single well study - well 'b' - wytch farm

Single Well Study - Well BJames Bowkett

ContentsList of Figures.................................................................................................................................2

List of Tables..................................................................................................................................2

List of Equations............................................................................................................................2

Acknowledgements...............................................................................................................................4

Executive Summary...............................................................................................................................4

Introduction...........................................................................................................................................4

Core Description....................................................................................................................................4

Structural/Regional Geology.................................................................................................................8

Petrophysics........................................................................................................................................10

Quality Control............................................................................................................................11

Petrophysical Summary – (Figure 23)..........................................................................................11

Core Correlation / Core Shift.......................................................................................................12

Borehole Corrections...................................................................................................................12

Log Analyses................................................................................................................................14

Shale Volume...............................................................................................................................15

Porosity........................................................................................................................................15

Permeability/Permeability Prediction from Porosity...................................................................17

Water Saturation.........................................................................................................................18

Net Pay Analysis...........................................................................................................................19

Poro/Perm – Excel.......................................................................................................................21

Conclusions..........................................................................................................................................25

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

Appendices..........................................................................................................................................26

1


List of FiguresFigure 2- River Cross-Sections: (a) meandering; (b) anastomosing; (c) braided. Allen (1964); Smith and Smith (1980; Smith and Cant (1982)...............................................................................................5Figure 1 - Triassic Sherwood Sandstone (Meadows & Beach, 1993).....................................................5Figure 3 - Reservoir Schematic (McKie et al, 1998) Height 150m..........................................................6Figure 4 - Sedimentological Description and Interpretation..................................................................7Figure 5 – Depocentres and structural evolution of Southern England; a) Permo-Triassic b) Jurassic-Cretaceous c) Cenozoic (Underhill & Stoneley, 1998)...........................................................................8Figure 6 – N-S Cross-Sections (Present & Late Cretaceous) through Wytch Farm Oilfield illustrating rotated fault blocks. (Underhill & Stoneley, 1998)................................................................................9Figure 7 - Original Data........................................................................................................................10Figure 8 - Logged Section 1639-1949 (C Koeninger). Chris’ logs were used as they coincide with a large change of GR...............................................................................................................................12Figure 9 - Which resistivity tool to use?...............................................................................................13Figure 10- Cross-plot of CPHI vs CKH...................................................................................................17Figure 11 – Porosity and Permeability Histograms..............................................................................22Figure 12- Lorenz Plot of Horizontal Permeability...............................................................................23Figure 13 - Lorenz Plot of Vertical Permeability...................................................................................23Figure 14 – Cloud Variogram & Directional Variogram........................................................................24Figure 15 - Sedimentary Log (1631-1636m).........................................................................................26Figure 16 – Sedimentary Log (1636-1641m)........................................................................................27Figure 17 - Resistivity (Recieved, Corrected, Rt/Rxo & Diameter of Invasion).....................................28Figure 18 - Shale Volume (Vsh)............................................................................................................29Figure 19 - Neutron-Porosity Cross-plot..............................................................................................30Figure 20 - Neutron-Sonic Cross-plot...................................................................................................31Figure 21 - Porosity Analysis Curves....................................................................................................32Figure 22 - Permeability Analysis.........................................................................................................33Figure 23 - Water Saturation, Hydrocarbon Saturation and Moveable Hydrocarbon Saturation........34Figure 24 - Final Composite (with Gross Reservoir & Net Pay)............................................................35

List of TablesTable 1 - Petrophysical Log Suite for Well B.......................................................................................10Table 2 - Net Pay (1610-1730).............................................................................................................20Table 3- Net Pay (1610-1730)..............................................................................................................20Table 4 - Net Pay (1620-1650) Reservoir Interval................................................................................21Table 5 - Statistical Data for the Interval 1620-1704m........................................................................36Table 6 - Statistical Data as resampled...............................................................................................36Table 7 - Permeability & Anisotropy....................................................................................................37Table 8 - Constants..............................................................................................................................38

List of EquationsEquation 1 – Preferred Resistivity Tool?..............................................................................................13Equation 2 – Rw Calculation................................................................................................................14

2


Equation 3 - Vshale (GR Index)............................................................................................................15Equation 4 – Acoustic Porosity............................................................................................................15Equation 5 – Density Porosity..............................................................................................................16Equation 6 - Tixier Permeability...........................................................................................................17Equation 7 - Timur Permeability..........................................................................................................17Equation 8 - Coates Permeability........................................................................................................17Equation 9 - Archie Equation...............................................................................................................18Equation 10 – Indonesian Equation.....................................................................................................18Equation 11 - Simandoux Equation......................................................................................................19

3


AcknowledgementsHannah Beattie, Chris Koeninger, Sunday (James) Odunuga, Alessandros Tasianas, Jose

Estaquio Pampuri-Barbossa, Shuzhe Tian, Arfan Ali, Patrick Corbett.

Executive SummaryLithology: Sherwood Sandstone (Triassic) terrestrial braided arkosic sandstones. Deposited

Proximal to source, elsewhere Aeolian influence is important.

Reservoir Type: Fluvial Jigsaw/Layer cake. Lateral flow unimpeded over 10s/100s of metres.

Vertical flow baffled over 10s/100s metres.

Gross Interval Sand: 120 metres

Net Pay: 18.50 metres

IntroductionThis report aims to evaluate the Sherwood Sandstone as drilled in Well B. It contains a core

evaluation; sedimentological and environmental interpretation as well as petrophysical

evaluation of logs and statistical analysis of core plug data; porosity and permeability. By

these means it is hoped to qualitatively evaluate the expected performance of the well in

terms of the pay interval and moveable hydrocarbon. Flow rates are beyond the scope of

this report.

