Natural Drainage Reservoir Engineering

PRODUCTION MECHANISMS Alain Auriault

1

FIELDS DEVELOPMENT

Données geological géologiques data Cartes maps Logs

petrophysical Mesures pétrophysiques measurements

PVT Analyse analysis PVT

Essais Well testing des puits

VR, φ, Swi Swi

φ, K, k, Pc, Pc, Kr, kr , Cr Cr

Bo, Bo , Bg, Bg , Co, Co , Cw, Cw , Rs Rs

Pi, Pi, T, K, k, S S (skin)

ÉVALUATION HYDROCARBON DE L'ACCUMULATION IN PLACE MÉCANISMES PRODUCTIONDE MECANISMS DRAINAGE Expansion Expansion of fl.ds/ pore shr. Dissolved Expansiongas gazexpansion dissous Gas cap expansion Activité Gas cap Aquifer influx Activité de l’aquifère Water or gas ou injection Injection d’eau de gaz

Force Aquifer de l’aquifère activity Coning Coning(gas/water) (gaz/eau) Imbibition Subsidence / compaction

COMPLÉTION WELL COMPLETION DES PUITS PERFORMANCE WELL PERFORMANCE DES PUITS

Configuration Well configuration des puits :

Complétion : Completion

Écoulement Flow :

vertical deviated dévié horizontal

open hole gravel pack cased cimenté hole

flowing éruptif pompage pumping gas lift

PRÉVISIONS PRODUCTION DE PRODUCTION FORECAST

Nombre Number de of wells puits Débit Field du rate champ

ARCHITECTURE FIELD ARCHITECTURE du champ Pipes

Séparateurs Separators

Plateformes Platforms 2

OBJECTIVES

•

To know and to understand what are the main mechanisms involved in the production of a reservoir

•

To be able to perform simple material balance calculations, to know how the principles of what is implemented in softwares like MBAL

•

To have a qualitative understanding of the main issues involved in an injection process and to be able to use "rules of thumb" to quantify the impact of injection

•

To know the main EOR processes and the typical environment in which they are typically used

3

PRODUCTION MECHANISMS

• Introduction to production mechanisms • Natural drainage • Secondary recovery • Enhanced Oil Recovery

4

Introduction to production mechanisms

PRODUCTION MECHANISMS

Conventional oil recovery

PRIMARY RECOVERY NATURAL DRAINAGE

LIFT / HORIZONTAL DRILLING

WATER INJECTION

SECONDARY RECOVERY

PRESSURE MAINTENANCE

GAZ INJECTION GAS CYCLING

Enhanced oil recovery

TERTIARY RECOVERY

GAS

THERMAL

CHEMICAL

• Vapor

• Miscible Hydrocarbons

• Polymer

• In situ combustion

• CO2

• Surfactant

• N2

• Soda

BACTERIA

6

PRODUCTION MECHANISMS • Natural drive (or primary recovery): the field is produced thanks to its own energy • Immiscible fluid injection (or secondary recovery): energy is provided to the field through injection – Water injection – Gas injection

• Enhanced oil recovery methods (or tertiary recovery): energy for production is provided through complex methods – Miscible process – Chemical process – Thermal process

7

PRODUCTION MECHANISMS • Primary production mechanisms have to be understood/ evaluated as early as possible in the field history - Gas cap - Active aquifer - Reservoir pressure vs. Pb

• Definition/ optimization and implementation of secondary and/or tertiary production mechanisms are key issues in the field development strategy (when required)

8

MATERIAL BALANCE

Principles • the reservoir pore volume is 100% filled-up with fluids • At reservoir conditions, adjustment of volumes (Mass conservation law): initial HC Volume = Remaining HC Vol. + Net Water and/or gas entries (+ Pore Vol. change + connate water Vol. change) It represents the equation of continuity for the considered reservoir/ part of reservoir for a finite time interval Can be described as the simplest reservoir simulation model (1 cell !)

9

MATERIAL BALANCE

Initial conditions

Producing well

After production

Producing well

Gas cap expansion Released gas volume

Remaining oil Water expans. and PV shrink.

Pi, Boi, Bgi & Rsi

P, Bo, Bg & Rs

10

MATERIAL BALANCE

• Two possible uses - Evaluation/ calculation of Original Hydrocarbon In Place (OHIP) from production history - Field behavior forecast for a given production mechanism (production/recovery for different reservoir pressures or pressure vs. cumulative production)

• Needed data - Petrophysic data of the reservoir (rock characterization) - PVT data (fluid characterization) - Production data ( productions, cumulative productions, pressure)

11

MATERIAL BALANCE – Main symbols and units

Fluid volumes Fluid

Oil

Gas

Water

Accumulation

N

G

W

Cumulative production

Np

Gp

Wp

Cumulative injection

-

Gi

Wi

water influx

-

-

We

All volumes are expressed in standard conditions (15°C, 1 Atm), except We (res. cond.) Material balance is done in reservoir conditions Units: stm3 or stb for liquid stm3 or scf for gas 12

MATERIAL BALANCE – Main symbols and units

Production rates Fluid

Oil

Gas

Water

Initial rate

Qoi or qoi

Qgi or qgi

Qwi or qwi

Current rate @ time t

Qo or qo

Qg or qg

Qw or qw

stb/d or stbo/d

scf/d

stb/d or stbw/d

(or pressure P)

Field units SI units

3

stm /d

3

stm /d

3

stm /d

reservoir rate = standard rate * FVF

13

MATERIAL BALANCE – Main symbols and units

Fluids Fluid Initial FVF Current FVF FVF @ Pb Field units SI units

Oil

Gas

Water

Boi Bo Bb

Bgi Bg

Bwi Bw

-

-

rb/stb

rcf/scf or rbl/scf

rbw/stbw

3

m /m

3

3

m /m

3

3

m /m

3

FVF symbol : B or b

14

MATERIAL BALANCE – Main symbols and units

Rock/ fluid data Saturation

- initial: Soi, Swi, Sgi - @ time t: So , Sw , Sg unit: no dimension

Compressibilities co cw cf (or cr or cp) field unit: psi-1 SI unit : bar-1

15

MATERIAL BALANCE – Main symbols and units

Pressure • • • • • • • • •

Initial Pi Current (at time t) P or Pr Bubble or saturation Pb Flowing Pwf (or FBHP) Well head Pwh Separator Psep Atmospheric Patm Absolute (above zero) Gauge (above atmospheric press.)

Units ?

