spe chicontepec

8/10/2019 SPE Chicontepec

1/12

SPE 92077

Integrated Characterization of Low Permeability, Submarine Fan Reservoirs forWaterflood Implementation, Chicontepec Fan System, MexicoNoel Tyler, SPE, The Advanced Reservoir Characterization Group; Heron Gachuz-Muro, SPE, Pemex Exploration andProduction; Jesus Rivera-R, SPE, University of Mexico (UNAM); Juan Manual Rodriguez Dominguez, SPE, PemexExploration and Production; Santiago Rivas-Gomez, Humyflo SA de CV; Roger Tyler, The Advanced ReservoirCharacterization Group; and Victor Nunez-Vegas, Independent Consultant, Caracas

Copyright 2004, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2004 SPE International Petroleum Conferencein Mexico held in Puebla, Mexico, 89 November 2004.

This paper was selected for presentation by an SPE Program Committee following review of

information contained in a proposal submitted by the author(s). Contents of the paper, as

presented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to a proposal of not more than 300words; illustrations may not be copied. The proposal must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

Through integrated characterization of highly heterogeneous

submarine fan reservoirs of the Chicontepec fan system

optimum location for a waterflood pilot was identified and

tested. Positioned in a high quality, comparatively low

heterogeneity part of the complex, results of the pilot indicate

that water flooding the Chicontepec is feasible and that thereservoirs tested would benefit from a several pattern, long-

term water injection program.

Introduction

The Chicontepec submarine fan system was deposited in the

Tampico-Misantla Basin of northeastern Mexico during the

Paleocene-Eocene and is the stratigraphic equivalent of the

Wilcox Group in Texas. The entire Chicontepec system is

considered to be prospective1, and as such, accounts for a

substantial component of Mexicos oil resource base. Primary

production has been established in several fields in the

northern and southern parts of the basin and limits to these

fields have not been defined. By-well cumulative productionsvary greatly. Like its close analog, the Spraberry Trend of

the Permian Basin, the Chicontepec is pervasively saturated,

and like the Spraberry, is considered a candidate for secondary

recovery.

There are many challenges to be overcome before

waterflooding can be initiated in the Chicontepec. The

turbidite reservoirs of the Chicontepec are both vertically and

laterally heterogeneous; reservoir quality is an issue as the

sandstones are cemented and they contain a minor but critical

amount of swelling clays; and the reservoirs are naturally

fractured. Establishing the architecture of the reservoir is a

critical element of waterflood design. Sediment architecture,

which includes sand distribution and facies composition

controls the spatial distribution of reservoir properties and

hence the distribution of original oil and place; how the

injected fluids will move in 4-D (3-D space and time) through

the reservoir; and ultimately, how the reservoir drains. Thusdefinition of reservoir architecture is the critical first step in

the waterflood deployment. Having established the

architecture of reservoirs in the field, the next steps are the

integration of petrophysical data, construction of maps of

reservoir properties and ultimately of reservoir volumetrics

synthesis of production data with reservoir geology to identify

production character of component facies, and where the

reservoir would best benefit from secondary recovery

operations. In this paper we discuss the characteristics of the

Chicontepec and the approach we followed to mitigate these

technical challenges in the selection of platforms as pilot test

wells for water injection in several reservoirs from the

southern Chicontepec submarine fan system.

Depositional Architecture and Reservoir Quality

Submarine fan deposits of the Chicontepec fan system in a

field located at the south central part of the Chicontepec

system were deposited under complex tectono-stratigraphic

conditions. Early deposition was widespread across the basin

and was followed by several phases of uplift and reworking

that resulted in complex stratal architectures (Figure 1)

Resolution of the stratal geometries was accomplished through

careful calibration of well log correlations and seismic

interpretation. Because of sand pinchout through changing

depositional processes and subsequent erosion the number of

reservoir sands present varies across the basin. Typically

between 8 and 16 major reservoir intervals are present in theChicontepec. In the field under study, 10 of these intervals

were considered as potential candidates for waterflooding

The multistoried reservoir system is typically composed of

channel complexes that are flanked by, and rest on, lobe

sandstones that grade into distal fan and basin floor deposits

Between-well-scale facies variability resulting from typica

submarine fan depositional processes coupled with tectonic

instability produced a highly heterogeneous reservoir system

in this field. However, net sand and facies architectura

mapping provide predictability in sand distribution and this

predictability has allowed us to select the prime locations for


2/12

2 SPE 92077

implementation of a waterflood pilot. Net sand and facies

maps indicate favorable sand content and facies at several

levels at this platform.

