Pore Pressure Prediction.indd

ABSTRACT

Rapid burial and high rates of sedimentation

in the Malay Basin has lead to development

of overpressure by disequilibrium compaction.

Overpressure developed by this process can be

quantifi ed using industry-standard techniques

that rely on porosity/effective stress relationships.

However, where thermally-driven secondary

processes create overpressure, porosity-based

analysis that uses sonic (or seismically-derived

velocity data) and resistivity data as a measure

of porosity change underestimate overpressure.

These processes will be active in relatively

shallowly-buried shales in basins with high

geothermal gradient such as the Malay Basin.

Using comparative datasets from several regions

where secondary overpressure generation are

present (Gulf of Mexico; Halten Terrace, Mid-

Norway and the Malay Basin), we discuss such

secondary mechanisms and their quantifi cation

by integrating velocity vs. density cross-plots with

understanding of basin history. Analysis of velocity

vs. density relationships is a powerful tool to help

discriminate overpressure generating processes

and using this technique and log data from the

Malay Basin, we identify load transfer (where rock

compressibility is affected) as present, in addition

to unloading and cementation effects documented

by previous authors. Overpressure generated by

load transfer may only be partially detected by fl uid

expansion-based relationships such as Bowers

(1994), leading to inaccurate pre-drill pressure

predictions.

The identifi cation of load transfer (and

cementation) processes and their quantifi cation

is vital to accurate prediction of pore pressure in

hydrocarbon-charged reservoirs in the Malay and

other basins worldwide

INTRODUCTION

The Malay Basin is a Tertiary trans-tensional

rift basin, offshore peninsular Malaysia. In this

basin, both gas-rich and mixed oil/gas zones are

present. Over 12km of fi ne-grained sediments

were deposited in the last 35 Ma, with rates

of sedimentation as high as 1000m/Ma are

calculated for the syn-rift phase (Madon, 2007).

The depth to the start of overpressure varies

across the basin and is shallowest in the basin

* GeoPressure Technology Ltd. ** PETRONAS*** Indiana Geological Survey

Pore Pressure Prediction in challenging areas - IPA Publication May 2011

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PROCEEDINGS, INDONESIA PETROLEUM ASSOCIATIONThirty-Fifth Annual Convention & Exhibition, May 2011

DEEP PORE PRESSURE PREDICTION IN CHALLENGING AREAS, MALAY BASIN, SE ASIA

Stephen O’Connor*Richard Swarbrick*Jamaal Hoesni**Richard Lahann***

IPA11-G-022


centre, e.g. wells such as Dulang-1 and Tangga-1,

1.9-2.0 km TVDss. The Middle Miocene Unit

F shale acts as a regional seal (Madon, 2007).

All well locations named in this study are shown

in Figure 1. A similar observation was made in

Singh and Ford (1982) based on analysis of over

150 exploration wells. The Middle Miocene unit

E represents a pressure transition zone. On the

basin fl anks, overpressure starts deeper, often at

3.0 km TVDss e.g. Larut-1. In the SW of the Malay

Basin, in the vicinity of wells such as Beranang

6F-18.1 and Resak 6F-18.2, anomalously high

overpressure occurs at depths of 2.6 km TVDss,

sealed by the on-lapping, transgressive shale of

unit L (Lower Miocene). Shale seals have a strong

infl uence on overpressure distribution, as do rates

of sedimentation and subsidence (Madon, 2007).

To-date, current drilling has rarely penetrated these

deeper, highly overpressured parts of the Malay

Basin. Those wells that have drilled deep, such

as the Bergading Deep and Sepat Deep-1 wells,

encountered High Pressure/High Temperature

(HP/HT) conditions, severe mud losses, well kicks

and other operational diffi culties such as stuck

pipes, hole stability and hole caving while drilling

of the well (Mohamad et al., 2006). Prior to 1994,

80% of exploration and appraisal wells were

terminated due to overpressure in the Malay Basin

(Shariff, 1994).

Careful and accurate pore pressure prediction,

therefore, will be the key to defi ning the

next exploration phase of the Malay Basin.

A major component of this process will be

the understanding of those processes that

create overpressure, and the identifi cation of

these processes in this basin. Disequilibrium

compaction is believed to be the primary

causal mechanism for the overpressure in the

basin (Madon, 2007), however, due to the high

geothermal gradient (51.8oC/km; Halim, 1994),

we show evidence in this paper that secondary

overpressure mechanisms are also important.

