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The permeableness of coal is recognised as the most of import parametric quantity commanding Coal Seam Gas production for it measures the easiness with which reservoir fluid moves through the coal, finding the measure of gas that can be recovered from the reservoir ( Guo, Mannhardt & A ; Kantzas 2008 ; Shi & A ; Durucan 2004 ) . Damage to the close wellbore permeableness during boring operations can significantly impact the reservoirs production, cut downing the overall gas recovery and decreasing the value of the resource ( Jahediesfanjani & A ; Civan 2005 ) . This boring harm is referred to as formation harm and is measured utilizing a mechanical Skin Factor, s, which is related to the deepness and grade of permeableness change illustrated in the equation below.

This skin factor is a dimensionless unit, where a positive value indicates that formation harm is present whilst a negative value indicates improved permeableness around the wellbore. Skin values typically range from -8 to 20 with a value of -8 bespeaking a important addition in permeableness around the wellbore and a value of 20 stand foring major permeableness bead through the damaged zone ensuing in a important decrease in gas recovery.

This method of quantifying formation harm assumes that permeableness is changeless throughout the reservoir, and any changes in near wellbore permeableness are the direct consequence of boring harm. Whilst these premises are sensible when working with conventional reservoirs, many believe that due to the different construction and mechanical belongingss of coal, its permeableness is more stress-dependent and complex than most reservoir stones and hence non changeless during production ( Guo, Mannhardt & A ; Kantzas 2008 ; Reid 2010 ; Saulsberry, Schafer & A ; Schraufnagel 1996 ) . This makes it difficult to find whether measured permeableness alterations in the close wellbore locality are entirely due to formation harm or whether other mechanisms are impacting the permeableness of the coal.

This undertaking was undertaken in partnership with Origin Energy with the intent of look intoing whether tegument values calculated for CSG Wellss were an accurate step of formation harm or if other factors were impacting the consequences. There were two parts to this undertaking. The first portion was to look into the possibility of taking the sensed harm zone of a well through the procedure of under-reaming. Under-reaming involves boring out subdivision of the well, increasing the well radius past its original drilled size and hopefully taking any formation harm caused during the initial boring of the well. If the tegument values calculated for each well were genuinely stand foring formation harm so trials conducted after the remotion of this harm zone should reflect a important decrease in tegument values. If formation harm can be reduced or removed utilizing this process so the commercial productiveness of the well will be increased, supplying a greater value to the company.

The 2nd portion of this undertaking investigated the sensitiveness of tegument values to the force per unit area drawdown imposed on the coal by manner of H2O shock absorber. Changing the magnitude of force per unit area drawdown will impact the emphasis governments of the coal around the wellbore and the object of this probe was to find if this alters the skin consequences calculated. If tegument is shown to be sensitive to coerce drawdown so we can reason that the tegument values calculated are non entirely the consequence of formation harm but are being affected by the mechanical belongingss of the coal.

2.0 Background and Literature Review

2.1 Coal Seam Gas

2.1.1 Introduction

Coal Seam Gas is an unconventional natural gas resource that is deriving increasing world-wide attending. In recent old ages CSG has grown into an of import natural gas resource in Australia, providing about three quarters of the Queensland gas market ( Queensland Government, 2010 ) . Unlike conventional gas reservoirs, the gas in CSG reservoirs is stored by surface assimilation in the solid matrix of the coal seams. The ability of coal to hive away gas is a map of coal rank, temperature and force per unit area which is related to char deepness ( Gash, 1991 ) . Large sums of gas can be stored at low force per unit area in coal reservoirs ; therefore the force per unit area must be drawn down to a really low degree to accomplish high gas recovery ( Gas Research Institute, 1996 ) . This force per unit area decrease is achieved by pull outing big sums of reservoir H2O from the coal seams. Coal is a double porousness reservoir stone which has a microporous matrix and a web of natural breaks known as cleats. Although cleats have really low porousness, & lt ; 2 % , they are entirely responsible for the permeableness of a coal seam ( Chen et al. , 2006 ) . Permeability of coal is recognised as the most of import parametric quantity commanding CSG production ( Guo et al. , 2008 ) .

