review of reservoir management

8/17/2019 review of reservoir management

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CHAPTER TWO

LITERATURE REVIEW

2.1 Background of Study

Petroleum reservoir management is a dynamic process that recognizes the uncertainties in

reservoir performance resulting from our inability to fully characterize reservoirs and

flow processes. It seeks to mitigate the effects of these uncertainties by optimizing

reservoir performance through a systematic application of integrated, multidisciplinary

technologies. It approaches reservoir operation and control as a system, rather than as a

set of disconnected functions. As such, it is a strategy for applying multiple technologies

in an optimal way to achieve synergy (Karimi, !"#$.


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!g 2.1" %he &eservoir 'anagement hallenge

%he reservoir management process must be tailored to individual fields depending on

(Karimi, !"#$)

• *ize

• omple+ity

• &eservoir and fluid properties

• epletion state

• &egulatory controls

• -conomics

2.2 T#$ conc$%t of R$&$r'o!r (anag$)$nt

2.2.1 *$f!n!t!on

&eservoir 'anagement has been defined by Al/ussainy and /umphreys as 0the

marshalling of all appropriate business, technical and operating resources to e+ploit a

reservoir optimally from discovery to abandonment. &eservoir 'anagement is about a

careful orchestration of technology, people 1 resources (*apulli et al., !!2$.


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!g 2.2) &eservoir 'anagement as the key to success in the life of a reservoir

2.2.2 R$&$r'o!r (anag$)$nt Pr!nc!%+$&

2.2., Stag$& of r$&$r'o!r (anag$)$nt

3asically, there are five main contributors to an integrated reservoir management

(Kalaydjian and Bourbiaux, 2002))

4 well design and management5 4 reservoir characterization and description5

4 reservoir modeling5

4 surface facilities design5

4 economics.


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It impacts the various facets of a field6s life, economic and uneconomic (see figure

below$.

!g 2.,) &eservoir 'angement Process (7ringarten, "889$

*ome of the stages of reservoir management are discussed as follows.

2.2.,.1 R$&$r'o!r *$&cr!%t!on

:ne of the most important stages of reservoir management is reservoir description,

this stage is to identify and present a model for describing the reservoir which it6s

behavior and answer be similar to the actual behavior of the reservoir as much as


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possible. &eservoir description is a dynamic process which is repeated as soon as

receiving the new information.

&eservoir model is yield from integrating the interpret models of different types of

information and by engineering software (*a;;adiyan,


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of inflows and outflows and by the effects which are applied on the input flow and output

flow the flow rate reach the optimal and economical status (Asadzadeh =arkhan, 3.,

!"!$.

2.2.,. W$++ *$&!gn and (anag$)$nt

In order to optimize the production and increase the reserves, the e+ploitation of the

reservoirs through comple+ wells (&enard et al., "889$ (horizontal wells, -& (-+tended

&each rilling$ wells, multibranched wells$ has become the common practice. %he ma;or

drilling progress performed during the last ten years has led to multiple options for well

design) stacked multibranch well, dual opposing laterals, reentry laterals from a vertical

well, cluster well, multidrain or multilateral well, even > wells for reservoirs with a

comple+ structure or sparselydistributed reservoir bodies. *uch wells have many

advantages over conventional vertical wells)

4 their in;ectivity?productivity is increased and their investigated area is larger, which

allows to drill fewer wells5

4 they enable to add reserves to difficult fields, characterized by thin reservoirs for

instance5

4 and they increase the benefit of -:& methods since they provide higher sweep

efficiencies.

7uaranteeing the in;ectivity?productivity of those wells is a ma;or issue as well. It is thus

re@uired to prevent as much as possible or remediate to any impairment (due to the


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invasion of drilling and completion fluids, particle deposition and retention$. =or this

reason, well productivity and in;ectivity restoration has to be part of the pro;ect

implementation plan, especially for openhole comple+ wells (ongeron et al., !!!$. %he

design of improved remediation methodologies can be optimized using a laboratory

approach that contributes to improve the physical understanding and modeling of well

productivity and in;ectivity. &egarding implementation plan, actions include)