Secondary mechanisms such as fl uid expansion

and cementation have previously been identifi ed

by Hoesni et al. (2007) in the Malay Basin. In this

paper, we review this work and show evidence of

additional processes, related to changes in rock

compressibility (load transfer).

Conventional porosity-based pore pressure

analysis using sonic/seismic velocity and resistivity

data as a measure of porosity retention, under-

estimates the overpressure effect of these

secondary overpressure mechanisms. Using

velocity and density data from a well in the South

and North Malay Basin, Wells A and B (Figure

1), we illustrate the methodology to identify

overpressure generation mechanisms in the Malay

Basin by using velocity vs. density cross-plotting,

and discuss implications for pre-drill prediction.

We also review approaches to allow for these

mechanisms i.e. often empirical fi ts to local data,

and results from our work in other basins, where

we have attempted to quantify these mechanisms

by integrating basin history with rock properties

and temperature data.

MECHANISMS OF OVERPRESSURE GENERATION

In environments such as the Malay Basin,

Gulf of Mexico and Nile Delta, where rates of

sedimentation are high, the sediments are young

and with low geothermal gradients, pore pressure

profi les through shale-dominated sequences can

be estimated confi dently using seismic velocity,

wireline sonic and resisitivity data. Assumptions

are that the basin is extensional and that the main

mechanism of overpressure generation is under-


compaction as a result of ineffective dewatering,

referred to as disequilibrium compaction (Hubbert

and Ruby, 1959). These profi les are typically

overburden parallel (Swarbrick et al., 2002), i.e.

increasing pressure with increasing depth with (a)

constant porosity, implying (b) constant vertical

effective stress (overburden minus pore pressure).

Such pore pressure profi les are present in the

North Malay Basin (Yussof and Swarbrick, 1994;

Figure 2). Another example is shown in Figure 2 in

Madon (2007). In both these examples, a series

of thin and/or undrained, thicker sands encased

in shales contain WFT (Wireline Formation Test)

data, that acts as a proxy for measuring shale

pressures. In both cases, sharp pressure transition

zones are present involving the deep reservoirs,

producing overburden-convergent pressure

profi les, and suggesting secondary mechanisms

are likely present (Figure 2).

As porosity is reduced to low values as a result

of mechanical compaction during burial and

the temperature increases (for instance, above

70oC in some basins; Gulf of Mexico, Bruce

1984), mineralogical changes occur in the shales.

These changes lead to the two main processes

of secondary overpressure generation, fl uid

expansion/volume change and load transfer (or

framework weakening).

Fluid expansion/volume processes include

dehydration reactions such as gypsum to

anhydrite, and smectite to a more dehydrated

form. Smectite to illite transformation produces

water released and silica, which will tend to

precipitate locally. The release of bound water into

sediment pores is minor in terms of generating

overpressure (Swarbrick, and Osborne 1998).

Maturation of hydrocarbons, particularly in

the case of gas generation, produces rapid

volume expansion, reducing effective stress and

increasing pore pressure. These fl uid expansion

mechanisms such as gas generation and

dehydration reactions generate overpressure

that can be calculated using Bowers (1994), a

relationship that is based on velocity and changes

in effective stress, where porosities are low.

Other mechanisms involve changes in rock

compressibility. If the rock compressibility

is increased, there will be an extra load

superimposed onto the fl uid phase as a result

of the applied stress. These processes involve

weakening of the framework and pore collapse

driven by clay diagenesis and dissolution of

framework-supporting grains such as kerogen and

K-feldspar (Lahann (2001, 2002) and referred to

as load transfer in Swarbrick et al, 2002). These

reactions only occur where the temperature

exceeds about 80oC, although in younger

sediments the temperature at onset is more

typically > 100-120oC.

