Skin Sensitivity To Pressure Drawdown Biology Essay

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The permeability of coal is recognised as the most important parameter controlling Coal Seam Gas production for it measures the ease with which reservoir fluid moves through the coal, determining the quantity of gas that can be recovered from the reservoir (Guo, Mannhardt & Kantzas 2008; Shi & Durucan 2004). Damage to the near wellbore permeability during drilling operations can significantly impact the reservoirs production, reducing the overall gas recovery and diminishing the value of the resource (Jahediesfanjani & Civan 2005). This drilling damage is referred to as formation damage and is measured using a mechanical Skin Factor, s, which is related to the depth and degree of permeability alteration illustrated in the equation below.

This skin factor is a dimensionless unit, where a positive value indicates that formation damage is present whilst a negative value indicates improved permeability around the wellbore. Skin values typically range from -8 to 20 with a value of -8 indicating a significant increase in permeability around the wellbore and a value of 20 representing major permeability drop through the damaged zone resulting in a significant reduction in gas recovery.

This method of quantifying formation damage assumes that permeability is constant throughout the reservoir, and any alterations in near wellbore permeability are the direct result of drilling damage. Whilst these assumptions are reasonable when working with conventional reservoirs, many believe that due to the different structure and mechanical properties of coal, its permeability is more stress-dependent and complex than most reservoir rocks and therefore not constant during production (Guo, Mannhardt & Kantzas 2008; Reid 2010; Saulsberry, Schafer & Schraufnagel 1996). This makes it hard to determine whether measured permeability changes in the near wellbore vicinity are solely due to formation damage or whether other mechanisms are affecting the permeability of the coal.

This project was undertaken in partnership with Origin Energy with the purpose of investigating whether skin values calculated for CSG wells were an accurate measure of formation damage or if other factors were impacting the results. There were two parts to this project. The first part was to investigate the possibility of removing the perceived damage zone of a well through the process of under-reaming. Under-reaming involves drilling out section of the well, increasing the well radius past its original drilled size and hopefully removing any formation damage caused during the initial drilling of the well. If the skin values calculated for each well were truly representing formation damage then tests conducted after the removal of this damage zone should reflect a significant reduction in skin values. If formation damage can be reduced or removed using this procedure then the commercial productivity of the well will be increased, providing a greater value to the company.

The second part of this project investigated the sensitivity of skin values to the pressure drawdown imposed on the coal by way of water cushion. Changing the magnitude of pressure drawdown will affect the stress regimes of the coal around the wellbore and the object of this investigation was to determine if this alters the skin results calculated. If skin is shown to be sensitive to pressure drawdown then we can conclude that the skin values calculated are not solely the result of formation damage but are being affected by the mechanical properties 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 gaining increasing worldwide attention. In recent years CSG has grown into an important natural gas resource in Australia, supplying approximately three quarters of the Queensland gas market (Queensland Government, 2010). Unlike conventional gas reservoirs, the gas in CSG reservoirs is stored by adsorption in the solid matrix of the coal seams. The ability of coal to store gas is a function of coal rank, temperature and pressure which is related to coal depth (Gash, 1991). Large amounts of gas can be stored at low pressure in coal reservoirs; therefore the pressure must be drawn down to a very low level to achieve high gas recovery (Gas Research Institute, 1996). This pressure reduction is achieved by extracting large amounts of reservoir water from the coal seams. Coal is a dual porosity reservoir rock which has a microporous matrix and a network of natural fractures known as cleats. Although cleats have very low porosity, < 2%, they are solely responsible for the permeability of a coal seam (Chen et al., 2006). Permeability of coal is recognised as the most important parameter controlling CSG production (Guo et al., 2008).