4 the use of breakers to overcome cake barrier5

4 stimulation procedures involving acid fracturing and matri+ acidizing5

4 well treatment by gels to prevent massive water or gas production, a drastic

re@uirement for optimizing surface treatment facilities5

4 and also an overall management of well rates at reservoir scale.

omple+ wells combined with conventional and -:& processes such as gas in;ection,

viscous flooding or thermal flooding represent new opportunities for mature fields. et us

consider the polymer flooding method. %he very long tra;ectories of comple+ wells

minimize the risks of polymer degradation because of lower flow rates around the

in;ector, whereas their in;ection rate remains higher than that of a vertical well. %hus,

fewer in;ectors are re@uired and moreover, the method can be applied to reservoirs having

lower permeability than the limit imposed by vertical wells.

%o end with, a detailed modeling of the well neighborhood using unstructured grids and

improved PI6s (Productivity Inde+ =ormulations$ (Beannin et al, !!!$ is useful for


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assessing well impairment and predicting well productivity?in;ectivity remediation

efficiency. *uch a modeling has to take into account the comple+ flow geometry around

the well (perforation effects, etc.$ as well as possible multiphase flow effects, with a

proper calibration from laboratory e+periments (ing et al, !!$.

2.2., (ot!'at!on for r$&$r'o!r (anag$)$nt

It is generally known that sound reservoir management policies is a panacea for sustained

success. ompanies like -++onmobil, 3P, %otal, *hell etc have been successful because

of their huge reserves discovery but have remained successful because of the reservoir

management policy they operate by. *ome of the motivation for reservoir management

are summarized in the table below.

Ta/+$ 2.1) 'otivation for &eservoir management (*aputelli et al, "88C$


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2., R$&$r'o!r )anag$)$nt Proc$&&

=or many years, the dream of the oil company operators has been to integrate the data,

interpretations, models, simulations, and effects of development and production decisions

in such a way as to optimally deplete the reservoir according to a business model and

economic constraints (Kha;avi, A., !!85 %ayyebi et al, !!2$.

%he basic steps are shown below.

!g 2." Key Inputs and basic steps of the overall reservoir 'anagement Process

(7ringarten, "889$

A central step in reservoir management is the development of a reservoir model that can

be used in mapping the distribution of fluids, identifying unswept reservoir volumes and


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developing production strategies, including placement of infill wells, design of in;ection

and production programs (such as e+tended well testing$, and targeting of horizontal and

multilateral (multiple wells from the same primary wellbore, possibly with further

branches and subbranches$ wells.

%he model must capture reservoir geometry, internal architecture, rock properties and

their variability, content and distribution, fluid properties and producibility.

Key elements of the flow simulation include the fluid mechanics of multiphase fluids in

comple+ porous and fractured media, the thermophysical properties of hydrocarbon

fluid?a@ueous salt solution mi+tures and their variation with temperature?pressure and

their thermodynamic phase behaviour under reservoir and production conditions. %he

overall ob;ective of building the model is reduced reservoir uncertainty in a broad sense,

from prospect appraisal to production e+tension. %his is a key to e+ploration risk

reduction and to optimum reservoir management.

Dot shown in the figure, but underlying all elements of the process, is the ata

'anagement system responsible for all data involved in reservoir management. -fficient

data management and software integration are of prime importance throughout

(7halehban, !"!$. %hey often limit the practicality of iterative, detailed reservoir model

development and 0what if6 scenario planning.

2. R$&$r'o!r (anag$)$nt *$c!&!on&

2..1 W$++ +ocat!on for d!ff$r$nt ty%$& of r$&$r'o!r&


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%he reservoirs and the well cost used in all previous the case studies represent the situation of a

development plan for mediumsize onshore reservoirs. If the well cost was much smaller (as in

onshore reservoirs$ or the size of the reservoirs was much bigger, the optimal number of wells

would be much larger and the modeling of the geological uncertainty could be less relevant for

the decision of the best number of wells and their spatial configuration.

'odeling the geological uncertainty between the conditional data is only relevant for the

decision of the best scenario if that decision varies depending on the realization.

