1 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 76 th 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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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]: