(9) Utica Play Resource Assessment

Introduction

The Utica Play resource assessment was conducted to estimate: (1) remaining recoverable hydrocarbon resources and (2) original hydrocarbon resources in-place. Remaining technically recoverable resources were determined using a probabilistic approach following an outline developed by the USGS. Original hydrocarbon-in-place resources were determined using a volumetric approach. Both approaches evaluate roughly the same play area (Figure 9-1).

9.1 Remaining Recoverable Resources

The first portion of the resource assessment task followed the probabilistic approach developed by the USGS and used in a 2012 assessment of undiscovered oil and gas resources of the Utica Shale (Kirschbaum and others, 2012). With this approach, the geologist defines the geographic limits of an Assessment Unit (AU), which is an area with expected oil or gas resources with generally the same or similar thermal maturity, organic content, lithology, source rock and trapping mechanism.

Input parameters for calculating the resource are AU area, drainage area per well, percentage of the unit untested, percentage of untested area in sweet spots, success ratios and estimated ultimate recoveries (EURs) for both sweet spot and non-sweet spot area, and co-product ratios (gas-to-oil and NGLs-to-gas ratios within oil accumulations, and liquids-to-gas ratio for gas accumulations). For each of these parameters, the geologist does not specify a single number, but rather estimates of expected minimum, maximum and average or mode, thus defining a distribution. The actual resource assessment calculations take place through a Monte Carlo procedure, that is, through repeated sampling of the distributions through a large number of trials (1000 or more). These independent trials are used to calculate the F5, F50 (Median), F95 and average volumes of oil and gas in the AU. The procedure is described in more detail in Charpentier and Cook (2010). Calculations are made through a spreadsheet available for download from the USGS, which requires the commercial package @Risk™ to do the Monte Carlo computations. Input parameters for computations are in Appendix 9-A pdf icon (PDF, 298.67 KB; 3 pages).

9.1.1 Definition of Assessment Unit Sweet Spot Areas

Within each assessment unit, we calculated percentage of the undiscovered area lying within sweet spots from maps of well locations, cumulative production from each well and geographic trends in thermal maturity. Thermal maturity data collected during this project were combined with published data from the USGS, converted to vitrinite reflectance equivalent through a regression equation and mapped (Figure 9-2). We were particularly interested in delineating a gas prone region, an oil-prone region and the primary area of wet gas. Two indicator variables were created, the first by setting all reflectance values greater than 1.1 to “1” and those less to “0”, and the second by setting values greater than 1.4 to “1” and the balance to “0”, these two thresholds being the generally-accepted ones for defining the oil, wet gas and dry gas windows of maturity. Kriging of these two indicator variables provides local probabilities that an observed reflectance will exceed the respective threshold (Figure 9-3). Overlaying the contoured probability of exceeding the 1.1 threshold with a map of oil cumulative production (Figure 9-5), we drew a map of minimum and maximum sweet spot (Figure 9-5).

Similarly, contoured probability of exceeding the 1.4 reflectance threshold and with maps of oil (Figure 9-4) and gas production (Figure 9-6) were used to delineate extents of the minimum and maximum wet gas sweet spots, as well as the extent of the wet gas AU as a whole (Figure 9-7). Because natural gas liquids were not split out from gas in data available to us from Ohio, we could not map wet gas trends directly.

Minimum and maximum extents of the gas sweet spot for the purpose of the resource assessment were based on locations of producing gas wells in the gas prone region. Areas for each of the assessment units and respective sweet spots were calculated from the resulting map shown in Figure 9-8.

9.1.2 Estimated Ultimate Recovery

Annual production data for 2011-2014 from Pennsylvania and Ohio graphed by year in production (1st, 2nd, 3rd and 4th) showed a lot of variation with no consistent trend in medians (for example, Figure 9-9). As the play develops, one can expect an increase in productivity as the best areas are discovered and well completion strategy improves. For instance, wells with four years of data were the earliest drilled and can be expected to have below average performance compared with wells drilled in subsequent year, for which less data are available. Therefore, we examined subsets of wells based on the number of years of data available (i.e., grouped by year of completion), giving us four sets of medians for fitting a model. Note that medians for wells completed in 2012, 2013 and 2014 were shifted six months toward the origin to reflect the average number of months online, and medians for wells completed in 2011 were adjusted downward nine months because the average period of production for these wells was about three months.

