Tu E Understanding Net Pay in Tight Gas Sands - A Case Study from the Lower Saxony Basin, NW- Germany

Transcription

1 Tu E Understanding Net Pay in Tight Gas Sands - A Case Study from the Lower Saxony Basin, NW- Germany B. Koehrer* (Wintershall Holding GmbH), K. Wimmers (Wintershall Holding GmbH) & J. Strobel (Wintershall Holding GmbH) SUMMARY We present an integrated workflow to describe and characterise Upper Carboniferous tight gas sands by systematically integrating core-based macroscopic geologic elements (depositional rock types), microscopic observations (post-depositional diagenesis) and pore-scale properties like capillary pressure and nuclear magnetic resonance data. Our workflow integrates multiple data sets and scales from a Wintershall-operated tight gas field in the Lower Saxony Basin of Northern Germany. The reservoir is of Westphalian C to Stephanian in age and consists of thick successions of fourth-order coarse- to fine-grained tight sandstone cycles separated by siltstones and in party by anthracite coal seams. The tight sandstones are intensely compacted and cemented with quartz, clay minerals and carbonate cements and generally characterized by low matrix porosities (< 10%) and very low permeabilities (<0.1mD). A hydraulic rock-typing approach was selected to better define net pay of tight gas sands. In contrast to conventional petrophysical net pay criteria (porosity and water saturation log cut-offs), our approach makes use of the calculated pore throat radius (using Winland R35 equation) and relative permeability measurements ( mobile gas ). Our multi-scale rock typing study enables a better understanding of tight gas sand recovery factors and sweet-spot identification especially for new field development/appraisal projects.

2 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. We present a workflow 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 R 35 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. 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. 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-upward cycles are interpreted as fourth-order cycle sets (400ka Milankovitch orbital cycles) that show a systematic upwards change from

3 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 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). 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. 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 76th EAGE Conference & Exhibition 2014

4 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 R 35, Pittman R 25, Razaee R 10 ), the best fit to the Winland R 35 (Kolodzi 1980) method was found [1]: R 35 = 10 ( Log(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): HRT 1: R 35 < 0.05 µm (nannoports, no flow capacity for gas, non-reservoir) HRT 2: R µm (microports, some flow capacity for gas) HRT 3: R 35 > 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 R 35 >0.05 µm): HRT > 1 PAY based on relative permeability (i.e. mobile gas with K rel to gas > 0): Sw < 60% 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

5 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. R 35 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 R 35 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. 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, 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, 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). Carboniferous hydrocarbon geology: the southern North Sea and surrounding areas. Yorkshire Geological Society, Publications Series Volume 7, 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 55 th Annual Fall Technical Conference, SPE paper 9382, 2-4.