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Hydrodynamic Characterisation of the Triassic ... - CO2CRC

Hydrodynamic Characterisation of the Triassic

Showgrounds Aquifer at the Wunger Ridge

Site in Queensland: Assessing Suitability for

CO 2 Sequestration

(Appendix 10.6.3 of report no.RPT05-0225)

A. Henning, J. Underschultz, L. Johnson , C. Otto, and C. Trefry

December 2006, CO2CRC Report No: RPT06-0036


Hydrodynamic Characterisation of the Triassic

Showgrounds Aquifer at the Wunger Ridge

Site in Queensland: Assessing Suitability for

CO 2 Sequestration

(Appendix 10.6.3 of report no.RPT05-0225)

A. Henning, J. Underschultz, L. Johnson , C. Otto, and C. Trefry

December 2006, CO2CRC Report No: RPT06-0036


Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC)

GPO Box 463

Level 3, 24 Marcus Clarke Street

Canberra ACT 2601

Phone: +61 2 6200 3366

Fax: +61 2 6230 0448

Email: pjcook@co2crc.com.au

Web: www.co2crc.com.au

Reference: Henning A, Underschultz J, Johnson L, Otto C, Trefry C, 2006. Hydrodynamic Characterisation of

the Triassic Showgrounds Aquifer at the Wunger Ridge Site in Queensland: Assessing Suitabulity for CO 2

Sequestration. (Appendix 10.6.3 of report no.RPT05-0225). Cooperative Research Centre for Greenhouse Gas

Technologies, Canberra. Report Number RPT06-0036.

© CO2CRC 2006

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Table of Contents

Executive Summary ........................................................................................................................... 1

Introduction ........................................................................................................................................ 2

Methods............................................................................................................................................... 5

Data and Data Quality ....................................................................................................................... 5

Salinity................................................................................................................................................. 6

Hydrostratigraphic Setting................................................................................................................ 6

Hydrodynamic Setting ..................................................................................................................... 11

Structural Setting ............................................................................................................................. 11

Production Effects............................................................................................................................ 12

Production History ........................................................................................................................ 12

Spud Date Analysis....................................................................................................................... 14

Pre-1979 .................................................................................................................................. 16

1978-1985 ................................................................................................................................ 16

1985-1988 ................................................................................................................................ 16

Post 1988 ................................................................................................................................. 17

Summary .................................................................................................................................. 17

Pre-production Flow System ........................................................................................................... 18

~1990 Flow System ........................................................................................................................... 20

Conclusion......................................................................................................................................... 24

Recommendations ............................................................................................................................ 24

References ......................................................................................................................................... 25

Tables

Table 1. Quality statistics for measured formation pressures.............................................................. 5

Table 2. Production data for fields in the Wunger Ridge study area................................................. 13

Figures

Figure 1. Map of the Wunger Ridge study area, showing (a) position relative to the GAB and (b)

structural elements (modified after Rigby, 1987)................................................................................. 2

Figure 2.Generic cross-section across the Bowen Basin showing how hydrocarbons leak up through

the formations. The right hand side represents the Wunger Ridge study area. (Modified after

Cadman, Pain and Vuckovic, 1998)..................................................................................................... 4

Figure 3. Hydrostratigraphic setting of the Showgrounds Formation (modified after Willink, 2004).7

Figure 4. Pressure-elevation plot for Mamaree-1 showing test interval, fluid recovery, gauge

location and reliability code for each test............................................................................................ 8

i


Figure 5. Pressure-elevation plot for wells with both Showgrounds and Rewan formation pressure

data, showing test interval, fluid recovery, gauge location and reliability code for each test, (a)

Namarah-4 and (b) Link-1, Lark-1 and North Boundary-1. ................................................................ 9

Figure 6. Pressure-elevation plot for wells with Moolyember Formation pressure data showing test

interval, fluid recovery, gauge location and reliability code for each test. ....................................... 10

Figure 7. Pressure-elevation plot for wells with Precipice Formation pressure data showing test

interval, fluid recovery, gauge location and reliability code for each test. (a) Meribah-1, (b) Grail

North-1. .............................................................................................................................................. 10

Figure 8. Producing fields showing date of production, fluid type and reservoir. Zero edges of the

reservoirs and seal are also shown. ................................................................................................... 14

Figure 9. Head vs. spud data for wells sub-divided into i) along the Wunger Ridge, south of the zero

edge of the Rewan Formation, ii) along the Wunger Ridge, north of the zero edge of the Rewan

Formation and iii) off the ridge and into the basin. Vertical lines show when each field began

production. ......................................................................................................................................... 15

Figure 10. Head vs. spud data for wells sub-divided into formation. Vertical lines show when each

field began production. ...................................................................................................................... 15

Figure 11.Pre-production flow system of the Showgrounds Formation ............................................ 18

Figure 12. Potentiometric surface map of the Precipice Sandstone (modified after Scorer, 1966). . 20

Figure 13. Post-production predicted flow system of the Showgrounds Formation at ~1990........... 22

ii


Executive Summary

The Triassic Showgrounds Formation of the Bowen Basin has been identified as a potential

reservoir for the long term storage of injected CO 2 . The current model proposes injection on the

eastern flank of the Wunger Ridge with migration occurring in a westerly direction updip towards

the (by then) depleted gas fields along the axis of the ridge. A hydrodynamic analysis was

conducted on the Showgrounds reservoir to investigate the risk of vertical communication with the

overlying Precipice Aquifer of the Great Artesian Basin and assess both the original, pre-production

flow system and the current production-induced, transient flow system. The formation water flow

system is a hydrodynamic environment which may affect CO 2 migration rate and direction.

The study found that the flow systems of the Precipice and Showground formations were not in

hydraulic communication within the study area; however, there was one site where the zero edge

of the reservoir and top seal coincide, and represents a risk of leakage were CO 2 to migrate to this

location. This site is at the western edge of the Wunger Ridge, south and west of both the injection

site and the producing fields outside the anticipated CO 2 migration path, so is considered to

represent a minimal risk. The study also found that there is a hydraulic low near the southern margin

of the reservoir, south of the migration pathway, towards

which flow within the basin is directed.

