Recovering Historical Decline Rates and Maximizing Production in a

Transcripción

Recovering Historical Decline Rates and Maximizing Production in a Mature Field*
Julián José Blanco1, Valeria Riveros1, Juan Tagliorette1, Flavio Donadio1, and Horacio Albarracín1
Search and Discovery Article #20312 (2015)**
Posted June 30, 2015
*Adapted from oral presentation given at AAPG Latin America Region, Geoscience Technology Workshop, Extending Mature Fields’ Life Cycles: The
Role of New Technologies and Integrated Strategies, Buenos Aires, Argentina, May 11-12, 2015
**Datapages © 2015 Serial rights given by author. For all other rights contact author directly.
1
YPF S.A., Argentina ([email protected])
Abstract
A restoration plan has been applied in the Señal Picada Field since 2012 to recover the historical decline rate, which had
deteriorated and doubled in the period 2007-2012. This situation led to P1 reserves loss in the same period. The field was
discovered in 1963 and had several drilling campaigns, mainly between 1960’s and 1980’s. In the 1970’s water injection for IOR
was implemented. Currently he field has 270 producers and 110 injector wells.
This restoration plan involves drilling replacement and infill wells, and also includes work-over and maintenance activities for
existing wells. An integrated subsurface model was proposed as the primary decision tool. A full field static model was finished
in 2012. In 2012-2014 we used data from the static model to propose new wells, either replacement or infill. We used and
compared a set of static and dynamic data as a method to maximize production:
• OOIP, RF, injected pore volume per layer and pattern, acreage.
• Last production rate and date in original wells (criteria for replacement wells).
• DCA analysis per pattern.
• Well integrity analysis, used to select work-overs (both injectors and producers)
This method has proved to be successful, considering that the project was profitable and decline rate recovered to near historical
values at the end of 2013. Major surface modifications were also needed to achieve this goal. In 2014 the method showed
marginal results and the need for a full field dynamic model was clear if we wanted to maximize production and profit. This was
created using dynamic software to evaluate current recovery factors and to assess new wells to be drilled in the field
(replacement or infill). We had to validate fluid production and injection for more than 400 wells (with 3 or more active layers)
and nearly 50 years of field history.
Current investment proposal in the field is supported by this tool, adding to the previous criteria the following:
• Current and final oil saturation, RF, and injected pore volume per pattern and layer. Identifies poorly
drained zones.
• Scenario analysis (e.g. do nothing vs. drill) with production curves supported by a model (not only by
DCA method)
Now we are drilling new wells and initial results are as forecasted by the model. We continue to gather new data from wells (e.g.
logs not acquired before, such as NMR or RFT) to improve the static and dynamical models.
EXTENDING MATURE FIELDS’ LIFE CYCLES: THE ROLE OF
NEW TECHNOLOGIES & INTEGRATED STRATEGIES
11-12 May 2015 | Buenos Aires, Argentina
Nota Legal
Declaración bajo la protección otorgada por la Ley de Reforma de Litigios Privados de 1995 de los Estados Unidos de América (“Private Securities Litigation Reform Act
of 1995”).
Este documento contiene ciertas afirmaciones que YPF considera constituyen estimaciones sobre las perspectivas de la compañía (“forward-looking statements”) tal como se
definen en la Ley de Reforma de Litigios Privados de 1995 (“Private Securities Litigation Reform Act of 1995”).
Dichas afirmaciones pueden incluir declaraciones sobre las intenciones, creencias, planes, expectativas reinantes u objetivos a la fecha de hoy por parte de YPF y su gerencia,
incluyendo estimaciones con respecto a tendencias que afecten la futura situación financiera de YPF, ratios financieros, operativos, de reemplazo de reservas y otros, sus
resultados operativos, estrategia de negocio, concentración geográfica y de negocio, volumen de producción, comercialización y reservas, así como con respecto a gastos
futuros de capital, inversiones planificados por YPF y expansión y de otros proyectos, actividades exploratorias, intereses de los socios, desinversiones, ahorros de costos y
políticas de pago de dividendos. Estas declaraciones pueden incluir supuestos sobre futuras condiciones económicas y otras, el precio del petróleo y sus derivados, márgenes
de refino y marketing y tasas de cambio. Estas declaraciones no constituyen garantías de qué resultados futuros, precios, márgenes, tasas de cambio u otros eventos se
concretarán y las mismas están sujetas a riesgos importantes, incertidumbres, cambios en circunstancias y otros factores que pueden estar fuera del control de YPF o que
pueden ser difíciles de predecir.
