casabe new tricks for an old field
TRANSCRIPT
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Casabe: New Tricks for an Old Field
At some point in the operational life of an oil field, natural drive dwindles and
additional energy is needed to sustain production rates. In the Casabe field water-
flooding has been used to enhance oil recovery. However, a combination of sensitive
lithology, structural complexity and water channeling caused hardware to fail and
wells to collapse, disrupting the waterflood efficiency. New techniques in geologic
analysis, waterflooding, drilling and production optimization are restoring this
once-prolific field to its former glory.
Mauro Amaya
Raúl Amaya
Héctor Castaño
Eduardo Lozano
Carlos Fernando Rueda
Ecopetrol SA
Bogotá, Colombia
Jon Elphick
Cambridge, England
Walter Gambaretto
Leonardo MárquezDiana Paola Olarte Caro
Juan Peralta-Vargas
Arévalo José Velásquez Marín
Bogotá
Oilfield Review Spring 2010: 22, no. 1.Copyright © 2010 Schlumberger.
For help in preparation of this article, thanks to José IsabelHerberth Ahumada, Marvin Markley, José A. Salas, HectorRoberto Saldaño, Sebastian Sierra Martinez and AndreasSuter, Bogotá; and Giovanni Landinez, Mexico City.
AIT, CMR-Plus, Petrel, PowerPak XP, PressureXpress,TDAS and USI are marks of Schlumberger.
Crystal Ball is a mark of Oracle Corp.
IDCAP, KLA-GARD and KLA-STOP are marks of M- I SWACO.
Old fields have stories to tell. The story of the
Casabe field, 350 km [220 mi] north of Bogotá
and situated in the middle Magdalena River
Valley basin (MMVB) of Colombia’s Antioquia
Department, began with its discovery in 1941.
The field was undersaturated when production
began in 1945, and during primary recovery the
production mechanisms were natural depletion
and a weak aquifer. In the late 1970s, at the end
of the natural drive period, the operator had
obtained a primary recovery factor of 13%. By this
time, however, production had declined signifi-
cantly to nearly 5,000 bbl/d [800 m3 /d]. Seeking
to reverse this trend, Ecopetrol SA (Empresa
Colombiana de Petróleos SA) conducted water-
flood tests for several years before establishing
two major secondary-recovery programs in the
mid to late 1980s.
> Casabe oil production and water injection. Waterflood pilot projects took place in the late 1970s, but itwas not until 1985 that the first of two major waterflood programs began. During the first three years ofeach program, high injection rates were possible; however, water soon found ways through the mostpermeable sands. Early breakthrough and well collapse forced the operator to choke back injection.The steady decline in injection was accompanied by a decline in production, and attempts to reverse this trend were unsuccessful. In 2004, when the Casabe alliance was formed, production rates were5,200 bbl/d. By early February 2010, these rates had increased to more than 16,000 bbl/d.
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WaterOil1. Peralta-Vargas J, Cortes G, Gambaretto W, MartinezUribe L, Escobar F, Markley M, Mesa Cardenas A,Suter A, Marquez L, Dederle M and Lozano E: “FindingBypassed Oil in a Mature Field—Casabe Field, MiddleMagdalena Valley Basin, Colombia,” presented at theACGGP (Asociación Colombiana de Geólogos yGeofisicos del Petróleo) X Symposio Bolivariano,Cartagena, Colombia, July 26–29, 2009.
Marquez L, Elphick J, Peralta J, Amaya M, Lozano E:“Casabe Mature Field Revitalization Through an Alliance:A Case Study of Multicompany and MultidisciplineIntegration,” paper SPE 122874, presented at the SPELatin American and Caribbean Petroleum EngineeringConference, Cartagena de Indias, Colombia, May 31–June 3, 2009.
2. Cordillera is Spanish for range. Colombia has threeranges: Oriental (eastern), Central, and Occidental(western). These are branches of the Andes Mountains
that extend along the western half of the country. TheMMVB runs WSW-NNE, and the Magdalena River r unsnorthward through it, eventually flowing into theCaribbean Sea.
3. Barrero D, Pardo A, Vargas CA and Martínez JF:Colombian Sedimentary Basins: Nomenclature,Boundaries and Petroleum Geology, a New Proposal .Bogotá, Colombia: Agencia Nacional de Hidrocarburos(2007): 78–81, http://www.anh.gov.co/paraweb/pdf/publicaciones.pdf (accessed February 5, 2010).
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During the secondary-recovery period, struc-
tural complexities, sensitive shales, heteroge-
neous sands and viscous oils all conspired to
undermine the effectiveness of the waterflood.
And although initially successful at increasing
production, injected water broke through prema-
turely at the production wells, an indicator of
bypassed oil (previous page). Sand production
occurred in a high percentage of wells, contribut-ing to borehole collapse and causing failure of
downhole equipment. Water-injection rates were
gradually decreased in an attempt to overcome
these issues, and waterflooding became less
effective at enhancing oil recovery; from 1996
onward the production rates declined between
7% and 8% per year.
In 2004 Ecopetrol SA and Schlumberger
forged an alliance to revitalize the Casabe field.
Using updated methods for managing highly
complex reservoirs, the alliance reversed the
decline in production: From March 2004 to
February 2010, oil production increased from
5,200 to more than 16,000 bbl/d [820 to
2,500 m3 /d].1 Also, the estimated ultimate recovery
factor increased from 16% to 22% of the original oilin place (OOIP).
This article describes the complexities of the
reservoirs within the Casabe concession and the
oil recovery methods employed over the last
70 years, concentrating primarily on the major
reengineering work using updated methods that
began in 2004.
A Prolific Yet Complex Region
The middle Magdalena River Valley basin is an
elongated depression between the Colombian
Central and Oriental cordilleras and represent
an area of 34,000 km2 [13,000 mi2].2 Oil seeps are
common features within the basin; their pres
ence was documented by the first western explor
ers in the 16th century. These reservoir indicator
motivated some of the earliest oil exploration andled to the discovery in 1918 of the giant field
called La Cira–Infantas, the first field discovered
in Colombia. Since that time, the MMVB has
been heavily explored. Its current oil and gas
reserves include more than 1,900 million bb
[302 million m3] of oil and 2.5 Tcf [71 billion m3
of gas.3
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The abundance of hydrocarbon resources in
the basin attests to the prolific petroleum system
active in this region. A thick, organic-rich lime-
stone and shale succession was deposited in an
extensive pericratonic trough along the north-
west margin of the Guyana shield during the
Cretaceous Period.4 These underlying source
rocks are separated from the primary reservoirs
by an Eocene unconformity. Major fluid-migra-
tion mechanisms to fields within the MMVB con-
sist of direct vertical migration where La Luna
Formation subcrops the Eocene unconformity,lateral migration along the Eocene sandstone
carrier and vertical migration through faults.
