Advances benefit tight gas sands development

Vello A. Kuuskraa, Thomas E. Hoak, Jason A. Kuuskraa
Advanced Resources International Inc.
Arlington, Va.
John Hansen
Gas Research Institute
Chicago

Advances in four key technologies have been important for more efficient development of tight gas sands.

The advances are:

Expanded use of 3D seismic.
Integrated approaches to natural fracture detection.
Improved well completions and advanced stimulation technology; and
Selected use of horizontal wells.

In addition, advances in drill bits, downhole motors, and basic procedures have significantly reduced the costs of producing tight gas, as demonstrated by an impressive increase in rate of penetration and associated reduction in costs for new wells (Fig. 1 [49212 bytes]).

Expanded Use of 3D Seismic and AVO. Reductions in costs and improvements in survey design have made 3D seismic a valuable tool for developing (and exploring for) tight gas sands. 3D seismic is helping to unravel the complex geology of tight gas reservoirs, particularly for defining the orientation of maximum channel thickness of meandering fluvial systems common to the Rockies and Midcontinent; for exploiting bypassed structural compartments not previously seen on 2D seismic; and for avoiding lower quality, low porosity zones. (The use of 3D and shear wave seismic for improved natural fracture detection will be discussed later.)

Today, 3D seismic is widely used, by both majors and independents, for about 80% of all new onshore seismic acquisition. A review of the use of 3D seismic by major tight gas players shows the following:

Enron, an active player in the Wilcox/Lobo and the Rockies, uses 3D data on 60% of its exploration prospects (including conventional and tight gas targets), up from 15% just 3 years ago, and expects that percentage to increase. Last year, Enron had 52 gas and oil discoveries out of 90 exploration wells (OGJ, Sept. 18, 1995, p. 32).
Meridian and Vastar are linking 3D seismic with the drilling of horizontal wells in the Piceance basin Corcoran tight sand and the Green River basin Almond tight sand.
TransTexas Gas Corp., a major Wilcox/Lobo tight gas developer, achieved the second best overall exploration success rate in the industry in 1994, completing 25 exploration wells out of 33 drilled (companywide) for a success rate of over 75%. TransTexas credits expanded use of 3D seismic for both its high success rate and (in combination with improved fracturing fluids) for increasing the initial productivity of its Wilcox/Lobo tight gas wells from their previous 3 MMcfd to the current 4-5 MMcfd.
UPRC, the most active gas developer in 1994, has greatly expanded its use of 3D seismic-adding 300 sq miles of coverage in the tight gas plays of the Green River basin-and is using 3D seismic to maximize production in Carthage and Oak Hill fields of East Texas.

An outgrowth of 3D seismic is the use of azimuthal AVO for detecting subtle changes in gas saturation in naturally fractured sandstones. Field use of AVO modeling has been successfully demonstrated by Amoco in the Cretaceous Frontier sands of Shute Creek field and by Coastal (ANR) in South Powell field of Wyoming.

Improved tight gas well completions and stimulation. Reducing drilling and completion damage, correctly identifying and completing the full package of tight pay, and improving the design and quality control of hydraulic fracturing are enabling producers to more fully exploit tight reservoirs. Examples are:

Use of air or underbalanced drilling and new fracturing fluids are helping reduce damage and speed well cleanup in the naturally fractured, often fluid sensitive tight sands common to the Midcontinent.
Improved log interpretation, which accounts for variable water resistivities and the presence of active clays, is helping spot productive pay in intervals previously interpreted as wet, particularly in the massively stacked lenticular sands of the Rockies.
New, 3D fracture simulators with improved designs and real-time feedback capabilities.
Advanced breakers and enzymes are enabling operators to more confidently use gelled fluids to place larger sand volume hydraulic stimulations without the risk of formation plugging from unbroken gels (Table 1 [18300 bytes]).

Horizontal wells for tight gas recovery. After early excitement about the use of horizontal wells in low permeability natural gas reservoirs, industry is studying its successes and failures and rethinking its position on this technology.

What has been learned is that: (1) horizontal wells for natural gas have site specific rather than universal application; (2) horizontal wells are about twice as costly as vertical wells; (3) only about half the horizontal wells have achieved economic success; and, (4) considerable front-end geophysical work is essential to delineate the local natural fracture and hydrodynamic conditions.

A selected review of horizontal well drilling in the tight sands of Rulison field, Piceance basin and Echo Springs field, Green River basin, shows a variety of problems and disappointments with horizontal wells (Table 2 [30940 bytes]). Still, some recent wells offer promise in tight sand areas where vertical wells and hydraulic fracturing have failed to achieve economic production:

The initial CER-DOE, Oryx, and Meridian horizontal wells drilled into the Cozzette sands (Piceance basin) quickly turned into high water producers despite high initial gas rates. More recent horizontal wells drilled by Meridian into the Corcoran sands show promise with one well producing 0.5 bcf the first 2 years and a second well testing 2 MMcfd with low rates of water.
The results from the joint Amoco/GRI co-op well, Champlin 254 Amoco B2H, in the Upper Almond (Echo Springs field, Wamsutter arch, Green River basin) are more difficult to evaluate. Amoco states that the estimated EUR of 2.6 bcf for the horizontal well is half of the 5.2 bcf of EUR for the vertical offset, or "parent" well (Champlin 254B1). Other studies indicate the horizontal well may be outperforming the larger set of vertical wells along the edge of this field.

Integrated approaches to natural fracture detection. Among the next generation of significant tight gas exploration technologies is integration of seismic and remote sensing technology for predicting naturally fractured, "sweet-spot" reservoir settings in advance of drilling. Here, azimuthal AVO, multicomponent and shear-wave seismic, high resolution aeromagnetic data, gravity surveys, and multispectral satellite imagery are combined to map the basement and identify zones of enhanced natural fracturing in tight gas formations. Numerous leading-edge field demonstration efforts are under way to demonstrate the use and benefits of this collection of methods, including the following:

Advanced Resources International Inc. (ARI) and Barrett Resources are conducting a DOE/METC sponsored field demonstration of this technology in the tight sands of Rulison field, Colo. Application of integrated fracture analysis by ARI has identified a series of naturally fractured zones that corresponds to higher gas productivity trends. Further fracture characterization will be made in this area using a 3D multicomponent survey, azimuth- al AVO analysis and a 2D shear-wave line in early 1996. Following this, Barrett Resources will drill or recomplete wells to confirm the interpretations.
Azimuthal AVO was applied by Coastal Oil & Gas to deep Cretaceous Almond sands of Mayberry field, Moffat County, Colo., to establish fracture azimuth and gas-filled fractures. The first well, 1-20 Mayberry, completed with azimuthal AVO flowed 3 MMcfd. Mitchell, one of the earliest tight gas developers, is using 3D and advanced shear-wave seismic to find naturally fractured "sweet spots" and select well locations in North Texas tight sands and shales (OGJ, Jan. 22, p. 53).
Following initial seismic based work on natural fracture characterization in giant Altamont-Bluebell oil field in Utah, Blackhawk Geosciences is applying these methods on the Madden Deep natural gas field in the Wind River basin.

Behind these direct and indirect natural fracture detection methods is an even more ambitious effort to numerically simulate the fracture genesis in a basin. This is the goal of a DOE and industry sponsored project being performed by the Basin Modeling Group (LCG) at Indiana University, directed by Dr. Peter Ortoleva.