2.1.2 Double Porosity Reservoir Systems

Coal seam gas reservoirs are double porousness reservoir systems, which consist of two porous media parts – primary and secondary porousness. The primary porousness system is made up of the coal matrix with the micropores of the coal estimated to hold diameters randing from 5 to 10 Angstroms ( Harpalani 1999 ) . The belongingss of the coal matrix are controlled by sedimentary procedures and post-depositional lithification. The secondary porousness system consists of a closely separated natural break web environing the matrix, called the cleat system, formed in response to coalification, local structural characteristics, and other variables. The coal cleat system is by and large extraneous with one way cross-cutting the other. The dominant cleat is normally called the face cleat which is normally uninterrupted throughout the coal. The cleat orientated approximately perpendicular to the face cleat is called the butt cleat, which is discontinuous and terminates at intersections with the face cleat. Figure thirty below shows a two dimensional representation of the cleat system.

Butt Cleats

Matrix Block Containing Micropores

Face

Cleatss

Figure xxxx: Dual Porosity System of Coal

Other than the face and border cleat system there is another set of natural breaks throughout the coal, the horizontal spacings between different coal beds known as bedclothes planes. Based on the three dimensional break system early literature frequently represented the physical coal construction utilizing a three-dimensional theoretical account dwelling of several regular hexahedrons put together, shown below in figure xxxxxxxxxxxxxx.

Figure xxxx: Cubic Model of Physical Coal Structure

In 1980 Reiss stipulated that due to the corpulence the bedclothes planes do non frequently conduct fluid and are of small involvement in fluid flow in coal. In order to diagrammatically stand for the flow of fluid through the perpendicular and close perpendicular cleat system a match-stick theoretical account was suggested and has been widely accepted since.

A CSG reservoir is a heterogenous medium that contains secondary porousness of higher permeableness than the primary porousness. Most of the fluid stored in the reservoir is contained within porousness developed in the coal matrix. The permeableness of the coal matrix is by and large believed to be in the scope of one microdarcy or less because of the little size of the matrix pores. The break porousness ( secondary porousness system ) by and large ranges from 0.1 to three per centum. The absolute permeableness of the secondary porousness system is by and large greater than one millidarcy in commercially developed CSG reservoirs.

2.2 Regional Geology

2.2.1 Surat Basin

The Surat Basin covers an country of about 270,000 km2 in southern Queensland and northern New South Wales. Up to 2500m of Jurasic and Cretaceous deposits were deposited into the basin in response to a period of overall intracetonic thermal droop. The deposits excessively unconformably on the scoured surfaces of Late Carboniferous to Triassic deposits of the Bowen and Gunnedah Basins every bit good as older cellar stones of the Tasman Fold Belt. To the West of the Basin, the Surat units interfinger across the Nebine Ridge with those of the Eromanga Basin, and eastward across the Kumbarilla Ridge with the Clarence-Moreton Basin. These interrelated basins constitute portion of the Great Artesian Basin System. Regionally remission was comparatively uninterrupted and widespread and the basins by and large retain comparatively simple geological constructions with shallow dips and small grounds of sidelong tectonic compaction. Late flection is apparent during the ulterior portion of the basins development.

Six major ticketing upward rhythms have been identified within the Surat Basin dominated by fluvio-lacustrine deposition during the Jurassic and going increasingly marine during the Cretaceous ( Exon 1976 ; Exon & A ; Burger 1981 ) . The fluvio-lacustrine sedimentary rhythms typically consist of coarse quartzone sandstone frading to labile sandstone, siltstone, mudstone and coal. Each rhythm is defined by a alteration in depositional environment from dominantly higher energy braided watercourses, to take down energy weaving stream environment with associated swamps and lakes. Towards the terminal of the Early Cretaceous, flood of the land through major alterations in sea degree led to the deposition of preponderantly coastal field and shallow Marine deposits.

