conductivity comparedto what would be obtained from unrestrictedfracture propagation; the fracture lengthis of secondary importance. This higher-conductivityfracture can be achieved with a larger fracture



width (versus an acceptable much narrowerwidth for low-permeability fracturing), large proppantpack permeability and short fracture length(versus a required long fracture length in low-permeability reservoirs). The need for high-proppant concentration in the fracture sometimesresults in the use of high proppant-slurryconcentration. Thus, high-permeability fracturingneeds more planning, better understanding of fluid and proppant rheology and careful placementof the proppant pack compared to low permeabilityreservoirs.

To maximize the proppant concentrationinside the fracture and to achieve higherconductivity, the TSO technique is employed.In a TSO, the lateral fracture propagationis arrested (a complete screen out shouldbe achieved), after which continued pumpingwill inflate the width of the fracture and willresult in a short but highly conductive fracture.To properly execute a TSO, a pre-treatment testor ‘minifrac’ should give accurate values forfracture closure pressure, fracture closure time,and fluid properties.

The execution of a fracture treatment in ahigh-permeability reservoir is impeded severelyby fluid leak-off. Filter cake-building fracturingfluids (such as crosslinked polymers) are used toreduce the invasion of polymer into the reservoir,normal to the direction of fracture propagation.Otherwise, if the invasion is not controlled,severe permeability damage could occur in thereservoir.

Cinco-Ley et al. (1978) and Cinco-Ley andSamaniego (1981) provided the understanding of thefactors affecting the performance of finite-conductivity fractures and identified the types ofdamage impeding their performance.

Reduction to the proppant pack permeability.This kind of damage affects the proppant pack insidethe fracture and is a manifestation of proppantcrushing and, especially, of unbroken fracturingfluid polymer. These phenomena have particularlydetrimental impacts on the fracture conductivity and should be avoided or minimized.The problem with proppant crushing can be reducedconsiderably by selecting appropriate-strengthproppants. In high-permeability fracturing‘cutting corners’ on proppant quality should be avoided, practically at any cost. In fact, in view of the relatively small volumes, required inhigh-permeability fracturing, moving towardsthe highest quality and strength proppants can bereadily justified. The potential incremental benefitsare such that any savings in proppant costs can be

over-shadowed by even minute reductions in theproppant pack permeability. To minimize polymer-related problems, extensive research has beenconducted in the last several years on breakertechnology (in which chemicals are used to breah thethree-dimensional structure of the polimers). Workhas also been done for the use of appropriate chemicalagents and the method of their delivery.

Choke damage. This refers to the near-well damageinside the fracture. It can be depicted by a skin effect.This kind of damage results either from finesmigration during production and their accumulationnear the well (within the fracture) or over-displacement at the end of the treatment (this is a fatalerror if it happens) or inadequate perforationsconnected with the fracture. It is possible to calculatethe skin from the choked damaged fracture byassuming steady state flow in the damaged zone(Cinco-Ley and Samaniego, 1981):

pxsk[16] sfs�113

bfskfs

where xs, bfs, kfs are the damaged fracture length (ft),width of damaged fracture (ft) and damaged fracturepermeability (mD), respectively. Fig. 9 is a schematicdiagram of choke damage.

Fracture face damage. This kind of damage,caused conventionally by fracturing fluid leak-off,results in permeability impairment outside thefracture, normal to the fracture face. Again Cinco-Leyand Samaniego (1981) provided a means to accountfor this damage by virtue of a skin effect, defined by:

pbs k[17] sfs�

133 �1�1�2xf ks

where bs (ft) is the penetration of damage normal tothe fracture face and ks (mD) is the damagedpermeability inside this zone. Fig. 10 is a schematicdiagram for this damage.

Combined effects. Mathur et al. (1995) proposed ameans to account for composite damage that can bequantified by a skin effect expression. This compositeskin, or damage skin sd, may be represented by:

p b2kR �b1�b2�kR b1[18] sd�1�111111�1111112 1�2 b1k3��xf�b1�k2 b1k1��xf�b1�kR xf

Fig. 11 is a schematic diagram of the compositedamages accounted for in sd.

The damage skin, given by Eq. [ 18] can beadded directly to the estimated fracture equivalentskin effect sf (Cinco-Ley et al., 1978) to obtain thetotal skin:

[19] st�sd�sf

where sf can be determined from Fig. 12.



It is relatively easy to see that for a longfracture (100 ft), the fracture face damage haslittle impact on well performance. This is nottrue for short fractures with significant damagepenetration and small fracture conductivity. For ashorter fracture, such as the ones performed in high-permeability reservoirs, it would be necessary toconsider fracture face damage impairment alongwith the all-important high fracture conductivity.

Hunt et al. (1994) have suggested that the initialproductivity impairment because of fracture face

damage may diminish over time for a suitablydesigned treatment. Aggour and Economides(1999) concluded that the penetration of damagenormal to the fracture face is more important thanthe degree of damage. If the penetration ofdamage is minimized, even 99% damage to thereservoir permeability should still result in anegative skin. This is an important conclusionsuggesting that even though the performance of high permeability fractures is expected to improve with time as cleanup of the fractureoccurs, the appropriate choice and engineeringof fracturing fluid can reduce or even eliminatethe time of initial loss production significantly.Aggour and Economides (1999) further proposedthe use of high polymer loads of crosslinkedfracturing fluids to minimize penetration ofdamage. To complete the fracturing fluid designthere is a crucial need for good breakers and filtercake building additives. This type of fracturingfluid can minimize the spurt loss and leak-off.Thus, in high-permeability fracturing, whilecreating a highly conductive fracture should be theprimary concern, the same treatment must beengineered to prevent fracture face damage, apotential highly detrimental event.

Causes of underperformance of high-permeability fracturing

Additional causes of underperformance of high-permeability fracturing include:a) the failure to attain the designed geometry, suchas unconfined height growth and failureof TSO to arrest lateral growth; b) inappropriateperforations that might lead to the creationof multiple and tortuous fractures instead of the



bf kf kfs

xs xf

kdamage zone fracturewell

Fig. 9. Vertical fracture with choke damage:xf is the semi-amplitude of the fracture, xs is the skin length, kf and kfs are the permeability of the proppant-pack with or without skin effect respectively, k is the permeability of layer bf .

bsks

kf

xf

bf

damage zone well

fracture

Fig. 10. Vertical fracture with fracture face damage.

fracture radialdamage

fractureface damage

rsxf

Fig. 11. Vertical fracture with composite damage.

3

2.5

2

1.5

1

0.50.1 1

s f �

ln(x

f /r w

)

10C fD

100 1,000

Fig. 12. Relationship between skin factor sf ,semi-amplitude of the fracture xf , wellbore radius rw, dimensionless fracture conductivity CfD.

designed vertical fracture; c) asymmetric fractureextension, which is more common in depleted reservoirs; d) insufficient fracturecoverage in multilayered reservoirs that can lead to communication breakdownbetween the formation and wellbore. Furthermore,an emerging understanding for well under-performance is one that can be attributedto the formation of liquid condensate ingas-condensate reservoirs.

Gas condensate reservoirs Gas condensate reservoirs frequently

experience a phenomenon that has a similar effectas fracture-face damage in high-permeabilityreservoirs. The pressure gradient that is creatednormal to the fracture causes liquid condensate toform, creating a gradient into the reservoir.This liquid condensate has a direct impact onthe relative permeability-to-gas, which isreduced. The phenomenon is tied to the phasebehaviour of the fluid, i.e., the dew pointpressure and the penetration of liquid condensate,which depends on the pressure drawdownimposed on the well. This entire process causesan apparent damage that affects theperformance of all fractured gas condensatewells irrespective of the reservoir permeabilityalthough it would be particularly detrimentalin high-permeability reservoirs. The fracturesare much shorter and the penetration of thepressure gradient normal to the fracture is muchlonger.

The pressure and flow rate behaviour of a gas condensate is distinctly different from the behaviour of a two-phase reservoir.In a two-phase oil and gas reservoir the two-phaseenvelope (see Chapter 4.2) describes a regionbracketed between the bubble point pressure and the flowing bottom hole pressure. Such behaviour applies to the left (i.e. at lowertemperature) of the pseudo-critical point on the phase diagram. Starting at the right of thepseudo-critical point, the locus of the dew point pressures curves until it reaches thecricondentherm point (maximum temperature point).Between the pseudo-critical and the cricondentherm points, as the pressure declines from the dew point pressure (at constant temperature)liquid emerges. The amount of liquid increases as the pressure in the reservoir decreases until a certain value at which furtherreduction of the pressure causes the liquid tore-vaporize. This region is called the retrograde

condensation zone and reservoirs experiencing

this phenomenon are known as gas condensatereservoirs.

The production rate of gas condensate reservoirsis not affected only by the pressure gradient butis a much more complex function of also theactual value of the flowing bottomhole pressuresince the latter dictates the amount and distributionof liquid condensate accumulation near thewellbore. One simple way to prevent the formationof condensate is to maintain the flowingbottomhole pressure to be above the dew point.However, in almost all cases the resulting pressuregradient may not be sufficient enough for aneconomically attractive production rate.This leads to either an optimization balancingof drawdown vs. relative permeability impairmentor, more appropriately, to the hydraulic fracturingof gas condensate wells.

Gas condensate reservoirs under radial flowcan be divided into three regions based on the type of flow (Settari et al., 1996). The firstregion is the farthest away from the wellbore,where the pressure is higher than the dew point.Only gas is present and is affected by Darcy radial flow with a controlling permeability,the effective permeability to gas. The secondregion is characterized by pressure slightly below the dew point. The condensate liquidforms but the liquid saturation is low.The flow is still Darcy flow. The flowing fluidis primarily gas in this region. However,the emergence of condensate causes a reductionof the relative permeability to gas. The thirdregion is the near wellbore area. It has thelowest pressure and the highest velocity.As the fluid converges to the wellbore, the cross-sectional area of flow is reducedsubstantially and the flow becomes non-Darcy.At the boundary of the first region and the secondregion, the pressure is equal to the dew point.From the boundary inwards (towards the wellbore and including the third region), thecondensate film or ring around the fracture acts asa fracture face skin.

Similar two-phase regions appear in the case of a hydraulically fractured well except thatthe distribution of the liquid condensate normalto the fracture (the length of damage penetrationcan be tens of feet for high-permeability reservoirs)can reduce the amount of productionsignificantly. Thus, optimization is necessarybecause of the need to adjust the fracturegeometry.

Wang et al. (2000) conducted a study ofproduction impairment and presented a purpose-built



design for hydraulic fractures in gas condensatereservoirs. The study demonstrated that the requiredfracture length was the essential element to adjustin order to offset the problems associated with the emergence of liquid condensate. Invariably, much longer fracture lengths (and therefore much bigger treatments) would be required to provide the expected productivity index from anoptimization scheme that ignored the effects of condensate.

Non-Darcy effectIn high-permeability reservoirs, non-Darcy effects

can significantly reduce well production rates. Non-Darcy flow hampers the well production in fracturedgas reservoirs in at least two ways: the apparentpermeability of the formation may be reduced(Wattenburger and Ramey, 1969); the non-Darcy flowmay reduce the conductivity of the fracture (Guppy etal., 1982).

Screenless and rigless completions Substantial effort has been expended to reduce

treatment costs and to simplify treatmentexecution. One important item is the removal or simplification of gravel-pack screens and tools that are still used in high permeabilityfracturing completions. Kirby et al. (1995)reported that several screenless highpermeability-fracturing treatments have been completed with considerable success. The executions eliminated the screencompletely and used conventional fracturingmethod with a modification: the final proppantstage was tailed in with resin coated sand tocontrol proppant flowback. However, furtherresearch is being conducted to ensurethe resin-coated proppant is placed as neededto prevent proppant flowback and thus, ensurea high conductivity connection betweenthe fracture and the wellbore.

Screenless, high permeability fracturinghas the potential to allow the development of multiple-zone high permeability fracturingcompletions. Hailey et al. (2000), proposeda new screenless single-trip multizone sandcontrol tool system. This system enhancesthe benefit of screenless high permeabilityfracturing by reducing the time requiredto complete multiple producing intervalsin unconsolidated sand formations during onesingle trip into the well. The approachincorporates the previously used pumpingprocess of simultaneous fracturingwith proppant slurry and chemical consolidation

of that proppant. Resin coated proppantis used during slurry pumping to provide sandcontrol and flowback control while leaving thecasing across the interval clear (except formultiple isolation packers that can be used forproduction management during the life of the wellin order to control production from the variouszone for optimum recovery and maximumproduction).

The primary cost cutback from utilizingthese approaches is the reduction of rig timeassociated with tripping drill pipe in and out of the hole, as it is necessary for conventional completion of multiple fracturing treatments. As the number of treatments completed in a single trip increases, the cost per treatmentdecreases. This type of completion providesopportunity for small and economically marginalreservoirs to be completed along with more valuablereservoirs in one process to make a total projectachieve the required profitability.

Screenless high permeability fracturing also allowsthrough-tubing completions. The major benefit of such completions is that they can be done without a rig on location. New high permeability fracturing equipments are also emerging to enable rigless coiled tubing completionsin wells that are completed with gravel-pack screens (Ebinger, 1996). This advancement could cut the rig costs and inefficiencies associatedwith rig timing.

6.2.4 Sand control

One of the major issues associated with oil and gas wells is the production of formationparticles, often referred to (and at times incorrectly)as sand. If the problem is not addressed properly, it can cause a wide range of costly and potentiallyhazardous problems. Sand production accumulating in the tubulars will reduce oil and/or gas production from the well. If the well has enough energy to carry the sand to the surface, it can cause severe pipe erosion. Once on thesurface, it can play havoc on the surface equipment.Premature failure of downhole equipment, such as electric submersible pumps, can prove very costly and failure of subsurface safety valvescan be extremely dangerous. In addition to theproblems it can cause on the mechanical aspects of the well, sand production can also causesignificant formation damage, which can reducewell performance dramatically. It is important that the potential of sand production is identified



before completing the well and steps are takento prevent it. If sand control measures are nottaken early enough, serious formation damagecan take place, which will limit the amount of optionsand diminish the productivity of the well.

Mechanics of sand productionTo design the correct sand control method, first the

mechanics of sand production need to be understood,as described below.

Grain-by-grain movement. Perhaps the cause of most formation failures; sand moves awayfrom the formation face. If sand control measuresare not taken in time, the options of sand controlbecome limited.

Movement of small masses. Formation rock canbreak away and cause rapid failure. The wellbore getssanded and once the perforations in the casing arecovered it will cease to produce.

Massive fluidization. Massive amounts of sandcan cause erosion or prevent production. Also,disposal of massive amounts of sand can become a problem.

Methods for sand production controlThere are five methods for sand production

control: production restriction, mechanical methods, chemical methods, combination methods and high-permeability fracturing.

Production restriction. Lowering the productionrate reduces the fluid velocity in the formation,which can reduce sand production. The lower ratehowever might not be always economical and notwork. Horizontal wells which can produce at thesame or high rate as vertical wells, at a lowerdrawdown pressure and a lower fluid velocity mightbe an option.

