using borehole image data and seismic …members.igu.org/html/wgc2006/pdf/paper/add10384.pdf ·...

23rd World Gas Conference, Amsterdam 2006

USING BOREHOLE IMAGE DATA AND SEISMIC INVERSION FOR IDENTIFICATION OF FRACTURES AND RESERVOIR

CHARACTERIZATION OF GAS CARBONATE RESERVOIR AT MERBAU FIELD, SOUTH PALEMBANG BASIN, SUMATRA, INDONESIA

Main author

Ricky Adi Wibowo

Indonesia

ABSTRACT

Using Borehole Image Data for Identification of Fractures and Reservoir Characterization of Gas Carbonate Reservoir at Merbau Field, South Palembang Basin, Sumatra, Indonesia

Ricky Adi Wibowo 1) Wisnu Hindadari 3)

Parada Devy Silitonga 2) Rusalida Raguwanti 2)

Merbau gas field situated on the southern part of South Palembang Basin at Sumatra Island, Indonesia. The field was discovered in 1975, but the delineation wells were drilled in 80’s. Recently, to support the high gas energy demand in vast growing economic area of Java and Sumatra, the South Sumatra Gas Project developed the field to fulfill commitment of 300 MMSCFD supply to energy demand of industry.

The gas project in the Merbau field has drilled 10 (ten) development wells already with significantly increase the calculated reserves. Application of borehole images data on two wells (MBU#6 and MBU#BA3) clearly show that fractures were developed and influenced the capacity of gas production of each well. The carbonate reservoirs in the field are heterogeneous laterally and vertically. A further detailed sedimentary and structural study of borehole images data is thus required, including detailed facies and secondary porosity identification, and structural controls of carbonate reservoir layers in the field.

The determination of fractures density and orientation, porosity distribution of carbonate facies, altogether with seismic inversion and interpretation were proved as the main tools to help next development well location and reservoir zones.

1) Geology Technology Support PERTAMINA UPSTREAM 2) Geophysics Technology Support PERTAMINA UPSTREAM 3) South Sumatra Gas Project PERTAMINA UPSTREAM

TABLE OF CONTENTS

Abstract

1. Introduction

2. Geology, Geophysics and Reservoir

- Geology

- Seismic Analysis and Reservoir Characterization

- Seismic Facies

- Reservoir and Reserves Calculation

3. Sedimentary and Structural Study

- Boreholes Images

- Result and Interpretation

4. Development Program

- Future Applications

- Prospect Development

5. Conclusion and Recommendation

6. References

7. List Tables

8. List of Figures

1. Introduction

The devepment of Merbau Structure (Figure-1) is based on prediction of its capability to deliver gas and the amount of its reserves after D&M certification on December 1996 (Figure-3). The certified reserves showed that Merbau Structure has Proven Reserves of 292.4 BSCF (IGIP 417.7 BSCF) and Probable Reserves of 97.7 BSCF (IGIP 102.5 BSCF), all coming from BRF reservoir only.

Geologic setting of Merbau area started in Early Miocene time by depositional of Talangakar Formation (TAF) on widespread area. TAF at Merbau overlying on Basement (BSM) which is believed are Pre-Tertiary, probably Cretaceous Era in age. The sedimentation of TAF had been started in Early-Miocene time when the central part of Merbau structure was a valley where the ancient distributaries fluvial channel and bar system deposited much sand material. The fluvial patterns were run from east to the north and across the central part of the Structure and went to west and southward of the Merbau. The detail mapping of its pattern has the limitation due to seismic data quality and quantity. The distribution of TAF is not the main concern for developing the field, because the main reservoir unit target is Baturaja Formation (BRF) which was overlying the TAF at Merbau area.

At the end of sand sedimentation of TAF, the transgression period begun and part of the area was covered by seawater and formation of carbonate platform of BRF. The beginning of carbonate cycle of biota was formed with the platform as the base which elongated from northwest to the southeast. The processes are conformably and overlying the TAF and started since Mid Miocene through Late Miocene. There were two (2) facies at the western side as it shows by seismic line 83 SJ-16. To the east and southward direction at the location of MBU-1 and MBU-15 wells, some facies of reef carbonate were evolving into clastic carbonate facies and becoming thin and pinchout laterally to the east. The BRF tends to develop on south and southeastward directions. Maximum thicknesses were occurred at western side of Merbau structure. After the deposition of BRF, the tectonic were active therefore part of the Merbau area was uplifted and have sand beaches sedimentation, and the other part was unchanged and contained intercalation of sand, shale and marl as it found in cutting. The transgression stage keep move forward and the area became deep enough for shale deposition of Gumai Formation (GUF) through Late Miocene.

The sequential deposition of LAF, TAF, and BRF were also involving the active tectonic that form the main fault which was occurred from northwest, east and southeast directions that across the TAF at MBU-3 well and GUF at the MBU-9 well. The fault intensity were also produced several fractures that enhance the permeability and productivity of gas such as at MBU-4A and MBU-8. Although, this tectonic activity were also resulted in tight formation and poor permeability such as in MBU-5 and MBU-14 wells.

The well evaluation and Geology-Geophysics-Reservoir & Production (GGRP) study resulted the planning to drill 14 development wells and workover on 3 existing wells in Merbau (Figure 2).

Fig. 1: Location map of study area, and major structural lineament trends with oil field distribution in South Sumatra Basin (after Pulonggono, et al., 1992).

2. Geology, Geophysics and Reservoir 2.1. Geology

There are three potential gas reservoir in Merbau field : Sands of Gumai Formation, Carbonat of Baturaja Formation (BRF) and Sands of Talangakar Formation (TAF). Baturaja Formation is the most prospective gas reservoir in Merbau Field. It was deposited during Mid Miocene and bounded by shale of Gumai Formation (GUF) on top of BRF and sandstone of Talang Akar Formation (TAF) at the bottom of the BRF. BRF has 50-200 meter of thickness.

Geological modeling in Baturaja Formation is generated based on 2D seismic interpretation (Figure 2). The development of external and internal geometry of carbonate reservoir body can be identified to better understand sedimentation process and identify probably vertical and lateral facies changing within the reservoir.

The detailed geological model will be merged into the band limited inversion result as low frequency content to broadband the seismic bandwith.

Fig. 2: Top Baturaja (BRF) Formation Depth Structure Map in the Merbau Gas Field Area

2.2. Seismic Analysis and Reservoir Characterization

The carbonate build-up which was interpreted as reefal facies can be recoqnized in seismic line 83SJ-16. The distribution of this facies is limited at the southwest of MBU-03 well. To the northeast, MBU-01 well, the carbonate Baturaja becomes thinner and interpreted as carbonate platform. The mounded facies and lateral shifting can be identified as the internal seismic reflection package, and most probably the Baturaja carbonate in this area was deposited during transgressive environment (Figure 6).

Based on the interpretation of acoustic impedance modeling, the thickest carbonat is mainly located in the central part (Figure.5). It is commonly characterized by two onlaping landward prograding facies on top of the sunda platform that distribute from west to east of the north south potential closure.

The GWC is at the 2000 msl. TAF on the other hand, develop very well in the northeaster part.

Merbau field has 4941.12 acres reservoir area. The thickest (60 – 80 meter) calcite lithology within BRF is in the central western part (MBU-06; MBU-04A).

The heterogeneity of carbonate reservoir is also shown by inversion result (Figure.5). The acoustic impedance anomaly represented by the color code. High acoustic impedance value, which ranging from red to yellow color is correspond to relatively poor porosity than low acoustic impedance value, which ranging from light blue to green color.

The facies changing is proven from well drilling (MBU-03 and MBU-01). The DST test of production zone lies on the difference range of acoustic impedance contrast between those 2 wells (Figure 6).

The high porosity is commonly concentrated in the west side of the central area. It gradually decreases to the north and south but dramatically decrease to the west and east. Unlike the porosity, the permeability on the other hand, increases to the northward but decrease to the south, west and east. The maximum porosity is 12%; permeability is 75 mD. The least porosity is 5 % and permeability 0.1 mD in the east side of the field. Shale streaks within the reservoir body that seal the connectivity. This conditions cause the boundary of the permeability effective distribution. Combination of well to well correlation, seismic inversion and logging data indicated the tightness of Baturaja Formation.

Integrated methods used for reservoir characterization are modeling acoustic impedance and facies analysis. While seismic has no vertical resolution, well data can map out lateral change in facies distribution. Pre-Stack Time Migration (PSTM) re-processing data is preliminary step to obtain the best quality of seismic data with preserving the amplitude. Constrained Sparse Spike Inversion technique (CSSI) is then constructed using 2D seismic data constraining with MBU-01 and MBU-03 well (Figure.3).

Geological modeling in Baturaja Formation is generated based on those two wells. The development of external and internal geometry of carbonate reservoir body can be identified to better understand sedimentation process and identify probably vertical and lateral facies changing within the reservoir using seismic data. The detailed geological model will be merged into the bandlimited inversion result as low frequency content to broadband the seismic bandwith.

The initial seismic interpretation is refined using the sparse spike inversion modeling result (Figure.4). Facies analysis is done by determining a sequence characteristic in which present from seismic section and used to control the interpretation of Acoustic Impedance data. The impedance model derived from well data gives significant improvement on the seismic data allowing geological events to be identified with high level of confidence.

Based on the interpretation of acoustic impedance modeling, the thickest carbonate is mainly located in the central part (Figure.5). It is commonly characterized by two onlaping landward prograding facies on top of the sunda platform that distribute from west to east of the north south potential closure.

2.3. Seismic Facies

Facies changing is proven from well drilling (MBU-03 and MBU-01). The DST test of production zone lies on the difference range of acoustic impedance contrast between those 2 wells (Figure. 5). Reefal facies can be recoqnized from carbonate build-up which shown by seismic line 83SJ-16. The distribution of this facies is limited at the southwest of MBU-03 well. To the northeast, which is MBU-01 well is located, the carbonate Baturaj becomes thinner and interpreted as carbonate platform. The mounded facies and lateral shifting can be identified as the internal seismic reflection package, and most probably the Baturaja carbonate in this area was deposited during transgressive environment (Figure 6).

The heterogeneity of carbonate reservoir is also shown by inversion result.The acoustic impedance anomaly represented by the color code. High acoustic impedance value, which ranging from red to yellow color is correspond to relatively poor porosity than low acoustic impedance value, which ranging from light blue to green color.

Figure 3. Well seismic tie through the objective of Baturaja Fm. It is shown match between real data (second panel from the left) and synthetic seismic (third from left) using wavelet (first panel) from line 83SJ-16 through well MBU-01. Gas zone finding in carbonate reservoir Baturaja Formation.

Figure 4. Overlaying seismic data with Acoustic Impedance section which proven that inversion modeling can be a powerful tool to refine the horizon interpretation. Top of Baturaja Formation was not significantly appears using the seismic amplitude itself, but getting more clear when the final AI data is incorporated.

Figure 5. High acoustic impedance value ( red to yellow color) correspond to lowest porosity than low acoustic impedance (light blue to green) showing from Acoustic Impedance section (Final AI) through key line 83SJ-16 and constrained by MBU-03 and MBU-01 well for Baturaja carbonate reservoir. Those reservoirs can be distinguished using inversion modeling.