2.2.2 Walloon Subgroup

The Walloon Coal Measures or Subgroup are Middle Jurasic in age, and stand for the top sequence within Cycle 2 of the Surat Basin subdivision. They conformably overly the Hutton Sandstone and are at times unconformably overlain by the Springbok Sandstone which erodes the upper portion of the Walloons.

The Walloon Subgroup thickens to the nor’-east to more than 400m around the Mimosa Syncline. The Walloons Subgroup contains legion coal seams that have been extensively explored for open-cut coal resources peculiarly in the Miles and Chinchilla country where they outcrop. The deposits consist really all right to medium grained volcanolothic sandstones, siltstones, and claystones with associated coals deposited in alluvial field depositional environments that hosted aerially restricted peat quags and lakes in a part affected by airfall tephras.

The Walloon Subgroup is subdivided into the Juandah Coal Measures, Tangalooma Sandstone and Taroom Coal Measures ( Jones & A ; Patrick 1981 ; Scott et Al. 2007 ) . Origin ‘s work in the country supports this sub-division and has farther divided the Juandah Coal Measures into Upper and Lower subdivisions divided by the Juandah Sandstone.

The coal seams are characteristancally rich in vitrinite and hapless in inertinite. Vitrinite content scopes from 70 % to more than 90 % and liptinite content ranges from 10-20 % . Inertinite content is by and large less than 1 % but can make up to 5 % in the thicker seams of the Upper Juandah and Taroom Coal Measures.

The coal are sub-bituminous in rank, by and large dull and high in ash forming thin plies that are interbedded with claystones and siltstones to organize this coal bundles. Individual coal seams ( plies ) can non be traced for more than a few kilometres, but coal bundles can be traced basin broad.

Reservoir Property Determination

When qualifying the reservoir belongingss of the Walloons, it is of import to retrieve that the coal steps are made up of 30-50 plies of coal over a 200-400m subdivision and each ply may hold really different belongingss. However, from nucleus analysis to day of the month throughout the basin, similarities between coal belongingss of single coal steps ( ie UJCM, LJCM and TCM ) have been observed and for this ground mean coal belongingss have been calculated for each of these and used in Reserve/Resource estimations.

Net coal thickness for each well was calculated utilizing a log-derived denseness cut-off of 1.75g/cc utilizing the GeologTM package bundle. This cut-off has been derived through a elaborate comparing between log informations, image log informations and nucleus regionally. For each well the derived net pay/coal were choice checked against Gamma, Caliper and Resistivity response to corroborate that merely coal had been included. For Wellss that had no or hapless geophysical logs, and nucleus was available, net coal was included from nucleus descriptions. Net coal thickness have been recorded for the UJCM, LJCM and TCM.

Gas Contentss were measured from HQ coreholes utilizing the “ Direct Desorption Method ” ( Australian Standard 3980-199 ) . Proximate analysis ( ash, wet, volatile affair, fixed C and comparative denseness ) was conducted for all samples subjected to desorption proving. Adsorption Isotherms were besides conducted on specific samples from relevant coreholes.

3.0 Data Collection

3.1 Drill Stem Testing Procedure

For each probe the tegument and permeableness values were obtained utilizing drill root trials. A DST is a conventional method of formation proving used to supply an indicant of flow rates, inactive and fluxing bottom hole force per unit areas every bit good as a short-run force per unit area transeunt trial of the reservoir ( Earlougher 1977 ) . Analysis of the DST transient force per unit area informations can supply an estimation of formation belongingss and wellbore harm, which is used to gauge the well ‘s flow potency.

A DST is run by take downing a particular tool mounted on the terminal of the drill threading into the wellbore. A simple conventional diagram of the straddle-packer DST tool used is shown in Figure twenty with the chief characteristics dwelling of three force per unit area entering devices, two baggers and a set of flow valves that can be opened and closed from the surface ( Horne 1995 ) .