The original flow rate is ~0.2m/yr (at 150 mD), and approximately normal to the proposed

migration path. This suggests that migrating formation water may deflect the movement of CO 2 to

the south by some degree. The magnitude of this has yet to be determined. Hydrocarbon production

has been underway on the Wunger Ridge for over 30 years and some fields have experienced

considerable pressure decline. A potentiometric surface was constructed for ~1990, which

demonstrates that production induced pressure decline has extended well beyond the field areas and

has significantly altered the original flow system. It has also increased the hydraulic gradient such

that the flow rate is now ~0.9m/yr (at 150 mD) and directed along the migration pathway towards

the producing fields. In the short term, this may speed up the CO 2 migration rate. Further

investigation is required to determine the magnitude and duration of these impacts.

1


Introduction

The Showgrounds Formation of the Bowen Basin of south east Queensland has been identified as

a potential reservoir for the long term storage of CO 2 (Bradshaw, et al., 2001). It forms part of a

reservoir/seal pair with the Snake Creek Mudstone and is considered to have sufficient

transmissivity and lateral connectivity to store a regionally significant volume of CO 2 (Sayers, et al.,

2005). This study forms part of a multidisciplinary investigation of the storage potential of the

Showgrounds Formation within an area on the eastern flank of the Wunger Ridge (Figure 1).

The current model proposes injection on the eastern flank with long term westerly migration updip

to the ridge, with the injected CO 2 retained by solubility and mineral trapping. The extended model

includes migration of CO 2 onto the ridge well after decommissioning of the hydrocarbon fields with

the depleted structures providing additional storage capacity. The other components of this study

can be found in Sayers et al., 2005. The hydrodynamic component described in this report will

address aspects of containment risk, specifically: i) seal capacity (top and fault) of the reservoir/seal

pair; and, ii) migration rate and direction.

(a)

(b)

Figure 1. Map of the Wunger Ridge study area, showing (a) position relative to the GAB and (b) structural

elements (modified after Rigby, 1987).

The aquifers of the Triassic Bowen Basin and the overlying Cretaceous-Jurassic Surat Basin form

part of the more regionally extensive series of interconnected aquifers that define the Great Artesian

Basin (GAB) (Habermehl, 2002). The Triassic Showgrounds Sandstone is not used as a water

resource. The overlying Jurassic Precipice Sandstone, which is an active water resource and host to

hydrocarbon production, is separated from the Showgrounds aquifer by the Triassic Moolyember

Group. The hydrodynamic flow system of the Cretaceous-Jurassic aquifers of the GAB is

reasonably well understood however, there has been little published work on the hydrodynamics of

the Triassic aquifers.

2


The current understanding of hydraulic communication between the Triassic and Jurassic aquifers in

the Bowen Basin is based on hydrocarbon migration and source rock correlation models. Cadman,

et al., 1998 created a generic cross-section across the Bowen Basin (Figure 2) describing a process

of hydrocarbon migration from deep Permian source rocks and sequential trapping either (i) within

the Rewan Formation, below the upper shaley section; or (ii) up past the zero edge of the Rewan

Formation to be trapped in the overlying Showgrounds Formation below the Snake Creek

Mudstone; and (iii) up through the Moolyember Group to accumulate in the overlying Precipice and

Evergreen Sandstone reservoirs. The hydrodynamic analysis will test this hypothesis by examining

the formation water flow system of the Showgrounds Formation and the underlying Rewan

Formation and comparing this with the formation water flow system of the Precipice Sandstone

Formation.

The movement of supercritical CO 2 is dominated by buoyancy effects. However, moving formation

water can influence the direction and rate of migration of supercritical CO 2 , the extent of which is

dependent on the hydraulic gradient over the predicted migration pathway (as well as the density

contrast between the two fluids). In addition, the original, natural flow system has been influenced

by the long term (30 years), ongoing removal of fluids (gas, oil and water) leading to declining

aquifer pressures. This has resulted in a transient flow system which is substantially different in

both magnitude and direction from the original flow system.

Characterising the flow system and its response to hydrocarbon production provides a basis for

understanding and modelling the influence of moving formation water on the migration parameters

of injected CO 2 . It also allows an evaluation of the continuity and transmissivity of the unit

(including the influence of faults and preferential flow paths) and hence the potential for

hydrodynamic trapping of injected CO 2 . This in turn may affect the injectivity parameters, including

the position and timing for injected CO 2 .

3


Figure 2.Generic cross-section across the Bowen Basin showing how hydrocarbons leak up through the formations. The right hand side represents the Wunger Ridge study area.

(Modified after Cadman, Pain and Vuckovic, 1998).

4


Methods

Standard hydrodynamic approaches to characterizing flow systems in aquifers include the analysis

of pressure data, both in vertical profile (e.g. pressure-elevation plot) and, after conversion to

hydraulic head, within the plane of the aquifer. Pressure data are supplemented with formation

water analysis and formation temperature data to aid in the evaluation of the flow system. Bachu

and Michael (2002), Otto et al. (2001), Bachu (1995), and Dahlburg (1995) provide an overview of

hydrodynamic analysis techniques.

Data and Data Quality

All of the data relevant to this study were sourced from the well completion reports (WCR) of

petroleum exploration wells and stored in CSIRO’s hydrodynamics database. This includes all

formation pressure measurements and data that are complementary to formation pressure analysis,

for example, temperature, salinity, lithology and stratigraphy. Fundamental to the database is

CSIRO’s quality control system, PressureQC , which is applied to each pressure, temperature and

salinity measurement and stored in the database. The quality controlled database is available as part

of the CO2CRC deliverables and a full description can be found in the accompanying manual

(Hennig et al., 2002).

For this study data from 85 wells was QC’d and entered into the database. The data quality is

reasonable, with greater than 50% being of moderate or higher reliability (Table 1). Most of the data

is from drillstem tests (DST’s) as only three wells had wireline formation tests (WFTs). The gauge

error for the DST’s is taken to be 30psi. There were several kicks (unexpected flow events), but

these were in the shallow formations and not included in the analysis.