Figure.6 Interpretation of facies changing in Baturaja carbonate reservoir can be distinguished by acoustic impedance data. Reefal facies at the upper part is represented by low acoustic impedance value (light blue to green color) and carbonate platform at the lower part is identified by laterally distribution of high acoustic impedance value (red to yellow color).

Based on well drillings evaluation, well correlation and re interpretation on 2D seismic, resulted the proven reserves in BRF reservoir was decreasing compare to D&M certification. The new proven calculated reserve is 282.9 BSCF (80% Recovery Factor out of IGIP 353.6 BSCF) as per April 2005 (shown at Table 1 below). 2.4. Reservoir and Reserves Calculation

The main objective reservoir target in Merbau area is BRF carbonates. It lies at depth 1650 to 2100 m (tvd). The formation is divided into two different facies; they are build-up carbonate facies and clastic carbonate facies which formed on the platform.

The BRF section at Merbau has a medium average porosity, ranging from 5 – 15% with average of 11%. With a low average of water saturation (Sw) that becoming greater to the bottom. The average Sw is 28% which ranging from 10 to 35%. The average thickness of BRF is 70 m.

The recorded reservoir pressure of BRF ranging from 2750 to 2850 psia @ 1800 m (tvd) depth. The average temperature is ranging from 260 to 270 oF. The Formation Volume Factor (FVF) is 140 – 150 v/v.

The drill stem test results (DST) a good gas potential and tends to have wet gas condition which contains condensate with condensate yield of 10 – 20 bbl/MMscf. Impurities from CO2 gas of BRF reservoir ranging from 15 to 29%.

Table - 1.

The significant decrease of gas reserves mainly was the result of less acreage of the structure and less thick of the netpay compare to the previous estimation by the result of reservoir characterization.

The differences of mapping result are more caused by the distribution of hydrocarbon within the potential reservoir that could not reach the area had been predicted before. The distribution of carbonate BRF itself was widespread as it predicted, even though was not as thick as it predicted before.

3. Sedimentary and Structural Study

The South Sumatra basin is a volcanic back-arch sedimentary basin, which developed during the Mio-Oligocene as one of the most prolitic hydrocarbon basins in western Indonesia (Hamilton, W., 1989; Pulonggono, et all, 1992; Sitompul, N., et al, 1992; Hall, R., 1995; Rashid, H., et all, 1998) as in Figure 5. The study is focused on the Baturaja Formation. This formation consists principally of bedded to massive (non-bedded) carbonates ranging from reefal to non-reefal in origin, and is often fractured. The generalized stratigraphic column of the study area is presented in Figure 8.

The study area is situated in a depression bounded by approximate N3000E and N-S directed faults of major size of pre-Tertiary origin and which since the start of Tertiary sedimentary history were rejuvenated until about Mid-Miocene time (Pulonggono, et all, 1992). There are three recognized N-S running lineaments in South Sumatra, and they are now seen as elements of major size (Figure 7). The two major north-south trending lineaments are structural boundaries of a north-south trending mega-depression which is the locus of high heat-flow and where most of the Tertiary hydrocarbons in South Sumatra have been generated and produced (Pulonggono, et all, 1992).

The primary aim of this study is to relate local stress directions in the fields to both regional tectonic stress and local geologic modifications. Future potential applications of the information obtained

Status : 31 Dec, 1996 30 April, 2005

No. Parameter Drilling Result

Proven Probable Proven

1 Reservoir Volume , (Acre-ft) 834,157 204,506 703,414 2 Porosity, (%) 0.11 0.11 0.113 Water Saturation, (%) 0.28 0.28 0.284 Initial For. Vol. Factor 145.7 145.7 145.75 Recovery Factor, (%) 0.7 0.75 0.8

IGIP, (BSCF) 417.674 102.458 353.577 RESERVE, (BSCF) 292.372 97.727 282.861

Note :- Assume of GWC, mss 2000 (MBU-3)- Volume of Reservoir based on evaluation of 17 drilled wells

Well Correlation and re interpretation of 2D seismic at Merbau

GAS RESERVES ESTIMATION BRF RESERVOIR, MERBAU STRUCTURE

Based on : 17 Drilling Wells

D&M-1996 Certified

from this study for designing an appropriate production and drilling strategy in the field are also discussed briefly.

Fig. 7: Structural regime style in the back arc and magmatic arc in South Sumatra basin. The study area is within the back arc basin in which two ellipsoid models apply in this region (A and B) for Mid-Miocene up to Recent (after Pulonggono, et al., 1992).

Figure 8: Simplified stratigraphic column of the study area (modified from Sitompul, N, et al., 1992, and Rashid, H., et al., 1998)

3.1. Borehole Images

The boreholes analyzed in this preliminary study were drilled as exploration, appraisal or development wells in the Merbau. The drilling target was mainly carbonate reservoirs of the Baturaja Formation (BRF). The boreholes are mostly vertical with maximum deviation, if any, locally being up to 90. All the data used were obtained from the electrical image tools of FMI including caliper data of the tools, and other standard suite of open-hole logs. FMI images were acquired in Merbau field from wells A-3 and A-6. Both image data and standard open-hole data are generally of good quality for detailed analysis, although some sections are locally washed out by several inches.