Core DescriptionThe full logged section is 40 metres (1621-1661m) of which the author of this report logged

the interval between 1631-1641m (Figure 4 and Appendices; Figures 14 & 15). The author

had access to the logs of other which helped in the sedimentological evaluation, and core

correlation. Timely access to the following logs was secured:-

Hannah Beattie (1627-1637m)

James Bowkett (1631-1641m)

Chris Koeninger (1639-1649m)

Sunday (James) Odunuga (1645-1655m)

Alessandros Tasianas (1650-1660m)

Jose Estaquio Pampuri-Barbossa (1652-1662m)

4


The section from 1631-1641 metres shows repeated upward fining cycles of red-brown

arkosic sands with frequent silty intervals, lithic fine grained clasts. An annotated description

is included in the text (Figure 4) and the logs (Figures 14 & 15) themselves are included in

the Appendix. The main lithological facies are coarse granulitic to finer sands, both of which

show evidence of current ripples, and fine grained muds showing evidence of water escape

structures. Bioturbation is observed in both coarse and fine grained sediments, all

sediments are observed to be extensively cemented by irregular carbonate the cement is

isolated and conjoined, rarely vertically and laterally continuous. From this it is interpreted

that cements are of vadose origin.

Figure 2- River Cross-Sections: (a) meandering; (b) anastomosing; (c) braided. Allen (1964); Smith and Smith (1980; Smith and Cant (1982)

The interval logged is representative of semi-arid

braided fluvial deposition (Figure 1) in a relatively

low lying area proximal to an uplifting orogenic

belt (Figure 2) from which immature sediments

are derived. The arid environment and proximity

to upland areas defined the formation of the

sediments here; during periods of drought

braided rivers will have flowed carrying high

volumes of fine grained and low density material

down river resulting in the formation of braided

channels with associated accretionary structures

and allowing the formation of overbank deposits

which show evidence of bioturbation. During

flood episodes water volumes will have increased

5

Figure 1 - Triassic Sherwood Sandstone (Meadows & Beach, 1993)


several fold causing sheet floods to flow down the width of the valley(s) carrying very large

volumes of mixed material onto the outwash plain. Where dewatering structures are

observed it is interpreted that current energies fell while the flows still contained a high

percentage of water which is observed to have been expelled upwards under the sediment

load. Fine grained sediments represent the subsiding phase of the flood cycle as fine grained

material settles out of suspension while water levels fall. Meadows and Beach (1993) discuss

the Sherwood sandstone of the Irish Sea Basin which they describe as a mixed fluvial, sheet

flood and Aeolian sands the later are not recognised in Well B although some of the quartz

sand may result from fluvial reworking of Aeolian sands.

Figure 3 - Reservoir Schematic (McKie et al, 1998) Height 150m

The section seen in Well B is the same as Zone 80 above

Reservoir architecture (Figure 3) is laterally discontinuous and vertically heterogeneous lying

in fluvial channels and overbanks of the braided river system. Draping muds are unlikely to

seal the reservoir but will provide baffles hindering recovery. The architectural style is

Jigsaw with a significant layer cake influence from sheet flood muds. Porosity may be

adversely affected by clay formation related to the arkose minerals, but the original high

porosity at deposition may be preserved by the cements which formed in the vadose zone

prior to significant compaction. Faults are not observed in the section logged; however the

sediments themselves suggest proximity to actively uplifting areas.

6


Figure 4 - Sedimentological Description and Interpretation7


Structural/Regional GeologyAs a means of discussing the Ceology

of the well in context the Wessex Basin

is here described, the Well B

sediments closely approximate the

sediments of the Wessex Basin

Sherwood Sandstone. The Irish Sea

Basin would also provide a close

analogue. The Geological boundaries

of the Wessex Basin are; to the West

the Armorican and Cornubian Massifs,

to the North the London Platform and

to the South the Central Channel High.

Related basins lie to the North West

and North East; the Bristol Channel

and Weald Basins respectively.

The basins are defined as a series of

post-Variscan sedimentary depo-

centres (Underhill & Stoneley, 1998)

reflecting Mesozoic intra-cratonic

extension across Southern England

and adjacent offshore areas. The Wessex Basin, in common with other UK basins, records

Cenozoic contraction and structural inversion. Basin evolution is controlled by faults along

an E-W trend; these formed a rift valley between the Pewsey Fault System and the Central

Channel High. Basin opening originated in the West, widening to the East during the

Jurassic-Cretaceous and narrowing during the Cenozoic contraction during which time major

anticlines formed during tectonic inversion, confining the Hampshire Basin.

8

Figure 5 – Depocentres and structural evolution of Southern England; a) Permo-Triassic b) Jurassic-Cretaceous c) Cenozoic

(Underhill & Stoneley, 1998)


Basins opened by rotational normal

faulting (Figure 6) from Permian -

Cretaceous, filling with increasingly

marine facies which thicken to the

South. Permian & Triassic

continental (red bed), initially filling

intra-montane basins resulting from

the extensional collapse of the

Variscan Orogenic belt followed by

the Penarth Group, a Late Triassic

lagoonal-marine transition (marine

transgression). Jurassic-Cretaceous

fully marine successions are

punctuated by a Cretaceous

unconformity showing a marked tilt

of the basins to the East. Marine

sedimentation resumed with the

deposition of the Lower Greensand

and continued until the Upper

Cretaceous unconformity after which Tertiary near-shore and non-marine facies dominate

East of Dorchester. Inversion formed anticlines with steeply dipping Northern limbs and a

number of normal faults in the south of the area underwent significant inversion.

