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Study Develops Fayetteville Shale Reserves, Production Forecast John Browning Katie Smye a Study of Reserve and Production Potential for the Fayette- Scott W

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Study Develops Fayetteville Shale Reserves, Production Forecast John Browning Katie Smye a Study of Reserve and Production Potential for the Fayette- Scott W Study develops Fayetteville Shale reserves, production forecast John Browning Katie Smye A study of reserve and production potential for the Fayette- Scott W. Tinker Susan Horvath ville Shale in north central Arkansas forecasts a cumulative Svetlana Ikonnikova Tad Patzek 18 tcf of economically recoverable reserves by 2050, with Gürcan Gülen Frank Male production declining to about 400 bcf/year by 2030 from Eric Potter Forrest Roberts the current peak of about 950 bcf/year. Qilong Fu Carl Grote The forecast suggests the formation will continue to be a The University of Texas major contributor to U.S. natural gas production. Austin The Bureau of Economic Geology (BEG) at The University In this cross section of the Fayetteville Shale, the pay zone is identified by lines correlated between logs. Shaded areas of density-log porosity (DPhi) curve represent DPhi values less than 5%. The map shows the location of the cross section. TECHNOLOGY 1 FAYETTEVILLE POROSITY * THICKNESS (PHI*H) FIG. 2 Contours,2 density porosity-ft Stone 5 8 11 14 17 20 23 26 29 32 35 38 41 44 47 50 Batesville Van Buren Cleburne Independence Pope Conway Faulkner Area shown White Conway 0 Miles 25 Arkansas 0 Km 40 1With 60° NE trend bias to reect fault trends. 2Porosity is net from density logs (DPhi). of Texas at Austin conducted the study, integrating engineer- sient flow model for the first 3-5 years, resulting in decline ing, geology, and economics into a numerical model that al- rates inversely proportional to the square root of time, later lows for scenario testing on the basis of an array of technical shifting to exponential decline as a result of interfracture and economic parameters. interference within the well drainage volume. This is the second of four basins study. The first was the • Adsorbed gas greatly contributes to production and is ac- Barnett (OGJ, Aug. 5 and Sept. 2, 2013). The third study, on counted for in well-decline modeling and in EUR calculations. the Haynesville, and the fourth, on the Marcellus, have just The BEG analysis is built on production data from all in- been completed. Results of these four basin stud- dividual wells drilled 2005-11 in the Fayetteville ies will help constrain forecasts of future economic shale. The study takes a “bottom-up” approach, U.S. shale gas production. starting with the production history of every well Other key findings of the Fayetteville study and then determining what remains to be drilled include: under various economic scenarios. The result is a • Original free gas in place of 80 tcf for the publically available view of the field that is unprec- 2,737-sq mile study area. edented in its comprehensiveness. • Technically recoverable gas resources of DRILLING & The study assesses natural gas production po- about 38 tcf. PRODUCTION tential in six productivity tiers and uses those tiers • Base-case total-field estimated ultimate re- to forecast future production. Well economics vary covery (EUR) of 18.2 tcf, which includes 6.1 tcf greatly across the basin as a function of productiv- EUR from the 3,689 wells drilled through 2011. ity, well and other costs, and geology. The study’s • Base-case drilling of 6,428 new wells through 2030, production forecast model accounts for this granularity, as added to the 3,689 wells drilled through 2011, for a total of well as for distributions around natural gas price, drilling 10,117 wells drilled through 2030. cost, economic limit of each well, advances in technology, • Base-case field-wide production reaches a plateau of and many other geologic, engineering, and economic pa- around 0.95 tcf/year and will slowly decline after most of the rameters, in order to determine how much natural gas op- better locations are drilled. erators will be able to extract economically from future wells • Wells drain the formation according to a linear tran- in the field. TECHNOLOGY FREE FAYETTEVILLE ORIGINAL FREE GAS IN PLACE (OGIP )* FIG. 3 OGIPfree, in bcf, values determined for each PLSS section in the Fayetteville pay zone Stone Batesville 0-18 19-21 22-25 26-28 29-32 33-35 36- 38 39-41 42-45 46-57 Van Buren Cleburne Independence Pope Conway Faulkner Area shown White 0 25 Conway Miles Arkansas Km 0 40 *Map gridded by section across the play. Sources: Arkansas Public Land Survey System (PLSS) data acquired from AGIO. Well data provided by IHS; well raster logs provided by MJ Systems. Compiled in ESRI ArcMap 10.2. NAD 1927 State Plane Arkansas North Integral to the project is a new method of estimating ulti- sis (OGJ, Aug. 5, 2013, p. 82),2 we performed a log-based mate production for each well on the basis of the physics of