Gary S. Swindell, Consulting Engineer, Dallas, Texas
This article was published in the Oil & Gas Journal, March 25, 1996. Copyright 1996 by Pennwell Publishing Co. All rights reserved. Oil & Gas Journal or any part therof may not be reproduced, stored in a retrieval system, or transcribed in any form by any means, electronic or mechanical without the prior written permission of the Editor.
Horizontal drilling has become one of the most valuable technologies ever introduced into the upstream oil business. Along with other advances over the last fifteen years such as massive fracturing and 3-D seismic, horizontal drilling has had a significant impact on oil and gas production.
A considerable number of articles and papers have been written on horizontal drilling, but the focus has been on the hardware and drilling side of the technology. Relatively little has been published on the reserves that have been found. This lack of reserve and economic information is partly due to operators wanting to retain a competitive advantage in their drilling. But it is also due to the difficulty in applying traditional reserve estimation methods to a situation which we do not fully understand.
Volumetric analysis is complicated because of a lack of knowledge on extent of the fracture systems - there are documented cases of wells interfering as much as two miles away, and other cases where wells 1,500 ft apart show no interference. Pressure transient and reservoir simulation methods are made difficult by the same poor understanding of the reservoir character. Analogy has not been effective since there simply are none to this new technology.
That leaves performance analysis as a reserve estimating tool. And it is only recently that enough history is available to reliably examine the reserve potential of horizontal wells. So, let's take a look at what we have found from horizontal drilling.
At least 12 states have some horizontal production. But Texas overwhelmingly dominates the use of the technique. Together with North Dakota, the top two states account for 89% of the producing horizontal leases drilled since 1987.
State New Leases Major Formations since 1988 Texas 2,054 Austin, Buda, Georgetwn, Ellenburger North Dakota 175 Bakken, Madison Wyoming 71 Niobrara, Minnelusa, Frontier Alabama 58 Pottsville Coals Montana 42 Red River, Mission Canyon Louisiana 35 Chalk, Miocene, Cotton Valley Oklahoma 27 Bartlesville, Miss, Viola, Hunton Utah 17 Desert Crk, Twin Crk New Mexico 13 Fruitland Coal, Mancos Shale Colorado 8 Niobrara, Codell Michigan 5 Antrim South Dakota 1 Red River US Total 2,506
One difficulty in evaluating the results of horizontal drilling is that production for Texas wells is reported on a lease basis and not by individual well. Dwights EnergyData shows some 2,700 Texas leases designated as "horizontal". These include older leases that have had horizontal wells drilled around existing vertical production. To reduce the effect of mixed vertical and horizontal drilling, this study was restricted to leases which began production after 1987. In Texas, the 1987 limit excludes about 700 mixed leases from the statistics. Most of the Texas study group are single well leases. Other states generally report production on a individual well basis and the problem is less significant.
Another problem with using summarized rate vs. time curves for reserve estimation is that the completions took place over a number of years. Our study accounts for the time effect by the use of normalized production.
Bakken Shale has been the primary target for North Dakota horizontal drilling. Billings and McKenzie have been the dominant counties. Through mid-1995, horizontal wells have produced 11,336,000 barrels and 18 BCF, or about 14 MMBOE since late 1987 when the first wells were completed. Note (fig. 2) that production began to fall in 1991, even as the total well count continued to rise. This is due to the sharp production declines often seen in the early life of fractured reservoirs.
Normalizing, the procedure of setting each well back to the same "time zero", provides a means for taking out the problem of time shown in figure 2. When all the horizontal wells that make up the total horizontal production for North Dakota are normalized, a composite average well profile develops as shown in figure 3.
The average initial production from the typical horizontal well in North Dakota is 4,300 BBL/month with an early decline of about 65% and only a small hyperbolic factor that serves to flatten the decline over time. The relatively small hyperbolic nature of the curve compared with the Austin Chalk wells may suggest poor contribution from the rock matrix versus the fracture system.
In an earlier study, we looked at every individual Bakken Shale well in the state and projected an ultimate recovery using rate vs. time curves. The average vertical well was projected to ultimately recover 104,000 BBL. Surprisingly, the average horizontal well's estimated ultimate recovery (EUR) was less than the vertical wells at 97,000 BBL. Perhaps the horizontal wells found fracture systems that had already been substantially depleted by vertical wells. Of the larger fields, only Elkhorn showed higher per well EUR for horizontal wells. The advantage was only a 15,000 BBL per well increase for horizontal drilling.
Poor overall economics have slowed the use of horizontal drilling in the Bakken Shale of North Dakota.
More than 101 Texas counties have experienced some horizontal production (fig. 5). Statewide leases designated as "horizontal" (Dwights EnergyData) with the earliest production after 1987, have produced 188 MMBBL and 497 BCF (271 MMBOE).
