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8000
8050
8100
8150
8200
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In Saudi Arabia, intense surveillance of a wateflooding
scheme in a complex carbonate reservoir has come up
with a few surprises. For example, it has shown that fluid
flow in a large and highly stratified reservoir appears to be
much simpler than the geology indicates. The monitoring
programme has also revealed how the production strategy
has influenced the vertical and horizontal water sweep.
This has prompted Saudi Arabian Oil Company to further
investigate water encroachment patterns in the reservoir.
Mahmood Rahman, Petroleum Engineering Specialist with
Saudi Aramco and consultant Manfred Wittmann outline
how the peripheral waterflooding scheme has been
monitored and explain how this mass of data is now being
incorporated into a geological model of the reservoir that
will form the basis for 3-D simulation studies.
This article is based on SPE Paper 21370, Case Study: Performance of a Complex
Carbonate Reservoir Under Peripheral Water Injection , by M. Rahman, M. B.
Sunbul and M. D. McGuire of Saudi Aramco presented at the SPE Middle East Oil
Show, Bahrain, 16-19 November 1991.
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44 Middle East Well Evaluation Review
Producer well
Injection well
Observation well
8 4 0 0
8 3 0 0
8 2 0 0
8 1 0 0
7 9 0 0
7 8 0 0
7 7 0 0
8 0 0 0
8 1 0 0
8 2 0 0
Efficient reservoir management relies on a good understanding of a field’s characteristics and per-
formance. Using open hole logs as adatum, this knowledge can be built upover a field’s life with carefully plannedmonitoring programmes. But this isoften too late. What a manager really
needs is a comprehensive and accuratemodel to help predict a reservoir’sresponse to drilling and recovery meth-ods.
This article takes a practical look at the development of a major carbonatefield in Saudia Arabia. The 25 km long by 15 km wide anticlinal reservoir wasdiscovered in 1964. Exploitation wasstarted in 1970 and has been achievedby flooding the field with water injectedthrough a series of wells on the north-ern periphery of the reservoir.
Over the past 20 years a fifth of theoriginal oil in place has been produced.
But, evaluation of areal and verticalsweep has shown areas of the reservoirwhere oil is not being effectively dis-placed by the peripheral waterflooding technique. The observed performancehas been incorporated into a geologicalmodel of the reservoir and forms thebasis of a 3-D simulation of the entirefield which has been built to guidefuture reservoir drainage management.
The producing formation is one of anumber of Late Jurassic shallowing-upward sequences in this region of Saudi Arabia (see Midd le East Well Evaluation Review, 1991 Number 11).
The fine, permeable, carbonate grain-stones become gravel-sized towards thetop of the formation giving most wellstypical shallowing-upward and/orcoarsening-upward porosity profiles(figure 4.2). This is a favourable perme-ability distribution for peripheral water-flooding as the gravity pull is offset bythe lower resistance to flow at the topof the reservoir.
During deposition, the field areastraddled a gently sloping carbonateplatform margin (figure 4.3). This sepa-rated a broad, flat area of shallow water(a carbonate shelf) from a deeper,
restricted basin. Carbonate grainstonesformed quickly on the northern shelf.Below, in the basin, a slow rain of
pelagic sediments produced fine-grained rocks with poor permeability. Atransitional zone developed betweenthese two depositional environments.This variation in deposition is responsi-ble for the rapid facies changes fromgrainstones on the northern ramp tomudstones in the basin. Associatedwith this is a reduction in reservoirquality from north to south.
The geometry of the depositional lay-ers was affected by the gentle slope of the margin (1-2 degrees). As a result,the geologic layers were not originallydeposited as flat, horizontal beds, but
were sigmoid-shaped similar to thoseshown in figure 4.3.
Fig. 4.1: MONITORING PERFORMANCE: Exploitation of this Saudi Arabian reservoir started in1970. Since then, a fifth of the oil-in-place has been produced. However, saturation monitoring has shown areas where potential oil reserves have beenmissed by the peripheral waterflooding technique.
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45Number 13, 1992.
8000
8100
8200
8300
8400
8500
0 100 2.0 3.0Gamma Ray API Bulk density g/cc
Top of formation
Base of formation
Depthft
Variations in sea level during theLate Jurassic also affected the shapeand make up of geologic layers. Thisresulted in highstand, lowstand andtransgressive sequence system tracts(figure 4.3). Geologic layers, depositedduring highstand sea level, built out toward the basin and draped succes-sively over one another like tiles on aroof. As a result, the reservoir facieswithin the highstand layers remained inclose contact. During the following low-stand time there was little or no deposi-tion on top of the shelf or at the outerramp. Instead, layers filled up the basin.
