SPE 119899Economic Evaluation of Shale Gas ReservoirsJohn D. Wright, SPE, Norwest CorporationCopyright 2008, Society of Petroleum EngineersThis paper was prepared for presentation at the 2008 SPE Shale Gas Production Conference held in Fort Worth, Texas, U.S.A., 16–18 November 2008.This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. AbstractThree 9-square mile areas in the Newark East Field were studied to investigate the economic viability of the Barnett shale gas play. The areas chosen corresponded to the 25th, 50th, and 75th percentiles based on average estimated ultimate recovery per well in the areas. The actual drilling and refrac schedule was used for each area along with actual and forecasted production and today’s costs and prices to calculate economics on the 329 wells in the areas. Most of the individual wells are not economic under the assumptions of this study. Of the three areas, only the 75th percentile area was economic when considered as a whole. The results are most sensitive to capital costs and gas prices.IntroductionGas shale plays are the current rage in the U.S. oil and gas industry. At the present time major gas shale plays are unfolding in the Barnett, Woodford, New Albany, and Fayetteville shales and other basins are being targeted as well. The most mature of these plays is the Barnett shale near Fort Worth Texas with more than 6000 wells on production. The most mature field in this play is the Newark East Field located primarily in Wise and Denton counties, Texas. This field was “discovered” in 1981 and rapid drilling began in the late 1990s. There is now enough production history to begin to develop an idea of how commercial these plays can be. As with any emerging resource play, there have been a number of changes in drilling and completion practices over the years. Major advances in technology include drilling horizontal wells, re-fracing existing wells, and using slick water for frac jobs. Rather than attempting to quantify the effects of those technological changes, this study examines the economics of the Barnett play as it was actually developed.Study MethodologyThe Barnett gas shale in the Newark East Field was studied by subdividing the field into 3-mile x 3-mile blocks. The average estimated ultimate recovery (EUR) for each 3 x 3 block was determined from a proprietary database containing EUR’s for approximately 4500 Barnett shale wells. This database was created by using decline curve analysis to estimate remaining reserves for each “event” on each well. “Events” subsequent to initial production are usually assumed to be refracs, but may include significant increases in production from other effects. Figure 1 shows the production rate from an example well along with the decline curve extrapolations. A bubble map of the average EUR for each block which contains more than 20 wells is shown in Figure 2. Figure 3 contains a cumulative frequency plot of EUR for those blocks. It can be seen that the cumulative frequency curve is almost linear, indicating that the average EUR’s for the blocks appear to be approximately uniformly distributed. Three blocks were chosen for more detailed study. These blocks correspond roughly to the 25th, 50th, and 75th percentile as shown by the large dots on Figure 3 and the black, red, and blue dots on Figure 2. Each of these study areas contains more than 100 wells. The study areas will be referred to as the “Low”, “Medium” and “High” areas in the remainder of this paper.For the purposes of this study the timing of the wells, the choice of horizontal or vertical wells, and the refracing was modeled exactly as it occurred. Actual production was used as long as it was available and the extrapolation of the final “event” was used to project future production. Obviously, these assumptions limit the applicability of the study results to new plays where different technology might be employed from the start. It also does not take into account potential refracs or recompletions or increased density drilling in the future in the three areas. However, in spite of these limitations, it is instructive to look at the economics of these areas based on historical timing and technology.119899 2 SPEEconomics were run for each individual well and summed to arrive at “project” economics using “base case” assumptions forprices and costs. This is equivalent to assuming that a company holds a 9-section area and develops it with approximately100 wells. Sensitivity runs were made to determine the effects of a 25% change in prices, capital costs, and operating costs.An additional sensitivity run was made in each area to examine the effect of the top 5% of the wells on the projecteconomics.Production ForecastFigures 4, 5, and 6 show a “project” production history and forecast on a semi-log plot along with the vertical and horizontalwell count and the number of refracs on a Cartesian plot. The historical production and forecast for each area is compared inFigure 7. While a quantitative comparison cannot be made, it is interesting to note that the Low Area has primarily verticalwells with few refracs, the Medium Area has primarily vertical wells with many refracs, and the High Area has about twiceas many horizontal wells as vertical wells and few refracs.Economic ParametersThe economics were run on an individual well basis and summed for each area. The base case economic parameters areshown in Table 1 and were chosen to represent an approximation of current conditions. The cases were run on a before-income-tax basis and the net cash flows were discounted back to time zero (the date of first production for each of theindividual areas) at 10% per annum.Base case runs were made for each area. Sensitivity runs were also made for each area by individually varying price, capitalcosts, and operating costs 25% higher and lower than the base case values. An additional sensitivity run was made byremoving the top 5% of the wells in each area from the analysis. A total of 24 different runs were made.ResultsBase CaseThe EUR’s for the wells ranged from about 50 MMCF to about 6 BCF with most of the wells being below 1 BCF. Figure 8shows the cumulative frequency of EUR (for the base case economic assumptions) for each of the three