TIGHT OKLAHOMA GAS SANDS REMAIN AN ATTRACTIVE PLAY

Gary L. Cartwright
Marathon Oil Co.
Oklahoma City

The Cherokee tight gas sands of Oklahoma remain an attractive play because of improvements in drilling and completion practices and actions by the Oklahoma Corporation Commission (OCC) that allow separate allowables for new wells.

The expired federal tax credits for tight gas wells, as highlighted in a recent article,1 have not been the only reason for increased activity.

Since decontrol of most regulated gas pricing and since 1986, the number of wells drilled and gas production per well have been increasing in the Cherokee area while overall drilling in Oklahoma has decreased.

These conclusions are based on wells as categorized by permit date and not by the spud, completion, or first production date. A few wells outside but adjacent to the Cherokee area may have been included, although, their impact on the conclusions is considered nominal.

TIGHT GAS CREDIT

In 1991, the U.S. Federal Energy and Regulatory Commission (FERC) designated the Cherokee as a tight formation in about 1,269 sections or 812,160 acres in western Oklahoma.(75421 bytes) This designation permitted any taxpayer (owner) of a qualified well to receive a tax credit of $0.52/MMBTU for gas produced from the well between Jan. 1, 1991, and Jan. 1, 2003.

For a well to qualify, the well must have been drilled after Nov. 5, 1990, but before Jan. 1, 1993.3 The term "drilled" was initially thought to be synonymous with spud, although it later was identified with "permitted to drill." This article uses the permitted to drill concept.

Within this area, the average heating value is about 1,100 MBTU/Mcf or a tax credit of $0.57/Mcf. For a taxpayer in the 34% federal tax bracket, this is equal to a $0.87/Mcf gas price increase. Oklahoma gas prices in 1991 and 1992 averaged $1.47/Mcf and $1.63/Mcf, respectively.4 Thus, the credit effectively increased wellhead price by 59% for 1991 and 53% for 1992.

This substantial increase in the effective price, coupled with the short 2-year time frame in which to drill, caused a mini drilling boom in 1992, during which about 90 additional wells were drilled (over and above the established trend line) for the tax credit. A similar spike in well count had not been seen since the 1981 and 1982 boom (Fig. 2)(31842 bytes).

PRORATION UNITS

Most wells in the 812,160-acres Cherokee area are on 640-acre drilling and spacing units (or proration units). The Oklahoma Corporation Commission is the primary regulatory agency over oil and gas matters within Oklahoma.

A 640-acre drilling and spacing unit means that only one well/640 acres is permitted and each well has one unit allowable. This allowable in Oklahoma is based solely on a percentage of the well's calculated absolute open flow (CAOF).

In other words, in a 640-acre unit one well is expected to adequately and effectively drain the entire 640-acre unit. Therefore, each unit has its own allowable and all units produce on par with the other units.

However, because the Cherokee is a tight formation, very few, if any, of the wells will drain 640 acres. Even if a well is capable, the required life to produce all reserves may be 50 years or more, which for the most part exceeds the expected casing life.

Based on volumetric calculations, many wells within the Cherokee area exhibit drainage areas as small as 25 acres or less, although a few wells in isolated areas exceed 160-acre drainage.

The OCC has two methods by which one can drill additional wells to produce nonrecoverable gas within the 640 acre section. These are:

1. A de-spacing application

2. An increased density application.

A de-spacing application can be used to downsize an existing 640-acre unit to an area more comparable to the observed drainage pattern. This allows the drilling of additional wells on smaller units, such as 160 acres. These wells would produce reserves unrecoverable by the one well/640 acre unit. Each new unit would have its own unit allowable.

However, de-spacing of existing producing proration units generally causes inequities for owners who participated in the initial well as well as for mineral interest owners. This is because the owners of the "downsized" adjacent 160-acre units may not be the same as those in the 160-acre unit with the initial well.

Prior to de-spacing, owners of the initial well would have shared revenues on a 640-acre basis. But after de-spacing, the owners in the smaller unit would not have to share revenues with the owners of the initial well. For these reasons, de-spacing applications of producing proration units are often hotly contested at the OCC.

An increased density application at the OCC is the favored approach within the Cherokee area. This application authorizes additional wells within a given drilling and spacing unit. Thus, two or more wells may be drilled within the same 640-acre unit. The benefit over the de-spacing application is that the equities of the owners in the initial well remain intact.