9

Figure 6 – N-S Cross-Sections (Present & Late Cretaceous) through Wytch Farm Oilfield

illustrating rotated fault blocks. (Underhill & Stoneley, 1998)


PetrophysicsElectric Logs Core Data

Gamma Ray GR Core Porosity

Caliper CALI Core Horizontal Permeability

Dual Induction Log ILD/ILM Core Vertical Permeability

Dual Laterolog LLD/LLS

Compensated Neutron Log NPHI

Bulk Density RHOB

Sonic (Acoustic Slowness) SONI

Table 1 - Petrophysical Log Suite for Well B

10


Figure 7 - Original Data

Quality ControlThe well logs are of reasonable quality for the most part but with clear wash-outs below

1730 metres (Figure 7). As this is in the water zone portions of the log below this depth may

be disregarded. The Gamma Ray (GR) tool is observed to be unreliable and may only be

used for qualitative analysis; it is adversely affected by radioactive readings from arkosic

minerals (particularly Potassium Feldspar and Biotite Mica). The Recovered Core depths

(Drillers Depth) are not compatible with the loggers depths on the electrical logs, this is a

result of cable stretch during the logging run, and the core must be shifted (downward) to

11


allow comparison of logs and core. Sonic logs are likely to be affected by cements in the

formation.

Petrophysical Summary – (Figure 23)A gross interval of 120 metres was evaluated of a total 170 metre logged interval, of this 21

metres are evaluated as Net Pay. The Net to Gross over this 120 metre interval is 0.15, but

this disregards the position of the oil water contact; when limited to the 30 metres of

recognised may lying above 1650 metres the Net to Gross increases to 0.7.

Following corrections a suite of Petrophysical Analyses were run using the downhole

electrical logs (Table 1). The data was cropped to remove wash-out zones below 1730

metres, the Gamma Ray log was largely disregarded having been used to depth match the

logs and core data. Borehole corrections of resistivity curves were run to provide Rt, Rxo

and depth of invasion (Rint-9b). The resistivity of water was found by the Ratio Method.

Shale volume was found using a curve (Figure 17) derived from the Neutron Density Cross-

plot (Figure 18) as a result of poor readings from the GR curve. Porosity was investigated

using the Neutron Porosity, Density Porosity and Acoustic Porosity, the curve used for

further analyses is the Neutron-Density curve (Figure 17), derived from the N-D Cross-plot

(Figure 18). Various permeability predictors (Figure 21) were run; the Linear curve of the

Terrastation suite matched best and matches the method demonstrated by Arfan Ali. Of the

water saturation curves (Figure 22) the Simandoux Equation was felt to provide the closest

approximation of real water saturation, particularly as it provided a consistent saturation of

the Sxo (invaded zone). Net Pay Analysis (Figure 23) was undertaken using the following

curves; Vsh_ND, Sw_Sm, PHI_ND and K_Linear.

12


Core Correlation / Core ShiftIn the interval

1631-1641 there

are no particular

excursions of GR

to indicate either

clean sand or

shale. In the

Interval (Figure

8), logged by

Chris Koeninger,

there are two

clear Gamma Ray

(GR) excursions

(Figure 7)

representing shales/dirty sands which are interpreted to have lower PORO/PERM character

or which are interpreted as sands with particularly high GR and high arkose content. The GR

intervals observed are at about 1649.5 m & 1644.6 m (Figure 7); the plug PORO/PERM

minimums are observed at 1642.70-1644.00 m (Figure 7) and 1646.90-1649.00 m; the

intervals are observed on Chris’ sedimentary log (Figure 8) at 1642.75-1643.8 and 1646.25-

1646.9 {with some core absent...}. Taking into account these values a downward shift of the

core, relative to the wireline data, of 130 cm was thought to be sufficient for the aims of this

report. It would be possible to apply a different shift in other parts of the well, but due to

sampling frequency concerns and time constraints it was decided to use this shift alone.

Borehole CorrectionsBorehole corrections account for variations in borehole diameter (CALI – Figure 23) and mud

cake thickness which can affect the reading of electric and radioactive logs. Many tools

include automatic correction of measurements and provide values which do not require

correction. This is the case for the Neutron Porosity (NPHI) logs used to evaluate Well B.

NPHI curves are converted to decimal for the purposes of this report. Gamma Ray (GR) logs

require correction; however GR readings throughout the formation interval in Well B are

13

Figure 8 - Logged Section 1639-1949 (C Koeninger). Chris’ logs were used as they coincide with a large change of GR.


unreliable as a result of high potassium content in felsic minerals and micas. After correction

GR curves are far too high in this formation and so are disregarded in so far as quantitative

evaluation is concerned. Resistivity (ILD, ILM, LLD, LLS and MSFL) curves have been

corrected for the effect of the borehole and mud cake which interferes with the accurate

reading of the formation and fluids. Corrections are insufficient to accommodate variation

caused by borehole collapse. The resistivity corrections applied:-

MICROSPHERICALY FOCUSED LATEROLOG (Rxo-3-MSFL)

DUAL LATEROLOG (Rcor-2)

DUAL INDUCTION (Rcor-4a)

LLD-LLS-RXO (Rint-9b)

After application of corrections resistivity logs are

treated as a true representation of resistivity at their

representative depths of investigation. The choice of

resistivity logs for use as representative of Resistivity

of the Invaded Zone (Rxo) and Resistivity of the

Formation (Rt) is decided according to ratio of

Resistivities of mud filtrate (Rmf) and water resistivity

(Rw), and the gross Rw. Laterolog is the preferred

measure of Resistivity as illustrated (Figure 9 and Equation ?).