Petrographic analyses indicate the Chicontepec sands

are lithologically immature litharenites consisting of quartz

grains, abundant carbonate fragments, and granitic fragments.

Because of the abundance of carbonate in the system, the

sediments are highly cemented by ferroan calcite and ferroandolomite, in addition to quartz overgrowths. The abundance

of cements is the primary control on reservoir quality as

cementation decreases porosity increases 2. Interestingly, the

sands are clean or clay deficient sands with only 1 percent

clay. However, those clays contain smectite, a swelling clay,

and in injectivity tests the swelling of the smectite in reaction

to injection of artificial brine resulted in a 40-80% loss of

permeability 3. Injection of fresh water resulted in a similar

loss of permeability (70%). Injection of KCL-bearing water

(5%) was non-damaging. As a result of these analyses it is

clear the injected water will require treatment and the addition

of an inhibitor.

Despite this intense diagenetic overprint, depositional

facies exert a strong control on reservoir quality. Conventional

core data from several wells completed at a deep zone within

this field were used to cross compare the relation between

facies and porosity and permeability. Cores intersected four

different facies types in this sand. These were: channel, lobe,

distal lobe and interlobe (or condensed section). Figure 2

shows the data fall into two populations, the distal facies

(distal lobe and interlobe deposits) and more proximal facies

(channel and their associated lobes). Maximum values of

porosity and permeability are substantially higher in the

proximal facies.

To identify areas of superior reservoir quality and to

avoid the effects of poor reservoir quality we constructed

maps of average porosity and permeability calculated fromwell logs for the key potential waterflood reservoirs. These

maps showed a direct relationship to net sand trends for that

reservoir. By combining information from the net sand and

facies maps with the maps of petrophysical properties the

direction of flow of the injected fluids becomes predictable.

Natural Fractures

The Chicontepec has been cored in numerous wells across the

basin and many of these cores display vertical and sub-vertical

natural fractures. Fractures are open and partially cemented

with calcite (Figure 3a) or are oil stained (Figure 3b). Outcrop

exposures of the Chicontepec bedding planes display a

network of intersecting systematic and non-systematicfractures (Figure 4a). The principal or systematic fractures are

fairly evenly spaced and show strike slip motion, and

subsequently offset the connectivity of the non-systematic

fractures. Microseismic analysis undertaken in the field

during drilling has shown that the systematic fractures have a

northeasterly orientation11

(Figure 4b). Lesser microseismic

events with a northwest orientation capture the effects of the

non-systematic fractures.

Selection of Candidate Wells for InjectionOn the basis of this integrated study we have selected

geologically optimum locations for injection wells in each of

the major reservoirs to be considered for waterflood

deployment. The geological basis for the selection of these

candidate injection wells was:

Optimum sand thickness

Minimized facies heterogeneity

Good resistivity indicating good saturation

Distance from faults

Moderate-to-good primary production (as anindicator of optimum reservoir quality)

Engineering considerations in the selection or pilot injection

wells included:

Mechanical status of the wells

Perforations and productions history

Cumulative oil productions

Reservoir heterogeneity and continuity

Reservoir physical properties as defined from wel

tests.

Water injection Pilot TestIn order to test the feasibility of conducting water injection

projects in complex reservoirs such as those located in the

Chicontepec system, a short-term pilot injection test was

carried out in a selected area of one reservoir from the

Chicontepec submarine fan system. This pilot water injection

area was basically an incomplete inverted seven-spot pattern

it was composed of 4 producer wells (wells B, C, D, and E),

and one injector (well A). It was implemented to test the

reservoir response to water injection in two sand bodies tha

will be denoted as S1 and S2. The pilot was located in a

channel complex in one of the reservoirs and in submarine fan

lobe facies of the second reservoir. Total sand thickness was

between 128 to 253 ft, while depth to the top of shallowersand body was between 4675 to 5022 ft. Figure 5 shows a

sketch of well distribution within the pilot 4. Table 1 shows

distances and calculated areas between injector and offset

wells. This pattern is not confined.

Initial conditions of this field were slightly

undersaturated oil with a reservoir pressure of 3195 psig (225

kg/cm2) and a formation volume factor of 1.1621 bbl/STB

Reservoir temperature is 158F (70C). At the time the pilo

was conducted, there were 77 wells drilled at the field; 65 of

them were under gas-lift. Field oil production at this time was

2,400 BOPD. Figure 6 shows monthly oil, gas and water

production from this field. The pilot test was conducted from

March 6, 1999 through March 31, 2000. Partial results of this

short-term pilot test were reported earlier in reference 5.

Well Testing Program during the Pilot Test

A multiple rate injection test was carried out at the beginning

of water injection 4,5. Six different increasing flow rates were

injected at well A during this test, ranging from 240 to 4000

bbl/day, with a final stable injection rate of 2600 bbl/day. I

should be mentioned that a mixture of separated produced

water coming from several fields in the area, with a minimum

treatment, was used as injection water. Pressure fall-off tests

were carried out at the end of each one of the injection periods

in order to estimate any possible formation permeability


3/12

SPE 92077 3

change due to the water injected. An interference test between

the injector (well A) and two producers (wells B and C) was

conducted at the end of the pilot test to calculate main

reservoir properties within the pilot area. Figure 7 shows the

observed pressure response at the offset wells.

Tracer Tests Conducted at the Pilot Area

A tracer injection program was carried out from the beginningof injection. Three chemical tracers and one radioactive tracer

were injected during the test. The injected chemical tracers

were fluorinated benzoic acid tracers (FBA) with low

detection limits (down to 50 ppt). Chemical tracers were

injected at different stages of the multiple-rate injection test,

as small slugs, with the main objective of sensing the presence

of pressure sensitive natural fractures within S1 and S2

formations. It should be mentioned that chemical tracers were

injected as short volume slugs, while the radioactive tracer

was injected as a continuous stream. As mentioned before,

main objectives of this tracer program were to investigate the

presence of pressure sensitive natural fractures within S1

and S2, as well as the presence of reservoir heterogeneities in

these formations that could adversely affect injected water

sweep, such as potential flow barriers, flow trends and

potential water channeling problems.

None of the FBA tracers were detected in early

produced water samples; this was taken as an indication that

no major natural fracturing connecting the injector with the

offset wells was evident in the S1 and S2 intervals of the Pilot

Area. However, as it was mentioned before in this paper, the

presence of natural fractures has been observed from both core

analyses and well tests conducted in several fields from the

Chicontepec Channel 9,10. Chemical tracers were only detected

at wells B and C. Observed response from chemical tracers is

shown in Table 2 and Figures 8 and 9.

A beta emitter- low energy level radioactive, waterphase tracer (tritiated water, HTO), with low detection limits

(around 1 pCi/ml) was injected at the final step of the multiple

rate test, once the injection flow rate was maintained at a

nearly constant level 5,6,7. The main objective of this tracer was

to evaluate the presence of reservoir heterogeneities, such as

flow trends, barriers and potential channeling problems (not

related to natural fractures). Table 3 shows the breakthrough

times of the HTO tracer at the offset wells.

As it can be seen from Figure 10, HTO tracer arrived

at all four offset producing wells. Breakthrough times ranges

from 77 to 238 days after injection. It can be seen from Tables

2 and 3, that the length of time to initial tracer breakthrough at

all four offset wells indicates no significant channelingoccurred during the pilot test. After breakthrough, HTO

production was continuous from the four offset observation

wells (Figure 10), indicating uniform movement of the

injected water through the producing formation.

Unfortunately, sampling was interrupted before complete

tracer profiles could be established at all observation wells,

since at the end of the sample collection period tracers were

still arriving at three of the four offset producing wells. Tracer

mass balance calculations suggests that the observed tracer

response represents fluid movement through only a limited

reservoir volume, which could correspond to a one or a few

thin high permeability layer(s) in the reservoir 4,6.

Arrival times of the HTO tracer to the four offse

wells (Table 3), suggests that movement of the injected water

from the injector occurs in a generally radial pattern. Taking

into consideration this flow pattern, an index can be

calculated, as the ratio of the distance from the injector to the

time it takes the tracer front to arrive at a given observation

well (called apparent superficial velocity, vsapp). As shown

in Table 5, it appears to be a higher effective reservoirpermeability in a northern direction from the injector, since

vsapp calculated values are higher in this direction (4.16 and

4.27 m/day towards wells C and B, respectively, compared

with 1.52 and 2.24 m/day towards wells D and E

respectively).