The Colorado, Mugrosa and La Paz forma-
tions that make up the Casabe field were depos-
ited during the Paleogene Period. These are
found at depths of 670 to 1,700 m [2,200 to
5,600 ft]. The reservoir sands in the field are
classified in three main groups: A, B and C,
which are subdivided into operational units
(above). Sands are typically isolated by imper-
meable claystone seals and have grain sizes that
vary from silty to sandy to pebbly.
Structurally the Casabe field is an 8-km
[5-mi] long anticline with a three-way closure, well-defined eastern flank and a southern plunge.
The northern plunge is found outside the area of
the Casabe field in the Galán field. A high-angle
NE-SW strike-slip fault closes the western side of
the trap. Associated faults perpendicular to the
main fault compartmentalize the field into eight
blocks. Drilling is typically restricted to vertical
or deviated wells within each block because of
heavy faulting and compartmentalization.
Throughout the history of the field, develop-
ment planners have avoided placing wells in the
area close to the western fault. This is because
reservoir models generated from sparse 2D seis-
mic data, acquired first around 1940 and later inthe 1970s and 1980s, failed to adequately identify
the exact location of major faults including the
4. Pericratonic is a term used to describe the area around astable plate of the Earth’s crust (craton).
5. Although the exact fault locations were not well-defined,by conservatively locating the wells away from thefault zones the waterflood planners ensured wellsremained within the correct block and inside thewestern fault closure.
6. For more on historical structural maps from the Casabefield: Morales LG, Podesta DJ, Hatfield WC, Tanner H,
> Casabe structural setting. The Casabe field lies to the west of La Cira–Infantas field in the middle Magdalena River Valley basin ( left ). The principalMMVB structures and producing fields are shown in the generalized structural cross section A to A’ (top right ). The basin is limited on the east by a thrustbelt, uplifting the oldest rocks. Cretaceous and Paleocene (green), Oligocene (orange) and Miocene (yellow) rocks are shown in the central part of the basincross section. The pre–Middle Eocene uplift and erosion have exposed the Central Cordillera on the west (gray). The Casabe field is highly layered, as shown in the detailed structural cross section (bottom right ). (Figure adapted from Barrero et al, reference 3, and Morales et al, reference 6.)
0m
Perolesfield
La Cira–Infantasfield
Barrancabermeja Nuevo Mundo syncline Rio Suarezanticline
Casabefield
CentralCordillera
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Infantas Peroles
Jones SH, Barker MHS, O’Donoghue J, Mohler CE,Dubois EP, Jacobs C and Goss CR: “General Geology andOil Occurrences of Middle Magdalena Valley, Colombia,”in Weeks LG (ed): Habitat of Oil . Tulsa: The AmericanAssociation of Petroleum Geologists, AAPG SpecialPublication 18 (1958): 641–695.
7. For more on undeveloped areas in the Casabe field:Gambaretto W, Peralta J, Cortes G, Suter A, Dederle Mand Lozano Guarnizo E: “A 3D Seismic Cube: What For?,”
paper SPE 122868, presented at the SPE Latin Americanand Caribbean Petroleum Engineering Conference,Cartagena, Colombia, May 31–June 3, 2009.
8. Peñas Blancas field, discovered in 1957, is located 7 km[4 mi] to the southwest of the Casabe field. Both fieldshave the same operator. The area between the fields wassurveyed because oil indicators were found.
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main strike-slip fault. The lack of a more accu-
rate structural model caused two main problems:
Reservoir engineers underestimated OOIP and
waterflood planners found it difficult to locate
injector-producer pairs within the same reservoir
and, to a lesser extent, within the same fault
block.5 These uncertainties led the managers and
experts of the 2004 Casaba alliance to build a
multicomponent redevelopment plan.
Ecopetrol SA has long-standing experience inand knowledge of the field and the measures
undertaken to keep it producing decade after
decade. Schlumberger provides new oilfield tech-
nologies to the operator, including seismic sur-
veying, downhole measurements, data analysis
and specialized drilling, as well as domain exper-
tise to decipher the challenges faced. With these
capabilities the alliance was confident it could
obtain results within a year.
The key goals of the redevelopment plan were
to increase reserves, manage the waterflood pro-
grams more efficiently and address drilling-
related problems such as reactive lithology,
tripping problems, low ROP, borehole collapse
and washouts, and completion challenges such as
poor cementing and casing collapse. Tackling
each of these elements involved close collabora-
tion between the operator’s professionals and
technical experts from the service company. The
first stage of the project involved a thorough field-
wide analysis based on existing data and the gath-
ering of new data using the latest technologies,
such as 3D seismic surveys and 3D inversion.
Undeveloped Areas and Attic Oil
Forty years ago it was common to create struc-
tural maps by identifying formation tops from
well data. With hundreds of evenly distributed
wells this task was quite straightforward over
most of the Casabe concession.6 However, a large
undeveloped area near the main NE-SW strike-
slip fault encompassed over 20 km2 [7.7 mi2].
Smaller undeveloped locations also existed.7
A lack of well log data in these undeveloped
areas meant that formation tops were not avail-
able to create structural maps for several key
areas of operator interest. As a result, significant
potential oil reserves were possibly being over-
looked. To improve structural understanding and
help increase reserves, Ecopetrol SA commis
sioned a high-resolution 3D seismic survey.
Geophysicists designed the survey to encom
pass both the Casabe and Peñas Blancas fields
and also the area in between.8 WesternGeco per
formed the survey during the first half of 2007
acquiring more than 100 km2 [38 mi2] of high
resolution 3D seismic data; data interpretation
followed later that year. The new data enabledcreation of a more precise and reliable structura
model than one obtained from formation tops
with the added advantage of covering almost the
entire Casabe concession (below).
In addition to accurately defining the struc
ture of the subsurface, seismic data can also give
reservoir engineers early indications of oil
bearing zones. In some cases oil-rich formation
appear as seismic amplitude anomalies, called
bright spots. However, these bright spots do not
guarantee the presence of oil, and many opera
tors have hit dry holes when drilling on the basi
of amplitude data alone.