As the sea level began to rise again aseries of transgressive backstep grain-stones were deposited at the top of thereservoir. As these backstep grain-stones incompletely overlapped oneanother, the uppermost part of thereservoir is made up of different agedgrainstones across the field.
South North
Outer rampBasin Outer rampmargin A
BCC'
E'
G
H
I
X/F
Transgressivesystemtract
Lowstandsystemtract
Highstandsystemtract
T i m e l i n e
D e p o s i t i o n
a l c y c l e
Organic richlime mudstones
Packstones/wackestones
Boundstones
Gravels
Grainstones
Fig. 4.2: Typical log showing the shallowing-upwards sequence in thereservoir.
Fig. 4.3: BLAME IT ON THE RAIN: The reservoir is situated in Late Jurassic sediments which straddle the edgeof a gently sloping carbonate platform. Porous carbonate grainstones formed in the shallow waters to thenorth. In the deeper waters to the south, a fine rain of pelagic sediments formed fine-grained mudstones with poor permeability. The two different types of rock are separated by a transitional zone which developed between these two different depositional environments.
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0 600300
South NorthWell XPermeability (md)
0 600300
Well YPermeability (md)
0 600300
Well ZPermeability (md)
K>20
K<20
K>20
K<20
8000
Depth ft
8080
8000
8160
8320
46 Middle East Well Evaluation Review
CYAN MAGENTA YELLOW BLACK
As predicted by the depositionalmodel, the reservoir is better devel-oped in the north and progressivelythins and degrades to the south. Therelatively low oil viscosity (0.5 cp at reservoir condition, about twice the vis-cosity of the injection water) togetherwith the end-point relative permeability
to oil being considerably higher than towater, gives the waterflood a favourablemobility ratio.
In the developed northern area of the field, productivity is generally high.However, the reservoir is highly hetero-geneous and consists of a mixture of lithologies. Porosities vary between 10%and 23%, while permeabilities rangefrom 5 md to 500 md. This is not uncom-mon in a carbonate reservoir wherepermeability depends on both porosityand rock type. For the same porosity,calcareous grainstones have permeabili-ties that are an order of magnitude
higher than fine-grained micritic rocks.The reservoir is also highly stratifiedwith large permeability variationsbetween layers. Figure 4.4 is a coreporosity and permeability plot for a typ-ical crestal well. Even in the well-devel-oped upper portion of the reservoirthere is a large permeability variation.The reservoir heterogeneity is illus-trated in the north-south cross-sectionshown in figure 4.5. It illustrates theessential reservoir characteristics, iehigh variability and a general deteriora-tion of quality from north to south.
Core permeability
Permeability md Porosity %
Core porosity
0.1 10,000
<10 md
10-100 md
100-1000 md
50
Measureddepth ft.
7950
8000
8050
8100
8150
8200
0
>10%
Fig. 4.4: Core permeability and porosity plot from a typical crestal well.There isa large permeability variation in thetop part of the
reservoir.
Fig. 4.5: This'fence' permeability diagramclearly indicates thewide rangeof permeability across thefield.
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47Number 13, 1992.
1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990
4200
3800
3400
3000
2600
P r e s s u r e ,
P s i g
Year
Pressure
Decline and build-up
Immediately after production started in1970, the reservoir pressure fell dramat-ically (figure 4.6). To stem the fall, awaterflood pressure maintenance pro-ject was initiated in January 1973 using
injection water from a shallow, rela-tively fresh, aquifer. Injection wellswere drilled close to the trailing edge of the OOWC and completed open hole.The objectives were clear:
• To ensure the reservoir pressureremained above the bubble point.• To keep wells flowing at high watercuts to obviate the need forpumps or gas lift.• To move the oil towards producing wells situated in the updip area.