=or a very large number of wells, the scenarios are defined by different grids (or patterns$ of

wells with regular spacing between the wells and the particular behavior of a few wells would

not change the overall response of a scenario. %he overall response of a scenario is determined

by the spacing between the wells in the regular grid defined in the scenario and by the average

properties of the reservoir, instead of by any local characteristic.

If the average properties of a reservoir do not change from one realization to another, because

they are correctly depicted by the conditional data which are honored by all realizations, the

decision of the best scenario (grid of wells$ would be the same with any realization.

2..2 V$rt!ca+ or #or!0onta+ $++

%he decision to drill a well vertically or horizontally is governed by the differences in cost and in

production (or in;ection$ of the two types of well. *ince a horizontal well is more e+pensive, it

must produce (or in;ect$ more and?or longer than a vertical well.

%he final oil recovery with a horizontal well may be higher than with a vertical well because of

two characteristics of a horizontal well)


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("$ higher productivity (or in;ectivity$ due to a greater length of the interval completed in the

well, and ($ better location of the completed intervals.

In general, the reservoirs in which a horizontal well is e+pected to work better than a vertical

well have a small oil column and good vertical permeability. *ome common situations where a

horizontal well may be preferred are)

*mall oil column with gas cap and?or bottom a@uifer.

%hin oil layer with good permeability embedded in other layers with much smaller permeability.

Daturally fractured reservoirs, with the direction of the horizontal well normal to the fractures.

%he geological characterization necessary to determine if a reservoir is appropriate for horizontal

wells is typically performed at the macroscale and this kind of characterization does not change

from one realization to another. =or e+ample) if there is a gas cap in one realization it would be

present in all the realizations5 if the average oil column is five meters in one realization, it is not

likely to be #! meters in any other5 if the average ratio of vertical permeability over horizontal

permeability is !.# in one realization, it is not likely to be !." in any other, etc.

%herefore, in general, the consideration of multiple realizations to decide between vertical and

horizontal wells is not likely to be relevant.

2.., Int$r'a+& to co)%+$t$ a $++

%he decision as to which intervals to complete in a well is made after the drilling of the well and

is based on)

("$ the overall recovery strategy for the field and

($ the specific electric logs of that well.


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%he overall recovery strategy for the field is determined using geological characterization at a

macroscale, which is the same for all the realizations. =or e+ample, if the oil column is thick with

homogeneous permeability, if there is an active bottom a@uifer and if no gas cap is e+pected to

be formed during production, the strategy may be to complete only the upper intervals for

production. In another e+ample, if the reservoir is multilayered with small hydraulic

communication between the layers and if there is a lateral a@uifer or waterEood, the strategy may

be to complete all the good layers to start producing and to return to the well in the future to

close some intervals with very high water cut.

%he definition of the specific intervals to complete in a well is made based on the electric logs,

which show the good and bad intervals for that well. %ypically, the data from the well are

considered deterministically, the well information is assumed laterally continuous around the

well and no uncertainty is considered in the definition of the specific intervals to complete in the

well.

%herefore, in general, the consideration of multiple realizations to decide the intervals to

complete a well for production is not likely to be relevant.

2.. 3u)/$r of %+atfor)&

%he definition of the number of platforms is not really a problem different from the definition of

the optimal number of wells and their spatial configuration5 the number and location of the

platforms must be part of the scenario definition. %he prot function used to compare the

scenarios must incorporate the costs of different numbers of platforms and the costs of the Eow

lines to connect the wells to the platforms.


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-ven for the case where ;ust one platform is considered in all the scenarios, the location of the

platform must be known to allow the incorporation of the costs of the Eow lines into the prots

resulting from the production of different numbers and locations of wells. =or e+ample, it may

happen that an additional well gives sufficient additional production to pay the additional drilling

cost, but that well may be very far from the platform and the inclusion of its Eow line costs may

lead to a lesser prot. onsidering geological uncertainty may be relevant to decide between one,

two or three platforms when the number of wells is moderate (less than #!$. %he necessity to

consider scenarios with different number of platforms depends on)

%he ma+imum number of wells within the range of possible numbers of wells defined by the

scenarios.

%he e+pected total length of the production lines with different number of platforms.

%he cost of the Eow lines by unit of length.