As it can be seen from Table 5, calculated fluid flow

apparent velocities from tracer response at two of the offse

wells are lower than the highest velocity direction by a factor

of 2 to 3. This is a clear indication of strong variations of

formation permeability in different directions within the pilot

area. It should be mentioned that results obtained from tracer

testing, agreed well with fluid flow directions inferred from

net sand trends correlations and log facies maps developed for

the formations within the tested area, as well as for other sand

bodies from the reservoir. These correlations show that sand

distributions within the sand bodies tested in the pilot, were

affected by depositional as well as erosional processes. Sand

bodies show bifurcations and pinch outs typical o

channel/lobe systems. For the pilot area, it was observed that

sand continuity and reservoir rock quality are good in a

northern direction from the injector, decreasing in east and

southeast directions, which as mentioned before agrees with

the results obtained from the observed tracer response. Further

discussion on reservoir facies is provided elsewhere in this

paper.

As can be seen from Table 4 and Figures 8 through

10, breakthrough times and times of arrival of peak tracerconcentration at observation well B are not the same for

different tracers. It is observed that breakthrough of tracers a

this observation well followed an inverse order from that at

which they were injected; HTO tracer (the last one injected)

arrived first, followed by the third in injection order, then the

second one injected, and at last, the first injected tracer

(FBA1). This is an indication that different flow paths through

the reservoir were available for each one of the tracers at the

time they were injected. A behavior similar to the one

previously described, in which the latest injected tracer arrived

faster at observation wells than the first one injected, has been

reported for tracer tests conducted at Ekofisk 7.

Since the main variables that have changed at reservoirconditions at times when the different tracers were flowing

through the producing formations were pressure and fluid

distributions through the reservoir, it is believed that rock

fluid interactions (such as imbibition), as well as local pore

geometry conditions (such as pore size and pore throa

distributions), and wide variations in petrophysical properties

between adjacent layers, among other possible factors, have

produced the apparent effect of decreasing breakthrough times

as tracers were injected at times when cumulative water

injected volumes were higher. This hypothesis requires

confirmation through laboratory experiments, using rock and

fluids samples from the reservoir, conducted at reservoir


4/12

4 SPE 92077

conditions. It is appropriate to mention that available

wettability measurements performed on cores from different

parts of the field suggest that rock wettability from this

formation could vary from slightly oil wet to neutral

wettability 8.

Response to water injection

As a clear response to water injection, reservoir pressureincreases and modest gas/oil ratios decrements were measured

at the offset wells; however, no clear increments in oil flow

rates were detected at the end of the pilot test. It is believed

that this may be due to the short duration of the test. Bottom-

hole flowing pressure at well B changed from 720 psig at the

beginning of injection to 975 psig at the end of the test; while

at well C it varied from 426 to 720 psig. At the injector well

A, bottom hole pressure changed from 1800 psig at the

beginning to a shut in pressure of 3601 psig at the end of the

test. Table 6 shows the cumulative volumes of water injected

at breakthrough of the displacement front in the offset wells,

as well as calculated swept areas, and reservoir mean

properties at the pilot area. Figure 11 shows calculated

water/oil displacement fronts at breakthrough in the offset

wells. Since the pilot area was a non-confined, incomplete

inverted 7 spot pattern, a portion of injected water migrated

outside of the pilot area. It is estimated that at the time of

water breakthrough in well B, about 1.5 % of injected water

migrated outside the pilot area, afterwards increasing with

time, until it reached an estimated 53 % of total volume of

injected water by the time of water breakthrough at well E.

It should be mentioned that from the results obtained

from the short-term pilot water injection test, preliminary

indications seem to indicate that some of the offset producers

were just beginning to show increase in reservoir pressure and

oil production at the time water injection was stopped.

Therefore, it is concluded that numerous Chicontepecreservoir sandstones should benefit from a several pattern,

long-term water injection program.

Conclusions

Based upon the information provided in this paper, the

following conclusions can be established.

Reservoirs of the Chicontepec are vertically and

laterally heterogenous and are naturally fractured.