The majority of pressure data are from the Showgrounds Sandstone and generally limited to one or

two DST tests per well. As the Wunger Ridge is a gas rich area, the fluids recovered were mostly a

mixture of gas, water, mud and occasionally condensate. This increases the uncertainty associated

with the conversion of formation pressure to freshwater hydraulic head. The recoveries have been

carefully examined in conjunction with all the data available for each test and posted on the maps

contained in this report.

In some areas, for example, the Silver Springs/Renlim gas field, published data were available to

estimate the potential error induced by conversion of mixed recoveries to hydraulic head (Roberts,

1992). In this case the error was small enough to allow inclusion of the data in the interpretation.

Table 1. Quality statistics for measured formation pressures.

Test Type

I

(Most

Reliable)

II

(Reliable)

Quality Code

III

(Moderately

Reliable)

IV

(Low

Reliability)

V

(Least

Reliable)

Fail

Total

WFT 0 10 (40%) 3 (12%) 9 (36%) - 3 (12) 25

DST 21 (15%) 24 (17%) 35 (24%) 20 (14%) 40 (28%) 3 (2%) 143

Kick 0 0 1 (17%) 4 (66%) 0 1 (17%) 6

Total 21 (12%) 34 (19%) 39 (22%) 33 (19%) 40 (23%) 7 (4%) 174

5


Salinity

Water in the Cretaceous-Jurassic aquifers of the GAB is predominantly fresh, with total dissolved

solids (TDS) in the range of 500-1500 mg/L and of the Na-HCO 3 -Cl type. In the south west of the

basin there are some Na-Cl-SO 4 type waters (Habermehl, 2002, Radke, 2000). In the Precipice

Formation the salinities are lower in the north east near the recharge area and higher in the west near

the discharge area (Hitchon, 1971).

The Showgrounds sediments are essentially from freshwater deposition, although there are minor

marine influences in the Middle and Upper Triassic (Hitchon, 1971).Water samples suggest that the

formation water is similar in composition to that in the Surat Basin (i.e. TDS values are generally

low and the water type is Na-HCO 3 -Cl). There was insufficient data to determine spatial variations

in chemical composition; however, the available TDS data indicate that it is appropriate in this area

to use a freshwater gradient to calculate hydraulic head values.

Hydrostratigraphic Setting

The stratigraphic setting of the Showgrounds Formation is shown in Figure 3. It is a contiguous

member of the more regional Clematis Sandstone, which outcrops in the north at the Great Dividing

Range. Throughout most of the study area the Showgrounds Formation overlies the Rewan

Formation, an aquifer and important hydrocarbon reservoir. To the west of the zero edge of the

Rewan Group the Showgrounds Formation directly overlies Permian aged formations.

The Showgrounds Formation is sealed by the Snake Creek Mudstone and the overlying

Moolyember Group acts as a secondary seal. The deepest Jurassic aquifer is the Precipice

Formation and an understanding of the vertical relationships between these units is necessary to

demonstrate the long term containment capacity of the intervening seal.

Habermehl, 2002, considers the Rewan Formation to be the bottom boundary of the GAB confined

aquifer sequence. Therefore, to characterise the formation water flow system in the Showgrounds

Formation it is necessary to understand its hydraulic relationship with the underlying Rewan

Formation and determine whether the two units are acting as a single aquifer system. If so, the

Showgrounds data can be supplemented with data from the Rewan Formation and production from

the Rewan Formation may impact the Showgrounds Formation.

6


HYDRO

Precipice

Aquifer

Snake Ck Member

Moolyember

Aquitard

Snake Ck Seal

Rewan

Aquifer

Figure 3. Hydrostratigraphic setting of the Showgrounds Formation (modified after Willink, 2004).

The Rewan Formation is generally considered to have low porosity and permeability (Butcher,

1984). The upper section is mostly shaly and considered to be a seal to the basal Rewan sands

(Elliott, 1989, Sayers, et al, 2005). Consequently, the upper Rewan is considered a barrier to

migration of hydrocarbons from the deeper parts of the basin in the east (Butcher, 1984). This

makes the zero edge of the Rewan Formation (Figure 2) an important hydrocarbon exploration

feature (Conybeare, 1970). However, producible hydrocarbons have been found within the

Showgrounds Formation above the Rewan Formation accounted for by localised faulting

(i.e. Walloon-1 as described by Brown, 1981).

The Showgrounds Formation comprises conglomerates, sandstones, siltstones and shales, deposited

in a dominantly fluvial environment (Butcher, 1984). The facies model consists of three units: a

braided and meandering fluvial channel system with high permeability; a deltaic environment where

the permeability is much more variable; and, a floodplain or overbank environment with generally

poor permeability (Sayers et al., 2005). Sayers et al have shown the permeability distribution is

dependant on the local deposition environment.

7


2

360

325

351

Figure 4. Pressure-elevation plot for Mamaree-1 showing test interval, fluid recovery, gauge

location and reliability code for each test.

This can be seen in several wells where the build-up data from DST’s clearly indicates a finite

reservoir volume.To clarify the relationship between the Showgrounds Formation and the Rewan

Formation, those wells with data in both units were considered. In the east of the study area,

Mamaree-1 had two DST’s carried out within the Showgrounds Formation which had oil, mud and

water recoveries and very minor or no gas (Figure 4).

A third DST testing the bottom of the Showgrounds and the Rewan formations recovered gas and

fresh water. The presence of gas below the water leg suggests the two formations are not in

hydraulic communication here, as suggested by the original migration model where the basal Rewan

sands are separated from the Showgrounds sands by the upper low permeability Rewan units.

However, the similar hydraulic head values for the higher Showgrounds test and the Rewan test

(within gauge error) suggest that there may be regional, hydraulic communication.

At the northern end of the Wunger Ridge, Namarah-4 had low quality DST’s measured in both units

with a difference of 21 m of hydraulic head which again suggests they may not be in

communication (Figure 5 (a). The petrophysical interpretation for this well agrees with this

interpretation as the lower test is from the basal Rewan sands and the intervening Rewan units had

low permeability.