A harmonic model of decline was fitted using the curve for wells completed in 2011 as a guide to shape and median production from wells completed in 2014 as an indicator of median production to expect (Figure 9-10). The model was used to compute cumulative production out to forty years as an EUR. The fifth percentile of production for wells completed in 2014 was used as a minimum within the sweet spot, and a maximum was fitted by eye from the range of outcomes for wells in their first and second year of production. Final results expressed as median resource were relatively insensitive to changes in the maximum EUR compared with changes in median EUR, offsetting the relatively high uncertainty in maximum EUR to expect.

The same procedure was followed for the oil, wet gas and gas assessment unit sweet spots (Table 9-1 to 9-3). For areas outside the sweet spots in each assessment unit, the median EUR was set at the value corresponding to the lowest five percentile of production from wells that went online in 2014, the minimum at the value corresponding to the minimum production in these wells and the maximum at the value of EUR obtained for the well at the tenth percentile.

Oil AU (MMbo)MinMedMax
Sweet Spot0.0220.1990.628
Non Sweet Spot0.0020.0220.049
Table 9-1. Parameters for estimated ultimate recovery used in resource assessment of Oil Assessment Unit.
(ed., Sweet Spot Max updated to "0.628"; original was "0.022". 7/15/2015)

 

Wet Gas AU (Bcf)MinMedMax
Sweet Spot0.645.7618.84
Non Sweet Spot0.200.641.19
Table 9-2. Parameters for estimated ultimate recovery used in resource assessment of Wet Gas Assessment Unit.

 

Gas AU (Bcf)MinMedMax
Sweet Spot0.197.0930.37
Non Sweet Spot0.0390.190.32
Table 9-3. Parameters for estimated ultimate recovery used in resource assessment of Gas Assessment Unit.

9.1.3 Success Ratios and Co-Product Ratios

Success ratios were defined, where possible, by examination of well performance (wells with zero production over several years, plugged wells, areas of numerous cancelled permits). Success ratios in sweet spots were set at the same values across assessment units: minimum of 90%, mode of 95% and maximum of 99%. They were set very low outside the sweet spot for the Oil Assessment Unit: minimum of 1%, mode of 5% and maximum of 10%, whereas these parameters for the Gas and the Wet Gas Assessment Units were set at 5, 10 and 40% respectively.

Co-product ratios were calculated from public records and used only for the oil assessment unit. The largest source of production data was the public database from the state of Ohio. In Ohio’s way of recordkeeping, production data report NGLs and gas as a single number. Therefore, calculation of the gas resource in both the gas and wet gas assessment units includes a significant percentage of natural gas liquids which could not be separated from these totals and/or evaluated individually. For this reason, we did not include NGLs in the liquids-to-gas ratio for the gas AU or a NGLs-to-gas ratio for the oil AU. Parameters used for the gas-to-oil ratio distribution in the Oil Assessment Unit were 900 scfg/bo minimum, 3600 scfg/bo mode and 8000 scfg/bo maximum.

9.1.4 Results

The results of the probabilistic resource assessment are provided in Table 9-4. Because total oil and gas resources tend to follow a logarithmic distribution, means assessment values are higher than the medians. Total mean gas resource, which includes wet gas equivalent in the Wet Gas and Oil assessments units, sums to 782,171 Bcf. Total oil resource is 1960 MMbo.

Oil Assessment
Unit
Oil (MMbo)Gas (Bcf)
F95F50F5MeanF9F50F5Mean
Sweet Spot7331677374419082231663617,7227949
NonSweet Spot2349915269191446216
Total7911728378819602370685817,9608165

Wet Gas
Assessment Unit
Oil (MMbo)Gas (Bcf)
F95F50F5MeanF95F50F5Mean
Sweet Spot 23,84049,601106,55055,980
NonSweet Spot 993791023447
Total 24,48450,037106,85256,427

Gas Assessment
Unit
Oil (MMbo)Gas (Bcf)
F95F50F5MeanF95F50F5Mean
Sweet Spot 220,473590,6801,542,873710,341
NonSweet Spot 2862658413,8357238
Total 228,478598,0261,549,586717,579
Table 9-4: Summary of recoverable oil and gas remaining.
MMbo = million barrels of oil
Bcf = billion cubic feet of gas

9.2 Original In-Place Resources

A second resource assessment method was used to determine original hydrocarbon-in-place following a volumetric approach. The volumetric approach provides a means to assess resource potential from fundamental geologic data in a manner that is independent of development practice, well performance, economics and the limited geographic extent of exploratory activity that often characterizes the early development of a hydrocarbon play. Basic geologic and reservoir data are used to define characteristics of selected stratigraphic units and to calculate hydrocarbon volumes. Original in-place resources were estimated for three separate units within the Utica Shale play: the Utica Shale, Point Pleasant Formation and Logana Member of the Trenton Limestone. A summary of the methodology, input data and results is given below.