> Casabe structural maps and model. Structural maps of the field weregenerated using formation tops from well logs (Formation Tops). Butoperators avoided drilling along the main strike-slip fault for fear of exiting the trap; hence, tops were unavailable (Structural Sketch, red-shaded area).This poorly defined and undeveloped area represented significant potentialreserves. High-resolution 3D seismic data were used to create a refined set
of structural maps (Seismic Data). These maps indicate additional faults in the field and adjusted positions of existing faults compared to the formation top maps. Calibration of the new maps from existing well logs furtherimproved their accuracy. Geophysicists input the maps into Petrel software to form a 3D structural model of the subsurface (inset, right ). (Figureadapted from Peralta-Vargas et al, reference 1.)
Structural Sketchwith Well Locations
Formation Tops Seismic Data
Area notdrained
or drilled
Well location
Depth, ft3,300
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4,800
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6,500
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Several conditions can create misleading
amplitude anomalies, but careful processing and
interpretation can distinguish them. Analysis ofamplitude variation with offset (AVO) corrects
data during the common midpoint gathering
process (above).9 Using AVO-corrected amplitude
maps as an additional verification tool, interpret-
ers were able to confirm both undeveloped and
attic oil accumulations.
Attic oil is an old concept. Operators know
there can be oil in these higher zones, but identi-
fying them is difficult if the exact location of
faults is uncertain. Interpretation of the Casabe
3D seismic data clarified field corridors where
wells had not been planned because of the uncer-tainty surrounding the main fault position. Wells
have since been drilled along these corridors
with successful results (next page, top).
A detailed geologic model provided a better
understanding of the subsurface conditions,
which helped during the waterflood planning and
drilling processes. Prestack inversion of the 3D
survey data yielded fieldwide estimates of rock
properties.10 Geophysicists calibrated these esti-
mates using data acquired by a suite of new-
generation logging tools (see “New Wells and
Results,” page 15 ) in approximately 150 wells.
Using these calibrated rock types, geologists
created a facies distribution map, which they
combined with the structural model to create a
model of reservoir architecture.
The architectural model highlighted more
than 15 reservoirs with an average thickness of3 m [10 ft] each. Reservoir engineers analyzed
10 of these reservoirs and discovered an addi-
tional 5 million bbl [800,000 m3] of estimated
reserves.11 The geologic model was then used dur-
ing the waterflood redevelopment process to help
improve both areal and vertical sweep efficiency.
Effective Waterflooding
When the Casabe field was switched from natural
drive to waterflood in the late 1970s, the operator
chose to use a typical five-spot pattern with
approximately 500 injector and producer pairs.
To sweep the upper and lower sections of Sands A
and B, up to four wells were drilled per injection
location (next page, bottom). During the initial
waterflood period, injection rates peaked in 1986
and 1991. These dates correspond to the first and
second year after the beginning of the two water-
flood programs for the northern and southern
areas of the Casabe field.
Two to three years after each peak there was
a noticeable drop in the water-injection rates.
This was due mainly to the restrictions imposed
on the rates to avoid casing collapse. However,
the reduction in water-injection rates was also
influenced by several other factors. These issues
were identified in the alliance’s redevelopment
plan and became a large part of the requirements
for reworking the Casabe waterflood programs.
9. For more on AVO analysis: Chiburis E, Franck C,Leaney S, McHugo S and Skidmore C: “HydrocarbonDetection with AVO,” Oilfield Review 5, no. 1(January 1993): 42–50.
10. For more on inversion: Barclay F, Bruun A,Rasmussen KB, Camara Alfaro J, Cooke A,Cooke D, Salter D, Godfrey R, Lowden D, McHugo S,Özdemir H, Pickering S, Gonzalez Pineda F, Herwanger J,Volterrani S, Murineddu A, Rasmussen A and Roberts R:“Seismic Inversion: Reading Between the Lines,”Oilfield Review 20, no. 1 (Spring 2008): 42–63.
11. Amaya R, Nunez G, Hernandez J, Gambaretto W andRubiano R: “3D Seismic Application in RemodelingBrownfield Waterflooding Pattern,” paper SPE 122932,presented at the SPE Latin American and CaribbeanPetroleum Engineering Conference, Cartagena deIndias, Colombia, May 31–June 3, 2009.
12. For more on understanding high-mobility ratios:Elphick JJ, Marquez LJ and Amaya M: “IPI Method:A Subsurface Approach to Understand and ManageUnfavorable Mobility Waterfloods,” paper SPE 123087,presented at the SPE Latin American and CaribbeanPetroleum Engineering Conference, Cartagena,Colombia, May 31–June 3, 2009.
> Minimizing uncertainty of amplitude anomalies. Bright spots ( top left ) are high-amplitude features onseismic data. These features can indicate oil accumulations, although they are no guarantee. One technique for understanding bright spots begins with modeling the amplitudes of reflections fromreservoirs containing various fluids (top right ). The amplitude at the top of a sand reservoir filled withwater decreases with offset. The amplitude at the top of a similar reservoir containing gas canincrease with offset. The results are compared with actual seismic traces containing reflections from asand reservoir (bottom left ) to more accurately characterize reservoir fluid. Combined with otherinformation such as seismic inversion data, AVO-corrected amplitude maps (bottom right ) can be auseful tool to confirm the presence of oil (light-blue areas). (Figure adapted from Gambaretto et al,reference 7.)
Bright spots
AVO-correctedamplitude map
AVO anomaly
Typical amplitude signature
Undeveloped area
Hydrocarbons
Uncorrected commonmidpoint gather
Amplitude anomaly
Offset
Offset
Offset
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The operator had recorded early water break-
through in the field’s producers during both
waterflood programs. This was a result of injec-
tion water channeling inside high-permeability
layers. Also, a poor mobility ratio was present
throughout the field: Viscous oils (14.8 to 23.3 API
gravity in the upper sands and 15.4 to 24.8 API
gravity in the lower sands) were pushed aside by
the more freely flowing water, and once break-
through occurred the water influx increased.12
These conditions caused a poor vertical sweep
efficiency average of only 20%.