Two years after injection started,
water began to breakthrough in the first row of producers. Initially these wet wells had to be shut in or recompletedto drier zones towards the top of thereservoir. However, water productionwas allowed from 1981 when wet crudehandling facilities were installed. Sincethen, the field’s average water cut hasonly increased to around 20% althoughthe flood front has advanced to the cre-stal area. This low water cut is main-tained because all wells flow naturally,so when an individual well’s water cut increases to between 60% and 70%, it becomes water logged, stops flowing
and dies. Hence, the total water (andoil) production is reduced. To sustainthe overall oil rate, new wells aredrilled and dead wells worked over andrecompleted to drier zones. ByDecember 1989, a total of 75 wells hadbeen drilled. Of these 42 were produc-ers, 15 were injectors and the remain-der were observation wells.
Fig. 4.6: WEAK AQUIFER: As soon as production started in 1970, thereservoir presure went into rapid decline. At this rate, bubble-point pressure would have been reached within two years. To prevent this, theoperator embarked on a peripheral waterflood scheme which successfully managed to reverse the pressure decline.
Fig 4.7: Since the injection wells are located outside the trailing edge of the OOWC - and because of the favourable mobility ratio - large banks of high salinity aquifer or formation water advancethrough the reservoir ahead of the injection water. This results inan increase in TDT log readings followed by a decrease as theformation water is replaced by less saline flood water.
D i r e c t i o n o f f l o o d
Time (distance)
0
1.0
Sw
Connate water saturation.
Residual oil saturation.
Producer Injector
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48 Middle East Well Evaluation Review
1977 1984 1985 1988
Porosity PNL PNL PNL PNL
90 0% 40 0 40 0 40 0 40 0CU CU CU CUft
7922
8000
8100
8200
Top of Res.
Base of Res.
Depth
Neutrons and networks
Extensive monitoring has been used toobserve the waterflood sweeping acrossthe reservoir. The principal saturationmonitoring tool has been the PulseNeutron Capture Log (PNL). This log has been run on a routine basis sincethe mid-1970s when flood water startedto break through in the outer producing wells.
Because of the high formation watersalinity of 240,000 ppm total dissolvedsolids (TDS), PNL logs have been veryeffective in tracking the advance of theflood front through the reservoir (fig-ures 4.7 and 4.8). In addition to produc-ing and observation wells, PNL logshave been run in 25 deep wells andthese have provided excellent water-flood observation points as they are not hampered by fluid invasion, acid orother effects.
Once the high salinity flood front haspassed through a monitoring point, it isfollowed by the relatively fresh injec-tion water - salinity 24,000 ppm TDS.The resultant mixed salinity environ-ment makes quantitative interpretationof PNL logs difficult - the calculationdepends on a known water salinity fac-tor†.
Further complications arise when azone is just starting to deplete and con-tains both oil and formation water whileanother zone in the same well hasalready been swept and contains a mix-ture of formation and injection water. In
this situation it is difficult to distinguishone zone from another using PNL logs.
To overcome this mixed salinityproblem, a network of key wells hasbeen established. These wells are fre-quently logged to monitor qualitativelythe displacement of oil-first by forma-tion water which causes an increase inPNL response, and then by the injectionwater which causes a decrease in PNLresponse.
In addition, wet wells are routinelytested and samples of produced watercollected for geochemical analysis.From this, the proportion of injectionand formation water in the wet produc-ing zones of the well is estimated.Finally, flowmeter surveys with gra-diomanometers are conducted to obtainthe flow profile and identify water pro-ducing zones (see Go with the flow inthis issue).
Well performance, geochemical dataand flowmeter-gradio results are com-bined with the PNL log interpretation
for each well to establish:
• Zones that are sweeping orresponding to the peripheral flood,
and;• Zones indicating no significant
movement or sweep.
Figure 4.8 is an example of this typeof surveillance data. It shows theprogress of the waterflood as observedfrom time-lapse PNL logging of a typicalflank well.
Another important aspect of thewaterflood monitoring effort is the eval-
uation drilling program that was startedin the late 1980’s. This is aimed at evalu-
ating the sweep in the reservoir’sundrilled areas, between the injectorsand first row producers. In addition tocores and open- hole logs, these wellsprovide the opportunity to selectivelytest individual layers to determine fluidcontent and salinity and to run wirelinemultiple-pressure testers, such asRepeat Formation Tester (RFT), across
the reservoir.Over the past four years, a total of
eight evaluation wells have beendrilled. Integrating data from these wellswith routine surveillance data from the67 existing wells gave a good under-standing of the reservoir’s waterencroachment patterns and flow charac-teristics. It also produced a good assess-ment of the areal and vertical sweepacross the reservoir, which was the pri-mary objective in evaluating the perfor-mance of the waterflood.
