The paper was presented at the 1982 SPE Cotton Valley Symposium of the Society of Petroleum Engineers held in Tyler, TX, May 20. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206.
The identification of pay in low porosity shaly gas sands is made difficult by the inaccuracy of calculating and interpreting water saturations. Outlined below are techniques that have been used to calculate water saturations in this type of reservoir.
Laboratory tests have been performed to measure saturation exponent and to define the formation factor-porosity and cation exchange capacity-clay relationships. The tests indicate that saturation exponent, n, is 1.36, and that formation factor, F, is given by 9/phi e 2.17. Formation factor tests and empirical calculations imply that m may be a function of porosity in porosities less than five percent. percent. The cation exchange capacity of the rock is due to illite. As the illite contains radioactive potassium, gamma ray activity can be used to calculate cation exchange capacity. Laboratory spectral gamma ray analysis indicates that the potassium component is a good indicator of cation exchange capacity.
Water saturations are calculated using the Waxman-Smits technique. Errors induced by not accounting for clay conductivities are presented as functions of porosity, water saturation, and illite content. The induced errors are greatest in low porosity zones.
Error analysis indicates that the major source of error in calculating water saturations (excluding the effects of exchangeable cations) is the inaccuracy of determining porosity. At porosities less than five percent, the possible error in water saturations approaches one hundred percent.
Data are presented relating the error in water saturations to errors in porosity and resistivity.
The significance of water saturations in low porosity, low permeability sandstones is unclear. porosity, low permeability sandstones is unclear. Drainage relative permeability data predict that except at extremely high water saturations the flowing phase should be predominantly gas.
One of the most important parameters for pay identification is water saturation. However, this can be difficult to calculate especially in low porosity shaly sands such as those of the Cotton porosity shaly sands such as those of the Cotton Valley.
To calculate water saturation, accurate values of formation factor, saturation exponent, and cation exchange capacity (if present) are needed. Further, the accuracy and importance of water saturations should be investigated before decisions on completion intervals and reserve estimates are made.
The area of study is the Cotton Valley of East Texas (see Figure 1). This Upper Jurassic sand-shale sequence is found at depths ranging from 8,000' to 10,500' and is approximately 1,400' thick. The sequence is bounded above by the Knowles limestone and below by the Bossier shale. Porosities are commonly less than 10 percent and Porosities are commonly less than 10 percent and in-situ permeabilities range from .04 to 10 microdarcies.
Twelve samples were tested for saturation exponent. The porosities of these samples range from 5.3 to 12.8 percent. Quartz is the primary mineral (ranging from 84 to 98 percent) with lesser amounts of calcite, feldspar, and clay. Simulated formation water consisting of 106,650 mg/l NaCl and 11,850 mg/l CaCl was used in the tests. Resistivity indicies and saturations are plotted in figure Analysis of the data shows that n is equal to 1.36.
Fifteen samples, including the twelve from above, were measured for formation factor. Mineralogy and porosity of the additional three samples are within the ranges given above.