En el futuro, la situación financiera, ratios financieros, operativos, de reemplazo de reservas y otros, resultados operativos, estrategia de negocio, concentración geográfica y de
negocio, volúmenes de producción y comercialización, reservas, gastos de capital e inversiones de YPF y expansión y otros proyectos, actividades exploratorias, intereses de los
socios, desinversiones, ahorros de costos y políticas de pago de dividendos, así como futuras condiciones económicas y otras como el precio del petróleo y sus derivados,
márgenes de refino y marketing y tasas de cambio podrían variar sustancialmente en comparación a aquellas contenidas expresa o implícitamente en dichas estimaciones.
Factores importantes que pudieran causar esas diferencias incluyen pero no se limitan a fluctuaciones en el precio del petróleo y sus derivados, niveles de oferta y demanda,
tasa de cambio de divisas, resultados de exploración, perforación y producción, cambios en estimaciones de reservas, éxito en asociaciones con terceros, pérdida de
participación en el mercado, competencia, riesgos medioambientales, físicos y de negocios en mercados emergentes, modificaciones legislativos, fiscales, legales y regulatorios,
condiciones financieras y económicas en varios países y regiones, riesgos políticos, guerras, actos de terrorismo, desastres naturales, retrasos de proyectos o aprobaciones, así
como otros factores descriptos en la documentación presentada por YPF y sus empresas afiliadas ante la Comisión Nacional de Valores en Argentina y la Securities and
Exchange Commission de los Estados Unidos de América y, particularmente, aquellos factores descriptos en la Ítem 3 titulada “Key information– Risk Factors” y la Ítem 5 titulada
“Operating and Financial Review and Prospects” del Informe Anual de YPF en Formato 20-F para el año fiscal finalizado el 31 de Diciembre de 2013, registrado ante la Securities
and Exchange Commission. En vista de lo mencionado anteriormente, las estimaciones incluidas en este documento pueden no ocurrir.
Excepto por requerimientos legales, YPF no se compromete a actualizar o revisar públicamente dichas estimaciones aún en el caso en que eventos o cambios futuros indiquen
claramente que las proyecciones o las situaciones contenidas expresa o implícitamente en dichas estimaciones no se concretarán.
Este material no constituye una oferta de venta de bonos, acciones o ADRs de YPF S.A. en Estados Unidos u otros lugares.
2
RECOVERING HISTORICAL DECLINE RATES AND
MAXIMIZING PRODUCTION IN A MATURE FIELD
Authors: J. Blanco – V. Riveros – J. Tagliorette – F. Donadio – H. Albarracín
Index
Introduction
Problem description
Methodology proposed
Initial Results
Methodology reviewed
Remarks & Final Conclusions
RECOVERING HISTORICAL
DECLINE RATES AND MAXIMIZING
PRODUCTION IN A MATURE FIELD
Geographic Location
0
ESCALA
GRAFICA
2
5
5
0
k
m
Señal Picada field is located in Neuquén
Basin, in Río Negro and Neuquén States,
60 km from Catriel town and 190 km from
Neuquén City.
Geology
Upper Fm Loma Montosa is the main reservoir in Señal Picada field.
Hydrocarbon production also provides from the Lower Member of It and
Centenario Fm.
The reservoirs of Upper Loma Montosa Fm consist of shallow marine
deposits represented by Sandstone, Limestone Sandy and less Cluster
Limestone. Its petrophysical properties are good.
The reservoirs of Lower Loma Montosa Fm consist of Limestone
Conglomerates, Limestone and Sandstone. It has worse petrophysical
conditions than the Upper Member.
6
Production and Injection History
e-81/e-82/204/223/224/230/281/...
E+05
WINJ m³/d
LIQ m³/d
E+04
E+03
OIL m³/d
E+02
3601965
1968 1971 1974 1977 1980
qoP[m³/DC]
qlP[m³/DC]
qwiP[m³/DC]
1983
e-81/e-82/204/223/224/230/281/...