16

MATERIAL BALANCE

Pressures Pwh

Pwh

Patm Patm

Pr = Reservoir Pressure Pwf= Flowing Bottom Hole Pressure Pwh = Well Head Pressure Patm= Atm pressure (Tank @ Patm)

Pr > Pwf > Pwh > Patm

Pwf

Pwf

Pr

Pr

17

MATERIAL BALANCE - PVT DATA

Evolution with pressure of main reservoir properties Bo

Bo

Rs µo

Rs µo

BUBBLE POINT

INITIAL RESERVOIR PRESSURE

PRESSURE

18

RESERVES - Basic definitions

Accumulation

=

Hydrocarbons initially in place (OOIP,OGIP, OHIP)

Reserves

=

Recoverable hydrocarbons

Recovery factor R =

Reserves Accumulation

Oil fields

10 % < RF < 50 %

Gas fields

50 % < RF < 95 % 19

RESERVES

• Estimate Ultimate Reserves (EUR): cumulative production at abandonment conditions or at a fixed date – Abandonment conditions = Minimum Field Economic Oil Rate (either limiting water cut or high GOR or low PReservoir) – The individual wells are progressively shut-in as they reach the limiting conditions

• Remaining Reserves @ time t = EUR - Cumulative Production at time t

20

RESERVES - Probability approach - Some Standards

Qualitative Judgement

Quantitative Probability

Certainty

0.99

Proved

0.90/0.95

Very Likely

0.90

Likely

0.70

Probable Equally Likely / Unlikely

0.50

Unlikely

0.30

Very Unlikely

0.10

Possible

0.10/0.05

Excluded

0.01 21

PROBABILISTIC APPROACH TO RESERVES

22

RESERVES •

Reserves are attached to a geological model, scenario of development,calculation methodology, economics, laws and contracts

•

Reserves are associated to a production profile

23

PETROLEUM RESSOURCE MANAGEMENT SYSTEM •

A new Petroleum Resources Management System was approved by the Society of Petroleum Engineers (SPE) Board of Directors in March 2007 (collaboration: SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE)).

24

PRODUCTION MECHANISMS

• Introduction to production mechanisms • Natural drainage • Secondary recovery • Enhanced Oil Recovery

25

Natural drainage

NATURAL DRAINAGE or PRIMAY RECOVERYXXX

Different production mechanisms can occur • Fluid expansion and pore shrinkage • Solution gas drive • Gas cap expansion • Natural water influx • (Gravity drainage) • (Compaction drive)

27

NATURAL DRAINAGE OR PRIMARY RECOVERY Pb is Bubble Point Pressure

•

Pi > Pb

(undersaturated oil reservoir) one phase fluid (oil) - Oil and connate water expansion - Pores shrinkage

•

Pi ≤ Pb

(saturated oil reservoir) - Solution gas(expansion of liberated gas) - Gas cap expansion

Aquifer expansion The field development strategy will take into account the strength of the aquifer, relative permeabilities, etc

28

ISOTHERMAL COMPRESSIBILITY •

Pore shrinkage and fluids expansion. Definition of compressibility: the relative volume change of matter per unit pressure change under conditions of constant temperature

1 ⎛ δV ⎞ c=− ⎜ ⎟ V ⎝δP ⎠

c: coef of isothermal compressibility units: [1/P], always a positive value Order of magnitude • co= 1 to 3 10-4 bar-1 Lab data • cw= 0.4 to 0.6 10-4 bar-1 Literature • cp= 0.3 to 1.5 10-4 bar-1 Lab data or Hall correlation • cg # 1/P (P in bars, ex cg=30.10-4 bar-1 for P=300 bars)

•

Usually petroleum reservoirs can be considered as being isothermal - Increasing pressure causes volume of material to decrease (compression) - Decreasing pressure causes volume of material to increase (expansion)

29

COMPRESSIBILITY- DEFINITIONS • • •

•

Matrix compressibility (Cm): relative change in volume of solid rock material (grain volume) per unit pressure change (usually Cm # 0) Pore (or formation) compressibility Cf : relative change in pore volume per unit pressure change Bulk compressibility (Cb): relative change in bulk volume per unit pressure change (usually ∆Vb # ∆Vp ) Impact - Formation compressibility can have a significant impact of production mechanisms - Subsidence (due to decrease of bulk volume) can have a significant impact on environment

30

FORMATION COMPRESSIBILITY •

Under static conditions, downward overburden force is balanced by upward forces of the matrix and the fluid in the pores

F F

•

M

O

F

F

Fo= Fm+Ff and Po= Pm+ P P fluid pressure in the pores

As fluids are produced in the reservoirs, fluid pressure (P) usually decreases while overburden is constant and: - Force on matrix increases (net compaction pressure or net overburden pressure Pm=Po-P) - Bulk and pore volume decrease - Fluid volume increases (=> production mechanism) 31

FORMATION COMPRESSIBILITY

Overburden Pore Pressure

Effective Pressure Abnormal effective overburden

Subnormal pore pressure

Subnormal effective overburden

Depth Abnormal pore pressure Hydrostatic pressure 32

NATURAL DRAINAGE - UNDERSATURATED OIL

Rocks and fluids expansion - Compressibilities Demonstrate the relation between Co and Bo (for P>Pb) Bo − Boi co = Boi ⋅ ( P − Pi ) Oil compressibility is given by: co = -

1 dVo ⋅ V oi dP

, Voi = V st ⋅ B oi

and V o = V st ⋅ Bo

hence ∆ V o = V st ⋅ Bo − V st ⋅ Boi = V st ⋅ ( Bo − Boi ) V st ⋅ ( Bo − Boi ) 1 1 Bo − Boi co = ⋅ =⋅ V st ⋅ B oi P − Pi B oi P − Pi 33

NATURAL DRAINAGE - UNDERSATURATED OIL

Material balance in the case: no water entry Produced volume = Increase of oil volume + Increase of volume of water + Decrease of pore volume

Those variations of volumes are related to compressibilities. Compressibilities of oil, water and rock being generally pretty low, the expected recovery factor is low.

34

NATURAL DRAINAGE - UNDERSATURATED OIL Material balance in the case: no water entry For a pressure drop ∆P from Pi to P with P>Pb

(Vp ⋅ Soi ) ⋅ co ⋅ ∆P (Vp ⋅ Swi ) ⋅ cw ⋅ ∆P (Vp ) ⋅ c p ⋅ ∆P

• Oil volume increases by • Water volume increases by • Pore volume shrinks by

Material balance: the rock and fluids volume changes of the reservoir is equal to Np (cumulative production in standard conditions) converted in reservoir conditions.