%he cost of the platforms with different sizes (number of wells$.

Fsing the ma+imum number of wells, if the cost of increasing the number of platforms increases

more than the decrease in the cost of the Eow lines, then there is no necessity to consider

different numbers of platforms in the scenarios.

/owever, if the cost of increasing the number of platforms is similar to or smaller than the

decrease in the costs of the Eow lines, then different numbers of platforms need to be considered

in the scenarios.

Dote that the assessment of the necessity to consider different numbers of platforms in the

scenarios is not inEuenced by the geological uncertainty, for a moderate number of wells.


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=or a very large number of wells, the scenarios are defined by regular grids of wells and the

number of platforms is defined based on the costs of platforms, costs of Eow lines and

multiphase Eow constraints5 the eventual difference of production between the realizations does

not a reflect the decision of the number of platforms.

2..4 Ty%$ of $n#anc$d o!+ r$co'$ry

ake ("889$ denes enhanced oil recovery as oil recovery by the in;ection of materials not

normally present in the reservoir. %he common types of enhanced oil recovery and their recovery

mechanisms are)

• hemical

• %hermal

o *team (drive and stimulation$ reduction of oil viscosity and vaporization of light

ends.

o Insitu combustion same as steam plus cracking.

• *olvent

o Immiscible reduction of oil viscosity and oil swelling.

o 'iscible same as immiscible plus development of miscible displacement.

3ased on the physical mechanisms of the recovery, it is clear that the Euid properties are more

important than the rock properties in the selection of the type of enhanced oil recovery to apply

in a reservoir. Although geological uncertainty may have some inEuence in the selection of the

type of enhanced oil recovery, the uncertainty that is really important is the uncertainty in the

Euid properties.

2..5 T!)$ to &tart at$r !n6$ct!on

=or reservoirs with original gas cap, a good practice is to starting in;ecting water at the same time

the production starts.


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=or reservoirs with original pressure above the saturation pressure, a company may have a

financial gain in delaying the water in;ection until the pressure drops to a value ;ust above the

saturation pressure. %his G;ust above the saturation pressureH point in time is determined by

material balance.

'aterial balance uses the average properties of the reservoir and, therefore, the modeling of

geological uncertainty is not necessary to decide the time to start in;ecting water.

2..7 *!r$ct!on of a #or!0onta+ $++

If the reservoir is naturally fractured, the horizontal well should be drilled normal to the main

direction of fracture to induce the Eow to be in the direction of higher permeability and to

communicate a large area of the reservoir with the well. %ypically, the definition of the main

direction of fractures is made based on seismic data without modeling of the geological

uncertainty.

If the reservoir is clearly elongated in one direction, the direction of the horizontal well may be

determined without any consideration about the geological uncertainty.

epending on the dimensions of the reservoir, a few horizontal wells aligned with the reservoir

length or several horizontal wells aligned with the reservoir width may be defined.

=or other reservoirs, though, the definition of the direction of a horizontal well is basically the

same problem of the definition of the number and spatial configuration of vertical wells and the

consideration of the geological uncertainty is relevant.


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%he most common action taken to improve the oil recovery of a reservoir is to in;ect water (or

gas$. Fnless the reservoir is known to have a very large a@uifer (and?or gas cap$, in;ection is

always considered in the development plan.

*imilarly to a producer well, the performance of an in;ector well depends on the specific

properties of the reservoir around the well and the consideration of the geological uncertainty

through multiple realizations may lead to different definitions of the best number and

configuration of in;ector wells.

Among the other types of reservoir management decisions, this problem of defining the best

in;ection scenario was selected, because)

(a$ consideration of in;ection is common and important in the definition of the development

plans,

(b$ the benefits of accounting for the geological uncertainty in the definition of the best in;ection

scenario needed to be @uantified,

(c$ this problem complements the e+ample used in the previous case studies for the definition of

the best scenario including producer and in;ector wells.

%he best in;ection scenario determination must be integrated with the definition of the best

production scenario. %he best number of in;ector wells depends on the number of producer wells

and the best spatial configuration of in;ectors depends on the spatial configuration of producers.

%herefore, any in;ection scenario is associated with a production scenario.

review of reservoir management

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