Formation imaging using microelectrical arrays has benefited the oil industry since its introduction in the mid-1980s. The FMI (Fullbore Formation MicroImager), the latest-generation electrical imaging device, is a four-pad tool with four flaps that uses arrays of electrodes to map the conductivity of the borehole. The tool actually records four sets (90 degrees apart) of total 192 micro-conductivity curves and their respective orientation. A vertical sampling rate of 0.1 inch and a high lateral density of measurement result in to the production of high resolution oriented images, with 80% borehole coverage in 8inches hole size. The tool has a 0.2 in. (5mm) image resolution in vertical and azimuth directions. The depth of investigation is about 30 inches, similar to that of shallow lateral resistivity devices. Detailed FMI specification and tool sketch can be found for example in Serra, O., 1989 and Lufhi, S.M., 2001.

STRATIGRAPHY MAIN LITHOLOGY DEP.ENVIRONMENT TECTONIC SUMMARY

Basin sag stage

Widespread compression

Primary traps formed

Late graben fill

Graben fill & localized uplift

Mio

cene

Oli g

o ce n

eLa

teE

arly

Mid

dle

NE

OG

EN

ESERIESSYSTEM

Late

TE

RT

IAR

Y

Plio-Pleis.

PENDOPO SHALE

BATURAJA FORMATION

shales, sandstones

shales

AIR BENAKAT FORMATION shales

limestones

shales

GUMAI FORMATION shales, calc. shales

BENAKAT SHALE

TALANGAKAR FORMATION

DELTAIC-SHALLOW MARINE

FLUVIAL-LACUSTRINE

DELTAIC

DELTAIC

FLUVIAL

MUARA ENIM FORMATION

KASAI FORMATION

shales, coal

tuff

SHALLOW MARINE

DEEP MARINE

MARGINAL-NEARSHORE

Ear

ly

Rifting begins

Graben fill & localized uplift

PA

LEO

G.

Oli g

o ce n

e

NE

OG

EN

E

shales, volcanics

igneous rocks

PR

E-T

ER

T.

Late

TE

RT

IAR

Y

Eoc

ene

LAHAT FORMATION

PRE TERTIARY BASEMENT

shalesBENAKAT SHALE FLUVIAL-LACUSTRINE

FLUVIAL-LACUSTRINE

The processed images are robust methods that provide a wealth of geological information and can be used for the analysis of structures (fracture, unconformity, fault) and sedimentology and stratigraphy (bedding, textural heterogeneities, paleocurrent direction). Some authors such as Thompson L.B., 2000 and Luthi, S.M, 2001 discuss and depict a sequential flow chart of the common borehole electrical and dipmeter processing steps.

The FMI data quality is excellent throughout the logged interval in the two wells, providing good imagery of geologic features for accurate analysis.

Dual caliper data (C1/C3 and C2/C4) can be used to detect breakout and breakout direction. This analysis was done using Caliban software developed on Geoframe. The software works on the following principles ( Figure 9).

- The enlargement of the borehole in the directions of the dual caliper is computed as the difference between the actual and nominal values of the calipers. The nominal caliper values are initially set to the bit size. The adjustment of the nominal values is sometimes needed if breakout and washout occur simultaneously but in perpendicular directions, affecting each other.

- The differential enlargement is taken as a measure of ovality. An ovalisation flag is set when the differential enlargement exceeds an ovalisation threshold.

- The axis with greater enlargement is called the enlarged axis and the azimuth of this axis is deduced from the azimuth of C1/C3.

- All points where the ovalisation flag is set, the rate of increase of the enlarged caliper is computed. If this increase exceeds a rate threshold, a breakout flag is turned on.

- The breakout flag remains on until ovalisation is reduced to below the ovalisation threshold.

Figure 9: Cross sectional schematics of possible wellbore conditions and their appearance on the four dipmeter caliper log. The Caliban computation is based on these conditions (see text for details).

Recognation of Breakout and Induced Fracture

In the past, the majority of stress orientation data was obtained using four-arm caliper (dipmeter) logs. Although the dipmeter’s caliper arms can reveal the orientation of wellbore breakouts (e.g. Cowgill, S.M, et al, 1992) provided those enlargements are occasionally large enough to stop tool rotation, the tool provides little information about the detailed shape of the hole (Lufhi, S.M, 2001). Although the majority of azimuthal images have been acquired to understand the geology and petrophysics of reservoirs, the images usually contain artifacts resulting from geomechanical processes. An analysis of these artifacts is important for understanding the geomechanics of the well and improving the geological and petrophysical interpretation (Bratton, T., et al, 1999). Now borehole images are essential for diagnosing the mechanism of wellbore failure and annular pressure while drilling data can help calibrate the strength and stress parameters (Barto, C.A., 1997; Bratton, T., et al, 1999; Anwar, H.A.A., et al, 2003). For geological studies, it is important to distinguish between a pre-existing geological phenomenon and effects related to the presence of the borehole, particularly the difference between induced and natural features seen in image logs. A number of paper have been published regarding the ways to distinguish both features seen in borehole electrical images (e.g. Serra, O., 1989; Lofts, J.C, et al, 1997&1999; Haller, D., et al, 1998; Bratton, T., 1999; Lufhi, S.M., 2001; Borlan, W., et al, 2001). In accordance to the aim of this study, only two relevant induced features seen in FMI and recognized by caliper analysis are described:

Figure 10. shows the dominant orientations of breakouts and drilling induced fractures determined from FMI images in the carbonate interval (wells A-6 and A-5), that indicate the maximum and minimum principal stresses (red and violet arrows, respectively). Fig. 8B shows breakout orientations observed in both wells for entire logged intervals, and no significant changes in the orienttions.

induced fracture

max. horizontal stress breakout min. horizontal stress

A-6 A-6

A-5 A-5

Fig. 10 A Fig. 10 B A-6

A-5 A-5

A-6

Figure 11: Two FMI images showing breakouts and drilling induced fractures in well A-5, Merbau field. The direction of breakouts is to NNW, while the direction of drilling induced fractures is NE. The lithology is predominantly limestone which is generally poorly bedded with localized vugular, porous zones.

