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Understanding Net Pay of Tight Gas Sandstone Reservoirs

Bastian Koehrer (Wintershall Norge AS)

This paper was originally presented at the 76th EAGE Conference & Exhibition 2014 in Amsterdam, The

Netherlands, 16-19 June 2014: Koehrer, B., Wimmers, K. & Strobel, J. (2014). Understanding Net Pay in Tight Gas

Sands – A case study from the Lower Saxony Basin, NW-Germany. EAGE 76th Conference and Exhibition 2014,

Amsterdam, the Netherlands.

The paper was further selected for the EAGE Distinguished Lecturer programme for 2015-2016 (Understanding Net

Pay of Tight Gas Sandstone Reservoirs).

Introduction

The definition of Net Pay is critical to correctly calculate the static in-place volumes as well as dynamic

recovery factors of oil and gas reservoirs. For porous and permeable conventional clastic reservoirs, routine

petrophysical Net calculation is most commonly based on static rock property cutoffs such as shale volume

or porosity. In tight sandstone reservoirs however, these properties are generally very poor indicators for

the dynamic behaviour within the reservoir and thus reservoir flow potential which strongly triggers the

field recovery factor. Especially in the early field development and appraisal phases in which field

production data is limited or even absent, reliable estimates of hydrocarbon recovery are crucial for field

development strategy and economics.

A workflow is presented to better define the Net Pay of tight gas sandstones using data from an Upper

Carboniferous tight gas field in NW-Germany (herein termed Field X), operated by Wintershall Holding

GmbH. By integrating core-based macroscopic geologic elements (depositional facies), microscopic

observations (post-depositional diagenesis) and pore-scale properties (porosity, permeability, capillary

pressure, NMR), the tight gas sandstones of the Field X reservoir are interpreted in terms of their dominant

pore throat radius (using the Winland R35 equation) and their effective permeability to gas (using relative

permeability measurements). Our Net Pay workflow integrates multiple data sets and scales using a

hydraulic rock-typing approach that is designed to calculate a first-pass estimate of the recovery factor and

thus define recoverable resources of Field X.

Database

The established workflow builds on geological and petrophysical data from Field X. The discovery belongs

to the North German Upper Carboniferous tight gas play in the Lower Saxony Basin that is sourced with

gas from Carboniferous coals and sealed by overlying Permian Zechstein evaporites. In the structure, gas

accumulated in a tilted horst block with a four-way dip closure (Figure 1). The structure initially formed

during Late Carboniferous postorogenic NW-SE trending dextral wrench-faulting. Trap modification by

contractional tectonic inversion occurred during the Late Cretaceous when the prospect was uplifted to its

present-day depth of 4 km. The reservoir is structurally (3 field cross-cutting faults) and vertically (2 free-

water levels) compartmentalized. The amount of tectonic fracturing interpreted from cores and BHI logs

was found to be minimal and natural fracture support for production (i.e. dual permeability behavior) can

be excluded.

Detailed sedimentological (facies), palynological (miospores) and chemostratigraphic (XRD, heavy

minerals) analyses on 129 m of core material from well A (Figure 1) showed that the reservoir is of

Westphalian C to Stephanian in age and consists of thick successions of fining-upward fluvial sandstones,

separated by siltstones and in part by anthracite coal seams. Fluvial sandstones were deposited in a broad

alluvial plain in the northern foreland basin of the Variscan Mountains. Sequence stratigraphically, fining-

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upward cycles are interpreted as fourth-order cycle sets (400ka Milankovitch orbital cycles) that show a

systematic upwards change from downstream accretion-dominated channels (low sinuosity) at the base to

heterolithic, lateral accretiondominated channels (high sinuosity) towards the top of each cycle set (after

Jones and Glover, 2005). Grain density, porosity and absolute Klinkenberg-corrected permeability were

measured on 337 plugs from 3 wells and values were corrected for overburden stress (55 Mpa). Results

show that the tight sandstones are characterized by low matrix porosities (av. 6.1 %) and very low

permeabilities (av <0.01 mD). Vertical textural and facies changes have a strong impact on reservoir quality

distribution with generally decreasing porosities and permeabilities from base towards the top of each cycle

set. For hydraulic rock typing purposes, capillary pressure measurements (MICP) were conducted on 10

plugs, relative permeabilities on 6 plug samples and nuclear magnetic resonance (NMR) data (e.g. pore size

distribution) on 40 plugs from well A.

Figure 1 Top structure map of Field X in NW-Germany. The structure is situated at the northern tip of

the Lower Saxony Basin (LSB). The prospect was appraised by four wells since the 1960s.

Petrographic and diagenetic studies on 60 standard thin-sections and 12 SEM samples from wells A and B

revealed a complex paragenesis of the reservoir (Figure 2). A complete destruction of primary intergranular

porosity occurred during shallow burial due to intense mechanical compaction and quartz cementation.

Secondary porosity was initially generated by framework grain dissolution (e.g. feldspar) under late

mesodiagenetic, deep burial conditions. These intragranular pores were subsequently filled with clay

minerals (illite, kaolinite) and ferroan carbonate cements during further burial, occluding most of the

remaining open pore space.

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Figure 2 Left: GR log of Well A (total well length: 550m MD), drilled vertically into the Upper

Carboniferous of Field X. Six cores with a total length of 129 m were taken. Right: Petrographic and

SEM analysis of a sublitharenite from core 4 (plug ambient porosity: 9.1%; plug ambient permeability:

0.32 mD).