The drawback is that the additional well or wells must share the unit allowable with the other wells in that unit. Currently, Oklahoma gas wells in unallocated fields, such as the Cherokee area, are prorated based on a percentage of the highest CAOF within the drilling and spacing unit. Recently, that percentage has ranged from 35 to 50%.

For example, if the statewide percentage is 50% and the highest CAOF of a unit is 4 MMcfd, the unit will have an allowable of 2 MMcfd that is shared by all wells within the unit.

The OCC periodically adjusts the statewide percentage on the basis of supply and demand. Also, each drilling and spacing unit receives a minimum allowable on a statewide basis. This minimum is periodically reviewed and recently has ranged from 750 to 1,000 Mcfd, with 1,000 Mcfd being the norm.

In an increased-density application, sharing allowables may not be a problem if only one or two additional wells are drilled and CAOFs of the new well or wells are sufficient to allow production from all wells. But in areas that may need as many as six to eight wells to produce the gas underlying the proration unit, drilling this number of wells may be uneconomical because of the low allowable production rate for each well.

This is further magnified by the fact that most tight gas wells initially have a high CAOF, but after the wells produce for 2 or 3 years, the CAOF rate falls to such an extent that the proration unit receives a minimum unit allowable of 750-1,000 Mcfd. Shared equally among eight wells, the 1,000 Mcfd equals only 125 Mcfd/well, a rate that is uneconomical for wells generally costing in excess of $1,000,000.

SEPARATE ALLOWABLE

In 1989 or 1990, the concept of a separate allowable was introduced for the Cherokee area.5 The reason for granting a separate allowable was that if the OCC was willing to grant an increased drilling density for new wells, then OCC should also allow the wells to be produced.

Without the separate allowable for a new well, the well could not be produced because existing wells already used all of the allowable for the unit. Initially, the separate allowable had a limit of 1 MMcfd/new well. However, based on economic data presented to the OCC, this limit was increased to 2 MMcfd/well for new wells, and in rare cases to 3 MMcfd.

The separate allowable provided opportunities of low-risk infill development in proven areas. It encouraged development of new gas reserves and thereby, provided new investments and added tax revenues for the state.

Without the separate allowable, the tight gas credit incentives, passed Nov. 5, 1990, would have been less effective. Restricted allowables that prevented wells from being produced would have decreased the number of wells drilled because of the tax credit.

Because it enables producers to tap undeveloped reserves and encourage development, the separate allowable remains an essential part in future Cherokee area development.

COSTS

Improvements in drilling and completion practices are another reason for the Cherokee area remaining an attractive play.

In the early 1980s when the Cherokee area was first being developed, operators set an intermediate string of 5 or 7-in. casing at about 11,600 ft prior to drilling out the Red Fork member of the Cherokee formation. This practice was based in part on drilling experience in more permeable formations and also because of overpressure in the Red Fork.

To maintain control, the Red Fork formation with bottom hole pressures of up to 9,000 psia can require mud weights as great as 14.0 ppg. However, because of the tightness of the Red Fork rock and other Cherokee formations within the Cherokee tight gas area, current practice has all but eliminated the intermediate string.

Current practice before drilling under-balanced to TD is to set a longer surface string, in some instances as deep as 5,000 ft, to isolate several salt stringers and weaker formations. A rotating head is often used to divert any drilling kicks away from the rig floor.

In case the well is dry, this practice minimizes capital investment because the only pipe remaining in the ground is the deep surface string. The practice also saves rig time (and time is money) to cement the intermediate string and set a liner.

A better bit selection is also available without the intermediate string. Hence, penetration rates are faster.

Sometimes well logging becomes more challenging, but logs can still be obtained by spotting a heavy mud pill, up to 16 ppg, on bottom to prevent or slow gas flow from the formation into the well bore.

Not having the intermediate string allows running larger casing to TD, minimizes mechanical risks of working inside a liner, and simplifies downhole tool selection. Completion practices are improved in part because of the larger casing and lack of a liner.

Because of the overpressured reservoirs, prior practice in the early 1980s was to perforate and stimulate through tubing. This limited the perforation size and stimulation pumping rates, which in turn increased screen-out probability during a fracture stimulation and reduced the overall hydraulic fracture length and conductivity. Because of the tight rock, almost all wells are fracture stimulation.