Mechanical methods. Perhaps the most widelyused methods, they are very heterogeneous but always include some kind of a device installedto filter and prevent the formation sand from entering the wellbore. These devices can be wire-wrapped screens, slotted liners, prepackedscreens and metal filters, usually used withgravel packs. Wire-wrapped screens and slotted liners filter out formation sand and retaingraded sand or propping materials, which are placedagainst the formation to support it. Gravel packs are mechanical bridging systems which can beachieved by placing large amounts of proppant (sized)against the formation face and held in place bya screen or slotted liner.

Chemical methods. These methods are achievedby injecting plastics or resins into the formation.The objective is to provide a grain-to-grain

cementation (sand consolidation) without loosingpermeability.

Combination methods. These methods combine mechanical sand control methods and chemical consolidation. Gravel pack sand or proppant material (mechanical filter) is coated with resin and when cured it bonds the sand together and holds it in place (chemical consolidation).

Methods of high-permeability fracturing. Perhaps the most effective technique for sandproduction control, while it also provides well stimulation in high-permeability fracturing. The control is achieved by a major reductionin the flux (velocity) of the fluid. Because thepresence of a fracture provides a very large cross-sectional area of flow, compared to radialflow, the fluid velocity is reduced dramaticallyfor a given volumetric flow rate. Particledeconsolidation is an erosion process and thereduction in the flux reduces the particle migrationconsiderably. Also, the presence of a successfulfracture precludes any radial flow into the well andan added benefit is that such well completion doesnot require screens, if the fracture proppant isconsolidated properly.

Gravel and screen designFor the gravel pack design to work properly

and to provide for the optimum well performance, the gravel must be large enough to allowformation fines and clay particles to flow through, so it does not plug up the gravel pack and, at the same time, it should be small enough to filter out formation sand. The screen must be ableto retain all the gravel in place. The first step to sizing the gravel is to obtain a representativesample of formation material and to determinethe particle size distribution in the formation by performing a series of sieve analysis. Once this is done, correlations have been developedin selecting the right gravel size.

There is a large variety of liners and screens,which can be used to retain the gravel pack, and its selection can affect how well the gravel is packed, the flow capacity and the life of thegravel pack. At the economic end of the scaleis the slotted liner. Slots are milled longitudinallyon oilfield pipe; the size of slots can vary tomatch the needs. This liner provides good strength

and it is best suited for water wells. Single or dual wrapped screens, are madewith slotted or drilled oilfield pipe, wrappedwith keystone shaped stainless or corrosionresistant wire. The screen is spaced-out from the



pipe to allow for maximum flow through thescreen. This type of screen can also be prepackedwith gravel. Another type is the casing-externalprepacked gravel-pack screen. Best suitedfor horizontal wells, this is a wire wrappedscreen with two concentric pipes. The innerdiameter is the same like a small-diameter slotted liner and the outer pipe is a larger slottedliner. In between they pack it with resin-coatedgravel. The wire wrapping is to prevent the gravelto leak through. It is usually prepacked withresin-coated gravel. There is also the low profile screen, the sintered metal screen, thewoven metal-wrapped, the auger-head screen,while new designs keep being developed.

Once the screen is selected and the gravel pack has been designed, the screen has to be placedin the well and packed with gravel. For this, specialfluids are required which are able to transport thegravel, separate from the gravel to allow for a goodpack, and be produced out of the well with little orno damage to the formation.

6.2.5 Perforating

The process of completing a well includes casing andcementing the wellbore. Steel casing is installed in thewell and is cemented in place, totally isolating thereservoir from the wellbore. Before any oil and/or gascan be produced or injected into the reservoir,communication between the wellbore and the reservoirhas to be re-established. This is done by ‘perforating’or drilling the casing at the objective horizon. Thepenetration of these perforations must extend beyondthe cement and into the formation.

One of the oldest methods of perforatingis the bullet gun kind. It was patented in 1926 and until the 1950s it was the most widely usedmethod. A short barrel (2'' or less) is loaded withpropellant and a bullet. Several of these barrelsare arranged on a steel carrier called the gun,which is lowered into the well at the desiredhorizon and the propellant is ignited by an electricsignal sent by wire. The bullet is acceleratedand shot into the casing, perforating both thecasing and the cement into the formation.The bullet type perforator is suitable for wellsin softer formations, but its performancediminishes in harder formations.

A second method of perforating is throughhigh-pressure water or sand laden slurry jets. Water or slurry is pumped down the tubing.A deflector and nozzle at the end of the tubingdirects the fluid stream, which impinges directly

into the casing making holes, sluts, or even cuttingthe casing completely. A variation of this method has a flexible extending lance at the end of thetubing, which can jet its way into the formation,creating clean tunnels with very little or nodamage at all. The drawback is that only oneperforation at a time can be made, a time consumingand expensive.

Jet perforating uses metal lined shaped chargesand is the widest method of perforating today.It is based on armour piercing technologydeveloped in the Second World War. The design of the shaped charge is simple (Fig. 13). It consistsof the case, a metal liner usually made of copperin a conical shape, high explosives and thedetonator. When the high explosives are detonated, the pressure, which is in the range of15,000,000 to 30,000,000 psi, is focusedon a small area, causing the copper liner tobecome a jet, travelling at a speed of 13,000 to26,000 ft/s. This high-pressure copper jet createsa channel through the casing, the cement and into the formation, just like a jet of watercan create a hole in gelatin. Typically, this channelhas a diameter of 0.25 to 0.4'' and length of 6to 12'', though perforations with larger diameterand deeper penetration are currently offered. Shaped charges are arranged on a steel carriercalled a train, or a perforating gun as shownon Fig. 14. The number of shaped charges per unitlength is called the perforation density andis typically measured in shots/ft. The anglebetween adjacent charges is called thephase angle. The train, or perforating gun, can be conveyed downhole with productiontubing, coiled tubing, slick line and electric line.The charges can be detonated with eithermechanical or electrical detonators.

At the moment of perforation, crushed rockand debris can enter the perforation tunnel,thus impairing its ability to allow fluid to flow



explosive

case

liner

detonator

Fig. 13. Shaped charge for perforating.

or even totally plugging the perforation off.One way that has been proven very effectivein minimizing damage to perforations isunderbalanced perforating. Underbalancedperforating is defined when the pressure in thewellbore is lower than the pressure in thereservoir. Thus, at the moment of perforation,fluid from the reservoir enters the wellborekeeping the perforation clean. Several field and laboratory studies have been done and the results, when plotted, showed the minimumunderbalanced pressure required to achieve cleanperforations. There are cases whereunderbalanced perforation is not possible, either because the reservoir pressure is nothigh enough, or for other mechanical reasons.Another technique that has been provensuccessful in field studies is the extremelyoverbalanced perforations. In this process, during the perforating procedure, the wellbore is filled with fluid above the perforations and then pressurized with a highly compressible gas. At the instant ofperforation, the stored energy in the gas forces the fluid into the perforations, which is believed tocause fractures in the formation and greatlyenhance well conductivity. This method is gainingpopularity, especially in preparations forhydraulic fracturing.

The number of perforations per unit length, thediameter and the channel length of the perforationsgreatly affect the well productivity. To account forthis, the perforation skin has been developed.Perforation skin is the sum of the plane flow effect,which is a function of perforation phase, the verticalconverging effect, which is a function of perforationspacing and channel length, and the wellbore effect,which is a function of the perforation diameter.

6.2.6 Production optimization by artificial lift

During the life of a producing field, static reservoirpressure may not be in adequate amount to lifteconomic flow-rates through the wellbore andovercome surface pressure restrictions. Lowproduction rates are also observed when wellbore fluidgradient increases as a consequence of water presencefrom the reservoir.