Integrated characterization of this complex submarine

fan system facilitated the identification of optimum

locations for a pilot waterflood test.

As a result of the characterization program, the pilot

test was located in high quality reservoir facieswherein the impact of the pervasive heterogeneity

was minimized.

The feasibility of conducting water injection projects

in the Chicontepec system has been established,

provided that a careful selection process is

undertaken, following the guidelines provided in this

paper.

A separated water mixture from several fields can be

used as source water for injection at this field,

provided a proper chemical treatment is design to

avoid clay swelling and incompatibility problems

with formation connate water.

Tracer breakthrough at all four offset wells indicates

no significant channeling occurred during the pilot

test. After breakthrough, HTO production was

continuous from the four offset observation wells,

indicating uniform movement of the injected water

through the producing formation. Tracer mass balance calculations suggests that the

observed tracer response represents fluid movement

through only a limited reservoir volume

Tracer response at offset wells suggests the existence

of higher effective reservoir permeability in a

northern direction, up the channel, from the injector.

It was observed that sand continuity and reservoir

rock quality for the pilot area are good in a northern

direction from the injector, decreasing in east and

southeast directions, which as mentioned before

agrees with the results obtained from the observed

tracer response.

Length of the pilot waterflood test was too short,since preliminary indications seem to indicate that

some of the offset producers were just beginning to

show increase in reservoir pressure and oil

production at the time water injection was stopped.

On the other hand, tracers were still arriving at three

of the four offset producing wells at the end of the

sample collection period.

From the results obtained from the pilot test, it is

believed that numerous reservoir sandstones should

benefit from the long-term water injection program.

Acknowledgements

The authors would like to thank the authorities of PemexExploration and Production for permission to publish the data

presented in this paper. Special recognition goes to the Pemex

engineering and geologic teams working on the Chicontepec

Project for their collaboration.

References

1. Busch, D.A. and Govela, A., 1978, Stratigraphy and structureof Chicontepec turbidites, southeastern Tampico-MisantlaBasin, Mexico;American Association of Petroleum Geologists

Bulletin, v.62, No. 2, 235-246.2. Japan National Oil Corporation (JNOC), Technology Research

Center and PEMEX Exploracin y Produccin, 2001,Geostatistical Modeling of Chicontepec Reservoir: Agua Fria,

Coapechaca and Tajin Areas, unpublished report.3. Davies and Associates, 1996, Formation damage study, AGUA

FRIA NO. 801, AGUA FRIA NO. 836 and ANTARES NO. 1wells, Agua Fria Field, Chicontepec Basin, Mexico,

unpublished report.4. Informe Final de la Prueba Piloto del Campo Agua Fra

Internal Report, PEMEX Exploracin Produccin, ReginNorte, Proyecto Chicontepec, (2000)

5. Rodriguez D., M.: Prueba Piloto y Perspectivas de Inyeccin deAgua Congenita en el Campo Agua Fria,Ingenieria PetroleraVol. XLI No. 10, (Oct., 2001).

6. Interwell Tracer Program Initial Summary Report Agua FriaField, Prueba Waterflood Pilot Area, ProTechnics, March

2000.


5/12

SPE 92077 5

7. Skilbrei, O. B., Hallenbeck, J. E., y Sylte, J. E.: Comparisonand Analysis of Radioactive Tracer Injection Response withChemical Water Analysis into the Ekofisk Formation Pilot

Waterflood, Paper SPE 20776, presented at the 65thConferencia Tcnica y Exhibicin Annual de la SPE, NewOrleans, LA, (Sept, 1990).

9. Caracterizacin Esttica-Dinmica, Ingeniera de PozosYacimientos, y Simulacin Numrica de Campos deChicontepec, COMESA/PEP Internal Report (2002).

10. Actualizacin del Modelo Geolgico e Ingeniera deYacimientos, Campo Soledad-Soledad Norte, COMESA/PEPInternal Report (2003).

8. Rivera, R., J.: Mojabilidad de las rocas de Tajin y Agua Fria,

Internal Report, Chicontepec Project, Pemex, Exploracion

Produccion, (Nov., 2003).

11. Monitoreo Microsismico de Fracturas Hidrulicas en el Campo

Chicontepec, Createch/PEP Internal Report (2003).

Figure 1. Stratigraphic architecture in a field of the south-central Chicontepec reservoir fan system, showing the interaction

between tectonism and sedimentation.