Fig.12: Two FMI images showing breakouts and drilling induced fractures in well A-6, Merbau field. Breakouts are oriented NNW, while most drilling induced fractures are oriented NE.

Drilling induced fractures

Undifferentiated beddings

Natural conductive fractures

Breakouts

xx26m

xx28m


Undifferentiated beddings


Breakouts

xx26m

xx28m



Vugular zones

xx30m

xx32m Drilling induced fractures


Vugular zones

xx30m

xx32m

Natural conducti ve fractures

Breakouts

Bedded limestone


xx23m

xx25m

xx27m

Natural conducti ve fractures

Breakouts

Bedded limestone


xx23m

xx25m

xx27m



xx68m

xx70m

xx72m



xx68m

xx70m

xx72m

(1) Breakouts appear only in the direction of maximum borehole diameter. Breakouts cause hole ovality, which is indicated by the difference between the two calipers C1 and C2 (Figs. 10, 11, 12). Hole ovality is common over the study intervals. In wells A-3 and A-6 that have FMI data, the caliper differential is generally less than 4 inches and does not affect image quality (i.e. the interpretation) significantly.

(2) Mechanically induced fractures are formed by the drilling process. The main criteria used to recognize these fractures from the FMI images are (see also Figs. 10, 11, 12): (a) an unnatural fracture never crosses the borehole (i.e. does not make a sive-wave or sinusoidal form), (b) always open, thus will be filled by drilling mud resulting in dark appearances on the FMI image, (c) cannot be micro-faulted, (d) oriented parallel to maximum principle stresses, (e) usually nearly vertical to vertical, and (f) occasionally forming a typical en-echelon pattern (petal fractures).

3.2 Results and Interpretation

The results of this study are presented in Figs 10-14 using statistical stereoplots and rose diagrams. Comparison of breakout orientations in all study wells based on caliper data is given in Figs.13-14. Fig. 15 summaries the breakout and induced fracture orientations in wells A-5 and A-6 from FMI image data. From the stereoplots and rose diagrams, the main findings can be summarized as follows:

1) The breakout orientations from the microresistivity data appear to have slightly higher variability than the caliper data. However, the differences between mean breakout azimuths determined from the two methods are insignificant overall. Results from both methods show that breakout orientations in the study fields are consistently oriented northwest - southeast (140-1600N/320-3400N). However, there is slight variation in breakout orientations in wells A-2 and A-5 (Merbau field) that are oriented 1700N/3500N and 120-1300N /300-3100N, respectively.

2) The majority of induced fractures (tensile failure vertical) in Merbau field (wells A-2 and A-6) are oriented approximately NE-SW (140-1600N/320-3400N)

Breakout orientations so far measured in a total of seven wells in the Merbau field and surroundings show an approximate north-southwest-southeast trend over the area, with the average minimum horizontal stress orientation being 140-1600N/320-3400N. However, slight different breakout orientations are observed within the boreholes from A-2 and A-5 in Merbau field. This orientation discrepancy is probably attributed to the influences of a thrust fault adjacent to well A-5 and of a normal fault adjacent to well A-2 (see Fig. 16), both of which intersect the zones under study. This may be also partly due to differences in the lithology. It has been suggested by detailed manual dip analysis on the image logs that natural fractures over the BRF in well A-6 is more intensive than the fracture development in well A-5 (Fig. 13). Additionally, recent study of well data suggests that reefal units and vugular zones are much better developed in well A-6 than those in A-5 and A-2, resulting in different rock properties.

The measurements have revealed that induced fracture elements detected both in the carbonate and basement intervals generally demonstrate a NE-SW strike. This orientation is in agreement with the present-day principal horizontal stress direction of petroleum basins in South Sumatra that is much affected by the regional collision between the Australian oceanic plate and Asian continental plate, as seen in the World Stress Map.

Figure 13: Breakout orientation determined from caliper data. The breakouts are constantly aligned NW-SE in these three wells, indicating the orientation of minimum principal stress to the northwest-southeast (N3100W-S1300E).

Figure 14: Breakout orientation determined from caliper data of selected intervals in the Merbau wells. The breakouts are constantly aligned NW-SE in wells A-1, A-3, A-6 indicating minimum principal stress orientation (approximately N3100W-S1300E). However, in well A-2 the breakout orientations differ slightly and are aligned along NNW-SSW (N3400W-S1600E). due probably to the existence of the thrust fault normal to the well (see Fig. 16).

Well: AA-2 Well: BA-15 Well: BA-16

x50

Well: A-2 Well: A-1 Well: A-3 Well: A-6

x50

Figure 15: Summary table of natural and drilling-induced features from wells A-5 (left) and A-6 (right).

Figure 16. shows direction of the regional maximum principal stress (in brown arrow) in the Merbau area based on the regional structural elements. Fig 16B shows s1 orientation in the Merbau field determined from breakouts and drilling induced fractures observed in FMI log of well A-5 that is located adjacent to the thrust fault.