Artificial lift systems objective is to reduce bottomhole flowing pressure and increase flow rate. Artificialgas lift objective is to reduce net hydrostatic gradientby injecting gas lift to the downhole produced fluids.Pump-assisted lift methods aim at boosting downholepressure by using sucker rod pumps, ElectricSubmersible Pumps (ESPs), progressive cavity pumpsor plunger lifts.

Numerous articles related to multiphase flow andartificial lift can be found in the literature. A few ofthese examples are cited in the references(Economides et al., 1998; Economides and Nolte,2000; Dusterhoft and Chapman, 1994; Mukherjee,1999).

As reservoir conditions change with time,artificial lift quantities (gas lift flow, compressorpower, pump head, or pump strokes) have to adjustin order to maintain proper fluid production. Acontinuous depletion of reservoir pressure willcause the bottom hole flowing pressure levelsufficiently low as to make the conventional lifting(spontaneous production) inefficient anduneconomic. These situations are ideally suitablefor combining different lifting practices suchas gas lift and ESP for improved utilization oflifting methodology. Additionally, surfacefacilities such as gas compression and/or electricpower may vary from site to site. Gas usage variesdynamically in accordance with market demand and corporate business strategy, therebyaffecting the field performance. On the other hand, some secondary recovery projects may turn out to be uneconomic whenthe investment cost of artificial lift using



rw

rperf

hperf

lperf

q

Fig. 14. Unit configuration for perforated wellwith shaped charge: rw is the well radius, rperfis the perforation radius, lperf is the chargeperforation length, q is the phase angle, hperf is the distancebetween two perforation processes.

ESP or gas lift are not appropriatelyconsidered.

Artificial gas liftGas lift consists of compressed gas injection

through mandrel valves located along theproduction tubing close to the perforations withthe purpose of changing net flowing fluid densityupward (Fig. 15). Wellbore fluid density isreduced with the consequent reduction in pressureloss due to gravity, however with some additionalpressure losses due to slippage (slippage of thegas relative to the oil) and friction. Reservoirenergy is now sufficient to lift the lighter fluidcolumn to the surface at current tubing headpressure conditions.

Lifting efficiency and hence oil production, is afunction of producing Gas/Liquid Ratio (GLR), WaterCut (WCT), lift gas injection pressure, initial injectionpoint depth, crude composition, pipeline andformation characteristics.

Gas-lift operating features and limits The main disadvantages in gas lift are,

initial high investment cost for compression,increasing demand for gas lift during reservoir life and uneconomic oil rates at lowreservoir pressures. Generally the producingrates increase with increasing lift-gasquantities (see again Fig. 15). There is a maximum gas-lift amount beyond which theproduction rate will decline. This is because of the fact, that a continuous increase of injection pressure will create additional backpressure towards the reservoir. Also,increasing amounts of gas in the producingtubing will create tremendous friction andpressure drop.

Gas lift is not efficient at very low reservoirpressures, since gas-lift pressure gradient mayimpose additional backpressure to the formationand avoid any fluid to be produced. Also, gas liftis not convenient at high water cut values, becauseof high water and gas slippage velocities. However,gas lift is quite effective when there is adequatepressure support and at relatively low water cuts.Moreover, low maintenance is required alongwell life cycle.

Dynamic gas-lift automatic control Automatic control and optimization is used to

inject the optimum gas rate. Given the currentconditions of mass flow rate, tubing head pressure andtemperature (controlled variables), a closed-loopcontroller will calculate the optimum gas rate and

pressure (manipulated variables) that maximizes flowrate at any time.

For a large number of wells and for variablegas-lift availability (due to compressor plant uptimeand market conditions), dynamic automated gas-lift allocation will permit the optimum fieldproduction subject to current well models and surface production constraints. This is usuallyworked out by posing a Linear Programming(LP) problem, solved iteratively on an hourlyto daily basis.

Plunger lift Plunger lift (intermittent gas lift) is an artificial lift

method principally used in gas wells to unloadrelatively small volumes of liquid. An automatedsystem mounted on the wellhead controls the well onan intermittent flow regime.

Plunger lift is a type of gas-lift method that uses a plunger which runs up and down inside the tubing. The plunger provides an interface between the liquid phase and the lift gas, minimizingliquid fallback. It has a bypass valve that opens at the top of the tubing and closes when it reachesthe bottom.

Plunger lift methods are used to remove waterand condensate from a well, but they can handleonly a limited column of liquid. Typically, thesemethods are applied to gas wells with high GLR tooperate only with formation gas. Plunger liftmethods are good for low-pressure wells andmedium fluid gas wells and for lifts fluids using gaspressure. The disadvantages of plunger lift includeproblems associated with production of solids andlimited operating range.

Sucker-rod pump liftThe sucker-rod or beam pump system (Fig. 16)

uses a downhole mechanical pump whichis activated by a sucker rod running insidethe producing tubing and driven by a surfacewalking beam, a crank, a counter weight, a gearreducer and a prime mover (electric or gas motor).The objective is to lift the reservoir fluid column to the surface while reducing well flowing pressure.Thus, lower backpressure is obtained at the reservoirsand face and fluid deliverability isincreased.

The sucker-rod pump system has variousadvantages: is simple and applicable to slim holes andmultiple completions, it can pump a well to very lowpressures, it can lift high temperatures and viscousoils, it can use gas or electric sources, it can becontrolled to work in cycles by time clock at low andhigh rates.



The disadvantages of the sucker-rod pump systemare: the depth limited (by rod size) to 12-16 kft; theproblems in gassy wells or high solids wells; the factthat it can be obtrusive in urban locations and bulkyfor offshore applications.

Electric-submersible pump assisted liftESP systems (Economides et al., 1994, 1998)

were initiated in Russia during the 1920s, as aproducing mechanism for water wells. Thetechnique was later improved in the United States

for oil wells. Even if reservoir pressure is relativelylow, ESP can be effective for lifting high liquid ratesof reservoir fluids. It is also convenient for use inremote areas where no gas compression is availablefor artificial lift.

Technology consists of a centrifugal pump andmotor located at the bottom of the wellbore (Fig. 17)for lifting reservoir fluid column to the surface andreducing well flowing pressure. Thus, lowerbackpressure is obtained at the reservoir sand face andfluid deliverability is increased.



conductor

surfacecasing

intermediatecasing

top-holepackers

productiontubing

productioncasing

gravel pack

packer

sub-seasafetyvalve

gas-liftvalve

slidingsleeve

pressuresensor

productionzone

oil out

gas-liftinlet

PT01

TT01

PT02

DP01

DP02

bottom hole

balance pointinjection point

formationfluid

gradientdp/dz1

combinedfluid

gradientdp/dznet

injectedgas

gradientdp/dzgas

tubing headpressure

gas-liftpressure pressure

depth

wellflowingpressure

valvepressure

drop

well flowrate

wellflowing

pressure

gas-liftquantity

tubing outflowwith no gas-lift

gas-lift quantity

IPR (InflowPerformanceRelationship)

qi1

qi1

q1 q2 q3

qi2

qi3

Pwf1Pwf2Pwf3

qi2qi3

Fig.15. Artificial gas-lift configuration (A), pressure gradients (B) and well performance (C).

A C

B

ESP operating features and limits The disadvantages for ESP include the relatively

high initial investment and the high powerrequirements; the need for sophisticated monitoringand control systems.