Pressures generated in shales, where porosity

is low, temperatures are increasing, and clay

mineral diagenesis and hydrocarbon generation

are ongoing, are transmitted to any associated

sands, particularly sands of restricted extent such

as turbidites. Many pressure depth profi les in

shale-dominated facies e.g. Nile Delta, Mann and

MacKenzie (1990) show increasing overpressure

with depth, proof of reservoir isolation and close

coupling with the enclosing shales e.g. in the

Malay Basin, Figure 2. Thicker, sands that are

laterally extensive have more capacity to allow

the dissipation of these pressures if a leak or

exit point is established via continuous reservoir

or fault networks to shallower levels. Examples

of reservoirs that have less pressure than the

surrounding shales and are laterally draining

pressures (and fl uids) include the Paleocene fans

of the Central North Sea (Dennis et al., 2000,

2005), as well as the Egga Sandstone Formation,


Ormen Lange fi eld reservoir, Mid-Norway, and

Cauvery Basin, East India reported in O’Connor

and Swarbrick, (2008).

METHODS TO IDENTIFY SECONDARY PROCESSES OF OVERPRESSURE GENERATION

Commonly used methods to estimate the

magnitude of pore pressures, such as Equivalent

Depth or “Vertical” and Eaton Ratio or “Horizontal”

(Eaton, 1975) are based on the detection of

anomalously high porosity for depth of burial. The

porosity is high due to the ineffective dewatering of

shales during burial, whereby part of the increasing

vertical load of the overburden is transferred to

the fl uid phase, increasing pore pressure above

hydrostatic. Both relationships are derived from

Terzaghi (1953) (Equation 1) based on soil

mechanics and related to the values of log data

such as sonic and resistivity compared with those

values associated with porosity-loss on a normal

or primary compaction curve.

Sv = σv + Pf (1)

Where,

σv = vertical effective stress

Pf = pore pressure

Sv = vertical stress, derived from density data or

sonic-derived density data from the equation;

As mentioned above, processes such as gas

generation or load transfer increase the pore

overpressures reducing the grain-to-grain contact

stresses (effective stresses). However, compaction

is mostly irreversible, therefore porosity-based

pore-pressure-prediction methods (e.g. Equivalent

Depth Method) will not detect these increases in

pressure as no associated porosity anomaly is

present, tending to underestimate pore pressures

caused by mechanisms other than disequilibrium

compaction. Velocity/density vs. cross-plots can

be used to identify the presence of overpressure

generated by these other mechanisms – see

Figure 3.

In the case of gas generation, reduction of

effective stress, has the effect of reducing density

a very small amount (elastic rebound) but has

a much greater impact on the velocity. Hence

the steep downwards trend associated with

“unloading” (Figure 3; modifi ed from Hoesni,

2004). Bowers (1994) has developed this

approach to distinguish between disequilibrium

compaction and other overpressure generating

mechanisms. An example of a typical resulting

profi le for unloading is also displayed in Chopra

and Huffman (2006). Normal compaction and

disequilibrium/under-compaction display typical

increasing velocity and density magnitudes.

This profi le or primary compaction curve initially

shows increase in density with relatively little

velocity response, a pattern which corresponds to

mechanical compaction with little/no cementation,

so that grain-grain contacts are minimal and

velocity increases slowly. With increasing effective

stress and as compaction proceeds more grain-

grain contacts are made, giving a distinctive

curvature of the profi le with depth where velocity

increases more rapidly relative to density (Gardner

or Bowers relationships for shales in Bowers,

2001).

Where load transfer occurs, the transformation of

framework-supporting grains to hydrocarbons (oil

and/or gas) in the case of kerogen, smectite to

illite transformation and/ or porosity as K-feldspar

dissolves causes an increase in density - if the

system can allow some to escape. A decrease

in velocity occurs as effective stress decreases.


Cementation such by silica will strengthen the

rock framework, reducing permeability (aiding

overpressure retention) and increasing the velocity

of the shales. Density increases may be variable,

depending on the types of cement and its

distribution.

Log data is the primary input for these cross-plots,

therefore, logs were initially processed, depth

matched and shale data extracted using a cut-

off based on gamma-ray data as an indicator of

lithology. Caliper logs were used to remove the

effects of wash-out that affect borehole integrity

and can cause inaccurate log responses. Finally,

a moving average fi lter can be applied to remove

spurious values such as high velocity spikes due

the localised cementation.

