Y
voirs. Commercial gas production requires thatsuffi-cient gas-in-place is contained within minute pore spaces, and that natural fractures connect the gas-in-place to production wells. Discussion of natural frac-tures and flow to wells is outside the scope of this book.
Refer to Reference 1 if you wish more information on these subjects.
The gas-in-place equation is:
(2-1)
Where:
G = gas-in-place volume, scf A = reservoir area, acres h = reservoir thickness, feet
ρ = average in-situ rock density at the average insitu rock composition, g/cm3
G
c = average gas content at the average in-situ rock composition, scf/ton
Example 1 illustrates application of Equation 2-1. You will usually apply this equation to individual reservoirs or coal seams in close vertical proximity that have similar characteristics. Sometimes, we will group reservoirs when they are of similar coal rank, sorptive capacity, and pressure. When you are interested in multiple reservoirs or groups, you sum the results of Equation 2-1 for each reservoir to obtain the total gas-in-place volume.
Chapter
2
Gas-In-Place Methodology and Error SummaryThe combination of the drainage area and the thickness in Equation 2-1 is the bulk volume of the reservoir. The bulk volume usually contains coal (rock with an organic content greater than 70% by volume and greater than 50% by weight1), carbonaceous shale (containing organic material in which gas is sorbed) and rocks devoid of organic material. You will gener-ally ignore the inorganic rock for gas-in-place esti-mates unless it contains producible gas.
An analyst’s selection of the drainage area is often based on surface surveys, ownership limits, or the well spacing used to develop the reservoirs. More properly though, the area should be determined by a combina-tion of geological, geophysical, and engineering meth-ods. A discussion of these methods isoutside the scope of this book. Examples of coal gas reservoir geologic evaluations are included in Reference 3 and 4. Refer-ence 5 presents an example of the use of geophysical and reservoir simulation methods. GRI presented a summary of coal gas reservoir engineering and simu-lation technology that you can use.1
We will cover the methods we used to estimate the thickness from density logs. You may also need to estimate thickness from a combination of other wireline
Example 2-1. Gas-In-Place at the COAL Site
At the GRI COAL Site research location in the San Juan Basin, the Fruitland Formation coal gas reservoirs are contained in two primary intervals referred to as the basal and upper. Each of these intervals had multiple coal seams that we grouped together since the coal rank, gas storage capacity, and reservoir pressure were similar in each interval. The following table lists properties required for the gas-in-place estimates for each interval. The area that we were interested in was the square mile section in which the research site was located.
Property Units Upper Coal Interval
Value
Basal Coal Interval
Value Drainage area acres 640 640
Thickness feet 28.3 61.7 Average in-situ density g/cm3 1.833 1.628 Average gas content at the average rock composition scf/ton 343.2 512.4
Initial gas-in-place per square mile Bscf 15.49 44.79 The total initial gas-in-place volume for both intervals was 60.28(109) scf or 60.28 Bscf (billion standard cubic feet) per square mile. The calculation is straight forward as performed below for the basal coal interval.
( )(
640 61.7)(
1.628)(
512.4)
4.479( )
10 scfor 44.79Bscf1,359.7
G= = 10
and mud logs when a density log is not available.
We need the in-situ density estimate to convert gas content on a volume per weight basis to a volume per volume basis. We will determine the in-situ density from open-hole density log data. We will use the density data to determine the depths of organic-bearing rocks from open-hole density data.
Most gas content estimate methods involve placing freshly cut coal samples in airtight gas desorption canisters. The total gas content is the sum of three components,
1. the gas content lost prior to sealing the canister, 2. the measured gas content, and
3. the residual gas content remaining in the samples at the end of the measurements.
The most common units for gas content are scf (standard cubic feet) per ton (2,000 lbm [pounds mass]) or g/cm3 (grams per cubic centimeter). One scf/ton is equal to 32.0368 g/cm3.
We will estimate the total gas content by analysis of the gas volume released vs. time from core samples reheated to reservoir temperature. These data are
ana-READ ME
The gas content estimates from multiple samples should be corre-lated to the inorganic content of the samples to allow estimates of the in-situ gas content. This procedure is superior to averaging the esti-mates from multiple samples.
Core data should be measured to determine the density of the or-ganic and inoror-ganic portions of the samples. These data allow the gas content to be correlated with den-sity. We have used the density cor-relations to show that the density range from which gas can be des-orbed includes both coal and car-bonaceous shale. The gas-in-place
in the carbonaceous shale intervals must be included for accurate gas-in-place estimates.
Once the gas content data is correlated to inorganic content and hence density, it is possible to estimate the in-situ gas content from the open-hole density data. The situ gas content estimate is made at the average in-situ inorganic content to provide a single in-in-situ gas content estimate for use in the gas-in-place equation.
Gas-In-Place Estimate Errors
Uncertainties or errors in each parameter included in Equation 2-1 limit the accuracy of coal gas-in-place volume estimates. These parameters are the drainage area, the thickness, the average in-situ density, and the average in-situ gas content.
Drainage Area Errors
Geologists and engineers usually estimate the res-ervoir drainage area from ground level areas such as survey limits, ownership boundaries, or well spacing.
However, geologic structural and stratigraphic varia-tions disrupt the lateral continuity of coalbeds. These disruptions complicate determination of the reservoir drainage area. Figure 2-1 illustrates a schematic of coal
gas reservoir geometry.
The uncertainty or error in producible gas-in-place estimates caused by natural geologic variability can be very significant. You should include a geologic evaluation of the structural and stratigraphic changes in reservoirs to obtain accurate estimates of the gas-in-place and the gas that may be recovered by existing or infill wells. Unfortunately, the presence of the discontinuities is often not apparent in the geologic evaluation. The locations of discontinuities often cannot be determined until you identify unusual patterns in gas and/or water production behavior.
Three-dimensional seismic technology has been used to improve estimates of drainage region extent in coal gas reservoirs. In the San Juan Basin, estimates of locations of rock discontinuities determined from seis-mic interpretation were consistent with the locations of flow barriers required in reservoir simulation models.5 This combination of reservoir simulation and seismic technology may someday, routinely improve the iden-tification of discontinuities beyond that possible with traditional geologic or production interpretation meth-ods.
Figure 2-1.
Coal Gas Recovery Geometry.
Channel
Chapter
2
Gas-In-Place Methodology and Error SummaryGross Coal Thickness Errors
The primary data source for determining the thick-ness of coalbeds is geophysical logs. Interpretation of open-hole density logs results in the most accurate estimates. Recognizing coal is often easy since the density of organic material is low compared to that of inorganic rocks.1 You will calculate the total reservoir thickness by summing the thickness of rocks whose density values are less than a maximum density limit.
The most commonly used maximum density limit for coal is 1.75 g/cm3. This limit may have come from the geologic definition of coal2 that states that coal contains more that 70% by volume and 50% by weight carbonaceous material. This limit corresponds to den-sities less than or equal to 1.75 g/cm3. However, 1.75 g/
cm3 excludes the gas contained in carbonaceous shale intervals and may result in low estimates of the gross reservoir thickness and high estimates of the average in-situ gas content. A more correct upper density limit for Fruitland Formation coal gas reservoirs is 2.1 to 2.5 g/cm3. Use of the lower “rule of thumb” value results in gas-in-place estimates that are low by up to 22%.
Average In-Situ Density Errors
Many analysts assume that the product of 1,359.7 and the average density in Equation 2-1 is equal to a value of 1,800 or 1,850 tons per acre-foot based upon information contained in Reference 7. The average density corresponding to these values is 1.324 to 1.361 g/cm3. The correct in-situ density should be estimated from open-hole density log data. The average in-situ density of San Juan Basin, Fruitland Formation coal gas reservoirs is often 1.5 to 1.85 g/cm3. Use of the correct average density value results in gas-in-place estimates that are 10 to 13% greater than obtained with the “rule-of-thumb” value.
Gas Content Errors
One of the key components of the gas-in-place estimate is the gas content of the reservoirs. Errors in gas content estimates are the greatest source of error in gas-in-place estimates. The errors usually cause the gas-in-place estimates to be low. We quantified the errors with benchmark gas content values. By compar-ing gas content estimates obtained by different
meth-ods to the benchmark values, we determined that gas content estimates are accurate if our methodology is followed.
We obtained the benchmark gas content values from pressure core samples and sorption isotherm data.
Pressure coring equipment seals core samples down-hole allowing all of the gas content to be trapped without loss before retrieving the samples to surface.
We used sorption isotherm data for benchmarks in reservoirs that we knew had in-situ gas contents that were equal to the in-situ gas storage capacity.
We measured all of the gas content data that we used to design the gas-in-place methodology during the Western Cretaceous Coal Seam Project of GRI.3 Ref-erences 9,10, and 11 document the details of the benchmarking and error analysis that we performed.
Table 2-1 presents the comparison between the bench-mark standards and gas content values.
We had two sets of pressure core samples avail-able; one from San Juan Basin, Fruitland Formation, reservoirs and one from Piceance Basin, Mesa Verde Group, reservoirs. The pressure core and Direct Method conventional core gas content estimates were within 7.2% for the Slant Hole Completion Test #1 well and 5.8% for the Southern Ute - Mobil 36-1 well. The agreement for both wells was important because gas is lost from conventional core samples while the samples are retrieved to surface. Pressure core samples do not suffer this limitation. The agreement for the Slant Hole Completion Test #1 was especially significant since the conventional and pressure core samples were retrieved from reservoirs at a true vertical depth of 7,000 feet.
The agreement between the pressure and conventional core estimates supported that our methods of estimat-ing the lost gas volume are correct. In addition, expen-sive pressure coring technology is not required for accurate gas-in-place estimates if core data are prop-erly measured and interpreted.
Pressure core data were not available from other wells. We turned to sorption isotherm data to provide additional benchmarks. We computed benchmarks for five wells with extended Langmuir isotherm theory that accounted for the sorbed gas composition that included methane and carbon dioxide. Five Direct Method core gas content estimates were within 1 to
10% of the isotherm benchmark values. We felt that this agreement provided additional support for the accuracy of our lost and total gas content analysis methods.
The two wells with the greatest apparent error in the gas content estimates were the South Shale Ridge
#11-15 and FC Federal #12 wells. Both gas content estimates appeared to be about 20% high. This may have been due to errors in the benchmark values rather than the gas content values. The benchmarks for both these wells were methane isotherms since the sorbed carbon dioxide content was believed low. However, had the carbon dioxide content been as small as 5%, the gas content and benchmark values would have been equal.
We used the benchmark data to evaluate the accu-racy of the methods used to estimate the lost gas content. We evaluated three commonly used methods.
These are:
• Direct (U.S. Bureau of Mines) Method,12 ,13,14 ,15
• Smith & Williams Method,16 ,17 and
• Amoco Method.18 ,19
We found that the Direct Method was the most ac-curate when used to evaluate core desorption data from samples reheated to reservoir temperature. The esti-mates based upon the Smith & Williams Method tended to be low while those obtained with the Amoco Method were usually high. Figure 2-2 illustrates a comparison of the estimates obtained with the three methods for the eight wells listed in Table 2-1.
The common industry practice is to measure gas desorption data from canisters stored at ambient
tem-perature. Lower ambient temperatures than reservoir temperatures caused large errors. Two temperature re-lated factors affected the accuracy of lost and total gas content estimates. First, gas desorption rates varied exponentially with temperature which greatly affected the volume of gas desorbed during the portion of the measurements used to estimate the lost gas content.
Second, the coal gas sorptive capacity was inversely proportional to temperature which increased the re-sidual gas volume and reduced the measured gas vol-ume.
Desorption of San Juan Basin samples at ambient temperature conditions caused errors of -30 to -33% in the total gas content estimates and -60% to -70% errors in lost gas content estimates. San Juan Basin Fruitland Formation temperatures range from 100 oF to 125 oF.
Ambient temperature conditions vary depending upon the time of year and can range from -15 oF to 100 oF.
Many researchers ignored temperature effects when they desorbed samples from reservoirs at lower tem-peratures than those of the San Juan Basin. However, since temperature effects are exponential in nature, errors may be significant for lower reservoir tures as well. Reheating samples to reservoir tempera-ture reduces errors in almost all cases.
The type of sample also has a large effect upon gas content estimates. Conventional or wireline coring methods are the preferred method for sample collec-tion. Less gas is lost from cores than from more commonly used drill cutting samples.