areas. In the LowArea, 90% of the wells are less than 1 BCF. In the Medium Area, 60% of the wells are below 1 BCF, and even in the HighArea about 50% of the wells are less than 1 BCF. All of the areas show a wide variation in EUR; between 1 and 2 orders ofmagnitude. On an undiscounted basis, the EUR necessary to pay out the well or just recover the capital cost ranges fromabout 550 MMCF to 900 MMCF as shown in Figure 9. There is an excellent correlation between EUR and undiscounted netcash flow (sometimes called NPV0) as shown in Figure 10, a “zoomed-out” version of Figure 9.A number of managerial indicators were calculated including undiscounted net cash flow, time to payout, net present value,discounted profit to investment ratio, and internal rate of return. Discounted profit to investment ratio (DP/I) will be used tocompare the different areas. For the purposes of this paper, DP/I is calculated by dividing the net cash flow discounted at10% by the investment stream discounted at 10% and adding 1. This is equivalent to dividing the discounted net operatingincome by the discounted investment. The “hurdle” value is therefore 1.0. A project or well that has a DP/I of 1.0 has a netpresent value (NPV) of zero at 10%. That means it has a 10% internal rate of return. For the assumptions in this study thereis a strong correlation between internal rate of return and DP/I as shown in Figure 11. Using the assumptions in this study,including the shape of the production profile, a DP/I of about 1.25 results in an internal rate of return of about 20%. Asignificant number of wells had internal rates of return that were less than zero, i.e., the wells never paid out.The economics for individual wells in the three areas can be compared by examining a cumulative frequency plot of DP/I asshown in Figure 12. Assuming a DP/I hurdle of 1.0, 50% of the wells in the High Area, 65% of the wells in the MediumArea, and 90% of the wells in the Low Area are uneconomic. The results on a total project (area) basis are a DP/I of 0.54 forthe Low Area, 0.90 for the Medium Area, and 1.24 for the High Area. That means that if each of the areas were a project,one project would be a dismal failure, one would be a mild economic failure, and one would be a reasonable, but notoutstanding, economic success. Successful refracs in the future will help the economics somewhat from those presented here.Sensitivity CasesThe sensitivity cases are presented on an area basis. The results are contained in Table 2. The input variable with the mostimpact on DP/I is the capital cost. A 25% decrease in capital costs results in a 44% to 72% increase in DP/I. A 25% increasein gas price results in a 28% to 34% increase in DP/I. As usual, operating expense has little effect on full cycle economicswith a 25% change in operating costs making a 3% to 9% change in DP/I. Production profile has the largest effect, however.A 25% decrease in capital costs or a 25% increase in prices will not, by themselves, make the Low Area economic.However, changes of those magnitudes will cause the Medium Area to become economic. The fragile nature of these typesof plays is illustrated by the effect of a price decrease or cost increase on the High Area. A 25% decrease in price or a 25%increase in capital costs will cause even the High Area to become uneconomic.SPE 119899 3 The top 5% of the wells are very important to the overall economic viability of the projects. If the top 5% of the wells were not discovered then the DP/I would be 0.48 instead of 0.54 for the Low Area, 0.83 instead of 0.90 for the Medium Area, and 1.10 instead of 1.24 for the High Area. In that scenario, the High Area becomes somewhat marginal as a project. Considering that the High Area represents the 75th percentile of the entire field this has large implications for the development of the play.Conclusions1.There is wide range in EUR’s and, according, a wide range in economic value for individual wells in the Barnettshale play.2.At today’s costs and prices it takes an ultimate recovery of about 550 to 900 MMCF to pay out a well.3.Based on the economic assumptions used in this paper, 226 of the 389 wells studied (69%) had less than a 10%internal rate of return.4.At today’s costs and prices the 25th percentile areas based on EUR are not economically viable, the 50th percentileareas are almost economically viable, and the 75th percentile areas are reasonably economically viable.5.Discounted profit to investment ratio is very sensitive to capital costs and gas prices and much less sensitive tooperating costs.6.In any given area, the top 5% of the wells based on ultimate recovery have a significant effect on the economicviability of the project.4 SPE119899Table 1 – Economic ParametersCapital CostsVertical Well Drill & Compl. $2,400,000Vertical Well Refrac $ 600,000Horizontal Well Drill & Compl. $3,400,000Horizontal Well Refrac $1,000,000Operating Cost 6000 $/well/monthAsof Date Varies by AreaDisc Rate 10% /AnnumWorking Interest 100%Net Revenue Interest 85%Severance Tax Rate 7.5%Ad Valorem Tax Rate 3.0%BTU/SCFBTU 1000Shrinkage 0Net Back Wellhead Gas Price $7 /MMBTUTable 2 – Results of sensitivity cases on discounted profit to investment ratioDiscounted Profit to Investment Ratio (DP/I) @ 10%AreaArea HighArea MediumLow-25% Base +25% -25% Base +25% -25% Base +25%Price 0.36 0.54 0.72 0.62 0.90 1.18 0.89 1.24 1.59Capex 0.91 0.54 0.35 1.55 0.90 0.59 1.79 1.24 0.93Opex 0.58 0.54 0.49 0.96 0.90 0.85 1.29 1.24 1.20Figure 1 – Production history and forecast for an example well.SPE 119899 5 Figure 2 – Bubble map of average EUR for all wells in a 3-mile by 3-mile block with study areas highlighted4Bl Low (25th Percentile) AreaMedium (50th Percentile) AreaFigure 3 – Cumulative frequency of average EUR with study areas highlighted119899 6 SPEFigure 4 - Production history and forecast, wellcount, and refrac count – Low (25th percentile) AreathSPE 119899 7 Figure 6 - Production history and forecast, wellcount, and refrac count – High (75th percentile) Area119899 8 SPEFigure 8 – Cumulative frequency of EUR for each of the three areasSPE 119899 9 Figure 10 – Correlation between EUR and undiscounted net cash flow10 SPE119899 Figure 12 – Cumulative frequency of individual well DP/I for each area。