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1 SPE Impact of Completion System, Staging, and Hydraulic Fracturing Trends in the Bakken Formation of the Eastern Williston Basin Randy F. LaFollette, SPE, William D. Holcomb, SPE, and Jorge Aragon, Ph.D., SPE, Baker Hughes Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 6 8 February 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. Abstract In this study, the authors have analyzed well and production data beginning with more than 400 wells in the greater Sanish-Parshall area of the Bakken. The study used Geographical Information System pattern-recognition techniques along with other data-mining techniques to interpret trends in the data sets. The study was made possible by combining data sets from the North Dakota Industrial Commission Oil and Gas Division, public data, and in-house proprietary data. The study was designed to search for relevant trends in the distribution of production results for wells completed with fracturing sleeves and packers, plug and perforated, or complex completions to determine whether differences in productivity existed and needed to be factored into completion recommendations. Trends examined in the project in addition to completion type included treatment parameters such as fracturing fluid types and quantities, proppant types and quantities, number of completion stages and stage lengths, perforation cluster spacing and length, and calculated perforation friction drop. All parameters analyzed were examined for statistical importance. This work is significant in that it shows that the application of practical data-mining methods to an intermediate-size Shale Oil (light, tight oil) well data set can result in learning key lessons that may not be apparent when working with small data sets. This work is significant in the use of merged reservoir quality proxies, well architecture data, completion data, and stimulation data, against which production results are placed in geographical perspective of the Bakken Formation for improved interpretation. The work is also significant in that it may be used to allow selection of completion systems on the basis of completion time and cost balanced against concerns over differences in well production impact of one system over another, e.g., frac sleeves versus plug and perf type and complex completion systems. Introduction Bakken shale production began in the 1970 s, but the combination of recent increases in oil pricing, interest in shale production, horizontal drilling, and multistage fracturing has created a boom in the Williston Basin and especially in Mountrail County, North Dakota. At this writing, more than 845 horizontal wells have been completed and are producing in Mountrail County. The geographic distribution of these wells and their relative oil production is presented in figure 1. This figure is a bubble map showing the log 10 scale of the highest monthly cumulative production during the first year of production. Only wells with at least 3 months of published production have been included, as examination of the data shows that the first month does not always represent the highest monthly production rate. As can be seen from the map, there are definite production sweet spots, implying non-uniform reservoir quality across the study area. This ongoing study was undertaken to analyze completion and stimulation parameters having the potential to impact Bakken Formation well productivity in the greater Sanish-Parshall area of the eastern Williston Basin. Data sources used included data from the IHS Energy US Well database (see acknowledgements), North Dakota Industrial Commission well information database, and in-house well completion systems and stimulation databases. The study was performed by studying and deciding on appropriate short term well production proxy values and then analyzing changes in completion, stimulation, area, and well productivity with time.

2 2 SPE Figure 1, Log 10 of maximum month production, Mountrail Co, Bbls per Month Well Productivity Proxy A short-term proxy for well productivity is required to achieve valid comparisons among wells. Many workers rely on the published initial production (IP). Others use the first reported month s production, others the second month, or sometimes the first 3 months cumulative production (first quarter). For a number of good and sufficient reasons, there is no single correct measure of productivity. For this work, the authors have chosen to use the maximum monthly producing rate in the first 12 producing months. Figure 2 is a bar graph showing the frequency count of the producing month in which peak production occurred. Often the first month is a short month in the public data and cannot be corrected unless days on line are reported. Also, fracturing fluid cleanup and other early time well operations may tend to reduce the first month s production rate. The second month is often a reasonable short term proxy but, as shown in figure 2, less than 50 percent of the wells are adequately represented by applying this measure across the data set. Initial production is often used but it frequently is not representative of the well s real potential. A plot of initial production, taken from IHS Energy s US Well Data, vs one year cumulative production from the same source is shown in figure 3. The correlation coefficient for one year cumulative production vs IP is While this is generally considered a reasonable correlation, using the maximum monthly reported production plotted against the one year cumulative production gives a more acceptable correlation coefficient of 0.96 (Figure 4). Since the Bakken play with these more recent horizontal wells only has a limited production history, this 1 year cumulative is the standard and the maximum month is a sufficient proxy for comparing production. Studies in other basins with longer production time data have shown this maximum monthly production measure to be an acceptable proxy for comparison of wells.