RESULTS FROM THE MALAY BASIN

Evidence for secondary processes in the Malay

Basin is presented in Figures 4 and 5. Both

density and sonic data were available for these

wells. In Well A, in the South of the Malay Basin,

the top of overpressure is at 1.2km, whereby shale

pressures increase parallel to the overburden (as

predicted successfully by the Equivalent Depth

Method, not shown). Below 2.0 km TVDss, shale

pressures under-estimate the K and L reservoir

pressures by 1500-2000 psi. These reservoirs are

un-drained, massive sands, overlain by thick shale

sequences (Hoesni, 2004). The estimated pore

pressure at TD is 7093 psi (15.8 ppg) (Hoesni,

2004). Figure 4 displays the velocity/density

relationship for this well. Deviation is observed

from the primary compaction curve of Bowers

(2001) at temperatures of 120oC, although more

signifi cantly at 160oC. This signature of increasing

velocity and density is identifi ed by Hoesni et al.

(2007) as suggestive of chemical compaction/

cementation effects.

In Well B, sandy lithologies pre-dominate deeper

than in Well A, therefore overpressure commences

at 1.8 km TVDss. Shales dominate below

this depth, and reservoirs display increasing

overpressures. High mud-weights were used to

control the pore pressure in this well, and indeed,

shale pressure prediction using the Equivalent

Depth Method (not shown) suggest mud-weights

used in the well were signifi cantly below the

shale pressures. The well was abandoned, due

to wellbore instability problems attributed to high

pore pressures; at 2747m TVDss, mud-weights

used were 17.6 ppg (Hoesni, 2004). Figure 5

displays velocity and density for Well B as well

as the estimated borehole temperatures. The

depth at which the shale pressure interpretation

by the Equivalent Depth Method proves to be

inaccurate i.e. under-estimates pore pressures

as confi rmed by WFT measurements in thin,

encased sands, is approximately 2.4 km TVDss

(Hoesni, 2004), corresponding to 124oC using a

geothermal gradient of 51.8oC/km (Malay Basin;

Halim, 1994). A defl ection to slower velocity and

increased density occurs at this temperature –

this trend is similar to that shown in Figure 3. The

trend is representative of load transfer i.e. the

transformation of kerogen to hydrocarbons (oil

and/or gas), porosity as K-feldspar dissolves and/

or smectite to illite – all of these processes affect

rock compressibility and load the fl uid phase.

DISCUSSION

Madon (2007) states that disequilibrium

compaction is the primary source of overpressure

generation in the Malay Basin centre, caused by

high sedimentation rates. Modeling results suggest

that overpressure generated early during the syn-

rift phase when sedimentation rates were high

(>1000 m Ma). As post-rift rates were lower (<


500 m Ma), no overpressure was generated in this

phase, such that current overpressure patterns

are due to re-distribution of overpressure via faults

and regional seals (F and L shales). Evidence

from our analysis suggests that additional

overpressure mechanisms may exist in the Malay

Basin, mechanisms that are not associated with

a porosity anomaly and therefore problematical to

detect. These mechanisms are identifi ed to be due

to load transfer processes. Hoesni et al (2007)

also provide evidence for secondary processes

in the Malay Basin via unloading, although typical

trends of rapid velocity loss (Figure 3) are not

visible on many velocity vs. density cross-plots

due to the effects of chemical compaction (via

cementation) as typifi ed in Figure 4 from Well A.

Hoesni et al. (2007) defi ne a model for chemical

compaction where shale framework collapse with

partial dewatering, followed by sequential fi lling of

pore spaces in shales by cement occurs, in both

storage (inter-granular) and connecting pores. This

cementation results in enhanced seal capacity for

shales acting as vertical barriers to migration.

Analysis of velocity vs. density cross-plot

data from Well B produces deviation from

typical shale trends characteristic of normal

compaction/disequilibrium compaction (i.e. a

primary compaction curve) (Bowers, 2001). The

defl ection to higher density and lower velocity

is characteristic of load transfer, where rock

compressibility is affected, resulting in a different

compaction profi le. This type of signature is

reported from the Gulf of Mexico by Lahann

(2001, 2002), and associated with changes

in rock compressibility by smectite to illite

transformation during clay diagenesis at 80oC

(Figure 6). However, several factors such as time

and clay type affect the temperature of onset of

this transformation. Data in Lahann (2002) from

the Gulf of Mexico suggests that overpressures of

1500-3000 psi can be attributed to this process.