8


Otherwise, there are three wells, Lark-1, Link-1 and North Boundary-1 which are close together,

were all drilled around the same time and have similar hydraulic head values (Figure 5 (b) and are

slightly lower than expected for pre-production pressures. At this time all production was from the

Showgrounds Formation at the major fields to the south, suggesting that the Showgrounds and the

Rewan formations maybe in hydraulic communication in this area, and that pressures in both

formations are being affected by production further south (this will be discussed in more detail in a

later section).

(A)

(B)

325

337

325

Sho w

Re wa n

336

365

386

Figure 5. Pressure-elevation plot for wells with both Showgrounds and Rewan formation pressure data, showing

test interval, fluid recovery, gauge location and reliability code for each test, (a) Namarah-4 and (b) Link-1, Lark-1

and North Boundary-1.

The Snake Creek Mudstone Member (Figure 3) has a very consistent lithology of shale and

mudstone with minor siltstone laminations (Butcher, 1984). It appears have maintained its integrity

over a large area and through structural events, as evidenced by the general lack of hydrocarbons in

the Moolyember Formation and the successful trapping of hydrocarbons within the Showgrounds

Formation (Sayers et al., 2005).

The overlying Moolyember Formation is predominantly a fine grained deltaic unit which

conformably transitions into the Snake Creek Mudstone lacustrine system. The Moolyember

Formation is expected to have substantial sealing capacity with limited vertical hydraulic

communication and extends westwards well past the pinch-out edge of the Showgrounds Formation.

There are three wells with data in the Moolyember Formation (Figure 6). The pressure data for these

wells is insufficient for interpretation; however, there is a possibility of hydraulic communication

within the reservoir portions of the Moolyember Formation between Elgin-1 and Thomby-1.

9


268

323

334

1.42

324

Figure 6. Pressure-elevation plot for wells with Moolyember Formation pressure data showing test interval, fluid

recovery, gauge location and reliability code for each test.

The Precipice Sandstone Formation is an important freshwater resource and hydrocarbon reservoir.

It is predominantly a quartzose sandstone and represents a wide spread fluvial transgression

(Exon, 1976).

There were two wells in the area with data in both the Precipice and the Showgrounds Formation

(Figure 7 ). Meribah-1 has reliable hydraulic head values of 319 and 287 m respectively, both with a

recovery of GMW. The difference in head indicates that the Precipice and the Showgrounds are not

in hydraulic communication in this well. The data for Grail North-1 also suggests a lack of

communication, but the quality of the data is much lower.

(A)

(B)

302

319

290

319

Figure 7. Pressure-elevation plot for wells with Precipice Formation pressure data showing test interval, fluid

recovery, gauge location and reliability code for each test. (a) Meribah-1, (b) Grail North-1.

10


Hydrodynamic Setting

There have been several studies on the flow systems of the Cretaceous-Jurassic aquifers of the GAB

and the boundary conditions of the basin that drive formation water flow have been well described.

The flow systems of the deeper Triassic aquifers have not been extensively studied as they are too

deep to be of interest as a water resource.

Nevertheless, as they directly underlie the Cretaceous-Jurassic aquifers and have a linked

depositional and tectonic history, the same regional flow parameters are likely to be controlling both

systems. Therefore the boundary conditions for the Cretaceous-Jurassic aquifers have been used as a

framework for the Triassic aquifers, specifically the Showgrounds Aquifer. As Habermehl, 2002

states “Most of the individual aquifers (of the GAB) are relatively uniform in their hydrogeological

characteristics within large areas, and they are continuous and hydraulically connected across the

constituent geological basins”.

The Surat Basin constitutes a hydrodynamic system that is recharged by meteoric water at the

north-eastern basin margin which is defined by the Great Dividing Range, a major continental

watershed (Habermehl, 2002, Radke, 2000, Hitchon, 1971), (Figure 1). In the north the boundary

of the Surat basin is marked by Permian and Triassic outcrop and in the east by Palaeozoic igneous

complexes, the New England High, and a subsurface basement ridge that separates the Surat from

the Ipswich Clarence Basin (Hitchon, 1971). In the west, the Nebine Ridge acts as a watershed and

separates the Surat Basin from the Eromanga Basin. Flow within the basin is directed to the

south-west and discharges at the south-west margins (Habermehl, 2002, Radke, 2000).

Hitchon, 1971, building on previous work by Conybeare, 1970 and Scorer, 1966, extended the

hydrodynamic model of the Surat Basin to the underlying Bowen Basin. The hydraulic head values

he determined for the Triassic formations at the recharge point of the Surat Basin have been used

here to constrain the hydrodynamic interpretation for the Showgrounds Formation.

Structural Setting

The zero edge of the Showgrounds Formation and the overlying Snake Creek Mudstone seal is

shown in Figure 8. Along the ridge, the Showgrounds Formation is breached by bald paleo-highs in

the Silver Springs region and to the south, indicating the influence of the Wunger Ridge (Butcher,

1984) and forming stratigraphic traps for hydrocarbons. In most places the seal overlays the

Showgrounds Formation, except to the west of the Major gas field where the zero edges coincide

and this may be a site of vertical hydraulic communication with the overlying units. Eastwards, the

formation gradually thickens into the Taroom Trough (Figure 1) until it becomes the regional

Clematis Sandstone Group past the eastern edge of the study area.

The Taroom trough shallows to the south and the zero edge of the Clematis Group is south of the

study area. There is major faulting to the east of the Taroom Trough (i.e. the Moonie fault), but the

western side is faulted only on the Roma Shelf (Hitchon, 1971). There is only minor faulting along

the Wunger Ridge, which may be associated with vertical migration and hydrocarbon

accumulations in the Showgrounds Formation, for example, Warroon-1 (Brown, 1981). To the

south and east of the study area is another Permian ridge, the Yarrandine High ( Figure 1).

11


Production Effects

Production from the Wunger Ridge study area began in 1978 and there are currently several large

gas fields and many smaller fields producing large volumes of gas, water and/or oil. The removal

of such large volumes of fluid from a reservoir can induce areas of localised pressure reduction, i.e.

drawdown. Over such a long production time and with sufficient reservoir transmissivity it is

possible that the reduction in pressure may extend for some distance from the point of production.