RmfRw@183F=0.029

0.045=0.644

Rw<1

Equation 1 – Preferred Resistivity Tool?

The LLD-LLS-RXO correction also provides a depth of invasion profile for the well which

reflects the invasion depth above the Oil Water Contact. In the water column the depth of

invasion spikes where there are low porosity shales; the Schlumberger manual

14

Figure 9 - Which resistivity tool to use?


(Schlumberger, 1989) states “Generally, the lower the formation porosity, the deeper the

invasion.”

15


Log Analyses

Calculation of Water Resistivity (Rw) was undertaken by the Ratio Method as porosity in

the clean sand (~1725m) was not known. This requires knowledge of True/Formation

Resistivity (Rt), Invaded Zone Resistivity (Rxo) and Mud Filtrate Resistivity (Rmf).

RxoRt

=RmfRw

Equation 2 – Rw Calculation

1. Clean sand at 1724.14m.

2. Temperature at 0m 64.8F, T at 1816m 138F

3. Temperature Gradient 138F - 64.8F/1816m = 0.403F/m

4. Rmf at 64.8F 0.06 ohmm-1

5. Rmf at 134.3F = 0.06*((64.8+6.77)/(134.3+6.77)) = 0.0304 ohmm-1

6. At 1724.14 Rxo = 0.36; Rt = 0.53; Rmf = 0.304

7. Rw = Rmf*Rt/Rxo = (0.0304*0.53)/0.36 = 0.045

8. Using Chart Gen ? Salinity - 0.045ohmm at 134.3 = ~100,00ppm

N.B. - All values must be corrected to a standard temperature to undertake calculation of Rw

by the ratio method.

Resistivity – Once Rw has been found and resistivity curves corrected, they can be used

qualitatively to evaluate hydrocarbon-water contacts and quantitatively to provide depth of

invasion and water saturation.

Visual/Qualitative Evaluation: Departure of Rxo and Rt occurs at 1655 metres and

represents the Oil Water Contact. Shales above 1621 metres provide a seal for the

hydrocarbon column, there seems to be a transition zone into shales as the Rxo and Rt

curves do not meet in the interval above the oil column. Resistivity curves are used in later

analyses. The Depth of Invasion curve clearly shows the position of shales in the formation,

16


low porosity shales exert a strong imbibing force on water in the drilling mud and cause

deep invasion.

Shale Volume (Vsh) would usually be calculated as a function of Gamma Ray or

Spontaneous Potential using formulas of the form;

Vsh=GR−GRcleanGRshale−GRclean

Equation 3 - Vshale (GR Index)

However the results from this equation proved unreliable on this occasion, greatly reducing

the Net Pay zone (Vsh-Linear). An alternative method is to use the cross-plots of the

porosity logs and known cutoffs for shales. Of these methods the Neutron-Density (Vsh-ND)

and Density Sonic (Vsh-DS) are felt to provide the best approximation of shale volume, of

these Vsh-ND is preferred as providing a higher Net to Gross. Vsh-DS will be affected by

cementation. Vsh-Resistivity is uniformly low in the pay zone and uniformly high in the

water zone, clearly in error.

Porosity - from acoustic, density or neutron logs. Cements in this formation will tend to

cause lower apparent porosity by acoustic and density tools. Shales and bound water will

raise neutron porosity. Combination of tool responses provides reasonable accuracy.

1. Acoustic - The heavily cemented matrix of this formation means that porosity

derived from the acoustic curve will be in error, cements will increase the velocity of

sound in the sands and reduce apparent porosity. Cements are believed to have

been deposited prior to deep burial and so may preserve porosity. Hydrocarbons

may also slow acoustic waves and artificially raise apparent porosity.

17


∅=t log−tmat f−tma

Equation 4 – Acoustic Porosity

The acoustic porosity curve PHI_WTA is a good approximation of porosity, but may

read high in the hydrocarbon zone.

2. Density - Tool investigates to a depth of approximately 6 inches which is largely filled

with mud filtrate, in this borehole fluid density was 1.1 g/cc. High bulk densities are

equated with low porosity, calcite cements may raise bulk density and cause a low

apparent porosity.

∅=ρma−ρbρma−ρb

Equation 5 – Density Porosity

The density porosity curve PHI_rhob1 is a good approximation of porosity but may

be affected by cementation.

3. Neutron - Response reflects hydrogen concentration of the formation, but can be

adversely affected by; lithology, clay content and light hydrocarbons containing a

large proportion of water. The neutron porosity tool makes corrections internally to

provide a Neutron Porosity (NPHI) value. These NPHI should not be used

independent of other logs to estimate porosity; the values may be cross-plotted with

other logs to find porosity and mineralogy of complex lithologies. Light hydrocarbons

in particular may cause an increase in apparent porosity, there are no light

hydrocarbons in Well B. The neutron porosity curve Neutron Porosity (NPHI_dec)

reads uniformly high throughout the formation seen by this well.

18


4. Neutron-Density – Cross-plot indicates a mixed sandstone-limestone lithology with

porosities ranging from 12-30%. The neutron-density curve PHI_ND is a good

approximation of formation porosity removing some of the effect of calcite cements.