Figure thirty: DST tool conventional diagram

Once the tool is lowered to the proving zone the baggers are inflated on either side of the proving country to insulate the zone from the remainder of the well. Before the trial begins, a pre-determined volume of H2O ( known as the H2O shock absorber ) is poured into the drill root to supply a backpressure on the formation face in order to command the fluid flow rates ( Bourdet 2002 ) . The size of the shock absorber is judged by its per centum of the sum drill root volume, for illustration a 10 % H2O shock absorber is 10 % of the sum drill root volume. Once the H2O shock absorber is in topographic point, the valves inside the tool are opened and fluid from the stray zone flows through the tool and into the drill threading whilst the force per unit area recording equipments chart the changing force per unit areas. After a pre-determined flow clip, the valves are closed and the force per unit area builds up. A typical trial would normally dwell of four periods – a short production period ( the initial flow period ) , a short introvertish period ( the initial buildup ) , followed by a longer flow period ( the concluding flow period ) , and a longer introvertish period ( the concluding buildup ) ( Earlougher 1977 ) . The initial flow and build-up periods are performed to gauge the initial reservoir force per unit area. The concluding flow and build-up periods are performed to roll up the information required to gauge the reservoir fluid and flow belongingss. Figure ten below shows an illustration schematic of a DST force per unit area response.

Figure ten: Example of DST force per unit area Response

Over the period the force per unit area is lifting at a changeless rate as the tool travels down the well to the proving zone. At the tool is opened and there is an instantaneous force per unit area bead from the initial hydrostatic force per unit area ( Pih ) down to the initial streamlined force per unit area for the first flow period ( Pif1 ) . The period is the initial flow period and normally merely lasts for a short period of five to thirty proceedingss. The intent of this period is to alleviate the boring fluid hydrostatic force per unit area trapped below the bagger before opening the valve. Ideally, the period should be long plenty to bring forth the proving interval fluid volume through the tool to assist forestall tool stop uping jobs. The length of the initial flow period depends on the deliverability of the well. Wells with high deliverability will hold high flow rates and the proving interval fluid volume will be produced in less than five proceedingss. In low deliverability wells a longer clip will be needed. Flow times longer than 30 proceedingss are non recommended because of the inordinate initial build-up clip needed to gauge the initial reservoir force per unit area. As the formation fluid flows through the tool into the drill pipe the force per unit area increases making the concluding flowing force per unit area for the first flow period ( Pff1 ) merely before the tool is closed.

At the tool is closed and the force per unit area builds up until where it reaches the initial shut in force per unit area ( Pisi ) . This period between and is referred to as the initial build-up period and during this period the introvertish force per unit areas are measured as a map of clip. These force per unit area so can be extrapolated to the force per unit area that would ensue it the well was invalid for an infinite length of clip. The extrapolated force per unit area is an accurate estimation of the initial reservoir force per unit area at the deepness of the force per unit area guage. The recommended length of this build-up period is between four and eight times the length of the initial flow period or 20 proceedingss to two hours. This trial length is necessary to avoid drawn-out extrapolation.

This procedure is so repeated for the concluding flow and construct up periods. At the tool is opened once more and the force per unit area drops down to the initial streamlined force per unit area for the 2nd flow period ( Pif2 ) . The period is the concluding flow period. The chief aims of the concluding flow period are to bring forth a important volume of reservoir fluid and to close the well in before the well kills itself ( when bore pipe hydrostatic force per unit area peers reservoir force per unit area ) . The trial length depends on the reservoir force per unit area and deliverability. When surface entering bottomhole force per unit area gages are used, the trial can be monitered and introvertish at the proper clip. Without surface recording gages, it is necessary to supervise the “ blow ” at the bubble hosiery located on the choking coil manifold to choose the proper introvertish clip. Again during the flow period formation fluid flows through the tool into the drill pipe doing the force per unit area to additions making the concluding flowing force per unit area for this 2nd flow period ( Pff2 ) merely before the tool is closed.

At the tool is closed and the force per unit area builds up to the concluding shut in force per unit area ( Pfsi ) at. During this concluding flow period bottomhole force per unit area informations is collected which will be used to gauge the reservoir flow belongingss and geometry every bit good as the mean reservoir force per unit area at the clip of the invalid. The length of this period should be at least 1.5 times the length of the flow period.