> Attic well. Experts had long predicted a field corridor along the mainstrike-slip fault, but the lack of accurate seismic data made the risk ofdrilling these zones too high. Interpretation of the 2007 3D seismic surveyenabled geophysicists to identify undeveloped drilling locations (redellipses, left ) close to the major fault. A new offset well, approved for BlockVIII, was very close to the main strike-slip fault (dashed-green box, left ). 3Dseismic data and structural maps (middle ) visualized using Petrel software
helped well planners position the well. The trajectory avoided major faultsand targeted a large undeveloped zone and two attic oil zones in the B andC sands (right ). The wells constructed during the first and second drillingcampaigns were vertical; in the third campaign, especially from late 2008onward, most of the wells drilled were offset wells in target pay zones clos to faults. (Figure adapted from Amaya et al, reference 11.)
Undeveloped
Attic oilB sands
Attic oilC sands
Blocks I and II
Block III
Block IV
Block V
Block VI
Block VII
Block VIII
Drilled wells
Approved locations
Proposed locations
Undeveloped areas
0
0 6,000 ft
1,000 2,000 m
N
N
New well
D e p t h ,
m
400
600
800
1,000
1,200
1,400
1,600
. Casabe field injection and production scheme.
Original field-development plans included asmany as four wells per injection location to flood the multilayered sands (blue wells). Up to twowells were used to extract oil, but in somelocations a single production well commingledfluids from Sands A and B, B and C, or A, B and C(green wells). The current string design for newinjector-producer pairs, shown in a later figure,limits drilling to only one well per location. Thischange has reduced cost and also the incidenceof proximity-induced well collapse. (Figureadapted from Peralta-Vargas et al, reference 1.)
2,500
A1
A2
B1 SUP
B1 INF
B2 SUP
B3
C
A3
3,000
3,500
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4,500
B2 INF
5,000
5,500
L o w e r s a n d s
M u g r o s a
L a P a z
C o l o r a d o
O l i g o c e n e
U p p e r s a n d s
Formation –80 20
SpontaneousPotential
0 20mV ohm.m
Resistivity
Sand
Depth,ft
La Cira
Shale
A1 A2
Injection Production
B1 B2 A B CBA
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Sand production and high-velocity jetting of
sandy water through perforations significantly
eroded casing walls and completion hardware in
the producers. During a critical period of the
waterflood, numerous wells collapsed and were
abandoned or taken off line. To sustain production
levels the operator chose to convert many injec-
tion wells to producers, but this drastically
affected the waterflood patterns (left).
Choking back injection rates to mitigate well collapses was another factor that caused an
uneven water-flow pattern. Areal sweep was poor,
resulting in many areas of bypassed oil. The
field’s redevelopment team wanted to reestablish
patterns to improve areal sweep efficiency.
Therefore, a large part of the third drilling cam-
paign involved planning and placement of new
injectors and producers. These were located to
recreate an evenly spread network of wells
throughout the field. However, areal sweep is
largely dependent on obtaining good vertical
sweep efficiency. Waterflood specialists first
needed to design better injection control systems
that would improve vertical sweep and also pro-
vide a mechanism to reduce the damaging effects
of water channeling on the production strings.
Vertical sweep efficiency is determined by the
effectiveness of water, flowing from injector
wells, at pushing oil through permeable layers to
formation-connected oil producers. The original
multiwell injector design had no injection profile
control, so water flowed preferentially through
the most permeable formations. This water-
channeling effect is aggravated by several mech-
anisms: Shallower sands can be unintentionally
fractured during waterflooding, significantly
increasing permeability. The injectivity index of
deeper layers may suffer if low-quality injected
water causes plugging of perforations or deposits
of scale in the production casing. Also, injected
water bypasses viscous oil, present in large
amounts in the Casabe field, and breakthrough
takes place in producers. As a consequence,
water flows through the layer of highest permea-
bility and may not be injected at all in others,
especially in the deeper sands with skin damage.
This has been a distinctive feature during Casabe
production operations.To optimize flooding, water management spe-
cialists recommended selective injection strings
using waterflood-flow regulators (next page).
These designs would enable the operator to choke
back injection rates in specific layers irrespective
of the reservoir pressure, permeability, skin dam-
age or any other factors that would normally
affect flow. Each layer is packed off to prevent any
> Comparison of 1986 and 2003 waterflood patterns. By 1986 the operator had
established an evenly distributed network of five-spot injection patterns throughout the Casabe field (top ). Well collapses had occurred in nearly 70% of the wells inBlock VI, and a significant number of collapses had been recorded in all otherblocks in the field. In 2003 (bottom ) many of the collapsed wells remained abandonedor inactive and numerous injectors had been converted to producers. Expertssuggested a new drilling campaign to reestablish fieldwide five-spot patterns.(Figure adapted from Elphick et al, reference 12.)
2003
Waterflood Patterns in Block VI
1986
Producers
Injectors
Top of A sands
Top of B sands
Top of C sands
Fault traces
3,000
2,400
1,800
1,200
600
0
0 750 1,500
East, ft
N o r t h ,
f t
2,250 3,000 3,750
3,000
2,400
1,800
1,200
600
0
0 750 1,500
East, ft
N o r t h ,
f t
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fluids within that zone of the wellbore from invad-
ing another zone. An injection nozzle is located
within this section and is controlled from the sur-
face. The new selective-string designs have
improved the vertical sweep efficiency by enabling
the operator to maintain higher injection rates
into layers less affected by waterflood-induced
problems. Conversely, the new designs have miti-
gated issues related to channeling by allowing a
reduction of rates in problematic layers.Use of a single well designed with packed-off
flow control was also much more cost-effective
than the previous design of up to four wells per
injection location. Up to 16 water-flow regulators
have now been installed in injectors in the
Casabe field. This solution also addressed the
possibility that drilling several injectors in close
proximity to one another was one of the likely
causes of casing collapse.
Overcoming Drilling Difficulties
From first production in 1945 to the end of 2006,
approximately 45% of the production wells in the
Casabe field had at some point collapsed, with
different levels of severity. As a result, wells were
abandoned, left inactive or reactivated only after
costly workovers. The abandoned and inactive
wells represented millions of dollars in capital
investment in the field and in lost revenue due to
lower production rates. The majority of casing
collapses had occurred in Block VI, which also
has the largest proven reserves. It was therefore
the focus of a casing-collapse study.13
In the first stage of the Block VI study,
production engineers gathered casing-collapse
statistics. In 2006 this block contained 310 wells.
A total of 214 showed some degree of collapse.
Slightly more producers than injectors collapsed,
but the difference was minor and indicated no
trend. Of the total number of wells with recorded
collapse events, 67 were abandoned and 80 were
inactive, a factor that the operator knew would
severely impact injection and production rates.