5. Neutron-Sonic – Cross-plot indicates a mixed sandstone-limestone lithology with

porosities ranging from 12-34%. The neutron-sonic curve PHI_NS has failed despite

repeat attempts with varying constants, it is disregarded.

6. Density-Sonic Cross-plot – is not suitable in this formation as there are no evaporites.

Permeability/Permeability Prediction from PorosityTerrastation includes a number of tools for conducting permeability prediction using the

various equations developed relating porosity and permeability. Of these the closest match

appears to be the linear equation, the other models below follow the trend of the core

permeability data less accurately.

Tixier, k 0.5=250∗φ3

Swi

Equation 6 - Tixier Permeability

Timur, k 0.5=250∗φ2.25

Swi

Equation 7 - Timur Permeability

19


Coates, k 0.5=100∗(1−Swi )∗φ3

Swi

Equation 8 - Coates Permeability

A direct calculation of

permeability from porosity was

also suggested in the

Terrastation tutorials, and this

was also undertaken and found

to closely match the Terrastation

linear equation. This method

involved cross-plotting core

porosity vs core permeability,

placing a best fit line through the

resultant cloud of data and

finding the slope (m) and

intercept (c) of the line, these

values illustrate an average

difference between porosity and

permeability. The values are

used in the formula {K =

10**(m*X1*100+c)} to calculate permeability from a favoured porosity log.

K=10∗(m∗φ∗100+C )

KH - PHI; m = 0.2918142, c = -3.55437.

KV - PHI; m = 0.320142, c = -4.67861.

Water SaturationThree methods of water saturation measurement were used; Archie, Indonesian and

Simandoux. Water saturation equations derive from the Archie Equation;

20

Figure 10- Cross-plot of CPHI vs CKH


Sw=n√ F∗RwR t F= a

φm

a=0.81 CementationFactor m=2 n=2

Equation 9 - Archie Equation

As this is a well documented basin and formation, a and m are known, Rw has previously

been calculated and Rt is provided by deep laterolog measurements RT_Rint-9b the water

saturation can be easily arrived at.

The Indonesian Equation is effective in shaly sands, having been developed for the shaly

sands of the Mahakam Delta.

Sw=(V sh0.5 (2−V sh)

√ R shRt+√ RtRo )

−2n

Equation 10 – Indonesian Equation

The Simandoux Equation is a total shale equation of quadratic form. When m and n are 2 it

is solved according to the form below.

aSw2+bSw=R t−1

Sw=((V sh

Rsh )+√(V sh

Rsh )2

+5∗φ2

Rt ¿ Rw ) 0.4∗Rwφ2

Equation 11 - Simandoux Equation

Of these it is felt that the Indonesian provides the clearest representation of the water

saturation of the formation. The Sw and Sxo above the OWC are separated in the

hydrocarbon column where oil in the formation prevents ingress of water; below the OWC

Sw and Sxo are close to 1 indicating the water saturated condition of the formation. Sw/Sxo

is used to define whether the hydrocarbons are expected to flow, the Moveable

21


Hydrocarbon Saturation which can be seen on Figure? The MHS curve is believed here to be

incorrect although there may be residual hydrocarbon in the system. Improved parameters

should help remove the effects of any inaccuracies which lead to this high residual

oil/moveable oil in the water leg.

Net Pay AnalysisNet Pay Analysis (Figure 18) used the best curves from the previous analyses to create Pay

Curves as presented in Figure 18 and in the Net Pay Report. Below are tables of the values

resulting from the Net Pay Analysis; limiting window to oil leg provides a very different Net

to Gross. For the purposes of selling to management the 2nd set of data may be more

positive.