2.1.2 Dual Porosity Reservoir Systems

Coal seam gas reservoirs are dual porosity reservoir systems, which consist of two porous media regions - primary and secondary porosity. The primary porosity system is made up of the coal matrix with the micropores of the coal estimated to have diameters randing from 5 to 10 Angstroms (Harpalani 1999). The properties of the coal matrix are controlled by sedimentary processes and post-depositional lithification. The secondary porosity system consists of a closely spaced natural fracture network surrounding the matrix, called the cleat system, formed in response to coalification, local structural features, and other variables. The coal cleat system is generally orthogonal with one direction cross-cutting the other. The dominant cleat is commonly called the face cleat which is usually continuous throughout the coal. The cleat orientated roughly perpendicular to the face cleat is called the butt cleat, which is discontinuous and terminates at intersections with the face cleat. Figure xxx below shows a two dimensional representation of the cleat system.

Butt Cleats

Matrix Block Containing Micropores



Figure xxxx: Dual Porosity System of Coal

Other than the face and butt cleat system there is another set of natural fractures throughout the coal, the horizontal spacings between different coal layers known as bedding planes. Based on the three dimensional fracture system early literature often represented the physical coal structure using a cubic model consisting of several cubes put together, shown below in figure xxxxxxxxxxxxxx.

Figure xxxx: Cubic Model of Physical Coal Structure

In 1980 Reiss stipulated that due to the overweight the bedding planes do not often conduct fluid and are of little interest in fluid flow in coal. In order to graphically represent the flow of fluid through the vertical and near vertical cleat system a match-stick model was suggested and has been widely accepted since.

A CSG reservoir is a heterogeneous medium that contains secondary porosity of higher permeability than the primary porosity. Most of the fluid stored in the reservoir is contained within porosity developed in the coal matrix. The permeability of the coal matrix is generally believed to be in the range of one microdarcy or less because of the small size of the matrix pores. The fracture porosity (secondary porosity system) generally ranges from 0.1 to three percent. The absolute permeability of the secondary porosity system is generally greater than one millidarcy in commercially developed CSG reservoirs.

2.2 Regional Geology

2.2.1 Surat Basin

The Surat Basin covers an area of approximately 270,000 km2 in southern Queensland and northern New South Wales. Up to 2500m of Jurasic and Cretaceous sediments were deposited into the basin in response to a period of overall intracetonic thermal sag. The sediments overly unconformably on the eroded surfaces of Late Carboniferous to Triassic sediments of the Bowen and Gunnedah Basins as well as older basement rocks 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 interconnected basins constitute part of the Great Artesian Basin System. Regionally subsidence was relatively continuous and widespread and the basins generally retain relatively simple geological structures with shallow dips and little evidence of lateral tectonic compression. Late flexure is evident during the later part of the basins development.

Six major fining upward cycles have been identified within the Surat Basin dominated by fluvio-lacustrine deposition during the Jurassic and becoming progressively marine during the Cretaceous (Exon 1976; Exon & Burger 1981). The fluvio-lacustrine sedimentary cycles typically consist of coarse quartzone sandstone frading to labile sandstone, siltstone, mudstone and coal. Each cycle is defined by a change in depositional environment from dominantly higher energy braided streams, to lower energy meandering stream environment with associated swamps and lakes. Towards the end of the Early Cretaceous, inundation of the land through major changes in sea level led to the deposition of predominantly coastal plain and shallow marine sediments.

2.2.2 Walloon Subgroup

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

The Walloon Subgroup thickens to the northeast to more than 400m around the Mimosa Syncline. The Walloons Subgroup contains numerous coal seams that have been extensively explored for open-cut coal resources particularly in the Miles and Chinchilla area where they outcrop. The sediments comprise very fine to medium grained volcanolothic sandstones, siltstones, and claystones with associated coals deposited in alluvial plain depositional environments that hosted aerially restricted peat mires and lakes in a region affected by airfall tephras.

The Walloon Subgroup is subdivided into the Juandah Coal Measures, Tangalooma Sandstone and Taroom Coal Measures (Jones & Patrick 1981; Scott et al. 2007). Origin's work in the area supports this sub-division and has further divided the Juandah Coal Measures into Upper and Lower sections divided by the Juandah Sandstone.

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

The coal are sub-bituminous in rank, generally dull and high in ash forming thin plies that are interbedded with claystones and siltstones to form this coal packages. Individual coal seams (plies) cannot be traced for more than a few kilometers, but coal packages can be traced basin wide.