Fig. 4.8: SALT SURVEILLANCE:These time-lapse pulsed neutron logs give a clear indicationof the movement of the waterflood front across a section of thefield.
†Such measurements have been made easier with
the arrival of the Reservoir Saturation Tool (RST*)
into the Middle East (see Midd le Ea st We ll Evaluation Review, Number 11, 1991).
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49Number 13, 1992.
The effectiveness of a reservoir water-flooding scheme depends on three basicfactors - the microscopic displacement,and the areal and vertical sweep efficien-cies. For best results, these factorsshould be determined by a detailed
reservoir study which includes simula-tion. However, a quick assessment of thewaterflood performance can be made byassigning a value between 0.0 and 1.0 foreach of the three efficiency factors.
The overall waterflood efficiency canthen be computed by multiplying thesethree values. For example, a reservoirwith microscopic, areal and verticalsweep efficiencies of 0.6, 0.7 and 0.5respectively would have an overall floodefficiency of 0.21. In other words, only 21percent of the oil-in-place would berecovered.
Microscopic displacement efficiency
is a measure of how easily the oil can beremoved from the rock pores. Efficiencyvalues can be obtained from laboratorycore studies or the Log-inject-Log tech-nique using equipment such as theThermal Decay Time tool. The use of surfactants, which improve the rock wet-tability and reduce the interfacial tensionin the system, can increase displace-ment efficiency.
Areal sweep efficiency is a measureof how much of the reservoir has beenin contact with the flood water in anareal plane.
Vertical sweep efficiency is a mea-
sure of the uniformity of water invasionin a vertical cross section.Both the areal and vertical sweep are
dependent on a large number of factors:the distribution of horizontal and verticalpermeability, anisotropy, wettability,reservoir thickness, fluid characteristics,the injection/production rates, the place-ment of perforations, type of injectedfluid (water or gas), the well spacing etc.
Proper planning of a waterfloodshould take into account most of theseparameters and the predictions are usu-ally based on model studies (bothnumerical and laboratory). The actual
waterflood performance can be esti-mated by examining saturation datafrom in-fill and observation wells andtracer surveys. In a tracer survey, chem-ical or mildly radioactive tracers areadded to the injection water and theirarrival time at the producing well isnoted.
Today, reservoir simulation studiesare playing an increasingly important role in determining the areal and verticalmovement of the injected water. Theyalso help to guide drilling programmesaimed at maximising the sweep effi-ciency of the waterflood.
A CLEAN SWEEP
Injection wells
Producer
Oil
Water Water
Areal sweep
Water Oil
Sand WaterOil
Fig. 4.9: AREAL SWEEP: Ameasure of howmuch oil is left behind in areasnot swept by the
waterflood.
Fig. 4.10:VERTICAL SWEEP: Defined as the cross- sectional area
contacted by theinjected fluid divided by thecross-sectional area enclosed inall layers behind the fluid front.
Fig. 4.11: MICROSCOPIC DISPLACEMENT: Relates to theremoval of oil by water on the pore- scale.
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CYAN MAGENTA YELLOW BLACK
50 Middle East Well Evaluation Review
BM
L
N
K
C'
P Q RB'
B CD
E
F
HI
A
AA'G
J
N
O'
The term sweep, as used here, impliesthat a part of the reservoir has beencontacted by formation or injectionwater. Because of the problem of mixedsalinity, no effort was made to evaluatedisplacement efficiency.
As there was no reliable simulationmodel available, sweep was evaluatedby generating a series of cross sectionsparallel and perpendicular to the struc-ture (figure 4.12). Water encroachment data from individual wells was superim-posed on these sections and the swept and unswept zones identified and corre-lated from well to well.
The reservoir was then divided intoa number of layers, based on perme-ability. For each of these layers, mapswere drawn showing the swept andunswept zones. In addition, net oilisopachs were prepared to estimate thevolume of unswept oil. From this water-flood evaluation, which is mainly based
on observed performance, severalimportant conclusions can be drawn:1. In spite of the complexity and sig-
nificant variation in rock-type and per-meability, all facies with a permeabilitygreater than 20 md responded to theperipheral flood. Upper and middle sec-tions of the reservoir, which containedmost of the permeable layers, wereflooding together almost as one pack-age.