22


23

Well Name: Well B UWI: B RR ARITH AVG SW (Sw_Sim) 0.7952

Depth : 1610.00 to 1730.00 by 0.050 meters PAY ARITH AVG SW (Sw_Sim) 0.3330

Surface X, Y: -999.000000, -999.000000 RR MINIMUM SW (Sw_Sim) 0.1483

Depth reference: M.Depth[Raw];1 PAY MINIMUM SW (Sw_Sim) 0.1483

Curve Type Curve Name Cutoff value(s) Method

RR MAXIMUM SW (Sw_Sim) 1.0000

---------- ------------------------------------- -------------------- -- PAY MAXIMUM SW (Sw_Sim) 0.4988

Vshale Vsh_ND[Kobra];1 0.4000 LT PAY HYC THICKNESS (M) 3.2955

Sw Sw_Sim[Kobra];1 0.5000 LT PAY SW (phi-wt) 0.3289

Porosity PHI_ND[Kobra];1 0.1000 GT LOWER PHI (PHI_ND) CUTOFF 0.1000

Perm. K_linear[Kobra];1 0.0000 GT UPPER PHI (PHI_ND) CUTOFF 0.0000

Reservoir rock flag curve: Res. Rock[Kobra];1 RR ARITH AVG PHI (PHI_ND) 0.2213

Net pay flag curve: NetPay1[Kobra];1 PAY ARITH AVG PHI (PHI_ND) 0.2344

TOP INTERVAL (M) 1610.0000 RR MINIMUM PHI (PHI_ND) 0.1006

BASE INTERVAL (M) 1730.0000 PAY MINIMUM PHI (PHI_ND) 0.1055

GROSS INTERVAL (M) 120.0500 RR MAXIMUM PHI (PHI_ND) 0.3140

RR THICKNESS (M) 99.3500 PAY MAXIMUM PHI (PHI_ND) 0.3136

RR/GROSS RATIO 0.8276 RR POROSITY THICKNESS (M) 21.9899

NET PAY THICKNESS (M) 20.9502 PAY POROSITY THICKNESS (M) 4.9107

NET PAY/GROSS RATIO 0.1745 LOWER K (K_linear) CUTOFF 0.0000

PAY ARITHMETIC AVG KSWIS 0.0000 UPPER K (K_linear) CUTOFF 0.0000

PAY GEOMETRIC AVG KSWIS 0.0000 RR ARITH AVG K (K_linear) 382.6420

PAY HARMONIC AVG KSWIS 0.0000 PAY ARITH AVG K (K_linear) 463.3492

GROSS SAND THICKNESS (M) 101.9999 RR GEOM AVG K (K_linear) 253.4398

HYDROCARBON PORE VOLUME 0.1573 PAY GEOM AVG K (K_linear) 342.8680

PAY/RR RATIO 0.2109 RR HARM AVG K (K_linear) 124.4454

LOWER VSH (Vsh_ND) CUTOFF 0.4000 PAY HARM AVG K (K_linear) 228.9781

UPPER VSH (Vsh_ND) CUTOFF 0.0000 RR K THICKNESS (M) 38015.5781

RR ARITH AVG VSH (Vsh_ND) 0.0246 PAY K THICKNESS (M) 9707.2080

PAY ARITH AVG VSH (Vsh_ND) 0.0103 Performed at: 10:44:40 on 5-Mar-10

RR MINIMUM VSH (Vsh_ND) 0.0000 Performed by interpreter: james bowkett

PAY MINIMUM VSH (Vsh_ND) 0.0000 Project file name: GPIA_JEB200110

RR MAXIMUM VSH (Vsh_ND) 0.3985 Project directory: P:/TerraStation

PAY MAXIMUM VSH (Vsh_ND) 0.2804

LOWER SW (Sw_Sim) CUTOFF 0.5000

UPPER SW (Sw_Sim) CUTOFF 0.0000

Table 3 - Net Pay (1610-1730)


Poro/Perm – ExcelCore data for the interval 1620-1704m are available and of these were made statistical

analyses to quantify the degree of heterogeneity in the system. Below is a table of statistical

results for the dataset. The coefficient of variation (Cv) illustrates the high degree of

heterogeneity in the permeability data set, whilst porosity with a Cv of 0.4 shows a low

degree of heterogeneity. (Table 1)

24

Well Name: Well B UWI: B PAY ARITH AVG SW (Sw_Sim) 0.3224

Depth : 1620.00 to 1650.00 by 0.050 meters RR MINIMUM SW (Sw_Sim) 0.1483

Surface X, Y: -999.000000, -999.000000 PAY MINIMUM SW (Sw_Sim) 0.1483

Depth reference: M.Depth[Raw];1 RR MAXIMUM SW (Sw_Sim) 0.9668 Curve Type Curve Name Cutoff value(s) Method PAY MAXIMUM SW (Sw_Sim) 0.4988