(

N p Bo = V p ⋅ ∆P ⋅ co Soi + cw S wi + c p

) 35

NATURAL DRAINAGE - UNDERSATURATED OIL

Material balance in the case: no water entry Cumulative production = Sum of the 3 terms

(

N p ⋅ Bo = Vp ⋅ ∆P ⋅ co ⋅ Soi + cw ⋅ S wi + c p N p ⋅ Bo = Vp ⋅ Soi ⋅ ∆P ⋅

ce =

)

co ⋅ Soi + cw ⋅ S wi + c p

co ⋅ Soi + cw ⋅ S wi + c p Soi

Soi is called the equivalent compressibility

N p ⋅ Bo = (Vp ⋅ Soi ) ⋅ ce ⋅ ∆P = ( N ⋅ Boi ) ⋅ ce ⋅ ∆P For a ∆P pressure drop from Pi to P, P being greater that Pb • Cumulative oil production (*) • Recovery Factor (*) Standard conditions

N .Boi Np = .c .∆P Bo e Np B R= = oi .ce .∆P N Bo

36

NATURAL DRAINAGE - UNDERSATURATED OIL Material balance in the case: no water entry Numerical example FIELD A… without water entry Cumulative production is given Np =1,17 . 10+6stb and Wp =0 (clean oil)

Swi = 14%

c w = 3,28 . 10−6 psi−1 Pi = 4740 psia P = 3686 psia

cp = 4,36 . 10−6 psi−1 Boi = 1,3905 Bo = 1,4168

What is the corresponding accumulation (OOIP)?

37

NATURAL DRAINAGE

Solution gas drive • Reservoir pressure decreases under Pb (bubble point pressure) • Part of the gas dissolved in the oil is liberated in the reservoir • Quick increase of the produced gas • Fluids and rock compressibility effects can be neglected vs. expansion of the liberated gas (gas compressibility is much bigger)

38

NATURAL DRAINAGE - SOLUTION GAS DRIVE Prod.

O+G+W

Prod.

Prod.

- Pr < Pb - Inactive aquifer

W

Swirr

VP = VO + VGF + VW

100%/Sw

W

(VP)i = (VP)t at Pi ¿ VP = Voi + Vw at P ¿ VP = Vor + Vw + Vgf

Voi = Vor + Vgf 39

NATURAL DRAINAGE - SOLUTION GAS DRIVE

Pressure

Saturated oil-Phase diagram Critical point Tres, Pres

t1 t2

Separator

Tc Temperature

40

SOLUTION GAS DRIVE – Depletion below Pb

• Critical Gas Saturation -

Definition : Sg < Sgc krg = 0 Use of kr from displacement process = unreliable P > PSgc : monophasic flow (oil) P < PSgc : diphasic flow ( oil + free gas)

• Development of Gas Phase -

Nucleation: supersaturation + nucleation sites (energy) Coalescences: diffusion + supply Formation of an elongated gas channel (or "gas finger") Gas production

41

SOLUTION GAS DRIVE – Gas liberated in the reservoir •

Gas immobile as long as Sg<Sgc. (Only monophasic oil is produced). PI affected (kro effect). Only solution gas is produced at surface. Qg = GOR x Qo

•

GOR = Rs

At Sgc, part of liberated gas becomes mobile. Diphasic flow. Both solution gas and liberated gas are produced at surface. Production GOR (Rp) increases. Qg = GOR x Qo

GOR > Rs

Remark on Gas oil ratio definitions : Rs : solution (or dissolved) gas oil ratio GOR : production gas oil ratio Rp : cumulative gas oil ratio = Gp/Np 42

SOLUTION GAS DRIVE – Gas liberated in the reservoir • Part of the gas liberated in the reservoir below Pb may move up, due to gravity forces-to create a secondary gascap or supply an existing one - (balance between gravity,capillary and viscous forces) Gas (top reservoir) Gas

(well)

Oil

43

NATURAL DRAINAGE - SOLUTION GAS DRIVE Material balance •

Initial oil volume = remaining oil at P + released solution gas

(

)

(

(

)

)

N ⋅ Boi = N − N p ⋅ Bo + NRsi − N − N p Rs − G p ⋅ Bg Gp can be expressed in function of Np: G p = R p ⋅ Np

Performances P GOR

GOR

Pb Psgc P

Np/N 44

SOLUTION GAS DRIVE – Typical use Historical part: Np,Gp,P are measured Î N is evaluated Forecast • N is known, for a given value of one of the one of the 3 others parameters, the 2 others are calculated, ex for a given ∆P, what will be Np and Gp? • In can be demonstrated that Rp=f(P,So) and So=f(Np) Î iterative method: - ∆P being given Rp is estimated - Np is calculated by material balance equation - then So is calculated - then Rp=f(So) is calculated - if the initial Rs guess is with 1% equal to the final Rs calculation: OK, if not iteration Î this is now done within softwares 45

SOLUTION GAS DRIVE – Typical use Forecast – Some equations •

Rp is a function of So,P: GOR = R p = Qo =

Qg =

•

2π hko ∆P ⋅ r µo Bo ln e rw 2π hk g

µ g Bg

⋅

GOR = Rs +

∆P r ln e rw

Qg Qo

=

Qo Rs + Qgfree Qo

k g µo Bo

kg

ko µ g Bg

ko

= Rs +

Qgfree Qo

is a function of So

Rs is a function of P

So is a function of Np (VP is approximated as cst) - Initial oil volume @ Pi : - Oil volume @ P:

=>

VP Soi = NBoi

(

)

VP So = N − N p Bo

⎛ N p ⎞ Bo So = Soi ⎜ 1 − ⎟ N ⎝ ⎠ Boi 46

NATURAL DRAINAGE - SOLUTION GAS DRIVE

• Recovery from 5 to 25 % • The field / well production is shut-down when GOR is to high • Sgc, critical gas saturation is a very important parameter: High Sgc

High recovery

47

NATURAL DRAINAGE

Gas cap expansion • Gas cap is located in the upper part of the reservoir • Reservoir Pressure (Pr) is below Pb • When Pr decreases, the gas volume of the gas cap increases

48

NATURAL DRAINAGE

Gas cap expansion

1 /1 9 3 8

1 /1 9 3 7 1 /1 9 3 6

20 00

240 0p ied s

230 0

2200

2100

16 00 17 00 18 0 19 0 00

1 /1 9 3 3

Example of evolution with time of the GOC (Gas Oil Contact) (Mite Six field) 49

NATURAL DRAINAGE - GAS CAP EXPANSION Prod.

m=

GcBgi NiBoi

G?