2. The lower part of the reservoir,where the permeability is generally lessthan 10 md, was not flooding at all. Inspite of being completely overlain by
flood water in the permeable zonesabove, there was no noticeableencroachment of water or displacement of oil from these tighter facies. It is pos-sible that the tight lower zones that arenot flooding may be more oil wet thanthe more permeable zones above.However there is no wettability data tosupport this (see box on page 55).
3. On the northern flank of the field,there was unswept oil in the permeableupper part of the reservoir.
4. Although early PNL and resistivitylogs showed water breakthrough in thehighest permeability zones, there are no
major fingers anywhere in the reser-voir. This is believed to be due to goodvertical permeability, favourable mobil-ity ratio and the field operating strategyof restricting the producers ahead of theflood front.
A good way to illustrate waterencroachment in a reservoir is throughcross sections (figures 4.13 to 4.16).
The east-west section AA' representsthe northern flank, an area that is closeto the injectors, and had more injectionwater pass through it. This section isshown both stratigraphically (figure4.13) and structurally (figure 4.14).
There are two distinct permeability
zones - the lower zone with permeabil-ity generally less than 10 md and theupper zone which ranges from 20 to 500md. Individual log sections show theporosity profile on the left track. On theright track, injection wells show theflowmeter profile while producing orobservation wells show the PNL log response. These sections clearly showthat:• Water is entering more or less
uniformly into the permeable zones(K>20 md). It then gravitates down
to the base of the permeable zoneand continues to ride on top of the
tight zone (K<10md).• The flood water is sweeping
through the middle section of thereservoir with oil above and below.• Time-lapse PNL logs show that theoil at the top is still moving,although at a slow pace.• The oil in the tight facies (K<10 md)is not sweeping at all.
The cross section BB' (figure 4.15)goes through the crestal area from east to west flank. It shows a dry crestal pro-ducer with a flood front approaching from both sides. This cross sectionshows a similar flooding pattern as
observed in section AA'. However,
there are differences:• The injection wells have a poor
flow profile because the permeablefacies have become thinner on the
flanks. But even then, the floodwater is sweeping through thepermeable zones (K>20 md) butcompletely by-passing the tighter
zone (K<10 md) below.• The thickness of the unswept oil atthe top is much thinner (20 ft) thanthe unswept oil column (80 ft)
observed in the northern crosssection, AA'. This, as will be shown
later, is primarily due to better
drainage in the crestal areacompared to the northern flank.The north-south cross section, A'C'
(figure 4.16) which goes from the injec-tion well in the north flank to the drywells in the south, confirms the sweeppattern observed in the two east-west cross sections, AA' and BB’.
Fig. 4.12: ON THE WATERFRONT: Prior to the development of a reservoir simulation model, theonly way to assess the efficiency of a waterflooding scheme was to generate a series of cross- sections across the field. These helped to locate the swept and unswept zones. This map showsthe approximate location of each of the sections presented in figures 4.13 through 4.16.
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51Number 13, 1992.
Well - L
P O R
F B S
P O R
T D T
P O R
T D T
P O R
T D T
P O R
T D T
P O R
T D T
P O R
F B S
Well - M Well - N Well - O Well - P Well - Q Well - R
Injector Injector
W ESwept zone
Topres.
Baseres.
Oil
K = 20-500K = 10
Water
Flood
front
Flood
front
F B S
Well - A
P O R
F B S
Well - B
P O R
T D T
Well - C
P O R
T D T
Well - D
P O R
T D T
Well - E
P O R
T D T
Well - F
P O R
T D T
Well - G
P O R
F B S
Injector Injector
Oil
Oil
Top
res
Base
res
K = 20 - 500K=10
W E
Swept zone
Well - K Well - J Well - I Well - H Well - F Well - G
P O R
T D T
Topres
Base
res
P O R
T D T
P O R
T D T
P O R
T D T
P O R
T D T
P O R
F B S
Dry Wet
Flood front
Swept zone
Injector
Oil
Oil
K20-500
K =10
Water
S N
Well - A Well - B
Oil
Well - D Well - E
Well - F
Well - G
OOWC OOWC
P O R
F B S
P O R
T D T P
O R
T D T
P O R
T D T
P
O R
T
D T
P O R
T D T
P O R
F B S
Water
Well - C
K = 20K = 10
W E
Topres
Baseres
Swept zone
Fig. 4.13: East-west stratigraphic cross section showing twodistinct permeability zones. The flood water is sweeping through the middleof the reservoir,leaving oil above
and below.