The ESP technology is also limited with highGLRs (e.g. not greater than 30%). The use of adownhole in-line gas separator for high GLRs may berequired, which will increase the initial investmentcosts up to 20%. The power is transmitted through amulti-purpose cable. Applications at depth below18,000 ft have not been successfully implemented dueto the limitations of the cable. Initial investment maybe in the range of US dollars 100-300 thousand perwell. The breakdown of the cost is 40% for thecentrifugal pump and motor, 35% for the cable, andthe remainder is for the surface components(frequency variators, electric energy conversion, andmonitoring and data transmission units). ESP

equipment initial investment is increasinglyproportional to the product power requirements and the flow capacity. Their longevity is reduced because they are exposed to rough operating situations such as, high temperature,corrosion, sour crude. Normally, ESP installationslast about two years. If premature substitution is required, ESP are definitely less attractive comparedto other alternatives, such as gas lift or mechanical pumping.

A reliable energy supply for the electric motor isalso required. Portable local generation versus remotehard-wired energy supply is usually compared: a 100HP portable energy generation unit will costapproximately US dollars 12,800 per month plus anyfuel and operating expenses as well. A 5 km surfaceelectric cable network could cost US dollars 15,000.The energy costs will thus range from 9 to 16 cents perkilowatts/hour.



conventional low profile

standard (type I) air balanced (type III)

Fig.16. Several sucker-rod pumps.

Progressive cavity pump Progressive Cavity Pump (PCP) or screw pumps

systems consist of a downhole pump driven by asurface motor and connected by a rod. Downholepumps consist of a metal rotor and an elastomerrubber stator. Stator and rotor have a particulargeometric configuration (Fig. 18) to permit multiphasefluid movement in a very efficient way. PCP hasproven to be a very cost effective system in manytypes of oilfield operating environment. The maindisadvantage has been the quick and unpredictable

deterioration of the stator due to rubber swelling,wearing and break.

Advantages of PCP systems include lowbottomhole pressure (intake pressure), low energy consumption and low investment cost. It is also suitable for any viscosity, adequatefor high sand content and for high gas amountand high water cut.

The features of progressive cavity pumps includesmaller dimensions compared to conventionalpumps, minimized hysteresis phenomenon



conductor

surfacecasing

intermediatecasing

productiontubing

productioncasing

packer

electricmotor

pump

sub-seasafetyvalve

productionzone

oil out

gas out

PT01

TT01

PT02

DP01

DP02

pump depth

perforation depth

DPpump

annulargas

gradientdp/dzgas

flowinggradient with

formation GORdp/dznet

pumped liquidflowing gradient

dp/dznet

tubing headpressure pressure

depth

inflow with no pump tubingoutflow

inflowwith pump

oilrate

oil rate

wellflowing

pressure

IPR

Pwf1

q1 q2

Pwf2

q1

q2

well flowingpressure

@ pump depth

Fig. 17. Electric submersible pump configuration (A), pressure gradients (B) and well performance (C).

A C

B

(longer life time) and best control of rubber swelling.Main applications include crude oil with higharomatics and gas levels, high temperature wells(higher than 220°F), high depth wells (deeper than6,000 feet) and higher pressure per stage(more than 100 psia).

Metal-metal progressive cavity pumps These pumps are made out of two metals (for the

rotor and for the stator). Main applications includehigh viscosity crude oil (higher than 450 cp), highvolumetric efficiency (about 95%), high temperaturewells (higher than 400°F) and higher pressure perstage (up to 365 psia).

Hybrid progressive cavity pumps Hybrid progressive cavity pump are made of the

combination metal (for the rotor) and thermoplasticmaterial, such as Teflon (for the stator). Mainapplications include high viscosity crude oil (higherthan 100 cp), high volumetric efficiency about 90%,high temperature wells (higher than 350°F) and higher pressure per stage (up to 290 psia).

Hybrid progressive cavity pumps are four to fivetimes smaller compared to conventional pumps; theydo not imply hysteresis phenomena nor rubberswelling; their expected life time is longer comparedto conventional pumps; they have lower torque (thereis no friction torque between rotor and stator).

Jet pumps A jet pump is a dynamic displacement pump. It

works by boosting a power fluid through a nozzle.The bottom of the pump communicates with thewell fluid. The two fluids are mixed with the resultthat some of the energy of the power fluid istransferred to the well fluid, and it boosts thecommingled fluid to the surface either throughproduction tubing or up the annulus between thecasing and the injection tubing. At the surface, thepower fluid is separated from the oil and sent backto the booster pump to be reused.

The advantages of jet pumps are that, becausethey have no moving parts, they can be used to lift

gassy or dirty fluids without experiencing any of thewear the positive displacement pumps would, andthey have no depth limitations. The disadvantages arethat they have a low efficiency (20-30%) and theyrequire a high suction pressure to prevent cavitationin the pump. The latter can be remedied by carefulcalculation of the depth so to provide sufficientsuction pressure.

6.2.7 Asphaltenes and paraffincontrol

Heavy organics depositionOne of the most common causes of arterial

blockage in the petroleum production systems isdue to the deposition of heavy organics frompetroleum fluids. Heavy organics such asparaffin/wax, resin, asphaltene, diamondoid,mercaptans, and organometallic compounds mayexist in crude oil in various quantities and forms. Such compounds could precipitate out of the crude oil solution due to various forces causing blockage in the oil reservoir,in the well, in the pipelines and in the oilproduction and processing facilities. Solid particles suspended in the crude oil may stick to thewalls of the conduits and reservoirs. The hardnessof the precipitate depends on the amount ofasphaltene present in the crude oil. Being a highlypolar compound asphaltene could act as glue andmortar in hardening the deposits and, as a result,cause barrier to the flow of oil.

Heavy organic deposition during oil productionand processing is a very serious problem in manyareas throughout the world (Leontaritis andMansoori, 1988). There were wells that, especiallyat the start of production, would completely ceaseflowing in a matter of a few days after an initialproduction rate of up to 3,000 BPD (Barrel PerDay). The economic implications of this problemwere tremendous, considering the fact that aproblem well workover cost could get as high as aquarter of a million dollars. In Venezuela the



Dddr

4er

shortpitch(1/2)

geometry(2/3)

geometry(1/2)

crosssection

single multilobegeometry

Af (1/2) = 4er dr Af (2/3) = f (D, d)

geometry(2/3)

longpitch(1/2)

S geometry

D45 geometry

L geometry

Fig.18. Progressive cavity pumps geometries.

formation of heavy organics (asphaltic sludge)after shutting in a well temporarily and/or afterstimulation treatment by acid has resulted in partialor complete plugging of the well (Lichaa, 1977). Atthe Hassi Messaoud field in Algeria, deposit ofheavy organics in the tubing has been a veryserious production problem (Haskett and Tartera,1965).

Heavy organics have played a significant role inthe production history and economics of the deephorizons of the Ventura Avenue field, California(Tuttle, 1983). Heavy organics deposition problemsin this field ranged from deposition during early oilproduction and deposition resulting from wellacidizing and CO2 injection during Enhanced OilRecovery (EOR). However, the problems were sodrastic because of heavy organics (asphalt)deposition at the early history of this field thatmany wells were redrilled, thus affecting theeconomics of the project considerably. It was alsoreported that heavy organics deposits were found inthe production tubing in a CO2 injection EOR pilot(Tuttle, 1983). Generally heavy organics depositscould occur during primary, secondary, andenhanced oil recovery stages (Tuttle, 1983). Heavyorganics precipitation, in many instances, carriesfrom the well tubing to the flow lines, productionseparator, pumps, strainers and other downstreamequipment (Katz and Beu, 1945). Heavy organicmaterials deposited into the productioninstallations of Mexico’s oil fields have causedmany operational problems (Chavez and Lory,1991; Escobedo et al., 1997). For example, in thefields of Tecomonoacan and Jujo, depositions inmany wells have caused numerous shutdowns andnecessity of rather expensive aromatic washes.Heavy organics deposition in the North Sea and inthe Gulf of Mexico oil fields in recent years havecaused several under-sea pipeline plugging withsubstantial economic loss to the oil productionoperations.

In general, solids in crude oil fall into two classes:basic sediment and filterable solids. These particleshave an economic impact on petroleum industry.Carried along in the oil, they can cause fouling,foaming, erosion, corrosion, etc. Depending on thecase, coagulants (molecular weight�10,000) orflocculents (molecular weight�10,000), might providean indirect aid in solids removal (Schantz and Elliot,1994). Coagulants are molecules with strong polarcharge, which act to disrupt charges on the surface ofthe oil droplet that would otherwise preventcoalescence. Flocculents act to coalesce oil droplets,because they are very soluble in oil, but in some casesthey can have drastically reduced solids removal.

Asphaltenes and paraffin deposition and controlAsphaltenes are large aromatic agglomerates

composed primarily of heterocyclic rings. Held insolution in crude oil by naturally occurring petroleumresins that adhere to the outer surface of the asphalteneagglomerate, they will precipitate and deposit in theproduction system in locations where pressure dropsallow the resins to desorb.

Paraffins are saturated hydrocarbon waxes that willprecipitate and deposit in areas where the temperatureof the petroleum production system falls below thesolubility temperature of the paraffins, known as theWax Appearance Temperature (WAT). Likeasphaltenes, paraffins can block a production systemand completely stop production.

Several dispersants and solvents on the marketoffer the capability to remove paraffin and asphaltenedeposits and restore a production system to itsdesigned capacity. Those solvents remove paraffin andasphaltene deposits when used in batch treatments bysimply dissolving the deposits. Some dispersantscontain oil-soluble surfactants that break up theparaffin or asphaltene deposit and disperse it in the oil.

Some products can be used in continuous injectionapplications to control deposition of waxes andasphaltenes, although the normal procedure is toremove existing deposits through batch treatment. Thevolume of chemical and frequency of treatmentrequired for batch treatments will depend primarily onthe severity of the problem. Once existing paraffin andasphaltene deposits are removed, continuous injectiontreatment provides a cost-effective approach tomaintaining a system with no production-inhibitingdeposits.

Proper treating recommendations for cost-effectivecontrol of paraffins and asphaltenes are complicatedby the differences in characteristics of the producedoil, variations in system operating conditions and thewide variety of chemicals available for use. Selectionof the proper chemical and treating method should bebased on laboratory and field tests.

6.2.8 Workovers in case of casingand tubing collapse or in caseof lack of cement

Wellbore mechanical integrityWellbore mechanical integrity problems (casing

leaks) may have different sources: holes caused by gasleakages, corrosion or wear, splits caused by flaws,excessive pressure or formation deformation. Casingleaks can result in pump failure or stuck pump; theytypically occur above the top of the cement and/orthrough invasion of drilling mud. Wellbore mechanical



integrity failure will affect the isolation function of thecasing and cement. Communication problems will riseas unexpected channels behind casing, barrierbreakdowns, completion into or near water, coning andcresting, channeling through high perm zones orfractures and fracturing out of zone.

Mechanical integrity tests can be determined bypressure testing or casing inspection logs. In someinstances a fluid level shot assists in locating casingleak. Pressure testing is required on injection anddisposal wells by certain regulatory agencies. Isolateleaks use RBP (Retrievable Bridge Plug) and packer.The majorities of leaks occur where there is no cementbehind the casing. It is necessary to use compatiblefluid with producing formation, otherwise it can causefurther damage in bad casing.

Casing inspection logs include multi-fingeredcalliper logs, Electrical Potential (EP) logs,electromagnetic inspection devices and borehole tele-viewers. Most measures extent to which corrosion hasoccurred; EP log indicates where corrosion iscurrently occurring.

Remedial actions include cement squeeze, polymersqueeze, combination squeeze and liner/casing patches.

Remedial cement This is a remedial cementing operation designed to

force cement into leak paths in wellbore tubulars. Therequired squeeze pressure is achieved by carefullycontrolling pump pressure. Squeeze cementingoperations may be performed to repair poor primarycement jobs, isolate perforations (production levels) orrepair damaged casing or liner. Cement squeeze is thecareful application of pump pressure to force atreatment fluid or slurry into a planned treatment zone.In most cases, a squeeze treatment will be performedat downhole injection pressure below that of theformation fracture pressure. In high-pressure squeezeoperations, performed above the formation fracturepressure, the response of the formation and theinjection of treatment fluid may be difficult to predict.

Cement squeezing is basically a filtration processin which cement slurries subject to differentialpressure against a filter of permeable rock lose part oftheir mix water, leaving a cake of partially dehydratedcement particles. The rate of cake buildup depends onformation permeability, differential pressure applied,time and capacity of slurry to lose fluid. Ideal slurrycontrols rate of cake growth so uniform that a filtercake builds over all permeable surfaces. A techniqueknown as hesitation squeeze cementing involves thedehydration of the cement slurry by intermittentapplication of pressure, interspersed by periods ofpressure leak-off caused by loss of filtrate to theformation.

Low-pressure squeezing implies injecting belowfracturing pressure, near the wellbore, low volumes indepleted formations of spot cement at perforations soto prevent fracturing due to hydrostatic pressure.

High-pressure squeezing breaks down formation,fills fractures or microannuli; location and orientationcannot be controlled and properly performed and itleaves cement close to wellbore.

Before cementing operations commence, engineersdetermine the volume of cement (commonly with thehelp of a caliper log) to be placed in the wellbore andthe physical properties of both the slurry and the setcement needed, including density and viscosity. Acementing crew uses special mixers and pumps todisplace drilling fluids and place cement in thewellbore.

Polymer squeezes They are used as alternative or in combination with

cement. Type of polymer and process depends on thelocation and severity of leak and whether squeeze isrequired to hold pressure or block encroachment ofwater. Advantages of polymer squeezes include thewash out of wellbore after squeeze and lowerhydrostatic pressure.

Four basic gel systems are used: acrylic monomergrout, high concentration low molecular-weightpolymer, high molecular-weight polymer andcement/polymer combination.

Liner and casing patches When liner or casing objectives for remediation are

determined, patches are an alternative for fixing suchproblems. They are permanently installed in casing orincorporated as part of tubing string. Those patchesare available in different lengths and diameters. Onceinstalled, they may restrict internal diameter of casing.Some patches incorporate sealing elements attached totubing string (they may or may not have vent tubes).One important aspect to bear in mind when installingthese patches is to consider future uses or operationsof the well and how these tools could have an effect onthe accessibility of the downhole tools.

6.2.9 Well architecture forproduction optimization

Completion options: inclination, production hole,commingling

Vertical versus horizontal Depending on reservoir properties, drive

mechanisms and future enhanced oil recovery projects,there can be advantages to one type versus the other.



The cost of drilling a horizontal well is more than thatof a vertical well; completion costs are also usuallyhigher. Therefore, the volume of salable products mustbe higher in order to have a higher Return OnInvestment (ROI).

The basic benefit of a horizontal well from areservoir engineering perspective is the generation of aline sink versus a point sink. This geometry makesmore efficient use of reservoir pressure, illustrated byradial flow in the vertical well versus linear flow in thehorizontal well. A horizontal well can produce athigher rates than a vertical well at similar drawdown,or can produce similar rates at lower drawdown, thusdelaying coning in the case of a bottom-water/drivereservoir.

Case histories indicate that reservoirs thinner than200 feet and having a permeability of less than100 md should be considered for a horizontal well. Areservoir with vertical permeability greater than one-fourth of its horizontal permeability, a horizontalwell might be beneficial. The use of horizontal wellsgrants another technique to reduce water or gasconing/cresting while producing at higherhydrocarbon rates than those produced from verticalwells. Case histories have proven that critical oil ratesare three to twenty times higher in horizontal wellsthan in vertical wells.