Calculation of a hydraulic Net from pore throat radius

Routine volumetric maximum gas-in-place calculations (static GIIP) for both conventional gas as well as

tight gas sandstone reservoirs are essentially a function of porosity and water saturation. To account for

non-reservoir intervals that do not contribute to production, a Net-to-Gross (= Net) value is commonly

introduced into the static GIIP calculation. It is best practice to choose cut-offs for static properties like

porosity or Vclay to define Net. As neither porosity nor shale volume however are valid indicators for

flow potential especially in tight sandstones, a different approach has been selected for Field X. The

proposed hydraulic Net definition is based on the reservoir criteria published by Gaynor and Sneider

(1992) that have identified the pore throat radius as the key element that both represent physical rock flow

and storage potential. Accordingly, rocks with reservoir potential (= Net) are characterised by a mean

pore throat radius of >0.05 µm in order to have any flow potential to gas. By comparing measured mean

pore throat radii from 10 MICP curves and the theoretical pore throat radius calculations using various

standard equations for different mercury saturations (e.g. Winland R35, Pittman R25, Razaee R10), the best

fit to the Winland R35 (Kolodzi 1980) method was found [1]:

R35 = 10 (0.732 + 0.588Log(K) – 0.864Log(PHI)) [R: µm; K:mD; PHI:%] [1]

Based on calculated mean pore throat radii, a classification of hydraulic rock types was established

(modified from Hartmann and Coalson, 1990):

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• HRT 1: R35 < 0.05 µm (nannoports, no flow capacity for gas, non-reservoir)

• HRT 2: R35 0.05 – 0.5 µm (microports, some flow capacity for gas)

• HRT 3: R35 > 0.5 – 2 µm (mesoports to macroports, good to excellent flow capacity for gas)

Overburden corrected poro-perm plug data of the dataset from Field X was plotted against the calculated

hydraulic rock types (Figure 3). It is evident that a classical static porosity cut-off (here 5%) both

overlooks and overestimates reservoir intervals with flow potential to gas.

Figure 3 Overburden corrected absolute plug permeabilities from Field X related to effective porosity as

a function of the dominant pore throat radius (Winland R35).

Calculation of Net Pay from hydraulic rock type and relative permeability

To calculate Net Pay, a water saturation cut-off value at which gas is the mobile phase had to be selected

for Field X. Relative permeability data from well A and well C was used indicating an effective gas

permeability at water saturations of <60%. In summary, the hydraulic Net Pay definition for Field X can

be written as follows:

• NET based on hydraulic rock type (i.e. mean pore throat radius R35 >0.05 µm): HRT > 1

• PAY based on relative permeability (i.e. „mobile gas“ with Krel to gas > 0): Sw < 60%

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The outlined Net Pay definition was integrated into static reservoir modeling of the 4x4 km large central

segment of Field X (Figure 4). 3D-property models of facies, porosity, absolute permeability (co-kriging

with porosity) and water saturation (via facies-specific saturation height functions) were generated and used

as input for Net and Pay calculations. It is apparent that classical Net definitions based on shale volume

(here: 76%) or 5% porosity cut-off (here: 49%) both most likely overestimate the amount of rock matrix

capable of both storing and flowing gas (i.e. hydraulic Net = 39%). By applying the <60% Sw Pay cut-off

criteria, the resulting Net Pay of the investigated segment shrinks to only 9%. In the absence of natural

fracture support, the outlined Net Pay estimate yields a first-pass calculation of the recovery factor as it

captures the percentage of the rock matrix that is capable of flowing gas. The proposed Net Pay estimate

may be used for hydraulic frac planning, sweet spot identification and placement of development wells.

Figure 4 Application of outlined NET PAY calculation to central block of Field X. Lithology-based

(76%) or porosity (49%) based NET definitions overestimate rock matrix flow potential. R35 based Net

(39%) yields a more realistic estimate of dynamic reservoir properties.

Conclusions

A dataset from Field X in the Lower Saxony Basin of NW-Germany was used to derive a workflow to

calculate a hydraulic Net Pay especially applicable to tight gas sandstones. The proposed Net Pay

represents the percentage of the total rock matrix capable of both storing and flowing gas. Whereas Net is

based on the dominant pore throat radius (calculated by overburden corrected porosity and permeability

data using the Winland R35 equation), Pay is based on the water saturation at which gas becomes the

mobile phase, derived from relative permeability data. The outlined workflow is designed to calculate a

first-pass estimate of the recovery factor and thus define recoverable resources in early field development,

when field production data is largely absent.

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References

Gaynor, G.C. and Sneider, R.M. [1992] Effective Pay Determination: Part 6. Geological Methods. In:

Morton-Thompson, D. and Woods, A.M. (Eds.) Methods 10: Development Geology Reference Manual.

American Association of Petroleum Geologists Special Publication, Tulsa, 286-288.

Hartmann, D.J. and Coalson, E.B. [1990] Evaluation of the Morrow Sandstone in the Sorrento field,

Cheyenne Company, Colorado. Rocky Mountain Association of Geologists, 91-100.

Jones, N. and Glover, B. [2005] Fluvial sandbody architecture, cyclicity and sequence stratigraphical

setting – implications for hydrocarbon reservoirs: the Westphalian C and D of the Osnabrück-Ibbenbüren

area, northwest Germany. In: Collinson, J.D., Evans, D.J., Holliday, D.W. and Jones, N.S. (Eds).

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Society, Publications Series Volume 7, 57-74.

Kolodzie, S. [1980] The analysis of pore throat size and the use of the Waxman-Smits equation to

determine OOIP in the Spindle field, Colorado. Society of Petroleum Engineers 55th Annual Fall

Technical Conference, SPE paper 9382, 2-4.