1

Breaking Paradigms in old Fields. Finding “the reservoir key” for

Mature Fields Redevelopment, Part I: Reviewing infill projects in

complex reservoirs

Juan Diego Suarez Fromm

Jun 29th 2016

KW: Infill, Managed Pressure Drilling, HPHT gas, Chicontepec

“Progress is impossible without change, and those who cannot change their

minds cannot change anything”. George Bernard Shaw

Z140-85 Z140-85

Z70-45 Z70-45

400 m Seven spot patern 1000 m x 400 m Horizontal pattern

400 m 1000 m

800 m

Tight oil caseField development strategy with 7 spot and horizontal paterns

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1. Introduction

The Oil and Gas industry has probably endured a permanent change: oil prices might

never recover to 2010-2014 boom prices [1,2].

From the Oil and Gas Operators’ point of view, reengineering processes, layoffs,

projects delays, contract negotiations with service providers and operating cost

reductions has been put in action and will likely continue in the near future [3].

During this year, the focus has changed from Exploration / Development to that of cost

& production optimization and the upcoming years will probably require greater efforts

in Mature Fields redevelopment.

A well-known technique is that of infill optimization [4,5] - a field development strategy

that can be defined as “well spacing reduction in order to accelerate and increase

petroleum recovery factor through optimal cost effective and wellbore placement in a

reservoir”.

Some advantages for infill strategy are as follows:

Minimum petroleum system uncertainty. The Petroleum accumulation is proved,

petrophysical / geo-mechanical rock properties, reservoir fluids, downhole

pressures, and base productivity are usually known within a limited range. So

we should be working with 2P reserves development.

Minimum operational risk for specific wellbore designs and some completions

standards used in the field.

On the other hand, some disadvantages include:

Paradigms on field development to be changed;

Field history data availability;

In general, greater subsurface team effort is needed for integration and

evaluation of reservoir models, compared to Appraisal / Initial Field

Development.

Upsides could be overlooked due to paradigms on field development. The

successful one in terms of reserves and cost effective capital expenditure

could be visualized as “finding the key for the field”. But as development

takes place over many years (decades), the “key” should be a dynamic

concept over time, correlated with technology availability, enabling us a

better understanding of petroleum resources size, quality and distribution.

Two field examples will be presented, where after 50 years of development; fresh oil

and gas were produced by changing some reservoir paradigms.

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2. Gas & Condensate case

First case is about Mature Gas & Condensate Field in North Argentina. It belongs to

Tarija basin, a Palaeozoic deep thrust belt deposits from Carboniferous geological age [6,7,8].

The reservoir has 3 stratigraphic units, gross thickness is about 400 meters of altering

tight sandstones and shales, in multi faulted anticline structure.

Exploration and appraisal phase started in late 50’s, where main development took

place in 60’s decade with about 60 wells drilled, 70% gas reserves were delimited and

80% were put onto production, achieving 5 years plateau of 180 MMpc/d gas and 7500

bpd condensate. During 70's decade, field production declined as a mature field.

Finally a reinjection gas project was implemented from early 80’s over 20 years due to

low commercial gas value in the region, shutting field production. Meanwhile, field

operator changed in 90’s and started to produce condensate wells, keeping dry gas

injection.

During this time, operators applied good practices reservoir management by

monitoring downhole static and flowing pressures in open and closed wells, producers

and injectors during almost 50 years of history.

After detailed structural settings reinterpretation (integration of surface geology,

seismic markers, well logs and section restoration analysis), the redevelopment started

in late 90’s with the successful appraisal well placement in a new deeper block,

allowing the operator to booked new gas, condensate and oil reserves.

Over 1990 decade, only 5 wells were drilled and put onto production with relative

success due to formation impairment associated with partially depleted regions,

resulting in halting the drilling campaign in 2005.

In the subsequent years, the lack off a consistent productivity / reserves model, turned

out to inconclusive postmortem, increasing technical risk and therefore lowering

economical attractiveness for new wells. So, field started again to decline production,

undergoing for second time the mature stage.

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Two concepts remained as key factors for the project continuation:

Formation damage due to reservoir compaction and depletion, increasing potential

of pore throat blocking, leading to new drilling process requirements (reservoir

stimulation was not possible due to high fracture pressure about 12.000 psi

combined with low reservoir pressure).

Material balance upside due to massive bottom hole static pressure recovery in dry

gas producers and closed wells; and relative low final recovery factor forecast.

Resulting in 20/30% increase in material balance OGIP and 2P reserves.

Two years of reservoir engineering data integration leaded to infill, sidetracks and

replacement wells proposals. Among several technologies, the “Managed Pressure

Drilling” (MPD) was selected for production stage drilling, in combination with slotted

liner completion instead of standard cemented casing perforations.