---------- ------------------------------------- -------------------- -- PAY HYC THICKNESS (M) 2.9181

Vshale Vsh_ND[Kobra];1 0.4000 LT PAY SW (phi-wt) 0.3168

Sw Sw_Sim[Kobra];1 0.5000 LT LOWER PHI (PHI_ND) CUTOFF 0.1000

Porosity PHI_ND[Kobra];1 0.1000 GT UPPER PHI (PHI_ND) CUTOFF 0.0000

Perm. K_linear[Kobra];1 0.0000 GT RR ARITH AVG PHI (PHI_ND) 0.2151

Net pay flag curve: NetPay1[Kobra];1 PAY ARITH AVG PHI (PHI_ND) 0.2309

TOP INTERVAL (M) 1620.0000 RR MINIMUM PHI (PHI_ND) 0.1007

BASE INTERVAL (M) 1650.0000 PAY MINIMUM PHI (PHI_ND) 0.1055

GROSS INTERVAL (M) 30.0500 RR MAXIMUM PHI (PHI_ND) 0.3136

RR THICKNESS (M) 23.3500 PAY MAXIMUM PHI (PHI_ND) 0.3136

RR/GROSS RATIO 0.7770 RR POROSITY THICKNESS (M) 5.0223

NET PAY THICKNESS (M) 18.5001 PAY POROSITY THICKNESS (M) 4.2715

NET PAY/GROSS RATIO 0.6156 LOWER K (K_linear) CUTOFF 0.0000

PAY ARITHMETIC AVG KSWIS 0.0000 UPPER K (K_linear) CUTOFF 0.0000

PAY GEOMETRIC AVG KSWIS 0.0000 RR ARITH AVG K (K_linear) 364.7267

PAY HARMONIC AVG KSWIS 0.0000 PAY ARITH AVG K (K_linear) 440.2858

GROSS SAND THICKNESS (M) 24.6500 RR GEOM AVG K (K_linear) 216.6362

HYDROCARBON PORE VOLUME 0.1577 PAY GEOM AVG K (K_linear) 318.8704

PAY/RR RATIO 0.7923 RR HARM AVG K (K_linear) 95.9247

LOWER VSH (Vsh_ND) CUTOFF 0.4000 PAY HARM AVG K (K_linear) 212.6183

UPPER VSH (Vsh_ND) CUTOFF 0.0000 RR K THICKNESS (M) 8516.3760

RR ARITH AVG VSH (Vsh_ND) 0.0427 PAY K THICKNESS (M) 8145.3081

PAY ARITH AVG VSH (Vsh_ND) 0.0110 Performed at: 17:50:20 on 28-Feb-10

RR MINIMUM VSH (Vsh_ND) 0.0000 Performed by interpreter: james bowkett

PAY MINIMUM VSH (Vsh_ND) 0.0000 Project file name: GPIA_JEB200110

RR MAXIMUM VSH (Vsh_ND) 0.3985 Project directory: P:/TerraStation

PAY MAXIMUM VSH (Vsh_ND) 0.2804

LOWER SW (Sw_Sim) CUTOFF 0.5000

UPPER SW (Sw_Sim) CUTOFF 0.0000

RR ARITH AVG SW (Sw_Sim) 0.3828

Table 4 - Net Pay (1620-1650) Reservoir Interval


The data set was resampled for statistical tools requiring comparison of permeability and

porosity at specific depths this resulted in fewer data points and show a much greater

degree of heterogeneity. (Table 2)

The dataset is observed to be anisotropic and irregularly heterogeneous according to the

rules; KH ≠ KV and KH/KV is variable. (Table 3)

HistogramHistograms of Porosity and Permeability – The porosity can be seen to be a single population. The permeability seems to show evidence of two populations in the data; this can be interpreted as shale and sand layers and therefore indicates layered as opposed to dispersed shale.

Sampling interval is sufficient for the gross data set (Table 1) but the re-sampled data set has very high sampling sufficiency values and a low number of samples (Table2) which suggests that the re-sampled data set, used for the Lorenz Plot is not representative of the formation.

The Lorenz Plot shows a high degree of heterogeneity and layering in the system (Figures 10

& 11).

25

0 5 10 15 20 25 30 More0

10

20

30

40

50

60

70

Porosity (freq)

PHI (%)

0.0010.01 0.1 1 10

1001000

10000

100000More

010203040506070

Permeability (freq)KH (freq) KV (freq)

KH (mD)

Figure 11 – Porosity and Permeability Histograms


0 0.2 0.4 0.6 0.8 1 1.20

0.2

0.4

0.6

0.8

1

1.2

KHUNORDERED PLUG DATA ORDERED PLUG DATA

Fj - Flow (CUMK)

Cj -

Stor

ativi

ty (C

UMPH

I)

Figure 12- Lorenz Plot of Horizontal Permeability

0 0.2 0.4 0.6 0.8 1 1.20

0.2

0.4

0.6

0.8

1

1.2

KVUnordered Plug Data Ordered Plug Data

Axis Title

Axis Title

Figure 13 - Lorenz Plot of Vertical Permeability

The Variogram (Figure 13) plotted with Variowin does not give a clear indication of vertical

heterogeneity or of the scale of heterogeneity/layering in the system. h is the lag and

gamma the variance, it is clear from these plots that there is little layering at a scale which

can be visualised by the data.

26


Figure 14 – Cloud Variogram & Directional Variogram

27


ConclusionsThe Well B section logged is medium porosity sandstone laid down in an arid environment

as a braided fluvial system. It is laterally and vertically heterogeneous and anisotropic,

horizontal flow dominating. Recover from these facies would be complex as flow will be

baffled but not sealed by the heterogeneous subsurface.

The Net Pay interval in Well B is between 18-20 metres, laterally these layers may extend up

to 10s/100s of metres, but beyond this the sands are likely to be baffled. The large

difference between Sw and Sxo indicates that the well will flow, the rate of flow is beyond

the scope of this report. Faulting though not directly observed may be inferred from the

sedimentological evaluation.

References

Collinson, J. D. (1986) Alluvial sediments. In Reading, H. G. (ed.) Sedimentary

environments and facies (2nd edn), pp. 20–62. Blackwell Scientific Publications,

Oxford.

Collinson, J. D. and Lewis, J. (1983) Modern and ancient fluvial systems. International

Association of Sedimentologists, Special Publication No. 6.

Read more: fluvial sediments - Fig. 1., J. Sed. Pet, J. Sed. Pet., point bars

http://science.jrank.org/pages/47592/fluvial-sediments.html#ixzz0hJ0euPPK

UNDERHILL, J. R. & STONELEY, R. 1998. Introduction to the development, evolution

and petroleum geology of the Wessex Basin. In: UNDERHILL, J. R. (ed.) Development,

Evolution and Petroleum Geology of the Wessex Basin,Geological Society, London,

Special ublications, 133, 1-18.

MCKIE, T., AGGETT, J. & HOGG, A. J. C. 1998. Reservoir architecture of the upper

Sherwood Sandstone, Wytch Farm field, southern England. In: UNDERHILL, J. R. (ed.)

Development, Evolution and Petroleum Geology of the Wessex Basin, Geological

Society, London, Special Publications, 133, 399-406.

28



http://science.jrank.org/pages/47592/fluvial-sediments.html


Schlumberger, 1989. Log Interpretation Principles/Application, 7th Edition. Sugar

Land, Texas.

29


Appendices

Figure 15 - Sedimentary Log (1631-1636m)

30


Figure 16 – Sedimentary Log (1636-1641m)

31


Figure 17 - Resistivity (Recieved, Corrected, Rt/Rxo & Diameter of Invasion)

32


Figure 18 - Shale Volume (Vsh)

33


Figure 19 - Neutron-Porosity Cross-plot

34


Figure 20 - Neutron-Sonic Cross-plot

35


Figure 21 - Porosity Analysis Curves

36


Figure 22 - Permeability Analysis37


Figure 23 - Water Saturation, Hydrocarbon Saturation and Moveable Hydrocarbon Saturation

38


Figure 24 - Final Composite (with Gross Reservoir & Net Pay)39


KH KV PHI

Ns 271 60 283

MODE 0.04 0.01 9.4

MEDIAN 49 2.55 16.1

AVERAGE 576.4422878

208.481166

7 16.26537102

GEOMEAN #NUM! 3.11752257 #NUM!