Magnitude (Mean) Azimuth (Mean) Degree From North Degree From North

Carbonate Interval 8 52 350Entire Interval 14 64 238


Carbonate Interval 120 1.4 348Entire Interval 158 6.4 18

Carbonate Interval 1 45 285Entire Interval - - -



IntervalFEATURES

DIP

Number

BREAKOUT

INDUCED FRACTURE

CONDUCTIVE FRACTURE

RESISTIVE FRACTURE

BEDDING

FAULT

Magnitude (Mean) Azimuth (Mean) Degree From North Degree From North


Carbonate Interval 7 40 320Entire Interval - - -


Carbonate Interval - - -Entire Interval 1 75 280



DIP

FEATURES Interval Number

INDUCED FRACTURE

BREAKOUT

CONDUCTIVE FRACTURE

RESISTIVE FRACTURE

BEDDING

FAULT

Azimuth rosette diagrams of natural fractures and bedding dip in wells A-5 (left) and well A-6 (right).

Natural fractures Bedding dips (mostly shale dips) Natural fractures Bedding dips (mostly shale dips)

Well A-5 Well A-6

MERBAU

TOP BRF HORIZON MAPTOP BRF HORIZON MAPTOP BRF HORIZON MAPTOP BRF HORIZON MAP

S-10

S-09

S-08

A-05 A-02

A-01

A-08

A-04A

A-06

A-07

A-03

S-03

S-02

S-01

PPGS-06

S-07

S-16

B-06

G-226

J-03

B-04

B-07

B-05

S-05

-

16

-

16-

16-

16-

16-

17-

17-

17-

17-

17

-

18

PERTAMINAPERTAMINAPERTAMINAPERTAMINA PP GAS SUMBAGSEL

----1612161216121612

----

1634163416341634

----1659165916591659

----1773177317731773

----

1658165816581658

-

18

-

18

-

18

-

18

-1960

-1940

-1920

-1900

-1880

-1860

-

18

-1820 -1800

-1780

-1760

-1740

-1720

-1700

-1860

-1840

-1820

-1800

-1780

-1760

----1720172017201720

-1700 -1680

----1686168616861686 -1680

-1660

----

1828182818281828

Paleo Coast Line

Normal Fault Thrust Fault

Gas Well

Well Plan

Seismic Line

Contour Line & Depth -

18

x.x68.000x.x68.000x.x68.000x.x68.000

xxxx.x67.000.x67.000.x67.000.x67.000

x.x66.000x.x66.000x.x66.000x.x66.000

x.x65.000x.x65.000x.x65.000x.x65.000

x.x64.000x.x64.000x.x64.000x.x64.000

x.x70.000x.x70.000x.x70.000x.x70.000

x.x69.000x.x69.000x.x69.000x.x69.000

x.x71.000x.x71.000x.x71.000x.x71.000

xx8.000xx8.000xx8.000xx8.000 xx9.000xx9.000xx9.000xx9.000 xx0.000xx0.000xx0.000xx0.000 xx7.000xx7.000xx7.000xx7.000 xx6.000xx6.000xx6.000xx6.000

P E R T A M I N AP E R T A M I N AP E R T A M I N A

----

1680168016801680

----

1695169516951695

----

1765176517651765

----

1800180018001800

A

B σσσσ1

Breakout oriented N300W-S120E (minimum stress direction) in well A-6, that differ slightly to other breakout and

orientations in other Merbau wells.

0 2.0km

σ3σ3σ3σ3

4. Development Program 4.1 Future Applications

This preliminary study suggests that instabilities observed in the vertical wells will be probably exacerbated by orienting horizontal wells approximately 140-1600N/320-3400N, and that drilling in the 320-3400N direction being parallel to the breakout orientation may improve well stability. However, particular attention should be paid to the wells drilled adjacent to the faults: the orientations of breakouts and induced fractures can be affected by these faults resulting in different maximum and minimum stress orientations compared to those in other wells far from the faults.

Some zones in some of the wells were identified as productive reservoirs. They contain abundant natural fractures with various intensities. Interestingly, most of these fractures dip towards WSW-WNW, suggesting that they are associated to the NNE-SSW orientation tensional faulting present in the fields (Fig. 16). Therefore, directional wells due to SSW or NNE can be proposed in order to intersect a larger number of fractured zones and thus increase production.

4.2 Prospect Development

In the well correlation overlie seismic 2D line, shows that Merbau structure has several closures that elongated from northwest to southeast direction. The comprehensive data of cutting, logging curves and drilling parameters record showed that GUF has a limited hydrocarbon potential in the central part the block. The potential was recorded in sandstone reservoir of GUF.

The BRF hydrocarbon reservoir has only gas hydrocarbon within its central area of the block, although the distribution of BRF carbonate was extend beyond its GWC.

The highest TAF hydrocarbon potential only in the western side of the central block of Merbau structure.

In general, the GUF potential was on its lower part of formation, while the BRF and TAF potentials were on its upper part of formation.

In the structural manner, the development can be done by tracing the extension of GUF dan BRF horison closures to northeast ward of Merbau and TAF extension by looking for its paleochannel to the south of the Merbau structure present location.

The Wells development drilled base on the result of reservoir characterization and fracture determination have good a result for the prospect development (Table 2).

CONCLUSIONS

The existence and orientation of wellbore failure features (breakouts, drilling-induced fractures) are easily recognized in FMI logs of study wells due to the overall good quality of electrical images. Combined with caliper data, these images can provide accurate maximum and minimum horizontal stress directions

Maximum horizontal stress determined in both wells generally strikes NE-SW, which corresponds to the regional NE-SW compressive stress direction. Slight differences in maximum horizontal stress are observed, and they are due to the local structural influences (faulting).

When the fields are intended for future development and production, directional wells oriented SSW or NNE are advised in order to intersect the maximum numbers of productive fractured zones of reservoir.

Based on Acoustic Impedance modeling and facies analysis, Batu Raja carbonate reservoir can be identified as two major facies : Reefal facies which is characterized by low acoustic impedance value. Carbonate platform facies with laterally distribution of high acoustic impedance value.