Inter spacing was reduced from 800 m to 400 m, in the crest of anticline central block,

where 80% of effective gas cumulative production had been released (net from gas re

injection). Also side tracks were proposed in recently damaged wells due to issues with

casing integrity.

In 2010 first side track well was drilled, reaching very good gas and condensate

productivity. Initial rates were achieved 40 years later with 30/50% of initial reservoir

pressure, reinforcing the hypothesis of formation damage sensibility and the

importance of the mud weight management in these kinds of reservoirs.

Up to date 4 new wells from original campaign were drilled, completed and put onto

production with good results. One possibility for near future is the extension to flanks

where tight rock, lower productivity and lower recovery factor take place.

5

Chart 1. Gas & Condensate Case: Tarija Basin location and geological column.

Chart 2. Gas & Condensate Case: Wells, 2D seismic cross section and 3D structural

model.

6

Chart 3. Gas & Condensate Case: Field production & gas re injection history.

Chart 4. Gas & Condensate Case: Ultimate Recovery Factor areal distribution, and

bottom hole reservoir pressure history.

1953 55 57 59 61 63 65 67 69 71 73 75 77 79 81 83 85 87 89 91 93 95 97 99 01 03 05 07 09

101

102

103

104

105

Date

AREA: CD RESERVORIO: TUP(62)

Gas Rate (Cal. Day) ( Kscm/d )

Oil Rate (Cal. Day) ( m3/d )

Water Rate (Cal. Day) ( m3/d )

Ginj.Cum ( Mscm )

Cumulative Gas Production ( Mscm )

Ginj.CalDay ( Kscm/d )

Gas

Condensate

Water

Gas re injection

Main development First Natural decline Gas re injection – condensate prd

Gas & Condensate case

Field gas, condensate and water production & gas re injection history

North

58 – 69 %

R.F. Upside: ≈10%

Central

62 – 69 %

South

57 – 67 %

Yacimiento Campo Durán - Fm Tupambi

Evolución Pws POZOS SELECCIONADOS (PR 3000 TVDSS)

0

50

100

150

200

250

300

350

400

1/50 12/53 10/57 9/61 8/65 7/69 6/73 5/77 4/81 3/85 2/89 1/93 12/96 11/00 10/04 9/08

Fecha

Pw

s

[kg

/cm

2]

0

4000

8000

12000

16000

20000

24000

28000

32000

Ge

f: G

p -

Gin

y

[MM

m3

]

Pws YPF

Pws reiny de gas

Pws Tecpetrol

G efectiva [MMm3]

año 2007: Se produjo todo el gas reinyectadoReinyección de gas 1982 - 2000

año 2009: Extraídos 1000 MMm3 desde el

inicio de la reinyección de gas

1950/77: gas production 1978/2008: gas reinjection/prod

2008: balance

R.F. @ Economic Limit Bottom hole static pressure history

OGIP Upside: ≈25%

Gas & Cond case

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Chart 5. Gas & Condensate Case: Structural model for well placement in faulted and

folded reservoir.

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Chart 6. Gas & Condensate Case: Example of reservoir redevelopment:

Replacement well response after 40 years from initial original well production, and

Sidetrack well response after 15 years from initial replacement well production. Initial

productivity of 11 MMpc/d is achieved in spite of reservoir depletion due to successful

mud pressure management during the drilling stage.

Yac. Campo Durán - Fm. TupambiPerforación 'Near Balance' en Campo Durán. Proyecto ST CDxp-1001

0

100

200

300

400

500

600

700

1-57 12-60 12-64 12-68 12-72 12-76 12-80 12-84 12-88 12-92 12-96 12-00 12-04 12-08 12-12 12-16 12-20 12-24

Qg

[M

m3

/d]

Qo

[m

3/d

] N

p [

Mm

3]

0

500

1000

1500

2000

2500

3000

3500

Gp

[M

Mm

3]

CD-15 Bloque II

(YPF)

ST CDxp-1001

(cuña perforada - pz original)

Julio 2008 CDxp-1001 (merma)

Rotura somera en el casing de producción 9 5/8” (aprox. 500 m) pincha tubing y descarga fluído E/C

csg 13 3/8”-9 5/8” con lodo inverso 1900 g/l – baritina (etapa de perforación de Los Monos)

CDxp-1001 Bloque II & III

(Tecpetrol)

Febrero 2008 CDxp-1001 (recup. Prd)

Limpieza con CTU CaCO3 - pozo vivo HCl 15%+N2

Replacement well after 40 years. Sidetrack after 15 years

First well

(1957)

Reservoir impairment (cement bond break)

Replacement well

(1997)

Live well perforations clean up

HCl jetting with CTU (2007)

Sidetrack well

(2012)

Peak 11 MMpc/d

Gas: M

illio

ns c

ubic

mete

r g

as /d, C

on

d:

cubic

mete

rs /d

Co

nd

Cu

m: 1000 c

ubic

mete

rs

Gas C

um

: M

illio

ns c

ubic

mete

r g

as

Gas & Condensate case

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3. Tight Oil case

Second case is a tight oil field located in North Veracruz, Mexico. “Chicontepec Medio”

is a Tertiary reservoir from Tampico-Misantla basin, an important onshore play, and

well known by its low recovery factor and marginal cash flow [9].