HARMEAN 0.242326409

0.05696373

2 12.5572375

ST DEV 1032.000892

412.711914

4 6.881473905

VAR 1065025.842

170331.124

3 47.35468311

Cv 1.79029352

1.97961245

6 0.423075127

N0=(10*Cv)2 320.5150887

391.886547

6 17.89925627

Ps=(200*Cv)/SQRT(Ns) 21.75051728

51.1133738

2 5.029841166

Table 5 - Statistical Data for the Interval 1620-1704m

KH KV

ARMEAN(K

) GEOMEAN(K)HARMEAN(K) PHI

Ns 60.0 60.0 60.0 60.0 60.0 60.0

MODE 0.0 0.0 0.0 0.0 0.0 9.1

MEDIAN 44.0 2.6 41.0 13.1 4.3 16.1

ARMEAN 383.4 208.5 295.9 240.0 220.0 16.2

GEOMEAN 13.4 3.1 12.1 6.5 3.5 14.3

HARMEAN 0.2 0.1 0.2 0.1 0.1 12.3

ST DEV 703.8 412.7 524.4 489.8 466.3 7.2

VAR 495290.7 170331.1 274994.9 239896.0 217478.9 51.9

40


Cv=SD/ARMEAN 1291.8 817.0 929.2 999.6 988.5 3.2

N0=(10*Cv)2 166887426.966750476.286346545.9 99926628.1 97705350.4 1030.9

Ps=(200*Cv)/SQRT(Ns) 33355.4 21095.1 23992.6 25810.4 25521.9 82.9

Table 6 - Statistical Data as resampled

Dept

h

KH-

KV KV/KH

Dept

h

KH-

KV KV/KH

Dept

h KH-KV KV/KH

1664 0 1 1663 -0.22 1.224489796 1689 185.9 0.016402116

1649 0.03 0.25 1636 0.86 0.14 1624 205.3 0.012980769

1657 0.03 0.25 1685 0.57 0.62 1658 -87 1.393665158

1671 0.03 0.25 1670 -23.1 5.714285714 1627 224 0.066666667

1680 0.01 0.75 1653 -11.9 2.469135802 1639 -675 3.721774194

1652 0.02 0.666666667 1662 8.1 0.024096386 1676 -429 2.088832487

1679 0 1 1684 13.97 0.002142857 1701 206 0.491358025

1668 -0.45 7.428571429 1690 -54 4 1641 460 0.08

1647 0.06 0.25 1642 -17 1.5 1693 257 0.584142395

1656 0.1 0.090909091 1666 5 0.868421053 1672 825.6 0.002898551

1678

-

85.87 661.5384615 1688 26 0.48 1692 -185 1.221556886

1635 0.13 0.1875 1622 28 0.490909091 1644 910.3 0.010543478

1631 0.15 0.166666667 1692 78 0.025 1651 220 0.838235294

1681 0.24 0.111111111 1700 -79 1.9875 1677 230 0.867052023

1643 0.29 0.033333333 1628 81.99 0.000121951 1646 1413 0.224052718

1626 -0.23 1.71875 1623 100.9 0.010784314 1674 1853.85 8.09061E-05

1682 -0.96 3.823529412 1667 151.8 0.007843137 1659 750 0.609375

1632 0.37 0.026315789 1625 180.1 0.015846995 1650 1020 0.514285714

1629 0.21 0.522727273 1686 178.9 0.043315508 1696 560 0.734597156

1648 0.85 0.095744681 1633 -307 2.632978723 1645 2273 0.291900312

Table 7 - Permeability & Anisotropy

41


Name Units Value Name Units Value

MD m 1610 BIT SIZE in 12.25

TD m 1780 MUD WEIGHT lb/g 9.67

INCREMENT m 0.05 FM SALINITY ppm 100000

ELEV m 33.5 BH SALINITY ppm 50000

RMC ohmm 0.16 STANDOFF (IL) in 0.125

TRMC degF 64.7 STANDOFF (NEUT) in 0.125

RM ohmm 0.08 SURF TEMP MD m 0

TRM degF 64.8 GR MATRIX GAPI NULL

RMF ohmm 0.06 RHO MATRIX g/cc 2.65

TRMF degF 64.8 DT MATRIX us/f 47.5

RW ohmm 0.040

4

CNL MATRIX pu 0.05

TRW degF 134.5 GR SHALE GAPI NULL

BHT degF 138 RHO SHALE g/cc 2.45

MEAN SURF TEMP degF 64.8 DT SHALE us/f 90

T-GRADIENT degF 0.040

3

CNL SHALE pu 0.3

ARCHIE A UNKN 0.81 GR FLUID GAPI NULL

ARCHIE M UNKN 2 RHO FLUID g/cc 1.1

SAT EXP (N) UNKN 2 DT FLUID us/f 185

R SHALE ohmm 0.9 CNL FLUID pu 1

TD OF REC. BHT m 1816 DT MATRIX SHALE us/f 82

Table 8 - Constants

42

single well study - well 'b' - wytch farm

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