In the early 1980s, a fracture stimulation where proppant concentrations reached 3 ppg was considered a success. Current practice is to perforate and stimulate via the larger casing rather than the tubing. This allows higher stimulation pumping rates which, in turn, create greater fracture lengths and allow greater proppant concentrations. Proppant concentrations of 5-6 ppg are now common.

Fig. 3 (32354 bytes) illustrates the improvements in drilling and completion practices made since 1981. In the Cherokee area in 1981, completed well costs for Marathon Oil Co./TXO Production Corp.operated properties averaged slightly over $160/ft. By 1993, these costs had been reduced to $80/ft.

The lower cost reflects improvements in drilling and completion design as well as improved planning and execution. Other operators have similar cost improvements.

COMPLETION EFFICIENCY

Fig. 4. (32309 bytes) illustrates another aspect of improved completion practices; that is, the peak rate observed per well for a given group of wells over time. The peak rate per well bottomed out during the drilling boom of 1981 and 1982 at rates of 506 Mcfd and 505 Mcfd, respectively. Since 1982, the peak rate per well trend has steadily increased to a high of 1,392 Mcfd in 1991, followed by a drop to 864 Mcfd during the miniboom of 1992.

The 1993 average peak rate per well was 1,216 Mcfd, signaling a return to the pre-1992 trend. This reflects improvements in perforating and hydraulic fracturing, as noted previously.

OUTLOOK

As seen in Fig. 5,(34870 bytes) the Cherokee tight formation continues to be a growth area within the state of Oklahoma relative to other drilling opportunities. From 1986 through 1993, during a period of relatively stable gas pricing, permitted wells drilled in the Cherokee area grew steadily from 30 in 1986 to 85 in 1993, or an increase of 283%, excluding the effects of the mini-boom in 1992.

Statewide drilling permits during this same time period declined from 6,585 wells to 3,464 wells, or a decrease of 47%. The growth of activity in the Cherokee area is because of both improved technology and practices and the recognition by various regulatory agencies, such as the OCC, that tight gas formations are a viable source of energy and revenue.

Improved technologies and practices reduced investment costs and increased rates on a per well basis, thereby improving the economics to drill. State recognition of the need for a separate allowable in the Cherokee area permitted these wells to be drilled and produced.

While improved technology and practices have enhanced economics and the separate allowables have permitted the wells to be drilled, no one can deny that the federal tax credit programs have impacted the Cherokee area economics and can significantly increase or accelerate drilling.

As seen in Fig. 4,(32309 bytes) drilling increased within the Cherokee tight gas area by 90 wells over and above the established base trend. This more than doubled the number of wells expected to be drilled in the Cherokee area in 1992. Assuming a completed cost of $80/ft and an average depth of 12,000 ft, this represented an additional or accelerated investment in Oklahoma of $86 million for 1992.

Peak field rate increased by 78 MMcfd during the tight gas mini-boom of 1992. Another indicator that the tight gas credit has provided incentives to drill is the observation from Fig. 4 (32309 bytes) that the peak rate average per well declined from 1,392 Mcfd in 1991 to 864 Mcfd in 1992. In other words, riskier, less attractive, and less economic areas were drilled in response to the credit as is shown by the decline in average peak productivity per well.

The future role of the tight gas credit policy on the Cherokee area is uncertain at present. But no one can deny that the credit is an incentive owners can take advantage of by bringing new gas to market, investing in new projects, and expanding their search for new gas reserves.

As of Dec. 31, 1993, there were about 1,130 active producing wells from the Cherokee formation within the Cherokee area or about one well/719 acres (Fig. 6)(41469 bytes). This represents a 9% annualized growth rate since 1986, when the active well count was 615.

Although not every 640 acre unit has proven productive but given that some units will require seven or eight wells to effectively drain the gas in place, the Cherokee area is expected to remain a strong growth area for some time to come. Future cost and productivity improvements will provide the inroads necessary to recover the proven undeveloped reserves. A future tax credit can do nothing but help accelerate this process.

ACKNOWLEDGMENTS

The number of wells drilled and the production associated with each well within the Cherokee area was derived from Dwight's Energydata Inc.'s production data on CD ROM. The number of wells drilled on a statewide basis is based on data provided by Larry Claxton of the Oklahoma Corporation Commission.