Reservoir Property Determination

When characterizing the reservoir properties of the Walloons, it is important to remember that the coal measures are made up of 30-50 plies of coal over a 200-400m section and each ply may have very different properties. However, from core analysis to date throughout the basin, similarities between coal properties of individual coal measures (ie UJCM, LJCM and TCM) have been observed and for this reason average coal properties have been calculated for each of these and used in Reserve/Resource estimates.

Net coal thickness for each well was calculated using a log-derived density cut-off of 1.75g/cc using the GeologTM software package. This cut-off has been derived through a detailed comparison between log data, image log data and core regionally. For each well the derived net pay/coal were quality checked against Gamma, Caliper and Resistivity response to confirm that only coal had been included. For wells that had no or poor geophysical logs, and core was available, net coal was included from core descriptions. Net coal thickness have been recorded for the UJCM, LJCM and TCM.

Gas Contents were measured from HQ coreholes using the "Direct Desorption Method" (Australian Standard 3980-199). Proximate analysis (ash, moisture, volatile matter, fixed carbon and relative density) was conducted for all samples subjected to desorption testing. Adsorption Isotherms were also conducted on specific samples from relevant coreholes.

3.0 Data Collection

3.1 Drill Stem Testing Procedure

For each investigation the skin and permeability values were obtained using drill stem tests. A DST is a conventional method of formation testing used to provide an indication of flow rates, static and flowing bottom hole pressures as well as a short-term pressure transient test of the reservoir (Earlougher 1977). Analysis of the DST transient pressure data can provide an estimate of formation properties and wellbore damage, which is used to estimate the well's flow potential.

A DST is run by lowering a special tool mounted on the end of the drill string into the wellbore. A simple schematic diagram of the straddle-packer DST tool used is shown in Figure xx with the main features consisting of three pressure recording devices, two packers and a set of flow valves that can be opened and closed from the surface (Horne 1995).

Figure xxx: DST tool schematic diagram

Once the tool is lowered to the testing zone the packers are inflated on either side of the testing area to isolate the zone from the rest of the well. Before the test begins, a pre-determined volume of water (known as the water cushion) is poured into the drill stem to provide a backpressure on the formation face in order to control the fluid flow rates (Bourdet 2002). The size of the cushion is judged by its percentage of the total drill stem volume, for example a 10% water cushion is 10% of the total drill stem volume. Once the water cushion is in place, the valves inside the tool are opened and fluid from the isolated zone flows through the tool and into the drill string whilst the pressure recorders chart the changing pressures. After a pre-determined flow time, the valves are closed and the pressure builds up. A typical test would usually consist of four periods - a short production period (the initial flow period), a short shut-in period (the initial buildup), followed by a longer flow period (the final flow period), and a longer shut-in period (the final buildup) (Earlougher 1977). The initial flow and build-up periods are performed to estimate the initial reservoir pressure. The final flow and build-up periods are performed to collect the data required to estimate the reservoir fluid and flow properties. Figure x below shows an example schematic of a DST pressure response.

Figure x: Example of DST pressure Response

Over the period the pressure is rising at a constant rate as the tool travels down the well to the testing zone. At the tool is opened and there is an instantaneous pressure drop from the initial hydrostatic pressure (Pih) down to the initial flowing pressure for the first flow period (Pif1). The period is the initial flow period and usually only lasts for a short period of five to thirty minutes. The purpose of this period is to relieve the drilling fluid hydrostatic pressure trapped below the packer before opening the valve. Ideally, the period should be long enough to produce the testing interval fluid volume through the tool to help prevent tool plugging problems. The length of the initial flow period depends on the deliverability of the well. Wells with high deliverability will have high flow rates and the testing interval fluid volume will be produced in less than five minutes. In low deliverability wells a longer time will be needed. Flow times longer than thirty minutes are not recommended because of the excessive initial build-up time needed to estimate the initial reservoir pressure. As the formation fluid flows through the tool into the drill pipe the pressure increases reaching the final flowing pressure for the first flow period (Pff1) just before the tool is closed.