Fig. 4.14: Structural section
along the same line asthat of figure4.13.
Fig. 4.15: East-west cross sectionthrough thecrestal arearevealing adry producer with theflood front approaching from both sides.
Fig. 4.16: Thisnorth-south section confirmsthe sweep patternwhich wasobserved in theeast-west sections.
A
B
A
C'
A'
A'
B'
A'
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CYAN MAGENTA YELLOW BLACK
52 Middle East Well Evaluation Review
The best evidence of good verticalpermeability can be obtained from RFTpressure profiles of wells drilled in bothproducing and non-producing areas of the reservoir. Twelve recently tested
wells showed a uniform pressure pro-file across the permeable section of thereservoir. Figure 4.17 illustrates a pres-sure profile of a crestal evaluation well.There is no differential depletion andthe pressure profile across the perme-able section of the reservoir is uniform.This confirms the absence of extensivehorizontal barriers and indicates that there is enough vertical communicationbetween layers to allow movement of oil and water across the reservoir.
The average mobility ratio of thewaterflood is estimated at 0.4. Based onexperience with other waterfloods,such a favourable mobility ratio has avery positive impact on areal and verti-cal sweep since it eliminates any possi-bility of viscous channelling (orfingering) of water through the oil, caus-ing early water breakthrough in the pro-ducing wells.
Also, reservoir management hasbeen a key factor in ensuring goodareal and vertical sweep. A producing strategy was implemented in 1982. Thisrestricted or shut in dry producersahead of the flood front and preferen-tially produced the wet wells to the
rear. As shown by the water arrivalisochrones in figure 4.18, this sloweddown the rate of advance of the floodfront, avoiding water breakthroughalong high permeability streaks andallowing gravity forces to smooth out the effect of stratification. This is whythere is no evidence of fingering in thereservoir even though the early resis-tivity and PNL logs showed waterbreakthrough in thin, highly permeablezones (figure 4.19).
RFTPressure-Psig
3700 3800 3900
Gradient = 0.30 Psi/ft
Oil/Waterinterface
Gradient = 0.42 Psi/ft
Gradient = 0.52 Psi/ft
Gradient = 0.30 Psi/ft
Supercharged ?
Resid.HCarbon
Moved Water
50 % 0
Depthft
7850
7900
7950
8000
8050
DST3950 Bbl/day
0% cut
DST843 Bbl/day
56% cut
DST278 Bbl/day
0.3% cut
1 9 7 4 1 9 7 6
1 9 7 8 1 9 8 0
1 9 8 6
F l o o d f r o
n t
Producer well
Injector well
Observation well
1 9 9 0
Fig. 4.17: VERTICAL EQUILIBRIUM: RFT pressure profile of a crestal evaluation well indicates absence of barriers.
Fig. 4.18: FLOOD FRONT ADVANCE: Movement of the flood front across thefield was slowed down by preferentially producing the wet wells and restricting the dry crestal wells.
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53Number 13, 1992.
Porosity Depth
ft
8000
8100
8200
PNLPlayback
1977Sigma cu
1984Sigma cu
1988Sigma cu
50 % 0
40 0
40 0
40 0
Dryoil
Sweptzone
F l o o d f r o n t
0 2 5 5 0 7 5
5 0
5 0
2 5 0
Unswept oil
Flood front
A sweeping improvement
There is a column of dry oil at the top of the reservoir that is sweeping veryslowly (figures 4.8 and 4.13). Theseunswept zones were identified andisopach maps showing the thicknessand extent of this unswept oil were
drawn for each layer.To investigate the reason for thislack of sweep in the permeable upperportion of the reservoir, especially inthe NE flank where there is adequateinjection support, all possible factorsthat may have a bearing on sweep werecritically reviewed. Structure, gross pay,pressure, permeability, cumulativeinjection/withdrawal, current injec-tion/production etc are some of the fac-tors that were examined (figures 4.21 to4.26). However, the parameter that gavethe closest correlation with poor sweepis poor drainage.
Currently, most of the producing wells are located in the crestal area of the reservoir. There is very little with-drawal from the NE flank where the oilat the top has stopped moving. This ispartly due to the reservoir being flat ( formation dip 1° - 1.5°) and alsobecause the crestal production is effec-tively supported by injection watermoving through the highly permeablemiddle section of the reservoir.Therefore, there is no horizontal pres-sure gradient to drive oil from the NEflank to the producing wells in the cen-tral area.