3.2 Analysis of Drill Stem Trials

The followers are some of the parametric quantities which may be determined from a well run DST utilizing the rules of force per unit area buildup analysis in radial flow system.

Inactive Reservoir Pressure

This is a mensural measure if the shut in force per unit area curves have been stabilised automatically ; otherwise it is derived by mathematical extrapolation.

Permeability thickness, kh

Derived straight from the DST analysis without debut of any parametric quantities from other beginnings.

Average effectual permeableness, K

Derived from the DST analysis and a log estimation of the perpendicular footage of uninterrupted porousness tested.

Skin factor

Stabilised productive index

Absolute unfastened flow capacity

Pressure depletion

In topographic point militias

Radius of probe

Barriers in the reservoir

Once the trials are finished the force per unit area charts and recorded flow rates are analysed against mathematical theoretical accounts utilizing PanSystem good test analysis package to cipher the permeableness and tegument values. Within this package the Horner method of analysis is used which assumes the undermentioned ideal conditions:

Radial flow

Reservoir fluid flows into the wellbore every bit from all waies in the formation.

A homogenous reservoir

This assumes changeless features throughout the length and thickness of the reservoir. Any values calculated from trial informations so go norms over the country tested.

“ steady province ” conditions of flow

infinite reservoir

individual stage flow

Generalised Superposition Plot which is used for build-up or Drawdown trial with a multi-rate history utilizing an tantamount clip map based on work by Agarwal.

Agarwal, R.G. : A ” A New Method to Account for Producing Time Effects when Drawdown Type Curves are Used to Analyse Pressure Build-Up and Other Test Data ” , paper SPE 9289, presented at the 55th Annual Fall Meeting of the SPE, Dallas, Texas, Sept. 21-24 1980.

The trial period to be analysed starts at [ Tj, P ( Tj ) , q ( Tj ) ]

What is plotted:

Y axis: Rate-Normalised Pressure

( 3.1 )

X-axis: Log ( Equivalent Time, a?†te )

( 3.2 )

Where:

( 3.3 )

Ti ( i=1, 2, … . M ) are the times of the rate alterations prior to the informations point t. ( TM, qM ) is the last rate alteration before the informations point at t. These are read from the rate alteration tabular array up to the start of the trial at TJ, so from the rate column.

( 3.4 )

gr ( TJ ) is a changeless ; the value of log ( a?†te ) up to the start of the trial at t=TJ

Radial Permeability ( K ) :

( 3.5 )

Skin Factor ( S ) :

( 3.6 )

m = incline of line per log rhythm

int = intercept of line at

good locations

4.0 Safety

5.0 Consequences and Discussion

Table 1 below shows a sum-up of the force per unit area drawdown, tegument ( S ) , permeableness ( K ) and productiveness index ( PI ) calculated from H2O shock absorber DSTs. These consequences are calculated from the mainflow periods of each DST which has a longer flow and build-up clip leting the well to make radial flow.

A

Water Cushion

Pressure drawdown

[ psia ]

K

[ mendelevium ]

Second

Pi

[ bwpd/psi ]

Well 1

60 %

69

130

A

-0.6

A

1.09

39 %

115

298

129 %

1.8

-400 %

1.59

28 %

139

386

29 %

6.4

262 %

1.85

Well 2

47 %

87

1941

A

6.1

A

11.26

35 %

248

787

-59 %

17.9

192 %

1.47

27 %

263

855

9 %

36.3

103 %

2.72

Well 3

63 %

208

686

A

1.8

A

10.53

57 %

247

1001

46 %

6.4

247 %

2.48

40 %

352

1046

5 %

11.7

83 %

7.95

Table 1: Permeability, tegument and productiveness index consequences from each H2O shock absorber trial

The volume of H2O shock absorber was calculated from the hydrostatic force per unit area reading obtained when the well was opened. The shock absorber volume shown in Table 1 are larger than the proposed 10 % , 30 % and 50 % H2O shock absorbers volumes because extra fluid from the preflow trial has entered the well increasing the shock absorber values. Figure 2 illustrates the relationship of the tegument values to the force per unit area drawdown imposed in each trial.

