tyler spe92077 international symposium

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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 ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, 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 heterogeneoussubmarine fan reservoirs of the Chicontepec fan system

optimum location for a waterflood pilot was identified andtested. 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. Primaryproduction has been established in several fields in thenorthern 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 andlaterally 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 naturallyfractured. Establishing the architecture of the reservoir is acritical element of waterflood design. Sediment architecture,

which includes sand distribution and facies composition,

controls the spatial distribution of reservoir properties andhence the distribution of original oil and place; how theinjected fluids will move in 4-D (3-D space and time) through

the reservoir; and ultimately, how the reservoir drains. Thus

definition of reservoir architecture is the critical first step in

the waterflood deployment. Having established thearchitecture 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 thesetechnical 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 afield located at the south central part of the Chicontepec

system were deposited under complex tectono-stratigraphic

conditions. Early deposition was widespread across the basinand 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 changingdepositional 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, lobesandstones that grade into distal fan and basin floor deposits.

Between-well-scale facies variability resulting from typical

submarine fan depositional processes coupled with tectonic

instability produced a highly heterogeneous reservoir system

in this field. However, net sand and facies architectural

mapping provide predictability in sand distribution and thispredictability has allowed us to select the prime locations for

SPE92077

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


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implementation of a waterflood pilot. Net sand and faciesmaps indicate favorable sand content and facies at several

levels at this platform.

Petrographic analyses indicate the Chicontepec sands

are lithologically immature litharenites consisting of quartzgrains, abundant carbonate fragments, and granitic fragments.

Because of the abundance of carbonate in the system, thesediments are highly cemented by ferroan calcite and ferroan

dolomite, in addition to quartz overgrowths. The abundance

of cements is the primary control on reservoir quality ascementation decreases porosity increases 2. Interestingly, the

sands are clean or clay deficient sands with only 1 percentclay. 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 ofpermeability 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 isclear the injected water will require treatment and the additionof 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 withinthis 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 2shows 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 ofporosity and permeability are substantially higher in the

proximal facies.

To identify areas of superior reservoir quality and toavoid the effects of poor reservoir quality we constructed

maps of average porosity and permeability calculated from

well logs for the key potential waterflood reservoirs. Thesemaps 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 cementedwith calcite (Figure 3a) or are oil stained (Figure 3b). Outcrop

exposures of the Chicontepec bedding planes display a

network of intersecting systematic and non-systematic

fractures (Figure 4a). The principal or systematic fractures arefairly 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 selectedgeologically optimum locations for injection wells in each of

the major reservoirs to be considered for waterflooddeployment. 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 welltests.

Water injection Pilot Test

In order to test the feasibility of conducting water injection

projects in complex reservoirs such as those located in theChicontepec 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 injectionarea 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 that

will be denoted as S1 and S2. The pilot was located in achannel complex in one of the reservoirs and in submarine fanlobe facies of the second reservoir. Total sand thickness was

between 128 to 253 ft, while depth to the top of shallower

sand body was between 4675 to 5022 ft. Figure 5 shows a

sketch of well distribution within the pilot4. 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 (225kg/cm2) and a formation volume factor of 1.1621 bbl/STB.

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

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

them were under gas-lift. Field oil production at this time was2,400 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 wereinjected at well A during this test, ranging from 240 to 4000

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

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 periodsin order to estimate any possible formation permeability


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[SPE92077] 3

change due to the water injected. An interference test betweenthe 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 beginning

of injection. Three chemical tracers and one radioactive tracer

were injected during the test. The injected chemical tracerswere fluorinated benzoic acid tracers (FBA) with low

detection limits (down to 50 ppt). Chemical tracers wereinjected 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 S2formations. 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 thepresence 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 andpotential 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 theoffset 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 coreanalyses 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 isshown in Table 2 and Figures 8 and 9.

A beta emitter- low energy level radioactive, water

phase 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 (notrelated 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 rangesfrom 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 channeling

occurred during the pilot test. After breakthrough, HTOproduction 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 completetracer 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. Tracermass balance calculations suggests that the observed tracer

response represents fluid movement through only a limitedreservoir volume, which could correspond to a one or a few

thin high permeability layer(s) in the reservoir4,6.

Arrival times of the HTO tracer to the four offsetwells (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 thetime it takes the tracer front to arrive at a given observation

well (called apparent superficial velocity, vsapp). As shownin Table 5, it appears to be a higher effective reservoir

permeability in a northern direction from the injector, since

vsapp calculated values are higher in this direction (4.16 and4.27 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 offsetwells 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 pilotarea. It should be mentioned that results obtained from tracertesting, 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 sanddistributions 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 of

channel/lobe systems. For the pilot area, it was observed thatsand 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 withthe 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 tracer

concentration at observation well B are not the same fordifferent tracers. It is observed that breakthrough of tracers at

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

reported for tracer tests conducted at Ekofisk7.

Since the main variables that have changed at reservoir

conditions at times when the different tracers were flowingthrough 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 throatdistributions), and wide variations in petrophysical properties

between adjacent layers, among other possible factors, have

produced the apparent effect of decreasing breakthrough timesas tracers were injected at times when cumulative water

injected volumes were higher. This hypothesis requiresconfirmation through laboratory experiments, using rock and

fluids samples from the reservoir, conducted at reservoir


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[SPE92077] 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 PilotWaterflood, Paper SPE 20776, presented at the 65th

Conferencia Tcnica y Exhibicin Annual de la SPE, NewOrleans, LA, (Sept, 1990).

8. Rivera, R., J.: Mojabilidad de las rocas de Tajin y Agua Fria,Internal Report, Chicontepec Project, Pemex, ExploracionProduccion, (Nov., 2003).

9. Caracterizacin Esttica-Dinmica, Ingeniera de Pozos-

Yacimientos, y Simulacin Numrica de Campos deChicontepec, COMESA/PEP Internal Report (2002).

10. Actualizacin del Modelo Geolgico e Ingeniera deYacimientos, Campo Soledad-Soledad Norte, COMESA/PEP

Internal Report (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 interactionbetween tectonism and sedimentation.

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


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[SPE92077] 7

OIL, GAS AND WATER PRODUCTION

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

30/06/1986 30/06/1991 30/06/1996 30/06/2001

OILANDWATERPRODUCTION(STB).

0

50

100

150

200

250

300

350

400

GASPRODUCTION(MMSCF).

Oil

Water

Gas

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


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


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


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

Breakthrough B and C wells

Wells

breakthrough well D

Breakthrough well E

Reservoir limit

Well C

Well B

Well A

Well F Well D

Well E

Breakthrough wells Band C


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Observation

well

Distance from

injector, ft (m)

Calculated area,

acres

B 1,175 (360) 12.3

C 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 FBA2FBA3

139117

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 .


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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

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.

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.

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

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

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