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
300
First oil (year)
Production Wells
Injection Wells
Oil bbl/d
Water inj bbl/d
240
OIL Producer Wells
180
120
1965
+250
+100
5600
157000
Water cut %
RF %
Lease exp. date
>96
27
2027
60
Water Injection Wells
0
1965
1968
PWP
I WP
1971
1974
1977
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
7
Problem description
In the period highlighted the field had a severe decline rate (twice than
previous rate), the main reasons were:
• Shut down of injector and producer wells by mechanical integrity.
• Poor vertical sweep efficiency (% conventional wells)
• Surface injection system damaged (pipes, tanks, pumps). Water injection
was discontinuous.
OIL Production
EVOLUCION DE SECUNDARIA
SEÑAL PICADA
SEÑAL OIL
PICADA
[m³/d]
Liq Prod & WInj
As a result the field lost P1 Reserves in consecutive periods
SEÑAL PICADA
Liq [km³/d]
Inj Wells Number
Inj [km³/d]
WO Iny
Pz INY.CONVENC.
Pz INY. SELECTIVA
8
Methodology
To recover the historical decline of the Field we focus on optimizing Oil production & Water Injection by:
• Workover in injection and producer wells.
• Replacement of injection and producing wells.
• Run selective completion in new injection wells
• Identification of new pay zones.
• Drill infill wells
• Repair and build surface facilities
Well Selection Period 2012 - 2014
In the period 2012-2014 we use data from the static model to propose new wells, either replacement or infill.
We used and compared a set of static and dynamic data as a method to maximize production:
• Last production rate and mechanical condition in original wells (criteria for replacement wells).
• DCA per pattern.
• OOIP, RF, acreage, Net Pay.
• Well integrity analysis: used to select workovers (both injectors and producers).
GERENCIA DE PERFORACION UNAO
INGENIERIA DE WORKOVER
PROTOCOLO VALORACION DEL RIESGO EN WORKOVER DE POZOS INYECTORES
POZO: YPF.Nq.SP-206
51
27
62
Condición del CASING
1
21
30
30%
88
67
Maximo
Estado
1.1
Estado de corrosion
25%
Desconocido
1.2
Existe fuga y/o comunicación entre tbg y anular?
15%
1.3
El cielo de cemento se encuentra desde la guia?
15%
Mas de 200 mts
1.4
Tiempo en años como Pozo Inyector de agua?
20%
Entre 4 & 8 años
1.5
Condición de la Cementación en la Zona de Interés?
10%
Bueno
1.6
Existe comunicación entre cañerias guía y aislación?
141
85
29
15%
Riesgo Casing
2
2.1
2.2
2.3
2.4
2.5
2.6
2.7
Condicion de Instalación de Inyección Actual
Hay obstrucción en el tubing según calibre de últimos 3 meses?
Indicios de rotura de tubing ?
La Instalación es Selectiva?
Sin válvulas reguladoras dentro de los Mandriles de Inyeccción?
Tiene Instalación con tubing de acero? (No Revestido)
Diámetro de Tubing menor de 2-7/8"?
Tiempo en años del Ultimo WO con movimiento de instalación?
Maximo
20%
10%
20%
10%
15%
5%
20%
Riesgo Instalación
Posibilidad de Cumplimiento del Objetivo:
No
No
15
70%
Riesgo
No
No
Convencional
No
Acero revestido
2 7/8"
Menor a 4 años
6
79
ORIGINAL WELL147/147(I)
1000
• Last production rate and mechanical
condition in original wells (criteria for
replacement wells)
10
REPLACEMENT
WELL
LIQ m³/d
80
100
60
10
121/121(I)
00
100
40
ORIGINAL WELL
REPLACEMENT
1
WELL
00
80
20
OIL m³/d
LIQ m³/d
60
0.1
1971
qoP[m³/DC]
10
1974
1977
1980
qlP[m³/DC]
PWP
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
40
OIL m³/d
1
0.1
Only productive wells with integrity issues were
replaced.
20
1971
1974
1977
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
0
11
2016
2019
0
• OOIP, RF, acreage (Infill Wells)
For the selection of Infill Wells, we calculated the drainage radios of
wells in Señal Picada field, with the following considerations:
Rd 
Np  Bo
  Hutil  1  Swini   Phi  FR
We considered that the selected positions were in zones with good
net pay.
Net Pay
Net Pay Current wells
Net Pay Proposed wells
0.000
2.000
4.000
6.000
8.000
10.000
12.000
14.000
16.000
Espesor Util [[m]]
18.000
20.000
22.000
24.000
26.000
28.000
30.000
32.000
34.000
36.000
Net Pay map with drainage radios bubbles. The selected wells are marked
• DCA per pattern.