Plans are underway to improverecovery of the unswept oil by provid-ing more drainage points in the NEflank. This will be done by recompleting existing wells and drilling infill wells.However, because of the relatively thinoil column and underlying water, wellsare expected to cone water. Therefore,horizontal wells are being planned andeventually artificial lift will be requiredto produce these wells at higher watercuts.
As regards the unswept oil in thetighter lower part of the reservoir, it isbelieved that the current peripheral
flood will recover very little oil fromthis facies. Developing these tighterfacies may require waterflooding at very close spacing or some other recov-ery technique.
Fig. 4.19: EARLY WARNING: Water breakthrough in the thin, highly permeable zonescan be clearly seen in this early log. However, the producing strategy was designed to prevent this from occurring in the crestal area of the field.
Fig. 4.20:Thickness and areal extent of the unswept oil zone.
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CYAN MAGENTA YELLOW BLACK
54 Middle East Well Evaluation Review
8 3 0 0
8 2 0 0
8 1 0 0
8 0 0 0
7 9 0 0
7 8 0 0 7 7
0 0
Unswept oil
Flood front
30
4 0
4 0
3 0
2 0
4 0 0 0
3 8 0 0
3 6 0 0
3 4 0 0
p s i g
Fig. 4.23: Isobaric map versus unswept oil inlayer BB1.
Looking to the future
The performance characteristics of thefield have now been incorporated intoa new geological reservoir descriptionwhich forms the basis of a 3-D simula-tion model of the entire field. Reservoirsimulation is now in progress and willbe used as a key reservoir management tool. It will not only be used to predict future performance but also to optimize
Fig. 4.22: Gross Pay versus unswept oil inlayer BBI.
Fig. 4.21: Structure versus unswept oil inlayer BBI.
6 0
8 0
100 m d
1 2 0
1 4 0
1 2 0
4 0 0
3 0 0
2 0 0
1 0 0
3 0 0
4 0 0
5 0 0
6 0 0
4 0 0
3 0 1 5 5
Unswept oil
1 6 0
1 8 0
Fig. 4.24: Permeability versus unswept oil inlayer BBI.
F
l o o d f r o n t
ProducerInjection well
ObservationwellUnswept oil
F l o o d f r o
n t
Producer
Injection well
ObservationwellUnswept oil
Fig. 4.25: Cumulative production/ injectionversus unswept oil in layer BBI.
Fig. 4.26: Current drainage/injectionversus unswept oil in layer BBI.
the producing and development strate-gies for the field.
Acknowledgement
Appreciation is given to the Saudi Arabian Ministry of
Petroleum and Mineral Resources and to Saudi Aramco
for permission to publish this paper.
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55Number 13, 1992.
Wettability is an extremely important factor as it controls the location, flowand distribution of fluids in a reser-voir. It is a measure of the preferencethat the rock exhibits for either oil or
water and has been defined as ‘thetendency of one fluid to spread on oradhere to a solid surface in the pres-ence of other immiscible fluids’.
If a rock is water wet, the waterwill tend to occupy small pores andbe in contact with most of the rocksurface - the ideal situation for any-one wishing to extract oil from areservoir. In an oil-wet system, therock retains the oil in its small porespaces, making production more diffi-cult.
There are several ways of assess-ing wettability. One relies on measur-
ing the contact angle which is formedwhen a drop of water is placed on arock surface immersed in oil (see fig-ure). If the rock is water wet, the con-tact angle is less than 90°. In anoil-wet system, the angle exceeds 90°.
Wettability measurements on coresamples are not always reliablebecause it is difficult to retain theoriginal wetting character of the rockduring sampling or in the laboratory.Logging techniques, which measurethe difference in resistivity betweenoil- and water-wet rocks, can provide
some estimates of in-situ wettability mea-
surements.
WET....WET....WET
Rock
Oil
Waterθc
Water wet (θc > 90˚)
θc
Rock
Oil
Water
Oil wet (θc < 90˚)
Fig. 4.27: In water-wet systems, thecontact angle is lessthan90 °.
Fig. 4.28: Inoil-wet rocks, theconverse istrue.
Further reading:
Wettability Literature Survey - Par t 1: Roc k/Oil/Bri ne Intera ctions and the Effects of Core Handling on Wettability by W.G.
Anderson in Journal of Petroleum Technology,Oct. 1986, page 1125.