Heterogeneous reservoirs, such as layeredformations and dipping layered formations that can bethick with high permeabilities, and be with or withoutgas caps and bottom water, can be producedeffectively using horizontal wells. However, theheterogeneity has to be defined, the well profile has tobe designed to handle the heterogeneity, and thewellbore’s trajectory must be oriented from thegeologic information gathered as drilling progresses.Large production improvements can be achieved inheterogeneous reservoirs. Reserves have beenincreased by as much as factor of 6 in the Austin chalkin South Texas. Partially depleted and floodedreservoirs can be more effectively drained usinghorizontal wells. In general the production increase ofhorizontal versus unstimulated vertical wells isproportional to the reservoir’s area contacted by thewells. Due to exposing more of the formation todrilling fluids for longer periods, formation damagemay be more pronounced in horizontal wells whenproblems with drill fluids are encountered.

Open hole versus perforated The open hole method is initially cheaper, since

perforating costs are eliminated. This method permitstesting of the zone as it is drilled, eliminates formationdamage by drilling mud and cement, and allows forincremental deepening as necessary to avoid drilling

into water. This last factor is important in thin, water-drive pay sections where no more than a few feet of oilzone penetration are desired. On the other hand, theperforated completion offers a much higher degree ofcontrol over the pay section, since the interval can beperforated and tested as desired. Individual sectionscan, in general, be isolated and selectively stimulatedmuch more easily and satisfactorily.

There is considerable evidence that hydraulicfracturing is more useful in perforated completions.Productivity ratios of perforated wells are about 50%higher than those of similar open hole completions.This superiority is apparently due to uniform treatmentover the entire pay section plus the stimulation benefitgained from penetration of the perforationsthemselves. The improved zonal control is also ofvalue when remedial measures, such as water or gasexclusion, are undertaken.

With perhaps a few exceptions in low pressure orthin water-drive pay areas, benefits of the perforatedcompletion overshadow those of the open hole type.This advantage has been made possible by modernperforating and stimulation techniques and advancesin drilling muds, cementing materials and methods, aswell as other aspects of petroleum technology.

Single zone versus commingledMost wells are initially completed in a single

zone. As production matures and the oil rate declines,other zones may be opened to keep the welleconomic. Sometimes the initial zone is plugged offprior to recompletion; other times, if it still producessome oil, it is left open or later commingled withother zones. Commingling zones within the samewellbore considers: a) compatibility of fluids (mixingdifferent formation fluids tends to increase scale andcorrosion problems); b) reservoir pressure of thedifferent zones (you don’t want one zone to thieveproduction from another); c) if unexpected thingsoccur, such as increased water production, so that itbecomes more difficult and costly to determinewhich zone is the culprit; d) whether the well willever be used as part of an improved oil recoveryproject, such as a waterflood.

Other completion options: use of downhole water separator

This includes all potential production scenariosprior to drilling and completing a well, e.g. the use ofdownhole oil-water and gas-water separators. Thistechnology, where a well serves as both a producer andan injector, is advancing rapidly and may be morecommonly used in the future. Questions to considerprior to drilling are if well should be drilled deeper tohave access to a disposal zone and what size casing



should be set to accommodate special tools andequipment.

Horizontal wellsHydraulic fractures have a distinctly defined

azimuth and for the vast majority of cases are verticaland normal to the minimum horizontal stress direction.One of the unfortunate events in fracturing is that thefracture azimuth is often the least favourable in that theminimum horizontal stress direction is also thedirection of minimum permeability. Thus, the smallestpermeability is the dominant problem in flow from thereservoir into the fracture (Economides, 1993).

Horizontal wells can be drilled as an alternative tohydraulically fractured vertical wells and Brown andEconomides (1992) have presented a series of studiescomparing the performance of horizontal vs. fracturedvertical wells. A more advanced concept is that thehorizontal well can be drilled exactly in thefavourable direction, i.e. normal to the maximumhorizontal permeability. In highly anisotropicreservoirs this would further tilt the decision in favourof horizontal wells.

Fracturing horizontal wells Horizontal wells can also be fractured and they can

be drilled either normal to the fracture azimuth (whichwill result in transverse fractures) or longitudinal tothe fracture azimuth (which will result in longitudinalfracture). The first configuration is applicable inrelatively low permeability formations, while thesecond configuration is applicable in higherpermeability formations (Economides, 1993).

In high-permeability formations, fractured verticalwells always yield finite conductivity fractures, whichcan be remedied to an extent if the TSOtechnique is used. Fracturing horizontal wellslongitudinally (Economides, 1993; Valkó andEconomides, 1996) provides an infinite conductivitystreak in an otherwise finite conductivity medium. Alongitudinally fractured horizontal well provides for asmaller pressure drop than the pressure drop in afracture intersecting a vertical well. Thus, thelongitudinally fractured horizontal well not onlydeserves further attention but it could be one of themost powerful tools in production enhancement. Sucha completion of course can only be considered if, theincremental costs over a fractured vertical well or anunfractured horizontal well can be covered by thediscounted incremental revenue. It is important todetermine whether such a configuration is logisticallypossible. In certain formations, well trajectories alongthe required maximum horizontal stress direction areeither not feasible or extraordinarily difficult (Vilegaset al., 1996).

Valkó and Economides (1996) showed that theperformance of a longitudinally fractured horizontalwell is often superior to a fractured vertical well or anunfractured horizontal well. In 1-10 md reservoirs, thelongitudinally fractured well behaves as an infiniteconductivity fractured well. At 100 md, thelongitudinally fractured well is still more productivethan the fractured vertical well and an unfracturedhorizontal well. However, this configuration does notbehave as an infinite conductivity fractured wellanymore. Valkó and Economides also showed that ahorizontal well fractured longitudinally with tenfoldless proppant, still outperforms the fractured verticalwell of permeability 1-10 md, and it is still competitiveat 100 md.

High permeability fracturing does not only meanwide fractures, which can be obtained only by TSOtechnique. The combination of horizontal wells andlongitudinal moderate-width fracturing may providethe optimal configuration. Furthermore,dimensionless fracture conductivity around unity isnot necessary if the fracture is intersected by ahorizontal well instead of a vertical well. However,the relative advantage with fractured horizontal wellsincreases as the ratio of the formation thickness to thefracture half-length (i.e. hD = h/xf) decreases (Valkóand Economides, 1996).

In the case of vertical-to-horizontal anisotropicformations, the vertical component of the flow addsanother dimension to the problem, thus, it becomes a3-D problem. The index of anisotropy, Iani is the squareroot of the horizontal-to-vertical permeability ratio(Economides, 1993):

kH[20] Iani��13kV

where kV is the vertical and kH is the horizontalpermeability which is taken as the square root of theproduct of the two main horizontal permeabilities.

Vilegas et al. (1996) conducted a study to evaluatethe effects of both vertical and areal permeabilityanisotropy on the performance of longitudinallyfractured horizontal well. Their results showed that thevertical anisotropy has little effect on the pressure andrate performance and the response of the fracturedhorizontal well is not very sensitive to the horizontal-to-vertical anisotropy. In fact, vertical-to-horizontalpermeability anisotropy, a major problem in horizontalwells (e.g., in laminated reservoirs), can be correctedwith hydraulic fracturing. In the Vilegas et al. study,the response of a fractured vertical well in an isotropicformation is outperformed by a longitudinallyfractured horizontal well for any degree of anisotropy.However, the horizontal anisotropy causes a reductionin the fractured well production rate. For large areal



permeability anisotropy, an unfractured, optimallyoriented horizontal well (i.e. drilled into the minimumhorizontal stress and, thus, normal to the maximumpermeability) becomes more attractive, compared toany fractured well.