The carbonate reservoir of Baturaja Formation in Merbau Field is commonly characterized by two

onlaping landward prograding facies on top of the sunda platform that distribute from west to east of the north south potential closure.

Status : 30-Apr-05 Sumur Test Rate @ Est. Gas Rate Max. WH Del. AOFP Date of Test Remarks

Ch. 32/64"(MMSCFD) (MMSCFD) (MMSCFD) (MMSCFD)

@ 800 psi

1 MBU-07 (AWS.1) 1.19 1.19 1.19 1.19 6 - 8 Juli 2003 5.97 8.67 9.84 18.30 19-22 Mar 2005 Ex. Nitrified Acid

2 MBU-06 (CA.2) Tbg 2-7/8" - BRF-1 (Lower) 6.85 9.28 10.37 15.54 15 - 18 Juli 2003 - BRF-2 (Upper) 6.68 9.08 10.04 13.25 10 - 14 Juli 2003 - BRF-1,2 6.96 10.04 11.26 16.46 18 - 20 Juli 2003 ( Ren. dual compl.) 13.53 18.36 20.41 28.79 Ren. Dual Comp.

3 MBU-05 (BA.3) 0.06 0.07 0.07 0.07 21-24 Juli 2003 Ex. Nitrified Acid 4 MBU-08 (PPG.4)

- BRF-1 (Lower) 5.15 6.01 6.55 6.55 17-19 Sep. 2003 - BRF-2 (Upper) 5.61 6.36 6.94 6.55 23-24 Sep. 2004 - BRF-1,2 ( Ren. dual compl.) 10.76 12.37 13.49 13.09 Ren. Dual Comp.

5 MBU-4A (AC2.S) 8.20 15.48 17.59 20.79 30 Sep - 3 Okt. 2003 Tbg 3-1/2"6 MBU-03 6.56 9.31 10.51 11.15 12 - 15 Nop. 2003 Tbg 3-1/2"7 MBU-10 (PPG.3) 3.70 3.71 4.19 4.32 29 Jan - 2 Peb. 2004 Tbg 3-1/2"8 MBU-01 7.47 15.56 17.27 19.11 8 - 11 Peb. 2004 Tbg 3-1/2"9 MBU-11 (PPG.1) 4.71 5.11 5.70 5.86 5 - 8 Mar 2004 Tbg 3-1/2"

10 MBU-13 (PPG.2DE) 1.89 1.80 2.04 2.07 18 - 21 Juni 2004 Tbg 3-1/2"11 MBU-14 (PPG.2DW) 0.93 0.80 0.93 0.93 15 - 17 Juni 2004 Tbg 3-1/2"12 MBU-15 (PPG.10) 8.72 21.44 32.54 47.46 23 - 26 Juni 2004 Tbg 3-1/2"13 MBU-16 (PPG.09) 5.96 8.66 9.73 10.61 10 - 13 Ags. 2004 Tbg 3-1/2"14 MBU-17 (PPG.07) 0.07 0.07 0.07 0.07 15 - 17 Ags. 2004 Tbg 3-1/2"15 MBU-12ST 7.64 15.79 16.79 25.06 10 - 13 Sep. 2004 Tbg 3-1/2"16 MBU-09ST 8.33 21.03 22.61 135.03 24 - 27 Nop. 2004 Tbg 3-1/2"17 MBU-02ST 8.32 22.25 24.75 32.65 30 Nop - 3 Des. 2004 Tbg 3-1/2"

Sub total MBU 86.30 166.14 184.18 339.37

TOTAL TEST 86.30 166.14 184.18 339.37

C:PPGS/MSB/DataSumur/Rekap_WT&FlowLine_Mar-2005.xls

Note : Sub total MBUMerbau Without dual completion on MBU-6 and MBU-8

PRODUCTION CAPABILITY ON MERBAU GAS FIELD PERTAMINA - PPGS 2003 - 2004

TABLE 2. WELL TEST RESULTS RECAPITULATION

The BRF hydrocarbon reservoir has only gas hydrocarbon within its central area of the block, although the distribution of BRF carbonate was extend beyond its GWC.

.The Wells development drilled base on the result of reservoir characterization and fracture determination have good a result for the prospect development.

REFERENCES Allen G.P., 1994, : Concept and Application of Sequence – Stratigraphy to Siliclastic Fluvial and Shelf Deposits. Total Scientific and Technical Centre Saint – Remy Less Chevreuse France. IPA.

Djamas.Y.S, 1986, : Biostratigraphic Study Of Wells Jene – 1, Jene – 2, Pian – 1 and Panglero – 1 PT. Stanvac Indonesia.

Geoservice PT (LTD), 1992: Studi Geokimia dan Stratigrafi Sub Cekungan Palembang Selatan. Ekslplorasi Pertamina UEP SUMBAGSEL.

Pertamina – BEICIP, 1985 : The Hydrocarbon Of Western Indonesia. Pulunggono, A , 1986 : Tertiary Structural Features Related to Extentional and Compressive Tectonic in

the Palembang Basin, South Sumatra, Proceeding 15 th IPA Convetion, pp. 187 – 213. Pulunggono, A : Haryo, A.S and Kosuma, C.G, 1992 : Pre – Tertiary and Tertiary Fault System as a

Frame work of the South Sumatra Basin : A study of SAR – MAPS, Proceeding 21 th IPA Convetion, pp. 339 – 360.

Poupon. A, Pulunggono. A, Weis.K, 1973 : Well Evaluation Conference Indonesia, Second Edition Schlumberger Indonesia.

Rashid, H., and two others, 1998. Musi platform and Palembang high: A new look at the petroleum systems. Proceedings Indonesian Petroleum Association, 26th Annual Convention, 265-276.

Robertson Handford.C, Loucks.R.G, 1993 : Carbonate Depositional Sequences and Systems Tracts – Responses of Carbonate Platforms to Relative Sea Level Changes. Arco Exploration & Production Technology Plano, Texas, USA.

Schlumberger, 1981 : Log Interpretation, Volume I – Principles Document Schlumberger Limited, New York.

Schlumberger, 1981 : Log Interpretation , Volume II – Applications Document, Schlumberger Limited, New York.

Schlumberger, 1991 : Log Interpretation Charts, Schlumberger Well Survive Indonesia. Sitompul, N., and 4 others, 1992. Effects of sea level drops during Late Early Miocene to the reservoirs in

South Palembang Sub Basin, South Sumatra, Indonesia. Proceedings Indonesian Petroleum Association, 21st Annual Convention, 309-424.

Tapponnier, P,et al, 1989 : On the Mechanics of the Collison between India and Asia, pp. 115 – 157. Vail P.R and Wornart.W.W, 1990 : Well Log – Seismic Sequence Stratigraphy An Integrated Tool for the

90’s. GESSEPM Bulletin, Foundation Eleventh Annual Research Conference Houston, p 379 – 388.

Van Wagoner.J.C, Mitchum.R.M., Campion KM, Rahmanian.VD, 1990, Siliclastic Sequence Stratigraphy in Well Log, Core and Outcrops, Concepts for High Resolution Correlation of time and Facies. AAPG Methods in Exploration Series No.7. Tulsa, Oklahoma, 55 h.

LIST OF TABLES Table 1. Gas Reserves Estimation BRF Reservoir, Merbau Gas Field Strucure Table 2. Well Test Results and Recapitulation Production Capability on MERBAU Gas Field

LIST OF FIGURES Figure 1: Location map of study area, and major structural lineament trends with oil field distribution in South Sumatra Basin (after Pulonggono, et al., 1992). Figure 2: Top Baturaja (BRF) Formation Depth Structure Map in the Merbau Field Area Figure 3. Well seismic tie through the objective of Baturaja Fm. It is shown match between real data (second panel from the left) and synthetic seismic (third from left) using wavelet (first panel) from line 83SJ-16 through well MBU-01. Gas zone finding in carbonate reservoir Baturaja Formation. Figure 4. Overlaying seismic data with Acoustic Impedance section which proven that inversion modeling can be a powerful tool to refine the horizon interpretation. Top of Baturaja Formation was not significantly appears using the seismic amplitude itself, but getting more clear when the final AI data is incorporated. Figure 5. High acoustic impedance value ( red to yellow color) correspond to lowest porosity than low acoustic impedance (light blue to green) showing from Acoustic Impedance section (Final AI) through key line 83SJ-16 and constrained by MBU-03 and MBU-01 well for Baturaja carbonate reservoir. Those reservoirs can be distinguished using inversion modeling. Figure 6. Interpretation of facies changing in Baturaja carbonate reservoir can be distinguished by acoustic impedance data. Reefal facies at the upper part is represented by low acoustic impedance value (light blue to green color) and carbonate platform at the lower part is identified by laterally distribution of high acoustic impedance value (red to yellow color).

Figure 7. Structural regime style in the back arc and magmatic arc in South Sumatra basin. The study area is within the back arc basin in which two ellipsoid models apply in this region (A and B) for Mid-Miocene up to Recent (after Pulonggono, et al., 1992).

Figure 8. Simplified stratigraphic column of the study area (modified from Sitompul, N, et al., 1992, and Rashid, H., et al., 1998)

Figure 9. Cross sectional schematics of possible wellbore conditions and their appearance on the four dipmeter caliper log. The Caliban computation is based on these conditions (see text for details).

Figure 10. shows the dominant orientations of breakouts and drilling induced fractures determined from FMI images in the carbonate interval (wells A-6 and A-5), that indicate the maximum and minimum principal stresses (red and violet arrows, respectively). Fig. 8B shows breakout orientations observed in both wells for entire logged intervals, and no significant changes in the orienttions.

Figure 11. Two FMI images showing breakouts and drilling induced fractures in well A-5, Merbau field. The direction of breakouts is to NNW, while the direction of drilling induced fractures is NE. The lithology is predominantly limestone which is generally poorly bedded with localized vugular, porous zones.

Figure 12. Two FMI images showing breakouts and drilling induced fractures in well A-6, Merbau field. Breakouts are oriented NNW, while most drilling induced fractures are oriented NE.

Figure 13. Breakout orientation determined from caliper data. The breakouts are constantly aligned NW-SE in these three wells, indicating the orientation of minimum principal stress to the northwest-southeast (N3100W-S1300E).

Figure 14. Breakout orientation determined from caliper data of selected intervals in the Merbau wells. The breakouts are constantly aligned NW-SE in wells A-1, A-3, A-6 indicating minimum principal stress orientation (approximately N3100W-S1300E). However, in well A-2 the breakout orientations differ slightly and are aligned along NNW-SSW (N3400W-S1600E). due probably to the existence of the thrust fault normal to the well

Figure 15. Summary table of natural and drilling-induced features from wells A-5 (left) and A-6 (right).

Figure 16. shows direction of the regional maximum principal stress (in brown arrow) in the Merbau area based on the regional structural elements. Fig 16B shows s1 orientation in the Merbau field

using borehole image data and seismic …members.igu.org/html/wgc2006/pdf/paper/add10384.pdf ·...

Documents