Figure 2. Relation between facies attributes and reservoir quality, Chicontepec reservoir fan system.


6/12

6 SPE 92077

Figure 3. Partially calcite-cemented (A) and oil stained (B) natural fractures are common in cored Chicontepec sandstones.

Figure 4. Chicontepec sandstones displaying a complex network of systematic and non-system natural fractures in outcrop

(courtesy of Francisco Espinosa, Pemex E&P) and subsurface core orientations, as determined from microseismic

tests 10(inset).

Figure 5. Distribution of production and injection wells within the pilot area.


7/12

SPE 92077 7

31.2

31.4

31.6

31.8

32

32.2

32.4

32.6

32.8

0 0.1 0.2 0.3 0.4 0.5 0.6Penetration rate of fracture

Oilrecovery(%)

Fd=50

Fd=35

Fd=25

Fd=15

Fd=5

Figure 6. Monthly oil, water and gas production.

Figure 7. Observed pressure response at observation wells B and C from shut-in of injector well A


8/12

8 SPE 92077

Figure 8. Concentration profiles of chemical tracers captured at observation well B 4,6.

Figure 9. Concentration profiles of chemical tracers captured at observation well C4,6.


9/12

SPE 92077 9

Figure 10. Concentration profiles of the tritiated water tracer captured at the four offset wells 4,6.


10/12

10 SPE 92077

B reakthrough B and C wells

W ells

breakthrough well D

B reakthrough well E

R eservoir lim it

Well C

Well B

Well A

Well F Well D

Well E

Breakthrough wells Band C

Figure 11. Calculated swept areas at breakthrough at the offset wells.


11/12

SPE 92077 11

Observation

well

Distance from

injector, ft (m)

Calculated area,

acres

B 1,175 (360) 12.3C 1,250 (381) 12.5

D 1,483 (452) 13.2

E 1,840 (561) 13.6

Table 1. Distances and calculated areas between injector and offset wells at the pilot.

Observation

well

Tracers

detected

Breakthrough

time, days

B

FBA1

FBA2

FBA3

162

139

117

C FBA2

FBA3

139

117

D None ----

E None ----

Table 2. Chemical tracers breakthrough time at the producer wells 5 .

Observation

well

Breakthrough

time,days

Distance from

injector, ft (m)

B 77 1,175 (360)

C 77 1,250 (381)

D 144 1,483 (452)

E 238 1,840 (561)

Table 3. HTO radioactive tracer breakthrough times at the four offset wells 5 .


12/12

12 SPE 92077

Tracer

Time elapsed

since beginning

of tracer

injection, days

Breakthrough

Time, days

Time of arrival of

tracer peak

concentration,

days

Tracer peak

concentration,

(FBA) ppb

(HTO) pCi/ml

Length of

tracer pulse,

days

FBA1 0 162 167 7 7

FBA2 16 139 144 20 14

FBA3 38 117 126 30 14

Tritiated

Water

(HTO)

74 77

2 peaks

84 and 168 25 203*

* Incomplete tracer profile. Sampling was ended before reaching cero tracer concentration in samples.

Table 4. Main characteristics of tracers captured by observation well B. Distance to injector: 1079 ft (329 m).

* ND=Tracer was not detected

Apparent superficial velocities for chemical (FBA), and radioactive

(HTO) tracers, m/d

Observation

wells

FBA1 FBA2 FBA3 HTO

B 2.06 2.40 2.83 4.27

C ND* 2.33 2.78 4.16

D ND* ND* ND* 2.24

E ND* ND* ND* 1.52

Table 5. Calculated apparent superficial velocities based upon breakthrough times and distance to injector from the

four offset wells, for radioactive (HTO) and chemical (FBA) tracers.

Offset

well

Average

Thickness,

m

k, (md) kh,

(md-m)

Cumulative water

injected at

breakthrough, STB

Calculated swept

area at

breakthrough, m2

B 137.8 1.2 50.4 298,207 35,472

C 157.4 1.4 67.2 309,047 36,401

D 131.2 3.5 140.0 596,338 39,373

E 116.4 3.2 113.6 389,447 38,180

Table 6. Cumulative water injected at breakthrough and calculated swept area of the displacement front at offset

well, and reservoir mean properties at the pilot area 5.

spe chicontepec

Documents