The remaining wells had been reactivated after
costly workovers. The engineers then looked for
a correlation between the 214 collapses and
when these wells were drilled to identify any
drilling practices that were incompatible withthe Casabe field.
Three main drilling campaigns coincided with
the primary-recovery, or natural-drive, period
(1941 to 1975); the secondary-recovery, or water-
flood, period (1975 to 2003); and finally the
waterflood period of the Casabe alliance (2004 to
present). Of the wells drilled during the first
campaign, 78% had casing-collapse events during
operation. In the second campaign this figure
was slightly less, at 68%. This period, however,
corresponded to the waterflood programs; hence
many more wells had been drilled. During the
study period there were no recorded collapse
events in Block VI for wells constructed in thethird drilling campaign. This change was consid-
ered to be a result of improved drilling practices,
which are discussed later in this section.
To determine a link between casing collapse
and subsurface conditions, the investigators con-
sidered the updated stratigraphic and structural
models built from the new 3D seismic data.
Petrel seismic-to-simulation software enabled
the production engineers to display both models
in the same 3D window. Using modeling tools
they could then tag and clearly see the wellbore
depths and the locations along the Casabe struc
ture where collapses had been recorded.
The engineers discovered that casing collapsehad occurred in all stratigraphic levels. However
collapse distribution did highlight a strong cor
relation to the overburden and to the water
flooded formations. The analysis of well location
> Selective injection design. New injection strings in the Casabe field have up to 16 waterflood-flow regulators (WFRs). WFRs and check valves preventbackflow and sand production in case of well shutdown. The zone-isolatedinjection devices are placed in the highly layered stratigraphic profiles of themost-prolific producers that commingle fluids from A, B and C sands.Production logs are unavailable because of rod pumps, but injection logs areavailable: Track 1 describes a typical lithology of A sands (yellow shaded
areas); spontaneous potential logs (blue curves) are more accurate thangamma ray logs (red curve) in the presence of radiation from feldspar, whichoccurs naturally in the field. Track 2 shows resistivity response of the formationat two measurement depths (red and blue curves) and water-injection zones(green shaded area). (Figure adapted from Elphick et al, reference 12.)
A3
A21
A2
A1H
Sand
SpontaneousPotential
mV–80 20
Resistivity
ohm.m0 15
Gamma Ray
Four-zone injector schematic
gAPI0 150
Perforations
WFR
Packer
13. Olarte P, Marquez L, Landinez G and Amaya R: “CasingCollapse Study on Block VI Wells: Casabe Field,” paperSPE 122956, presented at the SPE Latin Americanand Caribbean Petroleum Engineering Conference,Cartagena, Colombia, May 31–June 3, 2009.
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12 Oilfield Review
within the field and well-collapse distribution
revealed an evenly spread number of events,
which indicated no areal localization (above).
The next stage of the study was a probabilistic
analysis to evaluate the frequency of events
based on two variables: number of casing-
collapse events and operational year. Production
engineers created probabilistic distributions by
plotting both variables for each drilling campaign
using the Monte Carlo simulation component of
the Crystal Ball software. The results showed the
highest number of events (about 30) for the wells
drilled during the first drilling campaign occurred
in 1985, coinciding with the beginning of the first
major waterflood program.
Interventions were more frequently per-
formed on wells drilled during the second drilling
campaign, which meant that the timing of each
collapse event was recorded with greater cer-tainty than for wells drilled during the first drill-
ing period. Therefore, the probabilistic analysis
was even more reliable. It revealed that casing
collapse occurred primarily during the first few
years of the waterflood project and peaked during
1988. Investigators identified a critical period of
> Areal and stratigraphic localization of casing collapse in Block VI. Statistical analysis of casing-collapse events within each stratigraphic section (left )showed collapses in every formation. However, event frequency in the overburden and in the waterflooded zones (mainly Sands A1, A2, B1 and B2) wasseveral times higher than in other zones, indicating these intervals are more likely to cause collapse. Using Petrel modeling tools, engineers included Block
VI casing collapses in the structural model. A structural map of one reservoir (right ) indicates collapses occurred throughout the block and not in anyspecific area. (Figure adapted from Olarte et al, reference 13.)
Overburden Colorado Mugrosa La Paz
A20
10
20
30
40
N
u m b e r o f c o l l a p s e e v e n t s
Stratigraphic formation
50
60
70
80
B2 B3B1A3A1 C
Faults
Production wells Injection wells
N
> Critical fluid levels for production casing and liners of the first drilling campaign. Testing usingTDAS software determined the critical load condition for fluid evacuation in Block VI wells from the firstdrilling campaign. Casing (green box, left ) and liners (red box, right ) were tested first to obtain criticalfluid-evacuation levels based on original design specifications and again after calculations of 10%, 20%and 30% wall loss. All wells for the simulation were at depths of 5,000 ft; depending on the amount of wallloss, a collapse was probable as borehole fluid levels fell. For example, 7-in., 20-lbm/ft API Grade H40casing strings could collapse even at their installed condition when the fluid was evacuated past 3,200 ft.Wells that passed the first simulated test failed when wall loss was increased. This result indicated that corrosion or general wear-and-tear (causing wall loss) would have weakened casing or liners to the limit of collapse when the fluid level dropped to values that had been recorded in the field.(Figure adapted from Olarte et al, reference 13.)
5,000
7-in. H40
20 lbm/ft
7-in. J55
20 lbm/ft
7-in. K55
23 lbm/ft
7-in. N80
23 lbm/ft
65 /8-in. H40
20 lbm/ft
65 /8-in. J55
20 lbm/ft
4,000
3,000
2,000
1,000
0
4,500
3,500
2,500
1,500
500
F l u i d
l e v e l
, f t
Casing Liners
0% wall loss
10% wall loss
20% wall loss
30% wall loss
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Spring 2010 13
time during which collapse frequency was high.
This period coincided with the most intense rates
of water injection (right).
The next stage of the study evaluated the
mechanical integrity of the wells in the Casabe
field. This evaluation found that for the producers
in Block VI collapses occurred only in the produc-
tion liners and casing. To uncover the root causes
for all these collapses, every event was evaluated
using TDAS tubular design and analysis software.The application enables analysis of the mechani-
cal performance of a casing in two scenarios.
First, an initial installed state considers the origi-
nal casing-design specification and downhole con-
ditions such as temperature and pressure. The
next scenario includes subsequent operationally
induced events such as injection and production
that are interpreted as forces on the casing, called
case loads. Engineers analyzed case loads for
compressional, tensional and triaxial stresses.