Typically, 100-120oC is the temperature range at

which signifi cant overpressure can be generated

by this method. The departure from the primary

compaction trend in Figure 5 occurs at 120oC

It is not possible without further analyses e.g.

of shale samples to ascertain compaction and

mineralogical state, to determine which process

affecting rock compressibility is present/occurring.

Unloading as defi ned by Bowers (1994, 2001),

causes reduction in effective stress and velocity,

assuming plastic and elastic sediment behaviour.

Where processes occur that affect compressibility,

this behaviour will be inelastic, and the compaction

state of the rock permanently altered (Katahara,

2006). Although the velocity/effective stress model

in Lahann (2002) for the Pathfi nder well resembles

an unloading curve as discussed in Bowers

(1994), this method may only offer a partial

solution to pre-drill pore pressure prediction, where

load transfer processes are present, such as

the Malay Basin. In order to model the effects of

changes in rock compressibility, a post-unloading

compaction model as discussed in Lahann (2001,

2002) could be defi ned (if suffi cient data exists).

This model can be applied to data which are too

deep to be accurately modelled by a Bowers-

style unloading curve. The entire well profi le can

be modelled with a primary curve, a Bowers-

style unloading curve, and a deep compaction

model. Alternatively, the unloading interval may

be interpreted by a mixing function that changes

with depth from the primary model to the deep

compaction model.

This study (and Hoesni et al., 2007), would

propose that there is also evidence for additional

processes that generate overpressure in this

basin, caused by the high geothermal gradients.

An important outcome of this study is, therefore,


that more complete understanding of the effects

and changes in rock compressibility are needed

as these parameters cannot be measured/

predicted pre-drill. Pressure models based on

sonic log or seismic velocity analysis data will

not be accurate if the techniques mentioned in

this paper are used e.g. Equivalent Depth, Eaton

(1975) and potentially Bowers (1994). Clearly, in

basins where temperatures are elevated e.g. the

Malay Basin, velocity data could prove problematic

below 2.0 km, therefore using seismic data will

signifi cantly under-estimate pressures by 1000’s

psi – a major drilling safety issue.

Potential solutions often rely on fi nding empirical

fi ts to existing data and applying locally, or using

relationships derived in different basins, and

applied worldwide. An example of the former is

cited in published analyses by Dolson et al. (2005)

from the Nile Delta. In these datasets, seismic

interval velocities are considered too fast for the

Miocene section, resulting in inaccurate calculation

of pore pressures. Using an Eaton exponent of

5.0 in Wells such as Akhen-1, however, provides

a match with reservoir data. Geothermal gradient

data of 25oC/km in Manzoni et al (1998) suggests

Miocene shales of the Qantara Formation are likely

affected by thermal processes, transmitted to

these reservoirs.

A more robust approach is to use velocity vs.

density cross-plots in conjunction with knowledge

of overpressure mechanisms, rock properties and

understanding of basin history. For example, the

Lower Cretaceous deep-water Lange Formation

shales provide a continuous cover of fi ne-grained

sediment over the Halten Terrace, Mid-Norway.

From analysis of temperature data, the 100oC

isotherm is generally shallower than the Lange

shales and therefore the shales are in the window

where these thermally-driven mechanisms could

be a factor. Density log data increases with depth,

indicative of a primary compaction curve. The

suggestion is that overpressuring to the current

levels proceeded independently of porosity loss

i.e. there is a signifi cant component of secondary

overpressure is the Halten Terrace region that

post-dated compaction and has no associated

porosity anomaly (Hermanrud et al., 1998).

A burial curve based on composite log data for

Well 6506/11-6 (not shown) demonstrate two

periods of rapid burial (1) Turonian/ Campanian

and (2) Plio-Pleistocene. Work by Skar et al.

(1999) suggests that pressures were hydrostatic

prior to this latest burial due to pressure bleed-off

during the Tertiary hiatus. The relative contributions

of the rapid loading during the Plio-Pleistocene

(1.7 km of sediment; Norgård Bolås et al.,

2005) and secondary contribution to the current

Lange pore pressure profi le in Well 6406/2-3 are

illustrated in Figure 7 (GPT/IHS, 2007). The blue

line on the left is the hydrostatic (normal) pressure

starting point at 3 Ma ago. The darker blue line to

its right represents the pore pressure profi le after

the rapid burial event, with a constant contribution

to overpressure from rapid loading via ineffective

dewatering. The current Lange pore pressure

profi le (as defi ned by WFT data in encased

intra-formational sands, often four per well, and

defi ning a regional shale gradient) is indicated by

purple line on the right of the fi gure.