At the tool is closed and the pressure builds up until where it reaches the initial shut in pressure (Pisi). This period between and is referred to as the initial build-up period and during this period the shut-in pressures are measured as a function of time. These pressure then can be extrapolated to the pressure that would result it the well was shut-in for an infinite length of time. The extrapolated pressure is an accurate estimate of the initial reservoir pressure at the depth of the pressure guage. The recommended length of this build-up period is between four and eight times the length of the initial flow period or twenty minutes to two hours. This test length is necessary to avoid extended extrapolation.

This process is then repeated for the final flow and build up periods. At the tool is opened again and the pressure drops down to the initial flowing pressure for the second flow period (Pif2). The period is the final flow period. The main objectives of the final flow period are to produce a significant volume of reservoir fluid and to shut the well in before the well kills itself (when drill pipe hydrostatic pressure equals reservoir pressure). The test length depends on the reservoir pressure and deliverability. When surface recording bottomhole pressure gauges are used, the test can be monitered and shut-in at the proper time. Without surface recording gauges, it is necessary to monitor the "blow" at the bubble hose located on the choke manifold to select the proper shut-in time. Again during the flow period formation fluid flows through the tool into the drill pipe causing the pressure to increases reaching the final flowing pressure for this second flow period (Pff2) just before the tool is closed.

At the tool is closed and the pressure builds up to the final shut in pressure (Pfsi) at . During this final flow period bottomhole pressure data is collected which will be used to estimate the reservoir flow properties and geometry as well as the average reservoir pressure at the time of the shut-in. The length of this period should be at least 1.5 times the length of the flow period.

3.2 Analysis of Drill Stem Tests

The following are some of the parameters which may be determined from a well run DST using the principles of pressure buildup analysis in radial flow system.

Static Reservoir Pressure

This is a measured quantity if the shut in pressure curves have been stabilised mechanically; otherwise it is derived by mathematical extrapolation.

Permeability thickness, kh

Derived directly from the DST analysis without introduction of any parameters from other sources.

Average effective permeability, k

Derived from the DST analysis and a log estimate of the vertical footage of continuous porosity tested.

Skin factor

Stabilised productive index

Absolute open flow capacity

Pressure depletion

In place reserves

Radius of investigation

Barriers in the reservoir

Once the tests are finished the pressure charts and recorded flow rates are analysed against mathematical models using PanSystem well test analysis software to calculate the permeability and skin values. Within this software the Horner method of analysis is used which assumes the following ideal conditions:

Radial flow

Reservoir fluid flows into the wellbore equally from all directions in the formation.

A homogeneous reservoir

This assumes constant characteristics throughout the length and thickness of the reservoir. Any values calculated from test data then become averages over the area tested.

"steady state" conditions of flow

infinite reservoir

single phase flow

Generalised Superposition Plot which is used for build-up or Drawdown test with a multi-rate history using an equivalent time function based on work by Agarwal.

Agarwal, R.G.:  "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 test period to be analysed starts at [Tj, p(Tj), q(Tj)]

What is plotted:

Y axis : Rate-Normalised Pressure


X-axis: Log (Equivalent Time, ∆te)




Ti(i=1, 2, .... M) are the times of the rate changes prior to the data point t. (TM, qM) is the last rate change before the data point at t. These are read from the rate change table up to the start of the test at TJ, then from the rate column.


gr(TJ) is a constant; the value of log(∆te) up to the start of the test at t=TJ

Radial Permeability (k):


Skin Factor (S):


m = slope of line per log cycle

int = intercept of line at

well locations

4.0 Safety

5.0 Results and Discussion

Table 1 below shows a summary of the pressure drawdown, skin (S), permeability (k) and productivity index (PI) calculated from water cushion DSTs. These results are calculated from the mainflow periods of each DST which has a longer flow and build-up time allowing the well to reach radial flow.


