Atoka Sands (Pregnant Shale or Davis Sand) Play
Production Characteristics
Once the Pregnant Shale producing wells were identified, statistics of the Cumulative (CUM) production and Initial Potentials (IPs) were compiled. A distribution of probability was assigned to the producing wells (see Chart 1) after converting condensate to gas in a 6 to 1 ratio. To understand the chart, the P10 probability is assigned such that 10% of the wells will produce over their lifetime (CUM) about 3.3 million cubic feet of gas (3,300 MCFG); a P50 well, also known as the “most likely well,” will CUM about 130 MMCFG (130,000 MCFG); and the average well falls at P63 will CUM about 254 MMCFG (254,000 MCFG). The P90, where 90% of the wells are less than or equal to 760 MMCFG (760,000 MCFG), is a respectable number for wells that produce at such a shallow depths (3100 to 5700 feet deep). The exceptionally good wells with over 1 billion cubic feet of gas (1 BCFG) CUMs have been identified as Grant Sand completions, at the base of the Pregnant Shale interval. It is also important to know that these numbers are for CUMs, and that 48% of the wells are still active producing gas wells. Collectively, these wells have yielded 40 billion cubic feet of gas.
The distribution follows a log-normal pattern, like most oil and gas zones, with a few exceptional wells pulling the averages up above the median. Half of the wells produced 130 MMCFG or less, and half have produced more than 130 MMCFG. The best one-fourth of completions (P75 or higher) shows a rapid incline up to the best well. One explanation for this performance is the likelihood of natural fractures.
Chart 2 shows the relationship of Initial Potential (IP), the amount the well originally produces, to the total CUM for the wells. Generally, the better wells have had better Initial Potentials, and this relationship follows a best fit line. IP is given as the highest monthly CUM for the well on record. This trend is seen in most oil and gas zones; however, the power law best-fit equation is also common in other fracture dominated reservoirs.
Chart 3 shows the relationship of Initial Potential to the size of the Perforated Interval (“perf size”). In conventional reservoirs, the IP will increase with larger perf sizes, because thicker net pay intervals will often be completed with thicker perforated interval. This chart shows that this is not the case; therefore, a different variable is controlling the productivity of the wells. If natural fractures are a controlling factor, there would be little relationship between IP and perf size.