This can significantly increase the original hydraulic gradient. that may affect the rate and direction

of CO 2 migration.

To understand and quantify this it is necessary to separate those wells that represent the original

flow system from those that have been affected by production. In this way the pre-production flow

system can be determined and the effects of production on the flow system quantified. This is

necessary as the flow system will eventually recover to its original state, once hydrocarbon

production ceases. This has implications for the timing and location of CO 2 injection and the fate

of migrating CO 2 .

Production History

To simplify the analysis of the production data and more easily identify those wells that may have

anomalously low pressures, the wells were sub-divided into three geographically separate areas:

Area 1) along the Wunger Ridge, but south of the zero edge of the Rewan Formation; Area 2) along

the Wunger Ridge, but north of the zero edge of the Rewan Formation; and, Area 3) off the ridge

and eastwards into the basin (Figure 8). The first field to begin production from the Showgrounds

Formation was in Area 1 from the Silver Springs/Renlim gas field in October 1978 (Figure 8, Table

2), which although shown separately in Figure 8, is actually the same accumulation (Tucker, 1989;

Roberts, 1992).

The next major fields to come on line were Boxleigh (1979) and Sirrah (1985). Measurements at

both of these fields showed rising gas water contacts and decreasing pressure with accumulating

production from Silver Springs, for example, up to 30 psi/year at Sirrah (Tucker, 1989). Tucker,

using production history matching, successfully modelled the Silver Springs/Renlim, Boxleigh,

Sirrah and the nearby Taylor (1988) fields as separate accumulations communicating via a common

aquifer and hence are impacted by pressure depletion from each of the other fields. Production in

Area 1 is exclusively from the Showgrounds formation (Figure 8).

Production in Area 2 began in 1993 from both the Rewan and/or the Showgrounds formations.

The biggest fields here are Parknook and Namarah, which are producing from both the Rewan and

Showgrounds formations, and Roswin and Tinker which are producing from the Rewan and

Showgrounds formations respectively (Table 2). In Area 3 the only Showgrounds production is

from the Fairymount oil field which came online in 1985 and Louise, which came online in 1986.

Waggamba has had minor intermittent production from the Bandanna Formation and Alton has

been producing oil from the Evergreen Formation since 1966 (Figure 8, Table 2). In addition, many

of the fields are producing water, including Silver Springs. Some fields have been shut-in due to

high water cut, for example Louise, evidence of a dynamic aquifer.

12


Table 2. Production data for fields in the Wunger Ridge study area.

Field

Reservoir

Date Production

Started

Alton Evergreen 1966 Oil

Fluid

Beechwood Showgrounds 1993 Gas

Boggo Ck Showgrounds 1978 Oil

Boxleigh Showgrounds 1979 Gas

East Glen Showgrounds 1993 Gas

Fairymount Showgrounds 1985 Oil

Glen Fosslyn Showgrounds 1994 Gas

Lark Rewan 1994 Gas

Link Showgrounds/Rewan 1995 Gas

Louise Showgrounds 1986 Oil

Major Showgrounds 1995 Gas

McWhirter Showgrounds 1985 Oil

Moonie Precipice 1964 Oil

Namarah Rewan/Showgrounds 1993 Gas

Narrows Rewan 1986 Oil

North Boxleigh Showgrounds 1993 Gas

Parknook Rewan/Showgrounds 1993 Gas

Renlim Showgrounds 1978 Gas

Roswin/Roswin

North

Showgrounds 1993 Gas

Silver Springs Showgrounds 1978 Gas

Sirrah Showgrounds 1985 Gas

Taylor Showgrounds 1988 Gas/Oil

Thomby Creek Showgrounds 1979 Oil

Tinker Rewan 1993 Gas

Waggamba Bandanna 1982 Oil

Warroon Showgrounds 1994 Gas

Yellowbank Creek Showgrounds 1982 Oil

13


148:30

149:00

149:30

N

Depth toTop Permian

Broadway

Berwick

Yarrabend

Yarrabend

Area 2

Martini

-27:30 -27:30

Area 1

Area 3

Major

Zero Edge of Snake Creek Mudstone

5 10 20 kms

-28:00 -28:00

148:30

149:00

149:30

Figure 8. Producing fields showing date of production, fluid type and reservoir. Zero edges of the reservoirs and

seal are also shown.

Production in Area 2 began in 1993 from both the Rewan and/or the Showgrounds formations.

The biggest fields here are Parknook and Namarah, which are producing from both the Rewan and

Showgrounds formations, and Roswin and Tinker which are producing from the Rewan and

Showgrounds formations respectively (Table 2). In Area 3 the only Showgrounds production is

from the Fairymount oil field which came online in 1985 and Louise, which came online in 1986.

Waggamba has had minor intermittent production from the Bandanna Formation and Alton has

been producing oil from the Evergreen Formation since 1966 (Figure 8, Table 2). In addition, many

of the fields are producing water, including Silver Springs. Some fields have been shut-in due to

high water cut, for example Louise, evidence of a dynamic aquifer.

Spud Date Analysis

To analyse the effects of production on the regional flow system, the hydraulic head values for each

aquifer in each well were plotted against the date the well was drilled. Plotting hydraulic head as

opposed to pressure obviates the need to correct formation pressures along an assumed gradient.

Each well was colour coded for geographic area (Figure 9) and the same data was replotted

according to formation (Figure 10). When the two plots are examined together, the pressure

response to production over time can be seen for each formation according to location relative to the

onset of production at each field. This provides some insight into the permeability distributions and

lateral connectivity of the main producing reservoirs and any vertical communication between these

aquifers.

14


Waggamba/Yellowbank Ck

Boxleigh/Thomby Ck

Renlim/Silver Springs

Sirrah/Fairymount/McWhirter

Louise/Narrows (Re)

Taylor

Beechwood/East Glen/Nth Boxleigh/Roswin

Namarah (Re)/Parknook (Re)/TInker (Re)

Glen Fosslyn/Lark/Warroon

Link/Major

Figure 9. Head vs. spud data for wells sub-divided into i) along the Wunger Ridge, south of the zero edge of the

Rewan Formation, ii) along the Wunger Ridge, north of the zero edge of the Rewan Formation and iii) off the ridge

and into the basin. Vertical lines show when each field began production.