For the deeply buried rocks such as the Lange

shales, already having low permeability, this

additional overburden will be translated into

overpressure (assuming no signifi cant dewatering)

by:

1.7 km sediment thickness x (lithostatic gradient of

3.28 psi/m - water gradient of 1.45 psi/m) = 2711

psi

Therefore, at 4.0 km depth in Figure 7, using

the purple line representing current pressures in

the Lange indicates approximately 4350 psi of

overpressure (1639 psi greater than recent loading

history calculated above could have generated).

In such old and hot rocks, seismic-based velocity

prediction of pore pressure would be unreliable,

as there is no porosity/effective stress link. The

difference between dark blue and purple lines

represents our best estimate of the contribution

to overpressure from diagenetic changes in

the shales. Velocity vs. density cross-plot

analysis suggests load transfer (smectite to

illite transformation, K-feldspar dissolution etc.)

processes are active in these shales, with a

reduction in velocity, and increase in density.

CONCLUSIONS

In conclusion, in the Malay Basin, there is a

strong correlation between rate of sedimentation

and overpressure development by disequilibrium

compaction. However, as wells are drilled deeper

into this Basin (and other basins world-wide

below the 100oC isotherm), thermal processes

in shales will result in secondary overpressure

generation, and, if this overpressure is transmitted

to reservoirs, pre-drill predictions of pore pressure

will be inaccurate, compromising safety.

Using traditional techniques of pore pressure

prediction such as Equivalent Depth and Eaton

(1975) will be inadequate. Bowers (1994) offers

only a partial solution. New relationships will

need to be developed based on integrating an

understanding of basin history, shale behaviour,

clay mineral diagenesis, thermal behaviour and

geological time to successfully predict pore

pressures in this, and other, hot and deep basins

world-wide.

ACKNOWLEDGMENTS

The authors would like to extend their thanks to

the organizing committee for the chance this work

at the IPA Conference, 18-20th May, 2011.

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Figure 1 - Location map for Malay Basin adapted from Madon (2007).

Locations of all wells mentioned in the text are displayed.


Figure 2 - Well LA-3, Malay Basin (Yusoff and Swarbrick (1994). Wireline

Formation Test (WFT) data (blue ovals) refi nes an overburden-

parallel shale pore pressure profi le, characteristic of overpressure

generated by disequilibrium compaction (black line). Sharp pressure

transition zone below 100oC suggests additional overpressure

generated by secondary processes (based on geothermal gradient

of 51.8oC/km, Halim (1994). See text for discussion.


Figure 3 - Typical Velocity vs. Density signatures and their associated, causal

mechanisms of overpressure generation (from Hoesni, 2004).


Figure 4 - Velocity vs. density data plotted for Well A. Estimated borehole

temperatures also plotted. Deviation is observed from the primary

compaction curve of Gardner (red line) and Bowers (2001) (blue

line) for shales at temperatures of 120oC, although more

signifi cantly at 160oC. This signature of increasing velocity and

density is identifi ed by Hoesni et al. (2007) as suggestive of

chemical compaction/cementation effects.


Figure 5 - Velocity vs. density data plotted for Well B. Deviation is observed

from the primary compaction curve of Gardner (red line) and Bowers

(2001) (blue line) for shales at temperatures of 120oC. This

signature of increasing velocity and density is identifi ed as

suggestive of load transfer effects (refer to Figure 3).


Figure 6 - An example of velocity/density behavior that requires load transfer

interpretation in Gulf of Mexico. Solid blue line represents the

primary compaction curve. In this case, the load transfer (or

“unloading” termed by the author) shift (orange squares) occurred

within the smectite-illite reaction window (Lahann, 2002).

Figure 7 - Hydrostatic pressure (light blue), contribution to overpressure from

recent rapid burial (light blue to dark blue) and contribution to

overpressure from load transfer (dark blue to purple) for Lange

Formation shales, Halten Terrace, Mid-Norway. Reservoir

overpressures, as measured by WRT data in encased shales in the

Lange Formation, are substantially higher than could have been

created by burial-related processes alone.

O P T I M I S E S U C C E S S T H R O U G H S C I E N C E


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