9.2.1 Methodology

The calculation for original hydrocarbon-in-place (HIP) includes separate determination of free and adsorbed hydrocarbon volumes. The basic equation to calculate original hydrocarbon-in-place is:

HIPtotal = HIPfree + HIPadsrb (1)

To derive all required parameters, additional equations and a substantial amount of data were necessary. The derivation of each parameter is described in more detail below. For this particular assessment, the stratigraphic units were separated into two regions: one to address in-place oil resources in the western portion of the Utica Shale play and another to address the in-place gas resources to the north and east. For each region, a single phase (either oil or gas) was presumed to exist in the reservoir. Calculations were performed for selected wells at every one-half foot of thickness within the well. Data were gridded to interpolate between and extrapolate beyond wells. Petra®, ArcGIS and internally-developed software were used to manage, manipulate and analyze data.

9.2.1.1 Free Original Hydrocarbon-In-Place

Free hydrocarbon-in-place was determined using Equations 2 through 7.

GIPfree = (Φeff * (1 – Sw) * (1-Qnc) * Hfm * Ar * 4.356 * 10-5) / Bg (2)
OIPfree = (Φeff * (1 – Sw) * Hfm * Ar * 7758 ) / Bo (3)
GIPfree = free gas (Bcf)
OIPfree = free oil (bbl)
Φeff = effective porosity (fractional)
Sw = water saturation (fractional)
Qnc = non-combustible gas (fractional)
Hfm = reservoir thickness (feet)
Ar = reservoir area (ac)
Bg = gas formation volume factor (fractional)
Bo = oil formation volume factor (fractional) (modified from Crain, 2013a)

 

Φeff = ((Φn – (Vsh * Φnsh) – (Vker * Φnker)) + (Φd – (Vsh * Φdsh) – (Vker * ((2650 – ρker) / 1650)))) / 2 (4)
Φeff = effective porosity (fractional)
Φn = neutron porosity (fractional)
Vsh = shale volume (fractional)
Φnsh = shale neutron porosity (fractional)
Vker = kerogen volume fraction (unitless)
Φnker = kerogen neutron porosity (fractional)
Φd = density porosity (fractional)
Φdsh = shale density porosity (fractional)
ρker = kerogen density (g/cc) (modified from Crain, 2013a; Crain, 2013b)

Note: Effective porosity equation (4) used for wells without porosity data from core or other samples; equation adjusted depending on relationship between log-derived and core-derived porosity.

Sw = (((((1 - Vsh) * A * (RW@FT) / (ΦeffM)) * Vsh / (2 * Rsh))2 +
(((1 - Vsh) * A * (RW@FT) / (ΦeffM)) / Rfmd))0.5
(((1 - Vsh) * A * (RW@FT) / (Φeff M)) * Vsh / (2 * Rsh)))(2 / N)
(5)
Sw = water saturation (fractional)
Vsh = shale volume (fractional)
A = tortuosity exponent (fractional)
RW = formation water resistivity (ohm-m)
Φeff = effective porosity (fractional)
M = cementation exponent (fractional)
Rsh = shale resistivity (ohm-m)
Rfmd = formation resistivity, deep reading (ohm-m)
N = saturation exponent (fractional) (modified from Crain, 2013c)

 

Bg = (Ps * (Tf + 460)) / (Pfm * (Ts + 460)) * Zfg (6)
Bo = (Ps * (Tf + 460)) / (Pfm * (Ts + 460)) * Zfo (7)
Bg = gas formation volume factor (fractional)
Bo = oil formation volume factor (fractional)
Ps = surface pressure (psi)
Tf = formation temperature (oF)
Pfm = formation pressure (psi)
Ts = surface temperature (oF)
Zfg = gas compressibility factor (fractional)
Zfo = oil compressibility factor (fractional) (modified from Crain, 2013a)

 

9.2.1.2 Adsorbed Original Hydrocarbon-In-Place

Adsorbed hydrocarbon-in-place is determined using Equations 8 through 10.