Figure 2: Relationship of Skin to Coerce Drawdown

These consequences show a strong positive relationship between the size of the force per unit area drawdown used and the sum of tegument measured. The trials which used the smaller sized H2O shock absorbers, making a larger force per unit area drawdown, resulted in higher values of tegument calculated whilst the trials with the larger H2O shock absorbers produced smaller tegument values.

Looking at the equation used to cipher tegument ( Equation 2 ) it can be seen that tegument is straight relative to coerce drawdown ( pi – pwf ) nevertheless this equation besides shows that the tegument values should non be every bit sensitive to coerce drawdown alterations as seen in our consequences. The big alterations in tegument values collected suggest that extra factors other than formation harm are impacting the tegument values. Reid ( 2010 ) suggests that high tegument values seen in CSG Wellss may be the consequence of gas atoms trapped in the coal cleats hindering the permeableness of the coal.

The simplistic conventional construct of gas motion in coal is that the coal seams consist of solid stuffs which contain gas held by sorption ( Giras, 2006 ) . Coal is divided by cleats, larger articulations and mistakes. The cleats may be saturated by H2O at a higher force per unit area than the sorption force per unit area of the coal with all the gas is held in sorption. When the well is opened, an instantaneous force per unit area bead is transmitted to the coal face and the formation fluids start to flux into the well.

As the fluid content of the coal is reduced the fluid force per unit area in coal beads to below the sorption force per unit area and gas bubbles begin to let go of from the coal. These bubbles displace H2O from the cleat infinite. In making so, the effectual permeableness of the coal to H2O and gas, alterations with gas hindering the transition of H2O and frailty versa ( Reid, 2010 ) . This may explicate the tegument values seen in our trials. For the trials with the larger force per unit area drawdown there is a higher flow rate from the coals doing a larger bead in unstable force per unit area. This bead in unstable force per unit area may do little sums of gas to be released from the coal into the cleats hindering the H2O flow and cut downing the effectual permeableness ensuing in higher tegument values.

For the following probe DSTs were performed on a series of Wellss pre and station under-reaming in order to find if it was possible to take the sensed formation harm and cut down the tegument values. Following the consequences of the old probe, the H2O shock absorber size was kept changeless in order to keep similar fluid force per unit areas for each trial.

The consequences of the under-reaming probe are summarised in Figure 3 below.

Table 3: Skin consequences pre and station under-reaming

Of the eight Wellss tested, four showed important betterment of tegument values post under-reaming with Well A LJCM, Well A TCM, Well C TCM and Well D LJCM cut downing 40 % , 60 % , 32 % and 68 % severally. Well B LJCM and Well C UJCM showed a really minor decrease in skin station under-reaming whilst Well B TCM and Well D TCM showed an addition tegument.

These consequences show that under-reaming activities have possible to take formation harm, cut downing the tegument values on Wellss. Due to the high cost of executing these trials it is improbable that a larger sample of informations will be provided, nevertheless the analysis of production informations from under-reamed and non under-reamed Wellss located in a individual field may supply some more insight into the benefits of under-reaming. If under-reaming activities do cut down the formation harm in Wellss so the production informations should demo a higher volume of production from under-reamed Wellss compared to those that have non been under-reamed.

6.0 Decisions and Recommendations

6.1 Future Work

Consequences from this survey have shown that tegument values obtained from drill root trials are non an accurate measuring of formation harm in CSG Wellss. Skin values have been proven to be extremely sensitive to the force per unit area drawdown imposed on the coal, by manner of H2O shock absorber, proposing that the permeableness alterations measured are due to the mechanical belongingss of the coal non merely formation harm. Reid ( 2010 ) argues that tegument values obtained from drill root trials in CSG Wellss are overestimated due to the gas hindering the flow of H2O during the trial. If these skin values are overestimated so the forecasted production of each well has been underestimated significance that there is possible to retrieve more gas than ab initio estimated.

Consequences from the under-reaming probe showed it is possible to cut down tegument values in CSG good through under-reaming, nevertheless farther surveies must be performed to confirm these findings.

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