1. Tight sandstones of Williams Fork Formation,
Southern Piceance Basin, Colorado:
Key reservoir features and natural fracture detection techniques
By : Yulini Arediningsih
Abstract
Key reservoir features of tight sandstones of the Williams Fork formation of the Mesaverde Group,
in Southern Piceance Basin that include fluid distribution controls and natural fracture
characteristics are reviewed. Integrated techniques on delineating subsurface natural fractures
related to basement features in the reservoirs are also outlined.
Gas production from a large deep basin-centered gas accumulation in this formation has
significantly improved due to enhanced permeability by naturally occurring fractures in the
reservoir. The gas production is mainly from continuously gas saturated of about 900feet interval
of the highly lenticular nature of the fluvial sandstone reservoirs. Key reservoir features in the
Southern Piceance basin include thick, matured Cameo coals, presence of high heat flow at depth,
naturally occurring fractures due to over pressured condition and gas-saturated reservoir with little
movable water. The naturally occurring fractures control the mobility and distribution of the fluid
within the reservoir. Application of low cost aerial geophysical surveys integrated with an RTM
based basin modeling enables to detect anomaly fracture prone zones associated with basement
structures. The areas are then selected for 3D seismic survey to validate the presence of the
subsurface fracture zones. The 3D seismic survey is proven to provide a powerful technology for
identifying fracture zones associated with basement structural features to locate future
development area.
Introduction
Unconventional tight gas reservoirs have become popular targets in petroleum exploration in
recent years, due largely to its large volume, the increasing market demand for gas and to
technology advances used in stimulation treatment. The latter moreover has increased chance of
reopening previously uneconomical gas accumulation. Significant milestone of tight gas
exploration was marked by highly productive tight gas sand development from the Jonah and
Pinedale fields in Western Wyoming back in 1990s. The fields were discovered in 1957, but not
produced in next four decades due to advanced stimulation technology was not available yet at that
time to recover over-pressured gas, locked in tight reservoir rock. Finding ways to unlock the tight
gas fields so that the gas can be tapped off to the surface is a paramount goal in developing the
fields. In some tight gas fields, natural fracturing mechanism that may improve overall reservoir
permeability commonly occurs. In some extent, its occurrence requires favourable geologic
circumstances that should be fully understood. Optimization in detecting, and delineating its
1

2. distribution, intensity, and orientation of this fracture network may help in designing the drilling,
evaluation, completion and stimulation programs which in turn may increase the gas recovery.
This paper overviews key reservoir features of tight sandstones of the Williams Fork formation of
the Mesaverde Group, particularly in Southern Piceance Basin where most of tight gas fields are
located. It covers fluid distribution controls and natural fracture characteristics. The paper also
outlines integrated techniques on delineating subsurface natural fractures related to basement
features in the reservoirs.
Current Status of the Piceance Basin
Piceance Basin is one of major unconventional oil and gas accumulations in Lower 48 States in the
United States, located at the North West corner of Colorado (Figure 1). The basin is well known
for extremely prolific of world class oil shale deposit, estimated to contain 1.525 trillion barrels of
in place oil shale resources.1 Moreover, the basin also contains approximately 311 trillion cubic
feet (TCF) of original gas in-place, with 106 TCF of this gas volume is existent in four gas fields
located in the southern part of the basin,2 including Rulison, Mamm Creek, Parachute and Grand
Valley (Figure 2).
Figure 1. Map of Major Tight gas Plays in 48 Lower States, the United States3
2