To begin, engineers needed to define the
installed condition, characterized by tempera-
ture, pressure and casing strength, for casing
designs in Block VI. Then they could apply case
loads to determine when a casing would fail.
Pressure and temperature profiles for each well
were calculated using logs from the Casabe field.
Because corrosion also significantly reduces cas-
ing strength, the USI tool, which measures ultra-
sonic acoustic impedance, was used to determine
the loss of wall thickness attributed to corrosion
(see “Scanning for Downhole Corrosion,” page 42).
According to the USI data, wells exhibited wall
losses between 10% and 35%. Engineers defined
four corrosion profiles at 0%, 10%, 20% and 30%
wall loss. These four profiles were combined with
pressure and temperature data to generate the
installed conditions that engineers needed to
begin simulation of operational loads.
Engineers performed hundreds of simulations
using the TDAS software. The first analysis con-
sidered fluid evacuation, a decrease of fluid level
in the borehole, which can be a critical load con-
dition for casing collapse. Fluid levels in the well-
bore may become low during the productive life
of a field for several reasons. These include low
productivity, increased extraction during produc-
tion, sand fill, decreased water injection, andswabbing and stimulation operations, all of which
had taken place in the Casabe field. When fluid
level drops, the internal pressure no longer bal-
ances the external pressure and the casing must
sustain this force. The critical load condition for
casing collapse occurs when the differential pres-
sure is higher than the casing can withstand.
After analysis of the casing design chosen
for wells during the first drilling campaign,
engineers discovered that the specifications
had resulted in casing strings that were not
robust enough to withstand fluid evacuation
combined with the wall losses observed in
Block VI (previous page, bottom).
The final mechanical analysis was related to
the main operational events leading to casing col-
lapse. The reservoir pressure profile within theformation during water injection could impact
the casing in both producers and injectors. The
calculated increase in load from waterflooding
was applied to casing that had passed critical
load conditions in the earlier simulations; the
new test would determine if the additional pres-
sure could cause them to collapse. This analysis
indicated that waterflooding increased the like-
lihood of casing collapse.
Once all critical limits and conditions for
the Casabe field had been obtained, production
engineers ran simulations for several casing
strings with different specifications to find an
optimal design for future wells. The TDAS simula
tions enabled them to specify an ideal model tha
would give an estimated service life of 20 years
This model has been applied to all new wells
drilled throughout the field, with a successfu
reduction in the frequency of recorded casing collapse to less than 2% of wells from 2006 to 2009
This is a dramatic improvement compared with
events during the previous 60 years, in which 69%
of wells in Block VI experienced collapses.
> History of casing-collapse frequency. The frequency of collapse events byyear was plotted for the first and second drilling campaigns (top ). In 1985 thehighest frequency (28) of reported events was recorded for wells from the firstdrilling campaign. For wells from the second drilling campaign, which occurredduring the waterflood period, the peak frequency (20) of reported collapsesoccurred in 1988. Both values correspond to the beginning of the waterfloodprograms in the northern and southern areas of the Casabe field. A critical10-year period from 1985 to 1995 was identified as coinciding with the highest
rates of production and water injection (bottom ). (Figure adapted from Olarteet al, reference 13.)
0
1 9 4 7
1 9 4 9
1 9 5 1
1 9 5 3
1 9 5 5
1 9 5 7
1 9 5 9
1 9 6 1
1 9 6 3
1 9 6 5
1 9 6 7
1 9 6 9
1 9 7 1
1 9 7 3
1 9 7 5
1 9 7 7
1 9 7 9
1 9 8 1
1 9 8 3
1 9 8 5
1 9 8 7
1 9 8 9
1 9 9 1
1 9 9 3
1 9 9 5
1 9 9 7
1 9 9 9
2 0 0 1
5
10
15
20
25
30
N u m b e r o f w e l l s c o l l a p s e d
Operational year
103
104
1 9 8 5
1 9 8 6
1 9 8 7
1 9 8 8
1 9 8 9
1 9 9 0
1 9 9 1
1 9 9 2
1 9 9 3
1 9 9 4
1 9 9 5
1 9 9 6
1 9 9 7
1 9 9 8
1 9 9 9
2 0 0 0
2 0 0 1
2 0 0 2
2 0 0 3
2 0 0 4
2 0 0 5
2 0 0 6
105
I n j e c t i o n
a n d p r o d u c t i o n r a t e ,
b b l / d
Operational year
Oil produced
Water injected
First drilling campaign
Second drillingcampaign
Critical collapse period
Critical collapse period
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14 Oilfield Review
Together with the results from the other
major milestones of the field-redevelopment
plan, the new casing designs enabled the alliance
to begin a new drilling campaign. The third
campaign began in 2004, and by 2007 a total of
37 wells had been drilled. The alliance wanted to
drill as efficiently as possible to improve produc-
tion, but problems were encountered during
drilling. These included stuck pipe caused by dif-
ferential sticking in depleted reservoirs, prob-lematic wiper trips resulting from highly reactive
shales and well control issues introduced by
water influx from the waterflooding.
To address the hole-stability and stuck-pipe
problems, the redevelopment team began by
improving the drilling fluid design. Drillers had
been using the KLA-GARD mud additive to pre-
vent clay hydration, but it had little to no
success at inhibiting reaction in the troublesome
Casabe shales. Consequently, Schlumberger and
M-I SWACO initiated an investigation to find a
more effective shale inhibitor.
Laboratory analysis of 13 different fluid addi-
tives was conducted to compare their reaction-
inhibiting capabilities on Casabe lithology.
Experts deduced, from core and cuttings sam-
ples, that the clays and shales were highly reac-
tive to water; therefore, the optimal drilling fluid
must prevent water from contaminating them.
The KLA-STOP mud system was compatible with
the Casabe shales and had the best properties for
inhibiting these reactions: Its fluid composition
includes a quaternary amine that prevents water
from penetrating target formations by depositing
a synthetic coating along the borehole wall.
When the new system was put to use, however,
it did not meet expectations, and the reactive
lithology continued to affect drilling time. Design
iterations continued until 2008; at this point
experts had increased KLA-STOP concentration
to 2% and added 3% to 4% potassium chloride
[KCl]. However, hole problems persisted and
experts concluded that another contaminant
could be affecting the mud system. Using core
samples from a wide range of wells, analysts mea-
sured pore throat sizes and laboratory specialists
performed mineralogical analysis to determine
the causes.