500

Waggamba/Yellowbank Ck

Boxleigh/Thomby Ck

Renlim/Silver Springs

Sirrah/Fairymount/McWhirter

Louise/Narrows (Re)

Taylor

Beechwood/East Glen/Nth Boxleigh/Roswin

Namarah (Re)/Parknook (Re)/TInker (Re)

Glen Fosslyn/Lark/Warroon

Link/Major

400

300

200

100

0

-100

-200

1960

1962

1964

1966

1968

1971

1973

1975

1977

1979

1982

1984

1986

Hydraulic Head (m)

1988

1990

1993

1995

1997

MOOL REWA SHOW PREP EVER PERMIAN

Spud Date

Figure 10. Head vs. spud data for wells sub-divided into formation. Vertical lines show when each field began

production.

15


Pre-1979

Wells drilled prior to production show some scatter within the data for all three areas, reflective of

local fluid potential (hydraulic head) variations (Figure 9). When this data is examined by

formation (Figure 10), it can be seen that the majority of the data is from the Showgrounds

Formation, with only one point representing pre-production values from the Rewan Formation.

In addition, there are two points from sands within the Moolyember Formation and a single point

from the Precipice Formation.

1978-1985

Between 1978 and 1985 production is only from Area 1 and there is a definite decline in hydraulic

head values in the Showgrounds Formation in this area (Figure 9). There is one high head value

from the Permian Kianga Formation (Sirrah-1), which underlies the Showgrounds Formation

(Figure 10) and shows that the two units are not in hydraulic communication on the production time

scale. The wells drilled in Area 2 have higher hydraulic head values, reflective of the original flow

system, indicating the limits of pressure decline (or the effect is minor). This may be indicative of

the decline in reservoir quality of the Showgrounds Formation in this direction as noted by Roberts

(1992).

During this time the wells drilled in Area 3 were a considerable distance from the producing fields

and are not considered likely to have been affected by declining pressures. Therefore the hydraulic

head values from these wells represent the original flow system. These wells include those around

the Waggamba field in the northeast of the study area. There are three wells with very low head

values (~100m) drilled during this period. The data for these wells have been closely examined and

two have been eliminated on the grounds of being low quality, unreliable tests. However, the head

value of 104 m (from Teelba Creek-1) cannot be explained this way and it is believed to be a

reliable pressure measurement representing an area of low hydraulic head.

1985-1988

The majority of wells drilled during this time were from Area 3 and have relatively low head values

which appear to be decreasing with time (Figure 9, and Figure 10). These wells are considered to

have been affected by the production from the Wunger Ridge fields. Two of these wells are

particularly low, 194 m in 1985 (Captain Cook-1) and 148 m in 1987 (Kippers-1). The data from

both of these wells is of reasonable quality and indicate that the influence of production induced

pressure decline extends eastwards out into the basin as early as 1985.

There are two wells with high head values from Area 1, one of these is from the Evergreen

Formation (Wonolga-2) which shows that this formation is not affected by production at this time.

The other is from Glenearn North-1, in the Showgrounds Formation. This value, although high, is

considerably lower than that measured at nearby Glenearn-1 in 1965. Both of these wells are located

at the western edge of the Showgrounds Formation and the declining head value suggests that the

pressure reduction may have extended at least this far by 1987.

There is one very low hydraulic head value of 27 m in the Showgrounds Formation in Area 1

(from a reliable DST in McWhirter-1). This well lies west along the axis of the ridge relative to the

Thomby, Boxleigh and Silver Springs/Renlim fields, which had all been producing for several years

when it was drilled. The Boxleigh field pressure had dropped by 550 psi by 1989 (Tucker, 1989)

which gives a hydraulic head value of -60 m. This suggests that the low head value seen at

McWhirter-1 could be explained by production induced pressure decline.

16


Post 1988

After 1988 the majority of wells drilled were from Area 2. There is considerable scatter in the data,

however, the head values are lower than those measured prior to production. However, the reduction

is relatively minor due to the distance from the production and reduced reservoir quality (Roberts,

1992). It is present in both the Showgrounds and the Rewan formation, but the hydraulic head

values remain close to the original pressure range.

There are two head values from wells drilled in Area 3. The one from the Precipice Formation is

very close to the pre-production Precipice Formation pressure value, indicating that the Precipice

Formation has not been affected by production; and there is no production time-scale hydraulic

communication between the Precipice and the Showgrounds formations (Figure 10). The other is in

the Showgrounds Formation at 319 m in 1996 (Grail North-1). This well is located east of earlier

wells with higher head values and so is considered to represent the pre-production flow system.

Most of the wells from Area 1 have considerably lower head values; the lowest of these is -69 m

(North Sirrah-1) indicating considerable pressure decline. There are two exceptions which cannot be

eliminated due to data quality and are considered to represent original pressures. One is at 351 m

(Beechwood-2), This well is very close to the zero edge of the Rewan Formation and may mark the

onset of the reduced permeability in the Showgrounds Formation and thus hydraulic isolation. The

other is 276 m of head at Taylor-14. Taylor-14 shows some effects of reduced pressure, but not to

the extent of the other Taylor wells drilled at around the same time, for example, Taylor-10 has a

hydraulic head value of 50 m in 1988.

The reason for this is likely to be related to permeability variations and compartmentalisation within

the Taylor Field. There are two other wells which fall below the 300 m line (Figure 10) and which

may also be affected. These are 284 m (Lynrock-2) and 289 m (Namarah-3), both in the

Showgrounds Formation. Namarah-3 cannot be explained by production induced drawdown as

Namarah-4 was drilled soon after and had a much higher hydraulic head value in the Showgrounds

Formation.

