Friction and energy dissipation mechanisms in adsorbed molecules
The Discovery Group, Denver, Colorado Cimarex , Tulsa ... eval of gas...Langmuir volumes ≈ a...
Transcript of The Discovery Group, Denver, Colorado Cimarex , Tulsa ... eval of gas...Langmuir volumes ≈ a...
Bob CluffThe Discovery Group, Denver, Colorado
Mike MillerCimarex , Tulsa, Oklahoma
April 2010 DWLS luncheon
The early years – shale evaluation from GR and density logsTrying to get quantitative – deltaLogR and other methods to estimate TOC from logsThe porosity problem – if TOC looks like porosity on density logs, how can you tell them apart?Geochemical logs finally find their marketModern multi-mineral solutions – reverse engineering the Shale Gas logsWhere are going next?
There was the gamma ray log,And it was good…………
Recognition that black shales are radioactive is not rocket science, we saw it in the 40’sEarly uses were just to separate hot shale from the background and map net thicknessBlack shale vs. Gray shale in Appalachian basin terms
Uranium in sea water drops out in reducing environments
Uranium forms organometallic complexes with organic matter at or just below the sediment-water interfaceRequires very low oxygen in seawater (anoxia)Slow process, residence time dependentAnaerobic bacteria are involved in reduction of U(VI) to U(IV)
Tetraethyl lead is a common example of an organometallic complex
Linear dependence of GR on TOCy = mx + bTOC = m GR + bm = slope of GR (API) vs TOC (wt %)b = GR intercept at 0% TOC (gray shale baseline)
requires normalized GR logs relationship varies between basins
no single set of coefficients workneed local calibration to core data
only approximate- the amount of uranium associated with TOC varies even within a formationSchmoker, 1981, AAPG 65 1285-1298
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New Albany Shale, Illinois basinEGSP cores (1976-1979), all Big Blue logs
TOC
%
y = 0.0265x – 1.3161R2 = 0.5453
In the 1970’s, when bulk density logs first became common, it became apparent hot black shales also had low densityCross-plots of TOC vs. density quickly showed the story……..
Kerogen is light, like coal, so it “looks like” porosity on a density logVery, very common to pick a density porosity cutoff as “net pay” in gas shale plays
Schmoker, 1979, AAPG 63 (9) 1504-1537
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2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9Bulk density (g/cm3)
tota
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)New Albany Shale, Illinois basinEGSP cores (1976-1979), all Blue logs
! slope varies if you plotTOC as v/v or as weight %
y = -30.28 x + 79.94R2 = 0.95
Passey et al, 1990, AAPG Bull 74 (12) 1777-1794The deltaLogR method was proposed as an improvement over simple GR and RhoBestimators for TOCRelied on two key observations:
∆t (and also ρb) vary with kerogen contentResistivity increases with increasing maturityLogarithmic separation between ∆t and Rdeep, appropriately scaled, can be related to TOC
It’s just an old-fashioned sonic F-overlay!!!
∆logR = log10(R/Rbaseline) + 0.02(∆t-∆tbaseline)∆t - resisitivity separation means likely source interval∆logR separation is linearly related to TOC if maturity is known or can be estimated
where:Rbaseline is the “gray shale” baseline resistivity
∆tbaseline is the “gray shale” baseline ∆t
important: at any given ∆logR, TOC decreases as LOM increases
Many people have noted, including Passey, that ∆logR has trouble at high maturities
TOC relationship was calibrated for LOM of 6-9 and low ∆logR, everything else was extrapolated LOM scale is only loosely related to common lab values, including Tmax and Ro.
Resistivity does not continually increase through the gas window, in fact it starts to fall back above Ro of ~1.1%
We’ve seen conductive shales at very, very high Ro’s
Mike Miller, BP, DWLS 2010 Spring Workshop
Ro ~1.8 – 2.0 Ro ~ > 4.5
XRD mineralogy ~ equivalent between wells
Low RhoB, density-neutron converge, high Rt (100’s of ohmm)
high RhoB, density-neutron separate, very very low Rt (< 1 ohmm)
If kerogen has a density of ~1.15 g/c3 and water is ~1.0, and both contain hydrogen, how the heck do you separate them?Two separate, related issues:
Kerogen density is clearly low, but difficult to measure exactlyNeutron porosity of kerogen is unknown
So we just reverse the problemSolve for matrix values that work best to match both core measured TOC and core porosity
Both GR and density correlations implicitly assume porosity is constant within the error of the measurementsSlope-intercept of the regression compensates for the average porosityScatter around the trend is presumably a measure of porosity that varies independently from TOC
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Bulk density (g/cc)
tota
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RhoMa ~ 2.72
Example: at any fixed TOC, RhoBVaries by +/- 0.1 g/c3 around the mean.At RhoMa = 2.72, this is +/- 6% porosity
The old standard answer – somebody will sell you another measurement.Pe doesn’t cut it, not a matrix/lithology problem
also heavy barite muds render it useless in several plays (e.g. Haynesville Sh)
Spectral GR doesn’t reduce uncertainty much, if any
Nice to know the clay breakdown, but not essential
Finally….geochemical spectroscopy logs find their purpose in life!
ECS tool uses AmBe chemical source, detectsSi, Ca, Fe, S, Mg, and “pseudo-Al” (+ Ti, Gd; not used)
SpectroLith processing is a DETERMINISTIC set of equations, based on a large sample database, that solves for the common minerals:
Fe, S → pyrite“excess Fe” (after making pyrite) → sideriteCa → total carbonate (calcite + dolomite)Si, Ca, Mg, pseudo-Al → clayLeft over → quartz, feldspar + mica undifferentiated
Another regression equation is used to solve for grain density (RHGE)
NOT a linear combination of mineral volumes and densities
ECS does NOT see kerogenSpectroLith grain density is assumed to be a kerogen-free value: RHGE – RHOM → Vkerogen
SpectroLith outputs → ELAN combine with density, neutron, Pe, NGS, etc.STOCHASTICALLY solve for lithology, porosity, Sw, Vkerogen
First issue is adsorbed gas contentComplex function of TOC, pressure, temperature, maturity, and kerogen typeModel calibrated to core isothermsGenerally isotherms are run at reservoir temperature for the cored well, and T is ignored thereafter
Isotherms → set of Langmuir equationsLangmuir volumes ≈ a linear function of TOCThat plus pressures → adsorbed gas content
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Gab = VL * P / (P + PL)
GRI 91/0296
y = 14.217x - 32.974R² = 0.9733
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Just like a tight sandstone or siltstoneNeed to determine porosity and saturation from a log model or core dataGIP (scf) = 43560 ft2/ac * A h φ Sg / Bg
where A is the area in acresh is the net thickness, in feetφ is porosity available for gas storage, v/vSg is the gas saturation, v/vBg is the gas formation volume factor, rcf/scf
“gas filled porosity”
Multimineral, stochastic solutions seem to work better than deterministic 2, 3 or 4 mineral models
Challenge is to incorporate ECS-type data directly in the models, bypassing the current regression based approaches
Geomechanical modelingVp-Vs data from cores suggest most properties can be predicted from DTC logs alone
Better analysis of limited and older log suitesHorizontal well evaluation with minimal data