14. For more on bicenter bits and reaming-while-drilling technologies: Rasheed W, Trujillo J, van Oel R,Anderson M, McDonald S and Shale L:“Reducing Risk and Cost in Diverse Well ConstructionApplications: Eccentric Device Drills Concentric Holeand Offers a Viable Alternative to Underreamers,”paper SPE 92623, presented at the SPE/IADCDrilling Conference, Amsterdam, February 23–25, 2005.
> New versus old drilling design. Original drilling designs included a traditional polycrystalline diamondcompact bit (top ), but swelling clays caused problems during tripping. Engineers designed a reaming-while-drilling (RWD) BHA that incorporated a smaller pilot bit and a reamer (tan box). RWD enabledoversized boreholes, which helped compensate for swelling and achieve target diameters for casing.Further optimizations included larger cutters and a backup set of cutters to improve ROP (blue box). Achange in the number of nozzles and in the nozzle diameter dramatically reduced the washouts thatwere causing cementing problems (bottom ). The decision to redesign the bit was made partly to copewith clay reactions. A new mud system has successfully inhibited the clay, and engineers are nowreconsidering a concentric bit to improve drilling efficiency.
Pilot bit
28 cutters
5 nozzles
5 blades
13.4-mm cutter
Reamer
33 cutters
2 nozzles
4 blades
13.4-mm cutter
81 /2-in. bit
Pilot bit
26 cutters
6 nozzles
4 blades
19-mm cutter
Reamer
27 cutters
2 nozzles
4 blades
19-mm cutter
Modification: Stabilization
pad and guardian bearing
to drill out
Washout log
Before After
81 /2-in. OD stabilizer61 /4-in. miscellaneous sub 61 /2-in. collar
Schematic of First Four Sections of the Original BHA with a Concentric Bit
Design Improvements of Bicentric Bits and RWD
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Spring 2010 15
The tests indicated that concentrations of
smectite, previously identified as the swelling
clay, decreased with depth. But the mineralogical
analysis also revealed the presence of illite and
kaolinite, which were not included as part of the
original mud system investigation. These disper-
sive clays break off into the mud upon contact
with water, causing drilling problems such as bit
balling, and also increase the viscosity of the
mud, making mud-weight curves less accurate. Amore complete understanding of downhole con-
ditions enabled engineers to design a new mud
system with improved KLA-GARD B and IDCAP D
clay inhibitors. KCl was completely removed from
the fluid, helping to reduce environmental
impact and cleanup.
The mineralogy study showed why drilling in
the waterflooded zones was obviously problem-
atic. Existing methods to avoid water influx
involved shutting in several injection wells up to
several weeks before drilling to reduce pressure.
In one extreme case 40 injectors were taken off
line to drill just 2 wells, which ultimately reduced
production rates.
Experts looked into the different ways they
could reduce water influx while also limiting any
effect on the waterflood programs. Instead of
shutting in injectors they could increase produc-
tion in layers that were drilling targets, even if
this meant producing large volumes of water. In
addition, connected producers that were cur-
rently shut in could be reactivated, and if they
had no pump, there was a possibility that enough
pressure had built up for them to flow naturally.
Only after these steps were taken and deemed
insufficient would the alliance consider shutting
in injectors.
Another part of the investigation involved
reducing injector shut-in time. To avoid water
inflow, injectors were taken off line 15 days
before drilling commenced. However, it was
found that to avoid water delivery from the injec-
tor to the drilling location, injectors could be
shut in just before the drill bit penetrated the
connected zone. Also, with the production-based
pressure-reducing measures, injector shut-in
time was reduced from seven days to just two,
depending on the level of production.The continuing difficulties with stuck pipe and
tripping problems led the alliance to seek other
options. After initial analysis of the drilling-related
issues, engineers selected a bicenter bit and ream-
ing-while-drilling technologies.14 A pilot well,
CB-1054, was drilled with the new hardware, and
tripping times were notably reduced. Engineers
used the results from the pilot well to optimize the
bit and BHA designs. Experts ran unconfined com-
pressive-strength tests on core samples taken at
numerous depths from several wells in the Casabe
field, which returned values from 585 to 845 psi
[4.0 to 5.8 MPa]. The results from this analysis
allowed the engineers to optimize the number of
primary cutters and to introduce backup cutterson the drill bit (previous page).
Since the introduction of new technologies
and updated practices, the drilling problems
faced in the Casabe field have been resolved.
Better quality holes have increased the effective-
ness of cementing jobs. Tripping times have been
reduced by more than 22%. Higher ROPs have
been achieved with updated cutter configura-
tions and a PowerPak XP extended power steer-
able hydraulic motor (below). The majority of
new wells in the Casabe field have directional
S-type boreholes deeper than 5,200 ft [1.6 km] to
avoid collisions with existing and new wells or to
reach reserves in fault zones.
New Wells and Results
The sands in the Casabe field have been exten
sively developed, but it is common in mature
fields to find oil in unexpected places. For exam
ple, some zones in the Casabe field were over
looked because the presence of low-resistivity
pay is difficult to detect using traditional resis
tivity tools; alternative tools are discussed later
in this section. Other zones in the field were inac
cessible because a lack of structural data madethe drilling risk too high. Using structural infor
mation acquired by the alliance, the operator i
now developing the highest section of the Casabe
field’s anticline structure in the B sands within
Block V.
Only one well in this block, the wildcat
Casabe-01 located downdip in the flank of the
anticline, exhibited oil shows in the thin sand
within the attic zones, but these zones had neve
been tested. A new well, located updip of the
wildcat well, was proposed to develop the A
sands. After reviewing the new 3D seismic data
and the projected length of the oil leg, geoscien
tists revised the total depth for this newly pro
posed well and suggested deepening it to reach
the B sands.
> Drilling results. The new RWD and bicenter bit drilling technologies havehad a considerable impact, improving hole quality, reducing total trip times,increasing ROP, minimizing stuck-pipe risk, reducing backreaming operations,and improving the quality of primary cementing jobs. Average drilling-job timeshave been cut from 15.3 days to 6.8 days.