The accuracy of gas content estimates from drill cuttings suffers from two limitations. The primary GRI Observation Well #1 Methane-Carbon Dioxide Isotherm Data 99.7
GRI Observation Well #2 Methane-Carbon Dioxide Isotherm Data 99.6 Southern Ute 5-7 Methane-Carbon Dioxide Isotherm Data 103.1 Valencia Canyon 32-1 Methane-Carbon Dioxide Isotherm Data 109.0 FC Federal #12 Methane Isotherm Data 119.7 South Shale Ridge #11-15 Methane Isotherm Data 120.3 Table 2-1. Agreement Between Direct Method and Benchmark Gas Content.
Chapter
2
Gas-In-Place Methodology and Error Summaryshortcoming is that the samples are crushed downhole, resulting in high gas desorption rates and loss of a large fraction of the original gas content during sample recovery. Total gas content estimates from Fruitland Formation coal drill cuttings samples were 25% less than those obtained from conventional core samples when desorption was performed at similar tempera-tures. The common practices of drill cutting sample desorption at ambient temperature results in gas con-tent estimates that are 50% low based upon our results.
The second problem with drill-cutting samples is that rock debris from outside coal gas reservoirs often contaminates the samples. Differences in the density between the debris and reservoir rocks increased the inaccuracy in estimating the organic fraction and in-situ gas content.
We expected gas content estimates from drilled sidewall cores to be accurate due to short retrieval time.
However, we found that the estimates were as inaccurate as those obtained from cuttings for our limited data set.
Figure 2-2.
Comparison Between Direct and Other Total Gas Content Estimates
Another source of error in in-situ gas-in-place estimates results from basing the gas content on an incorrect mass. The variety of masses used to compute the sorbed gas content value confuses many people.
Table 2-2 summarizes the most common bases.
We are interested in three of these bases. We will begin by using the air-dry gas content basis to interpret data from multiple samples. We will extrapolate the air-dry data to an organic fraction basis. We will use the organic fraction basis gas content to estimate the in-situ basis gas content. The most important is the in-situ basis. This is the correct gas content basis to use for estimates of gas-in-place or other reservoir engineer-ing calculations. The air-dry and organic fraction bases are intermediate values that we require in the analysis.
People often ask why can’t we use the air-dry basis values. This is because desorption samples do not have the same average inorganic content as the reservoir due to natural variation and contamination by water and extraneous material.
Southern Ute 5-7 South Shale Ridge #11-15 GRI Obs. Well #2 GRI Obs. Well #1 Valencia Canyon 32-1 FC Federal #12 Slant Hole Completion Test #1 Southern Ute Mobil 36-1
200 180 160 140 120 100 80 60 40 20 Percentage of Direct Method Estimate 0
S&W Method Estimates Amoco Method Estimates
Direct Method: 100%
The dry, ash-free basis or the mineral-mineral-matter-free bases are useful for comparing gas content or storage capacity estimates obtained from samples of differing composition. We do not use these bases to estimate gas-in-place volumes.
A mineral-matter-free basis can be used when the sulfur content of coal is significant. When sulfur is present, the proximate analysis underestimates the mineral-matter content. A 1928 publication by Parr1 recommends a correction that has become known as the
“Parr Formula.” In the nomenclature used in this book, the conversion to a dry, mineral-matter-free basis mass can be performed with Equation 2-2.
m
mf
= m
ad
[1- (1.08w
as
+0.55w
s
)] (2-2)
inorganic components. Extraneous water and material might be removed from the original sample before mass measurement.
1.75 g/cm3 The mass of the portion of a crushed desorption sample that floats in a 1.75 g/cm3 Float Basis density fluid. This mass basis incorrectly assumes that all gas originates from the 1.75
g/cm3 and less sample density range.
Air-Dry Basis Desorption sample mass after drying for 24 to 48 hours at laboratory conditions.
Extraneous water and material are often removed from the original sample before mass measurement.
As-Received Basis Sample mass at the moisture content present when received by a laboratory.
Dry, Ash-Free Basis Air-dry or as-received sample mass corrected to 100% organic content with proximate analysis derived ash and moisture content.
Dry, Mineral-Matter Air-dry or as-received sample mass corrected to 100% organic content with long -Free Basis proximate analysis derived ash, moisture, and sulfur content.
Dry, Mineral-Matter Air-dry or as-received sample mass corrected to 100% organic content with long -Free Basis proximate analysis derived ash, moisture, and sulfur content.