The reservoir is very complex from structural, stratigraphic and diagenetic point of

view. Extensive and compressive faults systems coexist due to tectonic activity during

deposition of sediments. Characterized by 300 m gross thickness of shallow turbidites,

alternating sandstones and shales, where petro physical properties have been affected

by pore cementing and other diagenesis processes [10].

Leading to high vertical and horizontal heterogeneity, the scale of reservoir variations

runs from metres to centimetres.

Some rock quality predictive methods as seismic inversion have been applied with

some success. But appraisal wells are still needed in some regions many decades later

from discovery in order to delimit the reservoirs.

Seven spot pattern with 400 m well spacing has been the field development strategy

for 50 years, showing a great variation on productivity in the same reservoir unit

between adjacent wells, even with good reservoir continuity, according to seismic and

wells correlation. Due to low permeability, hydraulic fractures are needed, leading to

relative low initial productivity and reserves.

These factors motivated the evaluation of multi fractured horizontal wells, following the

concept of shale gas development strategy.

Challenges for horizontal wells compared to vertical wells:

Shallow reservoirs (low cost for vertical wells).

Reserves distributed in 200 m of layered reservoir (one fractured horizontal well

cannot reach and drain the entire column).

Lateral heterogeneity for horizontal wellbore placement.

Geo mechanical issues in some shale zones. Lack of experience in horizontal

drilling and multifrac completion.

In order to mitigate technical risks, the first horizontal well was planned in the central

part of the field, where higher production and recovery factor has been achieved after

50 years of exploitation. A detailed reservoir characterization and production

performance assessment was achieved due to existing wells.

With this scenario, reservoir pressure was the main risk; keeping in mind that reservoir

target was one of the champion units from the field, leading to potential depletion

issues during drilling, completion, stimulation, and production performance for

horizontal wells.

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Large amount of data were available but not yet integrated.

An extensive review and reinterpretation took place:

Material balance and decline analysis review.

Update of static model.

Dynamic model construction. History matching for main productive block.

Geo mechanical model was built from compression test in plugs, Young

Modulus, Poisson Modulus, Brightness calculations from logs, fracture gradients

from pre pad test and micro seismic mapping results from previous vertical

wells, seismic inversion correlation with logs (gamma ray, sonic and density).

Main outputs were:

More confidence on final recovery factor for vertical fractured wells and for

projected horizontal multi fractured new wells.

Principal horizontal stress directions and minimum horizontal stress gradients

distributions. Current reservoir pressure distribution.

Greater fracture vertical growing was reinterpreted from old fractured vertical

wells, due to brittleness of rock.

With the above considerations a new static, dynamic, and geo mechanical reservoir

model was built, allowing the ranking of new locations with lower geological risk for

horizontal wellbore placement, along the Minimum Horizontal Stress direction. A robust

fracture design was matched with micro seismic fracture geometry. Also mud weight

window was optimized, allowing better casing depths.

Sensibility scenarios were run with different horizontal length and number of fractures,

finding that 1000 m horizontal length, 400 m spacing between horizontals, and 150 m

fracture spacing are optimal from technical, economical and risk points of view.

The first horizontal drilled well showed excellent results. The second and third

horizontal well were drilled in undeveloped regions, obtaining similar results [11,12,13].

The main conclusions were:

Field development:

Initial productivity x 10 times vertical frac well.

Projected ultimate recovery x 8 times vertical frac well.

Projected final oil Recovery Factor increased from 5% to 7%.

Total well cost reduction: 5% respect to seven spot pattern.

Operative Expenditure Costs reduction (including minor workover): 30%

respect to seven spot pattern.

In addition, first horizontal well showed that significant undeveloped reserves

can be produced in drilled zones, in spite of lower reservoir pressure.

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Fracture geometry:

Micro seismic mapping allowed fracture geometry understanding for lower frac

spacing, where a complex micro fissures net is also created among principal

fractures geometries.

Chart 6. Tight oil Case: Geographical location of Chicontepec basin and general

geological column.

Tight oil case

SIERRA

MADRE

ORIENTAL

PLATAFORMA

DE TUXPAN

CAMPO COYOTESField

“Paleocañon de Chicontepec” location General geological column

Ju

rassic

Cre

tace

ou

sTe

rtia

ry

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Chart 7. Tight oil Case: Horizontal wells locations, structural configuration, and

reserves categories distribution. First horizontal well was drilled in P1 main block

affected by partial depletion. Second and third horizontal wells were drilled in SW and

N regions.