Complex wellsThe emergence of complex wells offers a number

of potential ideas for new configurations. Some ofthese ideas can eventually replace the fracturing ofsimple horizontal wells and even vertical wells. Theproblems that can be addressed deal both withincremental production but also with peripheral issuessuch as wellbore stability. For example, while in manyformations the performance of fractured horizontalwells would be theoretically superior to that of verticalwells, the requirement in high-permeability reservoirsto drill the horizontal well along the maximumhorizontal stress may cause long-term stabilityproblems.

One way to circumvent the problem is to take thevery bold step to drill a horizontal well in a competentformation above or below the target reservoir andexecute a fracture which will penetrate the potentiallyunstable formation. Hence production is accomplishedthrough the fracture into a well that acts as a mereconduit to flow.

Another, even more innovative idea is to drill ahorizontal mother bore and then drill vertical branchesoff the mother bore into the reservoir (Economides etal., 1998). This type of configuration would allow forthe placement of the horizontal borehole in acompetent, more stable, non-producing interval. Thereare several clear advantages in fracturing verticalinstead of horizontal branches: avoidance of tortuosity,fracture turning and multiple fracture problems;moreover, perforating strategy is much simplified andchoke effects are much less of a problem. Certainly, aconfiguration such as this, which with proper branchspacing could produce as much as the same number ofvertical wells, has considerable limitations in design,execution and zonal isolation.

6.2.10 Operation and maintenanceof petroleum productionsystems

Corrosion controlThe production of gas and oil is often accompanied

by water, either from the formation, fromcondensation, or from water injected as lift assist. Acidgases, such as hydrogen sulfide (H2S) and carbondioxide (CO2), are often present in produced fluids,and oxygen is sometimes a contaminant in the water

used for injection. These acid gases increase thecorrosivity of the waters to steel, and can significantlyreduce the safe operating life of production tubularand equipment, production vessels, and transportationsystems.

The presence or absence of multiple phases (gas,water, and oil or condensate) in the same system cancomplicate the problem of controlling corrosion. Theflow regime or pattern of fluids in a tubing string,vessel, or pipeline can have a significant impact oncorrosivity.

If a well or pipeline experiences slug orintermittent flow, highly corrosive conditions mayexist.

Pipelines can experience top-of-line corrosionwhen conditions promote the rapid condensation ofwater in a cooler section of the line, causing a film ofwater to form at the top of the line. This waterbecomes saturated with acid gases and corrodes thepipe. A further complication is a change in conditions,such as flow rate, temperature, and pressure over thelife of a well, production or processing system, orpipeline, which can result in changing corrosivity oreven a change in the potential corrosion mechanisms.

The control of corrosion in the oilfield can be acomplex problem, requiring detailed analysis and athorough understanding of the range of conditionsexpected during the life of the system prior to thedevelopment of a corrosion management plan.

Corrosion-inhibitors formulations have beendeveloped to address specific and wide applicabilitycorrosion problems. Applications include controllingcorrosion in all types of oilfield operations, includingoil and gas production, processing, and transportationsystems.

The composition of the particular oilfield brine,the system temperature, and the composition ofhydrocarbons in the system affect the solubility andpartitioning of oilfield corrosion inhibitors. Selectionof the adequate inhibitor is achieved by having athorough knowledge of the interplay of system effectson the performance of a corrosion inhibitor andknowledge of production operations.

This profit enhancement is accomplished byextending asset life, reducing failure rates, maintainingthe operability of the systems, and by allowingoperators the ability to manage risk associated withcorrosion.

Bacteria control in the oilfieldBacteria frequently become a significant problem

in petroleum drilling, completion, production,processing, and transportation operations.Bacteriological effects include reservoir fouling,production of biogenic (bacterially-generated)



hydrogen sulphide (H2S), plugging and corrosion ofproduction equipment, corrosion and fouling of heatexchange equipment, corrosion and permeabilitydamage in water disposal or waterflood systems, andcorrosion and product deterioration in transportationsystems such as pipelines and storage tanks. If notproperly managed, these problems may impact anoperator’s ability to maintain production levels, controloperating costs, and ultimately, reduce the profits fromoperations. These problems impact profit throughlowered production revenues; the need for costly wellinterventions; increased piping and equipmentmaintenance or repair costs; or the use of hydrogensulphide scavengers to control biogenic H2S at levelssafe for personnel and equipment, and to meetregulatory or contractual agreements. Several marketproducts and services are available for themanagement of bacteria in drilling, production,processing, and transportation operations. Biocidesand other formulations are designed to control bacteriapopulations and the resulting damage caused bybacterial action. Each application is evaluatedthoroughly, to select the appropriate product,application technology, and monitoring systems.

Scale controlScale is defined as deposits of insoluble inorganic

minerals. Common oilfield scales include calciumcarbonate, barium sulphate, and metal sulphides.While deposition of calcium carbonate scales dependspartially on pH and pressure, scale deposits generallyoccur when waters from different sources, anddifferent ion content, are mixed. Scale deposits canquickly block production tubulars and stop production.In many cases, scale deposits can be dissolved, but forsome scales, calcium fluoride in particular, mechanicalremoval is the only remedy.

There are several steps involved prior to theactual deposition of the scale on a pipe wall or insurface equipment. Prevention of scale can occur atseveral levels in the process. The methods used tocontrol scale deposition vary, and are often chosenbased on the application methods available as well asthe economics of the process. While chelation maybe the most technically effective method for scalecontrol, the cost is high, because there is a one-to-one, or maybe even greater, relationship requiredbetween the chelant molecule, such as ethylenediamine tetraacetic acid (EDTA) and the scale,whereas crystal growth modification is a thresholdprocess, whereby a small number of growth inhibitormolecules can slow or prevent the growth of anumber of scale crystals.

Scale inhibitors are based on three types ofcompounds: phosphate esters, phosphonates and

polymers. Phosphate esters are more tolerant of acidconditions than the polyphosphates and are stable totemperatures of 150-160°F (65-71°C). They canwithstand temperatures of 180-200°F (82-93°C) for afew hours. Within these temperature limitations,phosphate esters are generally excellent inhibitors forcalcium carbonate (CaCO3) and calcium sulphate(CaSO4). Except in acid environments (pH�5.5), theyalso provide excellent control of strontium sulphate(SrSO4) and barium sulphate (BaSO4) precipitation. Ingeneral, phosphate esters are soluble in- andcompatible withhigh calcium brines.

Several different types of phosphonates are used asscale inhibitors. Each type has different characteristicsof thermal stability, calcium tolerance, and efficiencyagainst the various types of scales. Phosphonate scaleinhibitors are supplied in the acid form or with anyportion of the acidity neutralized by ammonia, aminesor alkaline hydroxides. This provides an even broaderrange of characteristics.

The organic polymers most often used as scaleinhibitors are the low molecular weight polyacrylics.Polymers generally provide fair to good results intypical oilfield brines by laboratory anti-precipitationtests. However, polymers function primarily as crystaldistorters, i.e. they might permit precipitation of thescale-forming compounds, but polymersmodify/distort the shape of the scale crystals so thatthey will not grow or adhere to other surfaces.Polymers are stable to 400°F (204°C) or higher. Theyare generally effective at very low concentrations forcontrol of CaCO3 and BaSO4 in waters containing lowconcentrations of scale-forming ions. They are alsoeffective under acidic conditions, particularly in thecontrol of BaSO4. Polymers are often blended withother types of scale inhibitors to obtain a singleproduct with a broader range of applications.

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Michael J. EconomidesLuigi Saputelli

Department of Chemical EngineeringUniversity of HoustonHouston, Texas, USA



6.2 Production optimization

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