Pwf

Prod.r Prod.r

r

G+W Possible gas coning

(GOC)i Pwf

Pi = Pb at GOC Pwf < Pb

O+W Possible water coning

W

(OWC)i W

Gp = Gps + Gpf + Gpc 50

NATURAL DRAINAGE - GAS CAP EXPANSION Material balance Initial oil volume = remaining oil vol at P + gas cap expansion + free solution gas

(

)

((

)

) (

(

)

)

N ⋅ Boi = N − N p ⋅ Bo + G − G pc Bgc − GB gci + NRsi − N − N p Rs − G ps ⋅ Bg were G, Gpc, Bgc and Bgci refer to the gas cap and Gps, Bg refer to the dissolved gas

Performance P GOR

GOR

P

Np/N

51

NATURAL DRAINAGE - GAS CAP EXPANSION Material balance The initial volume of the gas cap is often expressed in function of the initial volume of the oil pool, using the m ratio

G ⋅ Bgi volume of the initial gas cap m= ( reservoir conditions ) = volume of the initial oil in place NBoi If the gas of the gas cap and the dissolved gas are not differentiated: Bg=Bgc and Gp=Gpc+Gps , MBAE becomes:

(

)

(

)

(

(

) )

N ⋅ Boi = N − N p ⋅ Bo + GBg − GB gi + NRsi − N − N p Rs ⋅ Bg − G p Bg

52

NATURAL DRAINAGE - GAS CAP EXPANSION

Depth

Rsi

Material Balance •

Necessity to know the evolution of Rsi versus depth (sampling at different depths)

•

While producing, if kv important, good gas segregation and GOR not impacted by gas from gas cap

•

A good gas segregation maintains pressure in the reservoir

•

Recovery can reach high values, up to 40 %OOIP 53

NATURAL DRAINAGE - ACTIVE AQUIFER

• The impact of an active aquifer is function of it size and characteristics • Bottom water drive (k vertical, coning,…) • Edge water driver (k horizontal, fingering)

54

MATERIAL BALANCE - ACTIVE AQUIFER

Water production • The field production does not stop at water break through • Following economics environment, fields can be produced up to very high water cut (Qw/Qtotal): 98-99% • One main issue: produced water disposal system • The rising of OWC should be continuously monitored (logging, observation wells, behavior of production wells)

55

NATURAL DRAINAGE - ACTIVE AQUIFER

SEALING FAULT

8

4

50

5 7 0 80

7

70 0

NT A CT

SE AL IN G

C O

FA UL T

6

2 1

OIL W A TE R

3

AQUIFER ?? 85

S EA

L IN G

FA U

0

LT

WOC: Water Oil Contact 56

NATURAL DRAINAGE - ACTIVE AQUIFER

Observation well

Producer OIL WATER

Bottom water drive

In the case of an active aquifer, Recovery Factor is in average between 25 to 50 % (up to 65% in very favorable cases) Maximum theoretical: (1-Swi-Sor)/(1-Swi)

Producer Observation well

Edge water drive

(Which is obtained in a core)

57

NATURAL DRAINAGE - ACTIVE AQUIFER Calculation of potential recovery in the case of water entry For a pressure drop from Pi to P with an oil production Np We consider the simplified case where P>>Pb (undersaturated oil) abcde-

oil volume expands water volume expands pore volume shrinks aquifer expands and generates a water influx in the reservoir: We water production: Wp

Oil production is given by i.e.

a+b+c+d-e Np Bo = N Boi ce (Pi - P) + We - Wp Bw

! in MBE, "We" is the only cumulative quantity expressed in reservoir volumes 58

ACTIVE AQUIFER – WATER INFLUX CALCULATION Np Bo = N Boi ce (Pi - P) + We - WpBw Simplified approach: Let's consider the case were the aquifer size is small enough and the connection between the oil pool and the aquifer very good so that when the pressure in the oil pool decreases by ∆P=Pi-P, the aquifer pressure also decreases instantaneously by the same ∆P value. If Vw, volume of the aquifer is known, We could be calculated as follows: • We = Vw (cw + cp) (Pi - P) This gives what would be the maximum impact of an aquifer of o given size

59

WATER INFLUX CALCULATION -Example Np Bo = N Boi ce (Pi - P) + We - WpBw Let’s take an aquifer with a volume Vw = 10 time pore volume of the oil zone which expands totally from Pi to P • We = Vw (cw + cp) (Pi - P) = [10 . N Boi / (1 - Swi)] (cw + cp) (Pi - P) • R = Np / N = (Boi / Bo) . Ce (Pi - P) + We / (N Bo) • R = (Boi / Bo) (Pi - P) [ce + 10 . (cw + cp) / (1 - Swi)] • Numerical example: cw = cp = 1/3 co et Swi = 20 % R = Np / N = (Boi / Bo) (Pi - P) [6,55 ce]

Theoretical recovery is 6,5 time higher in the case active aquifer than in the case non aquifer. It is important to know the size and the activity of an aquifer. 60

WATER INFLUX CALCULATION -Example Material balance in the case: field with water influx Numerical example Cumulative oil production is Np = 13,5.106stb (and Wp =0) • co = 1,79 . 10-5 psi-1 cw = 3,28 . 10-6 psi-1 • Pi = 4740 psia

and

Boi = 1,3905

• P = 3686 psia

and

Bo = 1,4168

cp = 4,36 . 10-6 psi-1

What is the minimum volume of aquifer? N being estimated at 48 106 stb

61

ACTIVE AQUIFER – WATER INFLUX CALCULATION For large aquifers, a time dependent model is necessary since the pressure decrease of the aquifer is not instantaneous We can represent an oil reservoir rounded by an aquifer as a "big diameter well' Producer

We look at the rate and pressure at the interface aquifer – oil pool (horizontal in the

Oil water contact

field, vertical in the model)

ro re

Aquifer models have been developed depending on the fluid flow characteristics 62

FLUID FLOW IN POROUS MEDIA (reminder)

P(r,t)

P(r,t)

transient flow

Late transient flow

no limit has been reached

some limits have been reached

or t↑

⎛ ∂P ⎞ ⎜ ⎟ = cte ⎝ ∂t ⎠r

pseudo steady-state flow All limits are reached The pressure profile goes down during time