Pozo/Location
1E+04
18
47
25
56
21
20
74
42
123
62
19
16
LIQ m³/d
1E+03
14
REPLACEMENT WELL
12
WINJ m³/d
10
1E+02
ORIGINAL WELL
8
6
OIL m³/d
1E+01
4
OIL Producer Wells
2
Water Injection Wells
1E+00
1986
1988
qoP Pozo[m³/DC]
1990
1992
qlP Pozo[m³/DC]
1994
1996
1998
2000
qwiP Pozo[m³/DC] IWP Pozo
2002
2004
2006
PWP Pozo
2008
2010
2012
2014
2016
2018
13
2020
0
• Well integrity analysis: used to select workovers (both injectors and producers)
Calculated
PROTOCOLO VALORACION DEL RIESGO EN WORKOVER DE POZOS PRODUCTORES
POZO: YPF.RN.SP-290
1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
Condicion de Instalación de Productor
2
2.1
2.2
2.3
2.5
2.4
40%
Maximo
Estado
5%
7
25%
Buena
15%
Por encima de la Guia
10%
Bueno
15%
No
20%
Entre 4 & 8 años
10%
No
Riesgo Casing
4
Diametro de Casing
Estado de corrosion
Tiene Rotura de Casing?
Tiempo en años como Pozo Productor?
60%
Maximo
20%
30%
15%
20%
15%
Riesgo Instalación
Tipo de Sistema de Produccion
Tiene alguna Pesca el Pozo?
El Pozo se encuentra parado desde ?
Tipo de Pozo?
PROTOCOLO VALORACION DEL RIESGO EN WORKOVER DE POZOS INYECTORES
POZO: YPF.Nq.SP-206
1
30%
Maximo
Estado
1.1
Estado de corrosion
25%
Desconocido
1.2
Existe fuga y/o comunicación entre tbg y anular?
15%
1.3
15%
Mas de 200 mts
1.4
Tiempo en años como Pozo Inyector de agua?
20%
Entre 4 & 8 años
1.5
10%
Bueno
1.6
15%
No
Riesgo Casing
15
2
2.1
2.2
2.3
2.4
2.5
2.6
2.7
Condicion de Instalación de Inyección Actual
Hay obstrucción en el tubing según calibre de últimos 3 meses?
Indicios de rotura de tubing ?
La Instalación es Selectiva?
Sin válvulas reguladoras dentro de los Mandriles de Inyeccción?
Tiene Instalación con tubing de acero? (No Revestido)
Diámetro de Tubing menor de 2-7/8"?
Maximo
20%
10%
20%
10%
15%
5%
20%
Riesgo Instalación
No
70%
Riesgo
No
No
Convencional
No
Acero revestido
2 7/8"
Menor a 4 años
6
79
Riesgo
PCP
S/PESCA
Produciendo
Menor a 4 años
Vertical
9
87
(2015+)
Calculated
WO 2012
Well
Percent of Success
WO_INY_1
WO_INY_2
WO_INY_3
WO_INY_4
WO_INY_5
WO_INY_6
WO_INY_7
WO_INY_8
WO_INY_9
WO_INY_10
WO_INY_11
WO_INY_12
WO_INY_13
WO_INY_14
WO_INY_15
WO_INY_16
WO_INY_17
Average %
Success
43%
77%
55%
38%
42%
58%
49%
70%
73%
86%
63%
62%
80%
64%
80%
39%
58%
61%
Well
Current
Campaign
Interventions
(Total/Failure)
% Success
2012
44 / 15
66
2013
7/0
100
2014
12 / 1
92
Total
63 / 16
75
% Success
WO-1
67
WO-2
91
WO-3
91
WO-4
87
WO-5
61
WO-6
73
WO-7
66
WO-8
62
WO-9
72
WO-10
71
WO-11
91
WO-12
71
WO-13
64
WO-14
87
Promedio
75
14
Initial Results 2012 - 2014
• After 3 years overall results were satisfactory. The project
included new wells, workovers and investment in surface facilities.
• Campaigns 2012-2013 showed results higher than forecasted.
PROJECT
• Field decline rate was improved.
• P1 Reserves were added in consecutive periods
• But campaign 2014 exhibited poorer results,
especially in new wells.