3. Currently, total daily gas production all over the Piceance basin has increased from under 200
MMCFD in the year 2000 to over 1 BCFD.4 The gas is primarily produced from the continuously
gas saturated sandstones of the Williams Fork Formation of the Mesaverde Group. Application of
10-acre well density has proven successful, particularly in some gas fields of the southern
Piceance Basin.4 Their EURs typically range from 1 to 2 BCF per well, resulting in reserves of
about 60-120 BCF per section.2
Figure 2. A contour map of Piceance Basin showing location of the gas fields
in southern part of the basin.5
Overview
A wide range of age rock formations from Cambrian to Holocene in general makes up the
Piceance basin. Stratigraphic unit of the main gas producer in the basin is Cretaceous Williams
Fork Formation of Mesaverde Group, consisting of shale, sandstones and coal deposited in a
coastal plain environment. In the past, this sandstone reservoir was bypassed due to very low
permeability in nano darcy range causing the prospect unappealing. Initial attempt to stimulate
hydraulic fracturing was performed in a well drilled into the Williams Fork Formation southwest
of Rifle Town, Colorado in September 1969, so called Project Rulison. The Project Rulison used
subsurface nuclear explosion to determine the potential of the technique for commercial
development of the tight Mesaverde sandstone.6,7 Utilisation of the well bore nuclear explosion left
3

4. the prospect unattractive and disapproving response from the communities of the surrounding area.
Rulison field, as the main field in the southern Piceance, is situated near Rifle town, along the
Colorado River in the southern part of the Piceance Basin, Garfield County (Figure 1). The field
was discovered in 1956 with the drilling of the Juhan #1 well. Within three decades, in fact, only
36 more wells were drilled, because of poor quality wells and numerous dry holes. Then, the
Rulison field was judged to be an uneconomic gas play. The field was estimated to have
approximately 10 Tcf of gas in place in the Mesaverde tight sands.8 During the period 1980s and
1990s, integrated work of Intensive resources Development and Multi-Well Experiments (MWX)
on the southern gas fields, supported by Department of Energy (DOE)/National Energy
Technology Laboratory (NETL) and several industry-sponsored resources, had been carried out to
characterize the reservoir and its natural fracture systems. It results improvement on its producible
flow rate.9 In 2009, the Piceance basin contained five of the top 50 US gas fields in proved
reserves including the Rulison field that posts rank of 24th.10
Geological setting and Stratigraphy
The Piceance basin is an intermountain structural basin formed by Laramide orogeny during Late
Cretaceous through Paleocene. The basin is located in the Rocky Mountain foreland,
morphologically characterised by a gently dipping western and southwestern flanks and a sharply
upturned eastern flank.11 Structurally, the Piceance basin has asymmetric north-western trending
axis with sedimentary rock that have thickness exceeding 20,000ft.12 The basin is bounded by the
Douglas Creek Arch, separating it from the Uinta Coal Basin (Utah) to the west. Grand Hogback
Monocline separates the basin from the White River uplift to the east (Figure 3). Fold structures
are commonly present, including northwestern trending anticlines within the basin such as such as
the Crystal Creek and Rangley Syncline, the Grand Hogback Monocline, and thrust westward.
Faults are present in some areas at the northern margin.
Tectonic setting associated with periods of uplift and erosion occurred during the Late Tertiary
have contributed the formation of vertical extension natural fractures.13 These typical fractures are
commonly found in the William Fork sandstones. The natural fractures also have formed in
response to high pore-fluid pressures that developed during hydrocarbon generation.4
Stratigraphically, Piceance basin is primarily made up by Mesaverde Group of the Late Cretaceous
Age, about 100 to 65 million years in age.14 Figure 4 shows generalized stratigraphic column of
the northern and southern part of the basin.
The oldest formation of the Mesaverde Group, Iles Formation, primarily comprises of interbedded
blanket sandstone units deposited in shallow marine to meandering stream to shoreline
environments with regressive cycles. The sandstone units include Corcoran, Cozzette, and Rollins
Sandstones, interfingering with deep water Mancos shale tongues. Williams Fork Formation
conformably overlying the marine Rollins member of the Iles Formation, can be divided into two
main units, namely Cameo-Wheller Coal Zone and Williams Fork Formation.16 The Cameo-
Wheller Coal zone with a total thickness up to 850ft, is made up by about 30 – 100ft thick
lenticular sandstone, interbedded with marshy coals and shale. The Cameo-Wheller Coals are
exposed in Coal Canyon on the western edge of the basin, and are buried as deep as 9,000ft in the
central part of the basin.18 This coal is thought to be the main source of natural gas charge in the
4

5. southern Piceance Basin, as large volumes of gas were generated from this 850ft thick coal as they
achieved high thermal maturity.17 The main part of the Williams Fork Formation can be described
as a 1500-2400ft thick stacked unit, primarily composed of lenticular sand bodies in shale matrix.
The sand bodies are deposited in distal braided stream, fluvial plain environment. The sand lenses
are laterally discontinuous with irregular distribution.19 Overlying the Williams Fork is Ohio Creek
Conglomerate, defined as proximal braided stream deposit with significant occurrence of a 20ft
thick laterally extensive shale known as the upper Williams Fork shale marker.20
Figure 3. Tectonic Map of the Piceance basin.12
Williams Fork Sandstone Characterisation
Reservoir characterisation of the William Fork sandstones of Mesaverde Group in the Southern
Piceance Basin is benefited by the availability of the well and core data from four MWX wells.
The wells were drilled vertically and horizontally in the vicinity of southern Piceance gas fields for
the purpose of on site laboratory. Various work and analyses that have been done based on those
data in order to get a better understanding on the lenticular sandstone characteristics,19,21,22 the
natural fractures2,8 and evaluation on stimulation performance on the low permeable sandstones.12
5

6. Some of the work and analyses include complete core analysis program, extensive well log and
well testing program, well to well profiling, and the use of seismic surveys and sedimentological
analyses.
Figure 4. Simplified stratigraphic column representing sequences and depositional environments of
the formations in the Piceance Basin.15
The Williams Fork sandstones are compositionally grouped as lithic arkose to feldspatic litharenite
with porosity and permeability measured from the cores at 1200psi ranging from 4.6 – 7.7 % and
6.1 – 7.1 microdarcy, respectively.22 Bulk density porosity determined from the logs ranged from
7.4 to 8.8%. An average corrected porosity of 8.2% was determined for the lenticular Williams
Fork section on the MWX site and inputted in the modeled porosity, giving a gas filled porosity of
3.7%. Based on MWX core analysis, average matrix permeability to gas is 250 nanodarcy, while
natural matrix permeability is 36 to 600 milidarcy. The well testing program provides maximum
permeability whose direction is approximately N780W, consistent with direction of the natural
fractures and maximum principal stress. Reservoir pressures measured at MWX site were 3,410
psi.12
6

7. Microscopic mineralogical analysis points out that diagenetic cements commonly present are
quartz, calcite and ubiquitous illite.21,22 Common pore geometry present in the William Fork
sandstones is dual porosity type of narrow intergranular slots that connect secondary solution
pores.21 (Figure 5). Other types are present minor as intergranular primary porosity and secondary
porosity resulted by dissolved feldspar (Figure 6).
A
B
Figure 5. Photomicrograph A22 and scanning microscope images B23
portraying slot type pores that is common in the sandstones
Figure 6. Primary and secondary pore types present.22
7

8. Diagenetic processes commonly occurred in the sandstones; include K-Feldspar dissolution and
illite pore filling. This K-Feldspar dissolution may contribute constituents required in altering
lower grade of mixed illite-smectite to higher-grade fibrous illite. Illite occurrence can provide a
diagnostic evidence of diagenetic succession associated with the burial history and change in pore
fluid.24 In the lower part of the Williams Fork formation, pore-filling clays are ubiquitous but its
quantity is less than in the upper interval. The upper part contains more variable and more
concentrations of pore-filling authigenic clays; however, less amount of K-feldspar has dissolved.
Pore-filling clays are typically process of reducing porosity and permeability leading to lowering
the reservoir quality,25 in some case, illite may still have microrposity.26 However, the fibrous
nature of the pore-filling clays makes them prone to breakage and pore-throat clogging during
stimulation and production.27 Mechanisms that likely to cause this are over pressured condition in
the lower section. The condition is prevailed as gas produced that drives the movement of pore
fluids from K-feldspar dissolutions to the upper section through natural fractures. Then, the fluids
precipitated illite as pore filling at some intervals.22
Key features of William Fork Reservoir
A massive gas in Piceance Basin is produced from a deep basin centered gas accumulation, in
particular from thick discontinuous lenticular fluvial sandstones of the Williams Fork Formation,
Mesaverde Group. A schematic cross section illustrating the key features of the reservoirs is shown
in Figure 7 below.
There should be mechanisms and specific geologic conditions prevailed in the Williams Fork
sandstone formations that have set off huge gas accumulation in the southern gas fields of Piceance
basin. First, significant presence of Cameo-Wheller Coal zone underlying the Williams For
formation has achieved high thermal maturity.17 As these coal beds generate abundant amount of
gas, over pressuring conditions prevailed as gas can not migrate out of basin center, inhibited by
low permeability and discontinuous lenticular nature of the Williams Fork sandstones. Extensive
over pressuring condition prevailed because of the gas phase pressure in the pore system exceeded
the capillary pressure of the water-wet pores, and water was expelled from the pore system.4 This
condition resulted in pervasive natural fracturing especially within the Iles formation and upper
part of the William Fork formation.15 This natural fracture network primarily provides conduits for
gas to move up to the Williams Fork lenticular sandstones. It appears that the natural fractures
have mostly controlled long-distance movement of gas and water within the reservoirs. However,
the fluid mobility is quite limited, because of the fracture characteristics are lower spacing and
limited in vertical and lateral extent and discontinuous lenticular geometry of the low permeability
sandstone reservoir.15 As a result, the Williams Fork sandstones well act as gas storage making it
as continuously gas charged interval of about 1500’ to 2400 ft. The abundant natural fractures that
are more distributed in the Iles formation and upper part of the William Fork formation are
pathways for gas expelled out of the Cameo coal zone and recharge of water into the subsurface,
respectively. This close association is validated by test data from across the basin.15 While these
reservoirs are locally good gas producers, they are most likely to produce large volumes of water
with gas. Test data also suggest a risk of high production water rates particularly for the upper
Williams Fork Formation and the Rollin Member of the Iles Formation.
8

9. Figure 7. Piceance Basin gas model – present day.20
There are two favourable conditions support the generation of highly gas charged accumulations in
the tight Williams Fork formation.28 First, as discussed previously gas generation from Cameo
Coals and gas migration up through major fault or fracture zones from highly pressured organic-
rich underlying units. Second condition is the presence of high heat flow that may also be
essential in generating considerable amount of gas accumulations. An example, high heat flow
appears to have significantly contributed to extensive amount gas generation in Wattenberg gas
field in the Denver Julesburg Basin.23
Similar to what happened in Piceance Basin, different magnitude of high heat flow between
northern and southern part of the basin shows its variation how gas accumulated in the Williams
Fork reservoirs in both areas (Figure 8).
In the southern Piceance, where the heat flow and the coal zone are higher and thicker than in the
northern part of the basin, respectively, the gas accumulation has relatively thick gas-saturated
interval with low water saturation. In contrast, in the northern Piceance Basin, the gas
accumulation is lower with variable water saturation and higher water production. The mechanism
that may have created the variation, is higher heat flow that exists in the southern Piceance. The
heat flow may have contributed to elevated over pressuring condition in the southern part, and
created an extensive natural fracturing which resulted in the overlying sandstones become fully gas
charged with thick interval. In the northern Piceance, areas near the fault zones have higher gas
saturations with thicker interval. These suggest that gas has migrated primarily along main fracture
zones. 28
9

10. Figure 8. Key reservoir features and fluid distribution control in Piceance Basin.15,28
Natural Fracture characterisation
Commercial production in a deep basin centered gas accumulations is generally related to sweet
spots in the reservoirs in which their overall permeability has been enhanced by the presence of
extensive natural fractures.23 The continuously gas-saturated reservoir intervals in the Williams
Fork are significantly typified by natural fracturing and lenticular depositional geometry.15 The
natural fractures are mainly present as joints of extension fractures and small faults of shear
fractures. Their orientation may relate to tectonic stresses. However their distribution and intensity
are very much controlled by over pressuring process during gas charging.4 Fracture distribution is
also lithologically bounded by rock layering, sand lenses or against other fractures.30
An integrated program to characterize more detailed the natural fractures in the Williams Fork
formation is required. As part of Intensive resources Development and Multi-Well Experiments
(MWX) program in the southern gas fields, a related work has been set up. The program described
here was designed to delineate location, natural fracture intensity and diversity of orientation.8,29
The detection techniques applied are to identify the reservoir fractures associated with basement
features. The techniques involve reasonably low-cost large scale geophysical data surveys to focus
on basin areas that are likely to contain fractures. Typical geophysical data required for the
analysis include8 :
10

11. • High-resolution aeromagnetic data (2500 m2) to delineate the geometry of the basement
structure.
• 2-D seismic and remote sensing imagery analysis were also used to provide consistency to the
interpretation.
These geophysical imagery data are correlated with fracture core data and integrated with a
forward numerical basin model, called BasinRTM. The Basin RTM is one dimensional simulation
package which accounts for compaction, fracturing, hydrocarbon generation, and effect of gas
generation on the dynamics of the system.31 Subsequently, the simulation will produce a
prognostic fracture mapping model that will provide a detailed fracture origins throughout the
basin evolution. The fracture mapping model is calibrated at the MWX laboratory field and
compared to match the present-day characteristics as observed at the MWX site. The model is also
compared with regional structural basement faults and other fracture zones as interpreted from the
imagery geophysical data previously mentioned. The results of the work are potential areas for 3-D
seismic location. A workflow of the techniques can be outlined as below :
Figure 9. A workflow of integrated detection techniques of the natural fractures in Williams
Fork formation, Southern Piceance Basin
11

12. The 3D seismic survey later on was conducted on a 4.5 mi2 area, aimed at targeting natural
fractures especially located at interval depth of 4000 to 7000 ft, in southern part of the Piceance
basin. The 3D seismic survey was multi-azimuth P-wave reflection survey, full-offset to evaluate
the P-wave azimuthal anisotropy and determine relative fracture density and orientation. The P-
wave anisotropy interpretation from the 3D seismic survey suggests anomaly areas with presence
of open fracture sets. These anomaly areas are confined and validated by well production history
and a well test which is allocated on a seismic anomaly. Overall results from the program include :
• Fractured production zones of gas reservoirs in the Mesaverde group overlie deep basement
faults. The fractured zones have northwest-southeast trends, parallel to the basement faults.
• Identification of basement faults is based on interpretation of the set of geophysical data of
remote imagery, and high resolution aeromagnetic surveys.
• Numerous basement faults have been located indicating many undrilled fracture prone areas
are present in the basin.8
Conclusion
A massive gas accumulation in the tight lenticular sandstones of the Williams Fork formation in
southern Piceance basin is mainly associated with certain favourable geological conditions. The
key parameters of the conditions include :
• Presence of Cameo Coals with high thermal maturity as gas source
• Natural fractures as conduits for gas generated moving up from the Coal zones to the Williams
Fork formation.
• Presence of abundant natural fractures in sandstones of the Iles formation and upper part of the
Williams Fork formation. These fractures largely control fluid migration within the formation.
• The tight sandstones of the William Fork formation is continuously gas saturated with 1500ft-
2400ft interval. A transition zone of mixed gas – water saturated sandstones above the
continuously gas-saturated interval.
Other relevant mechanisms that resulted in the enormous gas accumulation :
• Pervasive natural fracturing results from extensive over pressuring conditions in Cameo Coals
due to massive volume of gas.
• High heat flow and thick coal beds are proven essential to creation of pervasive highly gas
charged accumulations. The magnitude of the heat flow also determines the relative quantity of
gas produced as what happened in both Northern and Southern Piceance Basin.
• Due to high heat flow in the Southern Piceance basin, the gas accumulation has uniformly low
water saturations, low water production, and a gas-saturated interval that gradually thickens
into the deeper part of the basin, but the top of the gas interval shows little variation locally.
• The higher heat flow in the southern Piceance may have created a pervasive fracture system
that allowed all sandstones within the gas-saturated interval to be charged to high gas
saturations.
Integrated techniques involving low cost aerial geophysical survey data have been applied to get
anomaly fracture prone zones. The anomaly areas then are selected for 3-D seismic survey
location. This 3D seismic survey is proven to provide a powerful technology for identifying
12

13. fracture zones associated with basement structural features as applied in the tight sandstones of the
Williams Fork formation. The features can enhance overall reservoir permeability which provide
significant conduits required for commercial production from low permeability reservoirs.
Selected Reference
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of the Green River Formation, Piceance Basin, Western Colorado, Fact Sheet 2009-3012,
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Conference, April 24-29, 2005, Vail, Colorado.
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Upper Cretaceous Rocks, Piceance Basin, Colorado, and Their Relation to the Occurrence of
Hydrocarbons AAPG Special Volumes SG 24: Geology of Tight Gas Reservoirs, Pages 221 -
233 (1986)
13

14. 14. Johnson, R.C.: Geologic history and hydrocarbon potential of Late Cretaceous age, low
permeability reservoirs Piceance basin, western Colorado: U.S., Geological Survey Bulletin
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17. Cumella, S. : Mesaverde Gas Accumulation - Geology of the Piceance Basin (extended
abstract) Adapted from oral presentation at AAPG Annual Convention, Denver, Colorado,
June 7-10, 2009.
18. Johnson, R.C., and Flores, R.M.: History of the Piceance Basin From Latest Cretaceous
Through Earliest Eocene and the Characterization of the Lower Tertiary Sandstone Reservoirs,
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Colorado, p. 21-61.
19. Lorenz, J.C. : Prediction of Size and Orientation of Lenticular Reservoirs in the Mesaverde
group, Northwestern Colorado, paper SPE 13851 presented at the 1985 SPE/DOE Symposium
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21. Soeder, D.J. and Randolph, P.L : Porosity, Permeability and Pore structure of the tight
Mesaverde Sandstone, Piceance Basin, Colorado, SPE Formation Evaluation 1987.
22. Stroker, T., and Harris, N., : K-Ar Dating of Authigenic Illites: Integrating Diagenetic History
of the Mesaverde Group, Piceance Basin, NW Colorado. Adapted from oral presentation at
AAPG Annual Convention, Denver, Colorado, June 7-10, 2009
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from low-permeability sandstone reservoirs: Implications for resource assessment, prospect
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24. Burtner, R.L. and Hathon, L., : K-Ar dating of authigenic illite constrains the time of
diagenesis and brine migration in the Weber Sandstone of the Uinta-Piceance Basin, Colorado
and Utah: AAPG Meeting Abs Vol. 80, Issue 13 (Annual Meeting 1996).
25. Pallatt, N., Wilson, M. J. and McHardy, W. J. : The relationship between permeability and the
morphology of diagenetic illite in reservoir rocks: Journal of Petroleum Technology, v. 36
(1984), p. 2225–2227.
26. Rushing, J. A., K. E. Newsham, and T. A. Blasingame, 2008, Rock typing—Keys to
understanding productivity in tight gas sands: SPE paper 114164.
27. Almon, W. R., and Davies, D. K. : Clay technology and well stimulation: Transactions of the
Gulf Coast Association of Geological Societies, 1978,v. 28, p. 1–6.
28. Cumella, S.P. :Important Characteristics of Rocky Mountain Tight Gas Accumulations, The
Geology of Unconevntional Gas Plays, AAPG Conference 5-6 October 2010, in Burlington.
29. Kuuskraa, V., Decker, S., Lynn H. : Optimizing Technologies for Detecting Natural Fractures
vin the Tight Sands of the Rulison Field, Piceance Basin, DOE/NETL report IADI1953, 1996.
14

15. 30. Lorenz, J.C. and Finley, S.J.” Significance of drilling- and coring-induced fractures in
Mesaverde core, northwestern Colorado, Sandia Report SAND88-1623 UC-92, June 1988,
prepared for US DOE.
31. Dorothy F. P. and Kagan, T. : A Reaction-Transport-Mechanical Approach to Modeling the
Interrelationships Among Gas Generation, Overpressuring, and Fracturing: Implications for the
Upper Cretaceous Natural Gas Reservoirs of the Piceance Basin, Colorado AAPG Bulletin
Volume 84 (2000)
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