GIPadsrb = Gc * ρfm * Hfm * Ar * 1.3597*106 (8)
OIPadsrb = S2 * 0.001 * ρfm * Hfm * Ar * 7758 (9)
GIPadsrb = gas in place (Bcf)
OIPadsrb = oil in place (bbl)
Gc = gas content (scf/ton)
S2 = oil content (mg/g)
ρfm = density (g/cc)
Hfm = reservoir thickness (feet)
Ar = spacing unit area (ac) (modified from Crain, 2013a; Holmes, 2013)

Note: Adsorbed oil, equation (9) as proposed by Holmes, was calculated but not included in final results.

Gc = TOC * Gp(10)
Gc = gas content (scf/ton)
TOC = total organic carbon (weight %)
Gp = gas parameter (modified from Crain, 2013a)

9.2.2 Study Wells and Data

Digital petrophysical data, supplied by Utica Consortium partners, provided the foundation for the Study. Wells with gamma-ray, density/porosity and resistivity well log data (at minimum) were selected preferentially (Figure 9-11). Additional well selection factors considered included well orientation (vertical wells only), structural complexity (lack of faulting), stratigraphic unit depth (only wells with top of the Utica Shale play greater than 2500-3000 ft), geographic distribution and proximity to other wells. Depending on the particular stratigraphic unit, up to approximately 60 wells were selected for analysis (Figure 9-12).

To augment digital log data, reservoir-specific input included or encompassed: thermal maturity, TOC, gas content, pressure and temperature. As detailed in “Definition of Assessment Unit Sweet Spot Areas,” thermal maturity was determined for each study well from a map developed using equivalent %Ro values (Figure 9-12). TOC was available for individual wells or extracted from stratigraphic-specific TOC maps constructed for the in-place assessment (Figures 9-13 to 9-15). Stratigraphic-specific TOC maps were generated from individual wells with TOC data using the mean TOC value for a particular stratigraphic unit. Gas content, pressure and temperature were taken largely from publicly-available data, although some data were available for individual wells. In general, gas content was determined from methane isotherms given TOC and pressure (Figures 9-16 to 9-17). Reservoir pressure data were based on limited well data for West Virginia and Ohio, Consortium partner input and publicly-available data (Table 9-5). Temperature gradients were determined from a map generated from data gathered for the National Geothermal Data System (Figure 9-18).

StatePressure Gradient
(psi/ft)
Note(s)
LowHigh
New York
(NY)
0.4330.50.433 for most of NY; 0.5 for very small portion of southern NY
Ohio
(0H)
0.60.90.6 for most of OH; 0.7-0.9 for narrow region in east central OH
Pennsylvania
(PA)
0.60.90.6 for most of PA; 0.7 in small portion of central PA; 0.7-0.9 in southwestern PA
West Virginia
(WV)
0.60.90.6 for most of WV; 0.7-0.9 for northern WV panhandle
Table 9-5. Pressure gradient (psi/ft) as assumed given limited formation-specific well data for West Virginia and Ohio, Consortium partner input and publicly-available data.

 

A summary of all data and sources used to estimate original in-place free and adsorbed hydrocarbon resources are provided in Tables 9-6 and 9-7, respectively. Items marked with an asterisk (*) indicate those items obtained or derived, primarily or in full, from the results of this Study.

Data ItemGeneral Data Source(s)
Free Gas-In-Place (GIPfree)calculation (Equation 2)
Free Oil-in-Place (OIPfree)calculation (Equation 3)
Effective Porosity (Φeff)calculation (Equation 4)
Water Saturation (Sw)calculation (Equation 5)
Non-combustible Gas (Qnc)assumption
Reservoir Thickness (Hfm)well logs*, maps*
Reservoir Area (A)well logs*, maps*, reports
Gas Formation Volume Factor (Bg)calculation (Equation 6)
Oil Formation Volume Factor (Bo)calculation (Equation 7)
Effective Porosity (Φeff)calculation (Equation 4)
Neutron Porosity (Φn)well logs*
Shale Volume (Vsh)well logs*, analytical data*
Shale Neutron Porosity (Φnsh)well logs*
Kerogen Volume (Vker)analytical data*, calculation
Kerogen Neutron Porosity (Φnker)assumption
Density Porosity (Φd)well logs*
Shale Density Porosity (Φdsh)well logs*
Kerogen Density (ρker)assumption
Water Saturation (Sw)calculation (Equation 5)
Shale Volume (Vsh)well logs*, analytical data*
Tortuosity Exponent (A)assumption
Formation Water Resistivity (Rw)well logs*, assumption
Effective Porosity (Φeff)calculation (Equation 4)
Cementation Exponent (M)assumption
Shale Resistivity (Rsh)well logs*
Formation Resistivity (Rfmd)well logs*
Saturation Exponent (N)assumption
Gas Formation Volume Factor (Bg)calculation (Equation 6)
Oil Formation Volume Factor (Bo)calculation (Equation 7)
Surface Pressure (Ps)assumption
Formation Temperature (Tf)well logs*, published datasets
Formation Pressure (Pfm)assumption
Surface Temperature (Ts)maps, assumption
Gas Compressibility Factor (Zfg)assumption
Oil Compressibility Factor (Zfo)assumption
Table 9-6. Data items and general data source(s) for free hydrocarbon-in-place. Data items in bold type are values that are calculated from parameters listed below the item. *= from this Study.