⎛ ∂P ⎞ ⎜ ⎟ =0 ⎝ ∂t ⎠ r

steady-state flow the pressure profile is stable

63

FLUID FLOW IN POROUS MEDIA (reminder) Case no flow boundary Pi

t1

Producing face pressure

t2

t3 t4

t5

Pmini

Log distance Producing

No flow

face

boundary

64

FLUID FLOW IN POROUS MEDIA (reminder) Case no flow boundary Pi

t1

Producing face pressure

Transient flow (USS)

udo e s P

t2 t2

te fl a t s dy stea

ow

t3 t3 t4

Unsteady state flow t5

Pmini

Log distance Producing

No flow

face

boundary

65

FLUID FLOW IN POROUS MEDIA (reminder) The typical problem to solve is: for a given production rate at the wellbore what is the corresponding pressure profile in the reservoir as a function of distance from the wellbore and time, P=f(t,r). The solution found for P(t,r) depends on the following items: Fluid Liquid (incompressible) Gas (compressible)

Type of flow Steady state Pseudo Steady state Unsteady state

Geometry of flow Linear Radial

At this stage, let's consider an incompressible fluid and a radial flow. The most general case (and more complex to solve) is the unsteady state case. In this case the diffusivity equation has to be solved:

δ 2 p 1 δp ϕµc δp + = 2 δr r δr k δt

Solution have been developed for the following conditions at limits: @ ro @ re - constant pressure - constant rate

– no flow boundary – cste pressure boundary

66

ACTIVE AQUIFER – AQUIFER MODELS Typical models are: •

For steady state flow: Schilthuis'model

•

For pseudo steady state model: Fetkovitch's model

•

For unsteady state: Hurst& Van Everdingen's model -

in this case diffusivity equation has been solved with the hypothesis than Pressure is constant at the inner boundary (interface Oil/ water) it corresponds to a limited aquifer (no flow at the outer boundary)

Unsteady state being the most general case, Hurst& Van Everdingen can be applied in a lot of cases. But: -

it should be use from the beginning as, in the field , pressure can decrease, the time history is divided in time steps during which pressure can be estimated as constant, then superposition principle is applied

67

ACTIVE AQUIFER – WATER INFLUX CALCULATION Hurst & Van Everdingen method (unsteady state water influx in radial circular model) We: cumulative water influx due to a pressure drop of ∆P at ro and time=0

We = U ⋅ ∆P ⋅ WD (t D ) With U=aquifer constant for radial geometry: φ,h,ct=cr+cw aquifer characteristics f = encroachment angle/360°

U = 2π f ϕ hct ro 2 Θ° ro

re

And WD(tD) dimensionless cumulative water influx function function of rD and tD

re rD = ro

and

kt t D = Cte ⋅ ϕµ ct ro 2

68

ACTIVE AQUIFER – WATER INFLUX CALCULATION Hurst & Van Everdingen method –units Darcy Units

Field Units

kt t D = Cst ⋅ ϕµ ct ro 2

kt tD = ϕµ ct ro 2

Cst = 0.000264 (t in hours) = 0.00634 (t in days) =2.309 (t in years)

t is in second

U = 2π f ϕ hct ro 2

(cc/atm)

U = 1.119 f ϕ hct ro 2

(bbl/psi)

69

ACTIVE AQUIFER – WATER INFLUX CALCULATION System units Parameter

Darcy

Oilfield Units

European Metric

Canadian Metric

SI

cm

ft

m

m

m

k

darcy

mD

mD

mD

m2

t

s

h

h

h

s

µ

cp

cp

cp

cp

Pa.s

p

atm

psia

bara

kPa

Pa

V

cm3

ft3

m3

m3

m3

q(oil)

cm3/s

bbl/d

m3/d

m3/d

m3/s

q(gas)

cm3/s

MMcf/d

m3/d

m3/d

m3/s

r h

70

ACTIVE AQUIFER – WATER INFLUX CALCULATION Hurst & Van Everdingen method – example of curve WD=f(tD,rD)

71

L.P Dake Fundalmentals of res eng

ACTIVE AQUIFER – WATER INFLUX CALCULATION Hurst & Van Everdingen (continue) Time steps are selected to have P # Cste The superposition method gives: We

n

= U ⋅ ∑ ∆P i ⋅WDi (t Di ) i =0

For instance in the example shown here below: ∆P0 is applied during t3 ∆P1 is applied during t3-t1 ∆P2 is applied during t3-t2

72

ACTIVE AQUIFER – WATER INFLUX CALCULATION Hurst & Van Everdingen method – Prediction of future performances The additional production being given, what will be the corresponding reservoir pressure P ? There are 2 unknowns We and P 2 equations will be used: the material balance equation and the unsteady state flow equation, it is a trial an error process: - time increment is used (can be the same as the one used during the historical period) - the pressure at the end of the first period is estimated - using this P, We is calculated by material balance and by Hurst & Van Everdingen's method - if the 2 estimate are close enough (1%) => end - if not P at the end of the time step is modified (if We by material balance is greater than We by H&VE method decrease P)

Today: use of softwares as MBAL (Petroleum expert)

73

MATERIAL BALANCE - GENERAL EXPRESSION

Present oil volume

Original oil volume

=

(N − N p )Bo =

–

Freed solution gas

–

Gas cap expansion

–

Net water influx

–

Rock and connate water expansion

–

Injected volumes

N(Boi ) −

[

]

(Bg )s N ( Rs )i − (N − N p )Rs − (G p )s ) −

[(G − (G ) )(B ) − G(B ) ]− p c

g c

g i

[We −WpBw ] − ⎡ c f + S wi cw ⎤ N(Boi ) (1 + m) ∆P ⎢ ⎥− − 1 S wi ⎣ ⎦

[W

N=

(

)

[(

][

)

inj

Bw + Ginj Bg

]

N p Bo − Rs (Bg )s + (G p )s (Bg )s − G − (G p )c (Bg )c − G (Bgi ) − We − W p Bw − Winj Bw − Ginj Bg ⎡ c f + S wi cw ⎤ ⎥ (1 + m ) − 1 S wi ⎣ ⎦

(Bo − (Boi )) + ((Rsi ) − Rs )(Bg )s + (Boi )∆P ⎢

74

]

MATERIAL BALANCE EXPRESSED AS A LINEAR EQUATION

Let's re-arrange, the general MBE, with the following simplifications - Winj=Ginj=0 - Bgc=Bgs et Gpc=0 (Gps=Gptotal=Rp*Np)

We got :

(

(

) )

N p Bo + R p − Rs Bg

Where:

( ( (B + (R

⎛ Bg ⎞ + W p Bw = N Bo − Boi + Bg ( Rsi − Rs ) + mNBoi ⎜ − 1⎟ + ⎜ Bgi ⎟ ⎝ ⎠ ⎛ cf + Swi ⋅ cw ⎞ +NBoi (1+ m) ∆P⎜ ⎟ +We 1 − S wi ⎝ ⎠

(

) ) p − Rs ) Bg ) + W p Bw − W

)

F = N p Bo + R p − Rs Bg + W p Bw = withdrawal in reservoir conditions

(F = N

p

o

inj

Bw.inj − Ginj Bg .inj

)

if Winj and G inj were taken into account

Eo = Bo − Boi + Bg ( Rsi − Rs ) term decribing the expansion of the oil and its original dissolved gas

⎛ Bg ⎞ Eg = Boi ⎜ − 1⎟ which describes the expansion of the gas cap ⎜ Bgi ⎟ ⎝ ⎠ ⎛ c f + S wi ⋅ cw ⎞ E f , w = Boi (1 + m ) ∆P ⎜ ⎟ describes the expansion of connate water and the pore − 1 S wi ⎝ ⎠ volume shrinkage in the O+G zones

75

MATERIAL BALANCE EXPRESSED AS A LINEAR EQUATION

MBE becomes : F = N ( Eo + mEg + E f , w ) + We

Havlena and Odeh have shown that in many cases, this equation can be expressed as a linear function For instance in we consider the case where there is no gas cap and were connate water expansion and pore volume shrinkage can be neglected vs. the other production mechanisms F/Eo

F = NEo + We or:

F W =N+ Eo Eo

45 °

N We/Eo

A simple check can allow to validate that the field data are in line with the production mechanisms which have been determined in the field (history match process) 76

DRIVE INDICES

In is interesting to describe a field behavior by identifying the contribution of each mechanisms to the production (field withdrawal)

F = N ( Eo + mEg + E f , w ) + We 1=

can be written as:

NEo NmEg NE fw We + + + F F F F

NEo/F : depletion index drive NmEg/F : segregation drive index/gas cap expansion index NEf,w/F : expansion drive index We/F : water drive index

Typically software represent the evolution of those indices with time

77

DRIVE INDEXES Example of production mechanisms history through drive indexes evolution Drive mechanisms – Mature Reservoir 1

0.75

0.50

0.25

0 28/02/1977

16/05/1983

31/07/1989

16/10/1995

31/12/2001

Time (date d/m/y)

78

GRAVITY DRAINAGE

• Expansion of a gas-cap (initial or secondary) creates a gas invaded zone where So decreases leading to high oil recovery due to gravity drainage. • Gravity drainage is a recovery process in which the gravity forces are the main mechanism gravity forces sup. to capillary forces: h ∆ρogg > 2 σog cosθ / r • Gravity drainage must be efficient within an economical time scale good permeability - say sup 100mD -

79

GRAVITY DRAINAGE: MICROSCOPIC EFFICIENCY Formation of gas-oil interfaces and oil mobilization GAS

OIL

WATER

80

GRAVITY DRAINAGE Forces acting upon oil film

Forces applied by upwards flowing gas

ROCK PARTICLES

Gravity forces

WATER

OIL

GAS

81

GRAVITY DRAINAGE IN FRACTURED RESERVOIRS Case oil/Gas in fractured reservoirs Gravity drainage is a key production mechanism: Qg Single Block

Pc

Pd=∆ρ.g.H0 Sorg

• • • •

So

Qo

Oil is stored in the matrix, gas is in injected in the fractures By gravity oil from the matrix will flow into the fractures Capillary forces counterbalance partially gravity forces Threshold pressure represent the minimum pressure for gas to penetrate the matrix 82

GRAVITY DRAINAGE

• Driving force is due to the differences of densities between gas and oil - (more or less) ever present phenomenon • Reservoir factors affecting the process: -

high mobility to oil high formation dip. or thick reservoir lack of stratification rock fractured rock high density contrasts

Further information in the course gas injection

83

GRAVITY DRAINAGE

• Oil recovery up to 70% of O.I.P. • Recovery by gravity drainage >> recovery by solution gas drive because : Gas Oil (well)

Gravity drainage Gas

Solution gas drive

(well) Oil

84

COMPACTION DRIVE - SUBSIDENCE •

In some specific cases, rock compressibility can be very high with the consequences of: - a high RF due to pore shrinkage (+) - a compaction of the reservoir which can result into subsidence in the surface (-) ∆Vb ∆h with cb = φ ⋅ c f + (1 − φ ) cm ≈ φ ⋅ c f = cb ⋅ ∆P = Vb h

index b refers to bulk/total, f to formation/pore, m to matrix/grain

•

This is normally expected in shallow reservoirs with potentially unconsolidated reservoir (cf high), easy deformation transmission between reservoir and surface.

•

In forecast studies, the issues are - measuring/ estimating cf in the case of unconsolidated reservoir (inelastic and non reversible deformation) - the evaluation of subsidence to compaction ratio 85

SUBSIDENCE – Case Ekofisk • Ekofisk was discovered in the Norwegian North sea in 1969 (Phillips Petroleum Co.). • Water depth: 72 m • top of the reservoir at: 2840 ssm • Elongated anticline 6.8x9.3 km • 2 reservoirs (fine-grains chalk essentially) separated by a tight zone Ekofisk formation -

1978

net pay thickness 100 to 150 m Ф = 10 to 20% low k in the matrix

Upper Tor formation -

net pay thickness 75 to 150 m Ф = 30 to 40% low k in the matrix

Extensive natural fracturing

1986 86

SUBSIDENCE – Case Ekofisk •1971: production started, a large gravity based structure (GBS) was installed (other installations built later) •1975: gas start being injected partially •1976: peak production 350 000 bopd •1984: unexpected production-related subsidence was discovered (3 m) •1987: all the platforms were raised by 6 m in 1987, a protective seawall was installed around the GBS in 1989 •1987: in addition to gas injection water injection start to prevent depressurization •1989 and 1990: expansion of water injection

1978

1986 87

SUBSIDENCE – Case Ekofisk •Seabed subsidence was closely monitored and show continuous evolution (10 to 40 cm/year depending on the location in the field) •The current subsidence underneath the GBS is 9 m •Initially, due to the depth of the reservoir, the subsidence risk was not considered (although compaction was evaluated) •Part of the problem is related to the reservoir lithology (chalk) and to it observed "water weakening" (chalk

1978

strength decreases substantially in the presence of water compared to its strength when oil-saturated).

