Casabe New Tricks for an Old Field

8/9/2019 Casabe New Tricks for an Old Field

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4 Oilfield Review

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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Spring 2010 5

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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6 Oilfield Review

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.)

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La Cira–Infantasfield

Barrancabermeja Nuevo Mundo syncline Rio Suarezanticline

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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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Spring 2010 7

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

4,050

4,800

Depth, ft3,300

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6,500

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8 Oilfield Review

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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Spring 2010 9

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

4,000

4,500

B2 INF

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5,500

L o w e r s a n d s

M u g r o s a

L a P a z

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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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10 Oilfield Review

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

2,250 3,000 3,750


8/14

Spring 2010 11

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.


9/14

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


10/14

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


11/14

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


12/14

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


13/14

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.


14/14

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

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Casabe New Tricks for an Old Field

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