Well 2 0 0 4 t o 2 0 0 6
N u m b e r o f d a y s
0
3
6
9
12
15
18
2 0 0 7
2 0 0 8
2 0 0 9
C B 1 1 2 5 D
C B 1 1 2 7 D
C B 1 1 2 6 D
C B 1 2 7 1 D
C B 1 1 4 0 D
C B 1 1 2 9 D
C B 1 2 5 1
C B 1 1 1 0 D
C B 1 1 4 7 D
C B 1 1 8 4 D
C B 1 1 3 7 D
Average drilling timefor year
2010
Optimized wells in 2009, average depth 5,400 ft
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16 Oilfield Review
Data from this new well included chromatog-
raphy performed on mud from the B sands,
which revealed well-defined oil shows, and log
interpretation confirmed the oil presence. This
oil is due to a lack of drainage from the updip
wells. New data acquired with the PressureXpress
LWD tool indicated the compartment was at
original pressure. Interpretation of data from
the CMR-Plus combinable magnetic resonance
logs confirmed movable oil (below). The interval
was completed and the well produced 211 bbl/d
[34 m3 /d] of oil with no water cut. Historically,
A sands
B sands
New well
Oil
Water
Lithology
Sandstone
Bound Water
4,850
4,950
5,000
4,900
Depth,
ft
Schlumberger-Doll Research
mD0.1 1,000
4,
Timur-Coates
Permeability
Resistivity
mD0.1 1,000
Neutron Porosity
%60 0
Bulk Density
g/cm31.65 2.65
T2 Cutoff
ms0.3 3,000
AIT 10-in. Array
Capillary-Bound Fluid Clay 1
ohm.m0.1 1,000
AIT 20-in. Array
ohm.m0.1 1,000
AIT 30-in. Array
ohm.m0.1 1,000
AIT 60-in. Array
ohm.m0.1 1,000
AIT 90-in. Array
ohm.m0.1 1,000
Invaded Zone
ohm.m0.1 1,000
Small-Pore Porosity
T2 Log Mean
T2 Distribution
ms0.3 3,000
0 29
4 , 9
0 4 t o 4 , 9
2 2 f t
M D
4 , 8 8
3 t o 4 , 8
9 2 f t
M D
0 500 1,000 1,500
Pressure, psi
Original pressure
Depletedsands
Hydrostatic
Fault 130 D e p t h ,
f t
2,000 2,500 3,000 3,5005,500
5,000
4,500
4,000
3,500
3,000
2,500
2,000
Fault 120
PressureXpress data Hydrostatic Normal gradient
> Discovering the unexpected in Well CSBE 1069. A new well drilled to reach Sand B in Block V (right ) reflected a change in previous practices; in this area the B sands were considered depleted and invaded by water. After interpretation of mud logs indicated oil shows in two locations, Schlumberger acquiredpressure and nuclear magnetic resonance logs in the low-resistivity intervals. Interpretation of the CMR-Plus log (left ) confirmed the presence of oil(green-shaded areas Track 4). Pressure data (inset middle ) indicated the bypassed oil zones were at original reservoir pressure (blue box) along thenormal gradient.
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8/9/2019 Casabe New Tricks for an Old Field
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experts did not look for oil downdip in the
Casabe field because the deeper formation had
been flagged as a water zone.
The field provided another surprise during a
routine replacement of a retired well. A produc-
ing well had been mechanically damaged as a
result of sand production induced by the water-
flood. A replacement was planned using improveddesign factors garnered from the casing-collapse
investigation. The operator drilled the well into
the C sands for coring purposes. Before drilling,
this zone was considered to be water prone, but
during drilling, mud log interpretation suggested
there might be oil in these deeper sands. Log
interpretation was inconclusive because of the
low resistivity; a new approach was required to
identify movable oil (above).
Interpretation of CMR-Plus data suggested
movable oil corresponding to the oil shows in the
mud logs. Based on these results, the operator
decided to test the well, which produced
130 bbl/d [21 m3 /d] of oil with no water cut. After
six months, cumulative production reached
11,000 bbl [1,750 m3] with no water cut. These
values represent additional reserves where none were expected.
The Casabe field redevelopment project is
now in its sixth year, revitalizing the mature oil
field. Figures gathered at the beginning of 2010
show the Casabe alliance has increased overall
production rates by nearly 250% since 2004. This
improvement is due in part to a fast-track study
that quickly identified the root causes impacting
the efficiency of the waterflood programs in the
field and discovered additional oil reserves using
newly acquired data.
The collaboration between Ecopetrol SA and
Schlumberger has been notably successful and
the partnership is currently scheduled to con
tinue the Casabe story until 2014. Production
wells are being added in the newly defined southern Casabe field, enabled by the 2007 3D seismic
survey and improved logging methods. The new
drilling practices and waterflood technologies are
expected to achieve commercial production rates
for many years to come. —MJM
> Log confirmation of low-resistivity pay. Well CSBE 1060 log interpretation indicated shaly sand zones withsalinities exceeding 50,000 ppm NaCl. Identifying oil in the presence of high-salinity formation water may be difficult
because resistivity measurements cannot be used to distinguish the two (red-shaded area in Resistivity track).Shaly sands have higher water content than sand alone, and an alternative to resistivity measurements is needed.The CMR-Plus tool, which measures relaxation time of hydrogen molecules to identify oil and water, uncovered thepresence of oil (Free oil, red-shaded area). Based on these results the interval was tested and returned clean oil,confirming low-resistivity pay in the Casabe field.
Depth,
ft
Caliper
in. 166
5,200
5,350
5,250
Free water
5,300
Free oil
Timur-Coates
mD 1,0000.1
T2 Cutoff
ms 3,0000.3
Computed Gamma Ray
gAPI 1400
Spontaneous Potential
mV –4060
AIT 30-in. Array
ohm.m 200.2
AIT 60-in. Array
ohm.m 200.2
Neutron Porosity
% 060
Bulk Density
g/cm3 2.651.65
Invaded Zone
Resistivity
ohm.m 200.2AIT 30-in. Array
ohm.m 1,0000.1
AIT 60-in. Array
ohm.m 1,0000.1
Total CMR-Plus Porosity
Capillary-Bound Fluid Oil
Small-Pore Porosity
% 040
CMR-Plus Bulk Fluid
% 030
CMR-Plus Bulk Water
% 030
Density Porosity
% 030
CMR-Plus 3-ms Porosity
% 040
Free Fluid
% 040
Free-Fluid Taper
% 040
Density Porosity
% 040
Invaded Zone
ohm.m 1,0000.1
Permeability
Resistivity
Moved Water
Bound WaterT2 Log Mean
ms 3,0000.3
T2 Distribution
290