assessment of the key geological parameters influencing the system, rather than mathematical decline-curve fitting. production in the Fayetteville Shale. For the study, we digi- This method offers an accurate means of forecasting produc- tized and utilized logs that were deep enough to reach the tion declines in shale wells in other basins.1 base of the Fayetteville (including gamma ray, density po- For the purpose of tiering and decline-curve analyses, rosity (DPhi) and neutron porosity (NPhi) logs) and showed the study uses all 3,689 wells that produced through 2011. good log quality and caliper (measure of hole quality). The production outlook model forecasts field development Our dataset consisted of logs from 153 wells chosen to 2012-30 and then further extends production forecasts maximize spatial coverage of the field. Major stratigraphic through 2050. tops were picked in all wells (Fig. 1), and the analysis con- Although 2012 wells do not have a long enough pro- sidered the effect of thrust-sense deformation and normal duction history to provide stable decline analysis for faulting, which lead to, respectively, thickening and thin- forecasting, they do allow us to benchmark our forecast ning of the formation. against actual 2012 drilling and production results—an Net pay-zone thickness and density porosity maps were important vetting process. Although the model can run developed and combined to create a net porosity-thickness countless scenarios, we report on a base case assuming (DPhi*H) map (Fig. 2).3 When calculating free original gas in $4/Mcf natural gas and other relatively modest technical place (OGIPfree), we used industry-proprietary core porosi- and economic assumptions. ties from 76 wells supplemented by calibrated density log porosity for about 20 additional wells to estimate the stor- Geologic characterization age volume in the Fayetteville Shale. The porosity-thickness We chose our study area to encompass the extent of previous map was found to provide a good correlation with well pro- drilling within the known geologic boundaries of the field. ductivity, a key element in predicting future field production A total of 2,737 sq miles was included, although only 1,252 from undeveloped areas of the field. sq miles had been tested by drilling through 2011. We calculated OGIPfree, excluding adsorbed gas, for the Following the steps outlined in the Barnett Shale analy- entire play on a section-by-section basis, utilizing a conven- TECHNOLOGY ACTUAL WELL DATA VS. STUDY SOLUTION* FIG. 4 The study utilized a well-produc- tion-decline method on the basis of 5 3,000 linear transient flow in the reservoir.1 No. of wells Linear transient flow results in per- 4 2,500 well production decline inversely pro- portional to the square root of time 2,000 3 for the first 3-5 years of well life (de- pending upon reservoir properties and 1,500 completions), followed by exponential 2 no. Wells, One std. dev. 1,000 decline as interfracture interference begins to affect production. Scaled total production, bcf 1 500 The approach was supplemented Study theoretical solution by 3D reservoir simulation accounting 0 0 for the effect of adsorbed gas. The ad- 0 1 2 3 4 5 6 7 Years sorbed gas was found to contribute as *One standard deviation of well data. Interfracture interference effects have not yet been observed in these wells. much as 25% of wells’ EURs, but this Source: Reference 1 contribution varied across the play. A theoretical solution of linear flow would yield a straight-line increase tional volumetric approach (Fig. 3). Temperature and pres- of cumulative production vs. log time until interfracture sure were calculated as a function of reservoir depth. We as- boundary conditions were reached within the well fracture sumed a constant water saturation of 25% and gas properties pattern, resulting in the predicted gentle downturn. typical for similar reservoirs. We normalized production from 3,114 wells to the me- Total OGIP free was estimated at 80 tcf, with 45 tcf un- dian EUR, then plotted cumulative production vs. log-time derlying sections that were penetrated by at least one well distribution, along with the study’s theoretical solution (Fig. by yearend 2011. Variation in depth of the Fayetteville 4). The other 383 wells were found to be experiencing inter- shale leads to increasing formation pressure from north to fracture interference. south. In light of this, pressure was identified as another important element of OGIPfree. The Fayetteville OGIPfree Reservoir quality tiering map also includes interior faulting, taken from published Knowledge of the EUR and location for every well in the field structural maps.4 allowed us to map the geographical distribution of produc- We recognize that the geologic description could have tivity by individual section. A straightforward application of been enhanced greatly by analysis of seismic data to identify EUR would have been inappropriate because the well popu- faulting and other anomalies.
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