Summary

These observations demonstrate the extensive regional connectivity and transmissivity of the

Showgrounds Formation. Pressure in the southern end of the Wunger Ridge has been significantly

reduced as a result of hydrocarbon and formation water production and this has extended for a

considerable distance out into the basin. Permeability variations and reservoir quality has limited the

extension of this pressure reduction to the north end of the Wunger Ridge, however, it was present

by 1993. Given that there has been significant production from the northern end since 1993, and

ongoing production from the southern end, it is likely that the pressure decline is greater at both the

north and southern end of the ridge, and has extended much further out into the basin.

17


Pre-production Flow System

The pre-production flow system of the Showgrounds Formation is described in Figure 11. To the

north of the study area, recharge from the Great Dividing Range is directed broadly south toward

the Wunger Ridge. These contours are controlled by the potentiometric surface maps of Hitchon

(1971), and a high hydraulic head value from Amoolee-1 (645 m) some distance to the north of the

study area, not shown in Figure 11.

Along the ridge itself, flow remains broadly south and the hydraulic gradient is quite flat,

suggesting a low flow rate. What is not visible on the contours, due to the data sparsity is the

influence of the basement highs that project through the Showgrounds Formation, as at between the

Renlim and Silver Springs fields (Tucker, 1989). Along the western flank of the ridge, flow is

parallel to the zero edge of the Showgrounds Formation.

Figure 11.Pre-production flow system of the Showgrounds Formation.

18


Flow from across the entire area is directed into a hydraulic low trending southwest across the study

area (Figure 11). The lowest value is defined by Teelba Creek-1 (140m), but the discharge point of

this feature is uncertain. It may extend to the east across the thickest and most permeable part of the

basin to the Moonie Fault to escape vertically along the Moonie Fault. The potentiometric surface of

the Precipice Sandstone at the Moonie Fault is at similar values to the predicted Showgrounds

Formations potentiometric surface, which is consistent with vertical hydraulic communication here.

Wells in the area were examined; however, there was no data available to test this hypothesis

further. The other possibility is that discharge occurs to the south as shown (Figure 11).

There are several regional pieces of evidence which suggest this is the more likely scenario.

The hydrodynamic setting of the basin, described previously, shows regional discharge directed

toward the south-west. Secondly, the hydraulic head low lies within an area of high permeability or

“sweet spot” described by Tucker, 1989.

Thirdly, a large basement high, the Yarrandine high (Rigby, 1987), is located to the east of the

hydraulic low, providing the possibility of a high transmissivity “channel” as regions of high aquifer

transmissivity (i.e. thicker and more permeable) are preferred location of aquifer drainage. Finally,

the presence of a low hydraulic head value at Grail North-1 (315m) confirms this region is likely

connected in a trough of low hydraulic head.

The western edge of the hydraulic low coincides with the location of the zero edges of both the

Snake Creek Mudstone and the Showgrounds Formation (Figure 11), and form the only point of

potential communication between the Showgrounds and the Precipice Sandstone. It can be seen

from comparison of the two maps that the hydraulic head values in the Precipice Sandstone are

very similar to those in the Showgrounds Formation. In addition, there are two hydraulic head

values from Elgin-1 (334 m) and Donga-1 (323 m) measured in sands within the Moolyember

Group.

Both of these values were taken from Scorer, 1966, and the raw data was not available for

examination, however, both are very similar to the hydraulic head values seen at the edge of the

Showgrounds Formation (Figure 11), and very similar to those contours interpreted by Scorer, 1966,

for the overlying Precipice Formation (Figure 12). The similarity of these points suggests that there

may be communication between these units in this region, however the direction of flow is unclear.

Within the Showgrounds aquifer, even if a portion of the flux were to be on a westward directed

streamline into the Precipice, the geometry of the hydraulic head low (even lower than the values in

the Precipice) captures most of the flux and directs flow away from this edge and out to the south of

the study area.

The flow rate in the pre-production system in the vicinity of the injection point for CO 2 is about 0.2

m/year and directed almost at right angles (dark green arrow on Figure 11) to the predicted

migration pathway of buoyancy driven CO 2 (red arrow on Figure 11). The flow rate is based on an

average permeability estimate of 150 mD for the area (Sayers et al., 2005). Given the relatively low

structural gradient (tilt of the base seal) of the Showgrounds Formation, the impact of the

potentiometric impelling force may be significant. This will form the basis of investigation in the

next stage of this study.

19


The potentiometric surface map for the Precipice Sandstone Formation is shown in Figure 12.

It should be noted that this map was created in 1966 and as the Precipice Sandstone is an active

water resource there may be unrecorded local variations, as suggested by more the recent data added

to Figure 12 during this study. The absolute values of the contours for the Precipice Sandstone are

not dissimilar to the Showgrounds, indicative of their regional relationship. However, there are

significant differences in the head values at specific locations and in the local flow directions.

Significantly, the location of the hydraulic low in the Showgrounds Formation corresponds with a

high in the Precipice Formation. Overall comparison of the two flow systems shows that the two

units are not in hydraulic communication within the study area.

N

5 10 20 kms

Figure 12. Potentiometric surface map of the Precipice Sandstone (modified after Scorer, 1966).

~1990 Flow System

It is evident that there has been considerable decline in formation pressure within the Showgrounds

Formation since the beginning of hydrocarbon production on the Wunger Ridge. It is also evident

that this effect has extended for a considerable distance away from the producing fields and out into

the deeper parts of the basin. The spud data analysis in combination with the pre-production flow

system allows for a quantitative evaluation of this decline for particular time slices.

This in turn can be used to predict the induced hydraulic gradient in the future and to model the

effect this gradient may have on the rate and direction of movement of injected CO 2 .

20


The analysis may influence decisions on the injection location both from timing of CO 2 arrival at

producing oil and gas fields and migration direction. The highest concentration of data distributed

between the sites of production (along the axis of the ridge) and the greater basin area was obtained

in the period between 1986 and 1991, some 10 years after production began (Figure 13).

This period pre-dates production from the northern end of the Wunger Ridge, so pressure decline is

only being induced from the southern end. Data from this period is also confined to wells drilled on

the western side of the hydraulic low described previously, as the only wells available on the eastern

side (around the Waggamba field) pre-date production.