 

Data ItemGeneral Data Source(s)
Adsorbed Gas-In-Place (GIPadsrb)calculation (Equation 8)
Adsorbed Oil-In-Place (OIPadsrb)calculation (Equation 9)
Gas Content (Gc)calculation (Equation 10), literature
S2 (mg/g)analytical data*
Density (ρfm)well logs*
Reservoir Thickness (Hfm)well logs*, maps*
Spacing Unit Area (Ar)well logs*, maps*, reports
Gas Content (Gc)calculation (Equation 10), literature
Total Organic Carbon (TOC)analytical data*
Gas Parameter (Gp)calculation, assumption
Table 9-7. Data items and general data source(s) for adsorbed hydrocarbon-in-place. Data items in bold type are values that are calculated from parameters listed below the item. *= from this Study.

 

9.2.3 In-Place Assessment Results

Tables 9-8 and 9-9 provide summary results for each stratigraphic unit evaluated using the volumetric approach. Well log data in particular were limited especially for Pennsylvania and West Virginia; and therefore, the original in-place resource estimates might change if additional data were to become available thus results should be considered preliminary. Given the data that were provided for the Study, it is estimated that original oil-in-place is approximately 39.6 MMbo/mi2 within the sweet spot area as defined in "Definition of Assessment Unit Sweet Areas" (Figure 9-8) while the original gas-in-place is approximately 155.6 Bcf/mi2.

Stratigraphic UnitOriginal In-Place Resources,
Average Volumes Per Unit Area
Oil (MMbo/mi2)*Gas (Bcf/mi2)*
Utica Shale20.853.5
Point Pleasant Formation15.885.1
Logana Member of Trenton Limestone3.017.0
Total for Utica Shale Play
Selected Stratigraphic Units
39.6155.6
Table 9-8. Estimated original in-place oil and gas resources (volumes per unit area) as determined from data provided by the Consortium partners.
* = average volume per square mile in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources (Figure 9-8);
MMbo=million barrels of oil and Bcf=billion cubic feet of gas

 

Similarly given the data that were provided for the Study, it is estimated that original oil-in-place is approximately 82,903 MMbo within the sweet spot area (Figure 9-8) while the original gas-in-place is approximately 3,192,398 Bcf or 3192.4 Tcf.

Stratigraphic UnitOriginal In-Place Resources,
Total Volumes
Oil (MMbo)*Gas (Bcf)*
Utica Shale43,5081,098,119
Point Pleasant Formation33,0501,745,803
Logana Member of Trenton Limestone6345348,476
Total for Utica Shale Play
Selected Stratigraphic Units
82,9033,192,398
Table 9-9. Estimated original in-place oil and gas resources (total volumes) as determined from data provided by the Consortium partners.
* = estimated volume in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources (Figure 9-8);
MMbo=million barrels of oil and Bcf=billion cubic feet of gas

9.3 Comparison of Recoverable and Original In-Place Resources

ResourcesOil (MMbo)*Gas (Bcf)*
Recoverable Resources2,611889,972
Original In-Place Resources82,9033,192,398
Current Recovery Factors3%28%
Table 9-10. Approximate current recovery factors based on recoverable and in-place resource estimates.
* = estimated volume in the sweet spot area; sweet spot area is as defined to estimate remaining recoverable resources (Figure 9-8);
MMbo=million barrels of oil and Bcf=billion cubic feet of gas

Based on the resource assessments to determine remaining recoverable resources and original hydrocarbon-in-place, it is expected that given current technology the play-wide oil recovery factor will be approximately 3% and the gas recovery factor will be approximately 28% in the “sweet spot” areas (Figure 9-8).