As in North Dakota, the total oil production began to decline after late 1992 even as well count continued to increase. And when total horizontal well count generally stabilized in early 1994 the overall decline steepens considerably.
Although scattered horizontal drilling has occurred in most Texas basins, the vast majority of the wells have been in the Austin Chalk trend. The top ten Texas counties in horizontal drilling since 1987 contain more than 90% of the total horizontal leases, and our further study was narrowed to these ten counties.
Normalizing again provides a tool to take out much of the effect of differing dates of first production. Some of the leases in our study group did have additional wells added after the earliest production. Furthermore, some had wells which added a second horizontal leg, often in the updip direction. Overall, though, the effect of added wells and reworks of existing wells does not appear to have a significant influence on the statistics developed in the study.
Study Group Cumulative Oil Avg Ultimate Avg Peak No. of Wells (BBL) per Well Production (after 1987) (BOE) (BBL/Month) Brazos Co., TX 245 23,020,620 155,045 14,249 Burleson Co., 286 24,026,926 187,887 8,069 TX Dimmit Co., TX 109 7,193,795 86,171 7,218 Fayette Co., TX 317 33,988,344 200,198 13,538 Frio Co., TX 408 27,236,932 82,917 6,658 Gonzales Co., 142 8,767,873 77,882 7,416 TX LaSalle Co., TX 124 7,686,914 79,555 8,633 Lee Co., TX 115 11,194,118 153,278 11,743 Wilson Co., TX 51 2,337,059 62,470 3,824 Zavala Co., TX 93 15,279,901 199,134 12,387
Austin Chalk EUR
The average estimated ultimate recovery of horizontal wells, based on the normalized profiles of each of the top ten Texas counties, is shown in figure 6. Average EUR ranges from a low of 80,000 BOE per well in LaSalle County to 200,000 BOE in Fayette County.
Fig 6. Estimated Gross Ultimate per Well - Austin Chalk Trend
The average peak production can be obtained from the normalized rate vs. time curves. Usually this peak occurs in the first month of production but at times the second or third month is the highest level as wells clean up and produce back drilling and stimulation fluids. The data is influenced by the fact that the first month of recorded production may not be a full 30 or 31 days.
Fig 7. Peak Monthly Production, MBBL per Well, Austin Chalk Trend
Closer Look at Four Counties
The rate vs. time profiles of four counties, Brazos and Fayette in the northeastern part of the Chalk trend, and Frio and Zavala in the southwest, give a better understanding of the average reserves. Brazos County shows fairly high peak production, 14,250 BBL/month, but very rapid decline. Over 68% of the average EUR (155,000 BOE) is produced in the first year, and over 80% in the first two years.
Fayette County shows similarly high initial rates and higher EUR than Brazos because of more flattening of the decline. Still, over 65% of the EUR is produced in the first year. The Giddings Field is located in Fayette County.
Pearsall Field is on the southwestern end of the Chalk trend, covering portions of Frio, LaSalle, Dimmit and Zavala Counties. The Frio County rate vs. time plot shows a significantly lower initial rate the northeastern counties, but perhaps a stronger hyperbolic behavior. The first year accounts for 55% of the ultimate predicted recovery.
The Zavala County typical profile is a composite of 93 horizontal wells. Initial rate is fairly high at 12,400 BBL/month. Ultimate recovery is estimated to be nearly 200,000 BOE/well. Hyperbolic behavior is not very evident after the first 2 years, possibly suggesting that the primary porosity is less a contributing factor than curves with more flattening. Other studies2 have concluded that both fracture size and fracture density are significantly lower in the Pearsall area vs. Giddings Field.
Results from horizontal drilling have been highly varied. Successes on a large scale have been limited to the Austin Chalk Trend. And even within this sizable trend there are areas which have been unable to realize sufficient reserves to make horizontal wells profitable. It is apparent that not all fractured reservoirs benefit economically by the application of this technology. The two top states, North Dakota and Texas have produced over 285 MMBOE to date through horizontal wells, an important contribution to the US supply. Rapid return of investment due to high initial production rates, ability to implement economies of scale, and the realization of statistical averages with multiple well programs are the driving force behind continued use of the technique in much of the Chalk Trend.
1. Maloy, William T., Horizontal wells up odds for profit in Giddings Austin Chalk, Oil & Gas Journal, Feb 17, 1992, p. 67.
2. Maloy, William T., Statistical relations predict horizontal well production, World Oil, April, 1993, p. 55.
3. Beliveau, Dennis, Heterogeneity, Geostatistics, Horizontal Wells, and Blackjack Poker, Journal of Petroleum Technology, December, 1995, p. 1068.
4. Thomas, Gilbert E., Sonnenberg, Frank P., Homing in on sweet spots in Cretaceous Austin Chalk, Oil & Gas Journal, Nov. 29, 1993, p 110.
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