On the southern end of the Wunger Ridge the only recent well with reasonable data is North

Sirrah-1, which has a hydraulic head value of -69 m. This is not unreasonable given that Tucker

(1989) noted pressure drops in the Sirrah field prior to production of up to 30 psi/year and most of

the Taylor wells fit into this scenario. Taylor-14 is a little more difficult to explain as it still has a

hydraulic head value of 276m in 1989.

However, Taylor-14 is off structure and may exist in a lower permeability zone. Additional data for

(Figure 13) was obtained from the drawdown rates discussed in Tucker (1989), specifically for the

Boxleigh field (-72m, 1989) and for Silver Springs (8 m, 1989). A hydraulic head value of -448 m

was calculated from a DST measured for Boxleigh-6 in 1989, but the data was of low quality. The

Tucker (1989) paper included data from all the wells, production data and static gradient tests and

the value obtained from this paper was considered more reliable. On the western side of the ridge,

slight drawdown effects have been noted at Glenearn North-1 and at Lynrock-2.

21


Figure 13. Post-production predicted flow system of the Showgrounds Formation at ~1990.

The most recent of the wells drilled on the flank is Louise-1, which at 263m is considered to have

experienced a drop of approximately 120 m over six years. Examination of Figure 13 shows that

the group of wells around Louise-1 seem to show differential drawdown rates. As these wells are

quite close together both spatially and chronologically, the reason for the spread in data may be

reflective of permeability variations. Tucker, 1989, describes a “sweet spot” area of high

permeability, which includes Captain Cook-1 and Kippers-1, but excludes Louise-1 and Narrows-1.

Using the original hydraulic head contours, the hydraulic head measured at the time of drilling and

assuming a constant rate of pressure decline, an annual drawdown rate was calculated for four of

these wells, Kippers-1, Harbour-1, Causeway-1 and Louise-1 and used to extrapolate a hydraulic

head value at ~1990 to provide a basin-wide picture for this time period.

22


These extrapolations give a hydraulic head value of 170 m for Causeway-1 and Harbour-1, 182 m

for Louise-1 and 80 m for Kippers-1. Given this information, a possible flow system for ~1990 has

been constructed. It describes a hydraulic low centred on the Silver Springs/Renlim field. The

contours are extended out into the basin, based on the extrapolated 1990 values for Kippers-1,

Louise-1 and Causeway-1, but, given the inherent uncertainties, have been represented by the

dashed 100, 150 and 200m contour lines (Figure 13).

Although there are no recent wells available around the Waggamba field, given that drawdown from

the gas fields along the ridge has extended out as far as Louise-1, and the position of the high

permeability “sweet spot”, it seems likely that there is at least some degree of pressure decline being

felt at the wells around this area. The contours are terminated at the observed reduced drawdown

effects controlled by data at the northern end of the ridge (i.e. Taylor-14 and Beechwood-2).

The interpreted ~1990 hydraulic head map shows that flow from all sides of the basin is now

directed towards the low at Silver Springs/Renlim. The flow rate towards this point (0.9 m/year

based on a permeability of 150 mD) is significantly higher than it was for the original flow

conditions, and the direction has changed to be almost parallel to the predicted updip CO 2 migration

path. The effect of the increased potentiometric gradient will be to speed up the migration rate of

injected CO 2 .

In addition, although there is no data available, production from the northern end of the ridge has

been underway since 1993 and it is likely that there has been pressure reduction from that area also

(represented on Figure 12 by a dashed contour line in area 1 with no value assigned to it).

In summary, although Figure 13 represents the production affected flow pattern in 1990, there has

been continued production from fields in both the northern and southern ends of the Wunger Ridge.

It is possible that the current pressure decline is more extreme and the induced hydraulic gradient

even steeper. Inclusion of production data and numerical simulation is required to understand and

quantify these effects. Moreover, this model assumes uniform regional connectivity, which given

the facies model is unlikely to be the case. It is more likely that the effects are channelled along

zones of high permeability and greater understanding of the patterns of production induced

drawdown will provide insights into the preferential migration pathway of migrating CO 2 .

23


Conclusion

The objective of the hydrodynamic analysis was to provide input into the feasibility of long-term

containment of injected CO 2 into the Showgrounds Formation. The hydrodynamic analysis

confirmed that vertical communication between the Showgrounds Formation and the overlying

Jurassic reservoirs, specifically the Precipice Formation is unlikely. There is one site of potential

leakage which is at the south-western edge of the study area but this lies outside the predicted

migration pathway. The original formation water flow direction is southwest, almost at right angles

to the predicted migration pathway of injected CO 2, at a rate of about 0.2 m/yr (at 150 mD).

The impelling force of the moving formation water will have an effect of deflecting the CO 2 south

by some degree. The magnitude and significance of this deflection is unknown at this time. Flow is

directed from all sides of the area into a hydraulic low south of the migration pathway which is

postulated to exit to the southwest of the study area.

The Wunger Ridge has been an oil and gas producing area for nearly 30 years and the Showgrounds

aquifer has experienced considerable pressure depletion. The radial extent of this depletion is

unclear, but available data show it to have extended into the deeper parts of the basin as early as

1985. Wells in the deeper parts of the basin are experiencing differential rates of drawdown which

may be related to the permeability distribution within the Showgrounds Formation and correlation

of these may prove useful in further defining the permeability distribution.

Using the most current information available, a production induced flow system for the early 1990’s

was constructed. This showed that formation water flow in the study area is now directed towards

the producing fields. The flow rate has also increased to an average of about 0.9 m/yr (at 150 mD).

This means that the formation water is now moving in the same direction as the predicted updip

migration of buoyancy driven CO 2 . The effect of the coincident formation water flow may be to

speed up migration rate and reduce the time taken for CO 2 to arrive at the producing fields. Given

that production from the area has been ongoing since this time, it is likely that the induced hydraulic

gradient today is even higher.

Recommendations

• Access to production data and history matching may be beneficial.

• Correlation of pressure build-up patterns with facies model.

• Driving force vector analysis on the effect of the original and current hydraulic gradient on

migrating supercritical CO 2.

24


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