Unit Z140 – Faults & Depth contour lines

P3

P2

P1

P2

P2

P3

P3

P3

P2

P1

P3

P1 Block Main developed

region with 7 spot pattern

(depleted)

(1)

(2)

P3

(3)

(4)

(5)

T

J-K

P1/P2 Blocks Variable

vertical well results

P1: Proved reserves

P2: Probable reserves

P3: Possible reserves

First Horizontal

Second Horizontal

Third horizontal

P3 Block High productivity &

connate water risk (multiple OWC)

Tight oil caseHorizontal wells locations, structural configuration

and reserves categories distribution

Deeper zone: lower rock quality

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Chart 8. Tight oil Case: Knowledge evolution over field development for fracture

geometry. Interpretation in old vertical fractured wells showed greater fracture length

compared to microseismic results in fractures from vertical and horizontal wells

(conventional fracs).

Chart 9. Tight oil Case: Field development strategy with 7 spot and horizontal

patterns. Shaded areas are equivalent.

Tight oil caseKnowledge evolution over time (fracture geometry)

Former frac design

1990-2000 Hf/Xf: 0.7Micro seismic 2008:

Vertical Wells Hf/Xf: 1.0Micro seismic 2011.

First Multifrac Horiz

Hf/Xf: 1.6

Micro seismic 2012.

Second Multifrac Horiz

Hf/Xf: 0.90

6000 sks

(60 BPM,

conventional)

6000 sks

(60 BPM,

volumetric)

Z140-85 Z140-85

Z70-45 Z70-45

400 m Seven spot patern 1000 m x 400 m Horizontal pattern

400 m 1000 m

800 m

Tight oil caseField development strategy with 7 spot and horizontal paterns

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Chart 10. Tight oil Case: Reservoir characterization for wellbore placement.

4. Final comments

Two field cases were presented, both from 1960’s, where operators changed

subsurface paradigms, allowing them to increase recovery factor in drilled and

exploited regions.

This can be characterized as finding the “key for the reservoir”, where efficient and

intelligent technology usage plays a central role.

Nevertheless, the real paradigm is inside the professional´s mind, the aversion to

change from the “obvious path or follow the historical trend”.

So, the final challenge relies on management - at the end of the day it will not only

allow new ideas development, but it will also push them to flourish and grow.

5. Acknowledgments

Special thanks to Diego Lenge for his useful comments on this paper.

Tight oil caseReservoir characterization for wellbore placement

Lateral heterogeneity in horizontal wellSeismic cross section. Pseudo Gamma Ray

from Inversion & wellbore trajectory

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6. References

1. Macrotrends.net, 2016. Crude Oil Price History Chart.

2. Worldoil.com, 2015 .Petrobras sees “great wave” of 100 $ oil never coming

back.

3. Worldoil.com, 2015. Iraq asks oil companies to cut spending after drop in

prices.

4. Total E&P, 2006. Mature Fields. Inventing the future.

5. Norwegian University of Science and Technology / Statoil E&P, 2012. Improved

Oil Recovery with Infill drilling.

6. D. Starck, L. Constantini, A. Schultz., 2002. Sub Andean Thrust belt

Geometrical and evaluative analysis for North Argentina and South Bolivia.

7. D. Starck, A. Schultz, M. Cohen, 2002. Carboniferous and Tertiary traps from Sub

Andean North West Basin.

8. Different authors, Argentinian Institute of Gas and Oil (IAPG), 2002. Reservoir rocks

from Argentina.

9. National Commission of Hydrocarbons (CNH), National Secretary of Energy

(SENER), Mexico, 2010. Aceite Terciario del Golfo. First Revision and

Recommendations.

10. Daniel A. Busch, Amado Govela, 1978. The American Association of Petroleum

Geologists Bulletin. Stratigraphy and Structure of Chicontepec Turbidites,

Southeastern, Tampico-Misantla Basin, Mexico.

11. Juan Diego Suarez Fromm, 2011, 2012. Primeras Jornadas Tecnológicas -

Laboratorio de Campo Coyotes. Segundas Jornadas Tecnológicas - Laboratorio de

Campo Coyotes. AIATG. Design and development of Multi fracture horizontal

well in Tight Oil reservoir – Chicontepec.

12. Juan Diego Suarez Fromm, 2012. Mexican Oil Institute – AI ATG. New

technologies application for Coyotes Field – Chicontepec.

13. Juan Diego Suarez Fromm, Juan Martin Migliavacca, Neptalí Requena. Mexican Oil

Institute. First Non Conventional Completion in Chicontepec using Multi

fracture horizontal Wells.