• Methodology had to be improved
15
Initial Results 2012 - 2014
Field decline rate was improved.
Entire Projet (New Wells and Workovers, both
producers and injectors)
New Injection wells and WO
Current Decline
Δ 40%
Decline before
Project
Current Decline
Δ 65%
Decline before
Project
Proposed methodology 2015+
[mMD]
-0,50
• To reduce uncertainties a full field dynamic model was proposed. Time to deliver
was a constraint and an analytic tool was chosen to build the model.
• Static model was used as an input for layer properties, well tops, OOIP, etc.
• Extensive data gathering and analysis: more than 400 wells (with 3 or more
active layers) and 50 years of field history. Data quality is poor if it is old (>15
years).
• Time expended to build up the model: 10 months
1,04
100,00
251,43
851,81
855,00
857,00
858,23
860,07
861,00
864,84
869,96
870,67
872,00
874,50
0
0
0
0
0
875,02
875,75
876,69
877,58
• When the model was adjusted, it allowed us to:
• Evaluate current and final So, RF, PVI
• Identifies poor drained areas
• Make scenario analysis
• Support for new data acquisition: NMR logs, RFT, cores, well test.
881,00
0
887,50
0
897,00
0
0
0
900,25
906,45
907,58
909,00
0
0
910,28
918,03
927,49
928,36
930,00
952,19
27/12/2004
31/12/2004
06/01/2005
09/01/2005
11/01/2005
12/08/2005
16/08/2005
20/08/2005
21/08/2005
23/08/2005
06/01/2009
08/01/2009
20/05/2009
24/05/2009
Well Selection Period 2015+
• Pre-selection
2568000
2569000
2570000
2571000
2572000
2573000
2574000
2575000
2576000
2577000
2578000
2579000
2580000
2581000
2580000
2581000
5837000
0.00
2566000
2567000
0.20
2568000
0.40
0.60
2569000
0.80
2570000
1.00
2571000
1.20
1.40
2572000
Petróleo in Situ [[m³/m²]]
1.60
1.80
2.00
2573000
2574000
2.20
2575000
2.40
2576000
2.60
2.80
2577000
3.00
2578000
3.20
5827000
5828000
5829000
5830000
5831000
5832000
5833000
5834000
5835000
5836000
5837000
5836000
5835000
5834000
5833000
5832000
5831000
5830000
5829000
5828000
Infill Wells
Current RF of locations
with larger acreage than
field average.
5827000
Replacement Wells
Current RF of abandoned
wells or wells that are
going to be abandoned
soon
5838000
2567000
5838000
2566000
3.40
2579000
18
• Dynamic Model
So
RF
PVI
19
Infill well proposed
RF y So: better than field average
FR
SoAVG
20
Replacement proposed: producer well
RF
SoAVG
Production lost in original well
SP-0090
100
7
6
10
4
3
1
1
0,1
2005
qoP[m³/DC]
2006
2007
qlP[m³/DC]
2008
2009
2010
2011
2012
2013
SumergP[m]
QoP[m³/DC]
QlP[m³/DC]
21
0
2014
2015
QwiP[m³/DC]
Replacement proposed: injector well
PVI
SoAVG
RF
1000
SP-0114/SP-284/SP-141/SP-140/SP-141(I)/...
100
Production lost in original
injection pattern
10
1
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014
qoP[m³/DC]
qlP[m³/DC]
qwiP[m³/DC]
Scenario Analysis
LIQ SIM
Project
LIQ SIM
BASE CASE
LIQ
REAL
Do nothing vs Proposed wells
RF increase 0,4% (12 years period)
OIL SIM
Project
OIL REAL
OIL SIM
BASE CASE
OIL CUM SIM
Project
OIL CUM SIM
BASE CASE
REMARKS & FINAL CONCLUSIONS
•
The project showed initial success.
•
Decline rate was restored and P1 reserves were added
•
Even if successful, a methodology needs to be reviewed periodically to maximize profit in
a mature field
•
Until now analytic software for dynamic full field model is our best decision making tool. It
is recommended to evaluate feasibility of a numerical full field model (cost-benefit of the
tool).
•
New wells drilled in 2015 showed results according to dynamic model simulation
Thanks
NUESTRA ENERGÍA

Recovering Historical Decline Rates and Maximizing Production in a

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