1986 88

Example of field data

RESERVOIR PRESSURE EVOLUTION WITH PRODUCTION Example 4500

4300

4100

Depletion (psia)

J101 J102

3900

J103G drilling J104 J105

3700

J106 drilling J107 drilling J108 drilling

3500

3300

Pression de saturation

3100 0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

Cumulated production (Mbbls) 90

OWC EVOLUTION WITH PRODUCTION Example 3600

3700

(psia) 3800

3900

4000

4100

4200

4300

4400

4500

4600

4700

2400

2450

2500

(mv/SL)

2550

2600

2650

NEW WOC J107 2700

INITIAL WOC

2750

2800

91

EXAMPLE OF MATERIAL BALANCE N (Mbbls)

216

P

Np

Wp

Bo

We

Np (closed)

(Mbbls)

(Mbbls)

Co

Boi

1.3905

(psia)

(Mbbls)

(Mbbls)

Pi (psi)

4 455.0

4455

0.00

0.00

1.3905

1.27E-05

Bob

1.4496

4407

1.30

0.00

1.3927

1.28E-05

1.5

0.19

3159

4370

1.61

0.00

1.3944

1.29E-05

1.8

Cw (1/psi) 3.28E-06

4266

3.71

0.00

1.3991

1.30E-05

Cp (1/psi) 4.36E-06

4130

6.57

0.05

1.4053

Coi (1/psi) 1.27E-05

3947

11.25

0.17

Cob (1/psi) 1.50E-05

3922

11.83

Swi (%)

3878

13.51

Pb (psi)

13

Ct (1/psi)

Ø

0.13

(Mbbls) Area (km2)

6.6

Soi

0.92

216.0

Sorw

0.34

0.34

216.0

N/G

0.35

4.2

0.74

215.5

1.33E-05

7.5

1.23

210.5

1.4137

1.36E-05

13.3

1.85

203.0

0.18

1.4148

1.36E-05

14.0

1.94

203.0

0.18

1.4168

1.37E-05

16.2

2.10

204.0

1.82E-05 CALCUL D'ENTREE D'EAU APRES J 107 Measured

N

0.00

h (m)

14.8

Water entries

Closedreservoir

18

4500 4400

16

J... Field - Material Balance match

14

4300

12

4200

10

4100

8 6

4000

4 3900

2 0

3800 0

2

4

6

Np

8

10

12

14

92

Natural drainage Gas Fields

œ P



Oil reservoirs with dissolved gases

Bu

ep l bb

n oi

100% 75% 50%

Gas reservoirs with retrograde condensation

PHASE ENVELOP OF A MIXTURE OF HYDROCARBONS

Cricondenbar

ž

ve r u tc

Ÿ Gas reservoirs without retrograde condensation

Critical point Cricondentherm

Zone œ : No or poor contribution of dissolved gases

Dry gas

Zone  : Appreciable contribution of dissolved gases

Liquid + gas

30% 20% 10% 5% 0%

De w

t p o in

cu

Zone ž : Retrograde with liquid deposit in the reservoir

rve

Zone Ÿ : Dry or wet gas

T

94

GAS PVT: Bg CALCULATION For a given quantity of gas:

Hence Bg can be calculated:

P⋅V = Cste Z⋅T

V Z ⋅T P res res res Bg = = ⋅ st V P Z ⋅T st res st st

Field Units (US): Pst=14.7 psia, Tst=520 °R, Bg = 0.02827 ZT/P Metric Units: Pst=1.01325 bara, Tst=288 °K, Bg = 0.00352 ZT/P SI Units: Pst=101325 Pa, Tst=288 °K, Bg = 351.8 ZT/P Volume of one mole of gas in standard conditions=23.63 liters

95

CLASSIFICATION OF GAS FIELD

•DRY GAS is in gas phase from the reservoir conditions (P,T) to the separator conditions

A

C 25

B RESERVOIR TEMPERATURE

PRESSURE

50

75

Séparateur

Tc

Tcc

TEMPERATURE

96

CLASSIFICATION OF GAS FIELD

A

•WET GAS is in gas phase in the reservoir conditions (P,T), a liquid fraction appears in the separator

C B

25

RESERVOIR TEMPERATURE

PRESSURE

50

Séparateur

Tc

Tcc

TEMPERATURE

97

CLASSIFICATION OF GAS FIELD

A C 25

B 75

50 RESERVOIR TEMPERATURE

PRESSURE

•GAS CONDENSATES: following pressure drop in the reservoir, there is condensation of a fraction of liquid in the reservoir. This condensation is retrograde as after a peak it percentage may decrease with pressure.

Séparateur

Tc

TEMPERATUR E

Tc c 98

GAS FIELD - DRY GAS Case: no active aquifer In reservoir conditions: - rock and water compressibilities (cp,cw) can be neglected compared to gas compressibility cg - Vgas initial @ Pi= Volume of remaining gas @ P - i.e G.Bgi=(G-Gp).Bg or Gp.Bg=G.(Bg-Bgi) - by definition Bgi/Bg=(Zi/Pi).(P/Z) - Hence ⎛ Z P⎞ P P ⎛ G ⎞ G p = G ⋅ ⎜1 − i ⋅ ⎟ Pi Z ⎠ ⎝

or

Z

=

⋅ ⎜1 − ⎟ Zi ⎝ G ⎠ i

p

Cumulative Gas production is a linear function of P/Z Material balance in case of water influx - Gp.Bg=G.(Bg-Bgi)+We-Wp.Bw 99

GAS FIELD - DRY GAS

Gas reservoirs typical behaviour Curve P/Z vs. Gp very often used: => It is a straight line for closed reservoirs (i.e. no aquifer) => The straight line becomes exponential in case of active aquifer P Z we ≠ 0 active aquifer relatively inactive aquifer we = 0 no aquifer Gas produced

Gp 100

GAS FIELD - RECOVERY FACTOR

Gas compressibility being high Recovery Factor is high • without aquifer RF depends of abandonment pressure (Pa) RF = 1-(Pa/Za)/(Pi/Zi) RF = 80 to 90% (ex: Lacq in France)

• with aquifer

RF depends of Sgrw , Gas residual saturation after displacement by water R < (1-Swi-Sgrw)/(1-Swi) RF = 50 to 70% (ex: Frigg in Norway)

101

GAS FIELD - RECOVERY FACTOR

Gas condensate fields • Gas fraction (C1-C4)

RF depends of abandonment pressure RF=80 to 90% without aquifer LPG (C3-C4) can be sold separately

• Liquid fraction GCR= Gas Condensate Ratio (C5+)

GCR is constant until Ps is reached, and decreases afterward Part of the condensate is trapped closed to the wellbore, hence the well performances are degraded R=50 to 60% 102

11,00

1 000 900

10,00

9,00

800 8,00

700 7,00

600 6,00

500 5,00

Gas rate

4,00

Gp

100 1,00

0 0,00

45 000 400

40 000

35 000

350

30 000

25 000 250

20 000 200

15 000 150

Condensate rate Np 100

0 50

0

time

103

Gp (Tcf)

1 100

Np (MM Sbbl)

janv-2030

janv-2028

janv-2026

janv-2024

400

janv-2030

janv-2028

janv-2026

janv-2024

200

janv-2022

janv-2020

janv-2018

janv-2016

janv-2014

janv-2012

janv-2010

janv-2008

janv-2006

janv-2004

janv-2002

janv-2000

Gas rate (MM Scft/d) 300

janv-2022

5 000

janv-2020

10 000

janv-2018

janv-2016

janv-2014

janv-2012

janv-2010

janv-2008

janv-2006

janv-2004

janv-2002

janv-2000

Oil rate (Sbbl/d)

EXAMPLE OF GAS CONDENSATE FIELD Gas Production

3,00

2,00

time

Condensate Production

300

EXAMPLE OF GAS FIELD DATA PRODUCTION DATA

Date janv 83 févr 83 févr 83 juil 83 août 83 juil 84 juil 85 juin 86 juin 88 juin 89 août 90 août 91 août 92 juin 93 avr 94 mai 95 août 96

Duration [days] 0,5 0,4 35 5 18 3 20 36 8 8 10 16

8 16

W #1 447,8 443,7 429,7 425,7 387,0 339,9 301,5 243,7 224,3 191,4 164,9 146,2 130,1 110,8

W #2 447,8 443,3 433,2 430,3 390,9 347,3 309,0 248,7 228,1 197,2 173,0 152,7 136,4 126,7

Pressure [bar] W #3 W #4 W #5 447,8 447,8 447,8 438,1 426,8 424,3 379,9 333,7 298,0 241,3 222,4 192,7 166,5 146,7 132,5 113,3 100,8

341,2 302,7 244,4 223,1 190,7 163,3 144,6 126,6 111,9 98,7

Z W #6 447,8

244,0 224,6 192,6 165,8 148,6

244,7 224,4 191,3 164,4 145,5

122,3

118,9

@ -3750 mSL 447,8 443,7 440,6 429,8 426,6 385,8 340,3 302,6 244,4 224,4 192,6 166,3 147,3 131,4 122,7 111,9 99,8

1,1492 1,1455 1,1426 1,1329 1,1301 1,0948 1,0585 1,0315 0,9969 0,9876 0,9757 0,9691 0,9662 0,9651 0,9650 0,9654 0,9664

Gp [GNm3] 0,000 0,128 0,164 0,390 0,466 1,500 2,779 4,006 6,286 7,172 8,400 9,524 10,420 11,168 11,701 12,216 12,834

P/Z [bar] 389,7 387,4 385,6 379,4 377,5 352,4 321,5 293,4 245,1 227,3 197,4 171,6 152,5 136,1 127,2 116,0 103,2

104

EXAMPLE OF GAS FIELD DATA

Pressure vs Time 500,00

W#1

450,00

W#2

[b ar]

400,00

W#3

350,00

W#4

300,00

W#5

W#6

250,00

@ -3750 mSL

200,00 150,00 100,00 50,00 0,00 janv 83

janv 84

janv 85

janv 86

janv 87

janv 88

janv 89

janv 90

janv 91

janv 92

janv 93

janv 94

janv 95

janv 96

janv 97

janv 98

janv 99

105

EXAMPLE OF GAS FIELD DATA

Dynamic IGIP 400,0

p/Z [bar]

300,0

Linear Regression First-Last Points IGIP = 17.458 GNm3

200,0

100,0

0,0 0,000

Linear Regression Last Three Points IGIP = 17.716

Linear Regression All Points IGIP = 17.289 GNm3

5,000

10,000 Gp [GNm3]

15,000

20,000

106

EXAMPLE OF GAS FIELD DATA

Dynamic IGIP per Well 400,00 W #1 W #2 W #3 W #4 W #5 W #6 A1 = A2 = A3 = A4 = A5 = A6 =

p/Z [bar]

300,00

200,00

3.563 2.757 3.058 2.753 2.465 2.623

GNm3 GNm3 GNm3 GNm3 GNm3 GNm3

100,00

IGIP tot [GNm3]= 17,220 0,00 0,000

0,723

1,447

2,170

2,894

3,617

4,341

Gp [GNm3]

107

MBE - limits Very simplified model, 1 block: no geometry effects, no heterogeneities Only connected or active accumulations are seen Give semi-quantitative indications which can guide for further studies: - check production data consistency - validate geological hypothesis: accumulation, size of the aquifer, the gas cap - understand the main production mechanisms early in a field, evaluate secondary methods - make simple/ quick sensitivities (in history match a and in forecast) Can be pretty reliable in some specific cases: dry gas field without aquifer

108

MBE – limits : Volatile oil & Gas condensate So far all the MBE have been written for "black oil" and dry gas, which means: two hydrocarbon components: stock tank oil and surface gas • •

the surface gas can be dissolved in the reservoir oil or gas phase stock tank oil can't be volatilized in the gas phase

There is no compositional effects and Bo, Rs and Bg are only dependant of pressure and temperature For volatile oil or condensate gas, MBE should be adapted as those reservoirs produce liquid from the vapor phase Typical volatile oil • Rsi >200 m3/m3 • Bo > 2 V/V • gravity > 45°API • high reservoir temperature (close to Tc)

109

NATURAL DRAINAGE

• Implementation : Just open the well (or lift the well) • Performances : given by the follow-up of reservoir pressure, rates (Oil,Gas,Water,or GOR, WOR ) versus time

• Limitations (economical rate)

: - Pressure decline - Limiting water - cut - Limiting GOR

110

RECOVERY FACTORS FOR NATURAL DRAINAGE

Reservoir kind

Recovery factor

Undersaturated oil

Pa > Pb

< 10 %

Oil+ dissolved gas drive

Pa < Pb

5 to 25 %

Oil + gas cap

10 to 40 %

Oil + aquifer

10 to 60 %

Gas

60 to 95 %

Gas condensates

40 to 65 %

==> for Oil Reservoirs, in a lot of cases other mechanisms have to be initiated 111