Water Cushion

Pressure drawdown







Well 1






















Well 2






















Well 3






















Table 1: Permeability, skin and productivity index results from each water cushion test

The volume of water cushion was calculated from the hydrostatic pressure reading obtained when the well was opened. The cushion volume shown in Table 1 are larger than the proposed 10%, 30% and 50% water cushions volumes because additional fluid from the preflow test has entered the well increasing the cushion values. Figure 2 illustrates the relationship of the skin values to the pressure drawdown imposed in each test.

Figure 2: Relationship of Skin to Pressure Drawdown

These results show a strong positive relationship between the size of the pressure drawdown used and the amount of skin measured. The tests which used the smaller sized water cushions, creating a larger pressure drawdown, resulted in higher values of skin calculated whilst the tests with the larger water cushions produced smaller skin values.

Looking at the equation used to calculate skin (Equation 2) it can be seen that skin is directly proportional to pressure drawdown (pi - pwf) however this equation also shows that the skin values should not be as sensitive to pressure drawdown changes as seen in our results. The large changes in skin values collected suggest that additional factors other than formation damage are affecting the skin values. Reid (2010) suggests that high skin values seen in CSG wells may be the result of gas particles trapped in the coal cleats impeding the permeability of the coal.

The simplistic conventional concept of gas movement in coal is that the coal seams consist of solid materials which contain gas held by sorption (Giras, 2006). Coal is divided by cleats, larger joints and faults. The cleats may be saturated by water at a higher pressure than the sorption pressure of the coal with all the gas is held in sorption. When the well is opened, an instantaneous pressure drop is transmitted to the coal face and the formation fluids start to flow into the well.

As the fluid content of the coal is reduced the fluid pressure in coal drops to below the sorption pressure and gas bubbles begin to release from the coal. These bubbles displace water from the cleat space. In doing so, the effective permeability of the coal to water and gas, changes with gas impeding the passage of water and vice versa (Reid, 2010). This may explain the skin values seen in our tests. For the tests with the larger pressure drawdown there is a higher flow rate from the coals causing a larger drop in fluid pressure. This drop in fluid pressure may cause small amounts of gas to be released from the coal into the cleats impeding the water flow and reducing the effective permeability resulting in higher skin values.

For the next investigation DSTs were performed on a series of wells pre and post under-reaming in order to determine if it was possible to remove the perceived formation damage and reduce the skin values. Following the results of the previous investigation, the water cushion size was kept constant in order to maintain similar fluid pressures for each test.

The results of the under-reaming investigation are summarised in Figure 3 below.

Table 3: Skin results pre and post under-reaming

Of the eight wells tested, four showed significant improvement of skin values post under-reaming with Well A LJCM, Well A TCM, Well C TCM and Well D LJCM reducing 40%, 60%, 32% and 68% respectively. Well B LJCM and Well C UJCM showed a very minor reduction in skin post under-reaming whilst Well B TCM and Well D TCM showed an increase skin.

These results show that under-reaming activities have potential to remove formation damage, reducing the skin values on wells. Due to the high cost of performing these tests it is unlikely that a larger sample of data will be provided, however the analysis of production data from under-reamed and non under-reamed wells located in a single field may provided some more insight into the benefits of under-reaming. If under-reaming activities do reduce the formation damage in wells then the production data should show a higher volume of production from under-reamed wells compared to those that have not been under-reamed.

6.0 Conclusions and Recommendations

6.1 Future Work

Results from this study have shown that skin values obtained from drill stem tests are not an accurate measurement of formation damage in CSG wells. Skin values have been proven to be highly sensitive to the pressure drawdown imposed on the coal, by way of water cushion, suggesting that the permeability changes measured are due to the mechanical properties of the coal not just formation damage. Reid (2010) argues that skin values obtained from drill stem tests in CSG wells are overestimated due to the gas impeding the flow of water during the test. If these skin values are overestimated then the forecasted production of each well has been underestimated meaning that there is potential to recover more gas than initially estimated.

Results from the under-reaming investigation showed it is possible to reduce skin values in CSG well through under-reaming, however further studies must be performed to substantiate these findings.