3 SPE Figure 2 Frequency distribution of maximum month of production Figure 3, Reported IP vs One Yr Cum Oil Figure 4, Maximum Month Oil Bbls vs One Yr correlation coefficient =.70 Cum Oil - correlation coefficient =.96 Sanish and Parshall Fields, Mountrail County The Sanish and Parshall Fields are located in the lower eastern half of Mountrail County, North Dakota. The designation of the field names and wells is assigned by the North Dakota Industrial Commission, Department of Mineral Resources (NDIC). Sanish Field contains 204 wells with sufficient data to be included in this paper. These are wells characterized as horizontal wells producing from the Bakken interval, and with publicly released well, completion, stimulation, and production information. The NDIC has the ability to maintain well and production information in confidential status for up to 6 months time after filing by the operator with the commission. Therefore the number of wells studied here is considerably smaller than the actual number of wells in the study area. Figure 5 shows the horizontal well placement for the 204 wells in this study. Figure 5 also shows the Parshall Field. Parshall Field contains 221 wells meeting the same criteria described above for Sanish Field. Parshall laterals tend to be shorter and are designed to drain one section length, or about 5,000 feet on average. Sanish Field wells tend to be longer, with horizontal wellbores averaging nearer 9,000 feet. As can also be seen, the average azimuth of the wells is quite different.

4 4 SPE Figure 5, Sanish Parshall well locations Figure 6 is a contour map of mid perforation sub sea true vertical depth (TVDSS) for Bakken completions in the study area. The Bakken Formation trends from about 6,800 feet sub sea at the northeast corner of the Parshall Field to - 8,000 feet in the southeast corner. The Sanish Field has even greater depth of -8,300 feet on the western edge of the field. As can be seen from figure 5, there is a significant difference in the average azimuth of the two fields in addition to the difference in average wellbore length. Figure 6 shows the log 10 scaled maximum month s production for the two fields, and it quite apparent that Parshall wells, while much shorter, average considerably higher production than Sanish wells. Figure 6, Sanish Parshall Max Monthly Prod bubbles (Bbls / mo) over mid-perf SSTVD color contours

5 SPE Sanish Parshall Effective Wellbore Length Effective Wellbore Length - feet Parshall Sanish 0 01/ / / / / / /2012 Date Figure 7, Sanish Parshall Effective Wellbore Length Figure 8, Mountrail County Effective wellbore length In figure 8, above, a handful of wells have multiple laterals which measure over 15,000 feet per well when summed. These have not been studied for this work because, while all are uncemented laterals, some of these wells have production liners and some do not. Figure 9, Maximum Monthly Oil per Ft - Parshall Field Figure 10, Maximum Monthly Oil per Ft - Sanish Field Analysis of the production data yielded some interesting observations. The maximum monthly production rate, calculated per foot of lateral, was observed to decrease with time (Refer to figure 9, Parshall Field, and figure 10, Sanish Field). The same trend is noted for the entire Mountrail County area of interest. This decline in productivity was seen in both the 2,000 to 7,000 foot well class (blue) and the 7,000-14,000 foot well class (red). The number of stages pumped in the Sanish /Parshall wells along with the published stage numbers for Mountrail County, as reported to the NDIC, is presented in figures 11 and 12, below. Note that the actual number of perforation clusters and perforated intervals for fracture stimulation may be significantly greater than the reported number of stages. One stage may have several clusters of perforations or liner stimulation ports. However, the number of stages is considered to be representative of the number of stimulation treatments pumped per well. The number of stages has rapidly grown from less than 10 per well in 2008 to as many as 40 per well in 2011.

6 6 SPE Figure 11 Parshall Number of Frac Stages/well Figure 12 Sanish Number of Frac Stages/well Looking first at the Sanish and Parshall Fields, figure 13 shows maximum monthly production vs time for the Sanish F and shows an immediate contrast to the same plot for Parshall Field. The initially more prolific Parshall Field appears to have a significant reduction in productivity capacity as a function of completion date. There are many factors such as operator selected order of completion, location in the field, possible depletion of the reservoir, etc., but this is a rather significant reduction over such a short time period. It was observed that most of the horizontal wells drilled in the Parshall Field were 2,000-7,000 foot laterals but some of the later time wells were in the 7,000-14,000 foot category. As noted above, the production per foot of horizontal dropped dramatically when longer wellbores were completed. Increasing the wellbore length by a factor of two did not increase the production by anything near the same factor. Looking at the Sanish Field, we see that there is a relatively consistent maximum monthly production for the longer completions. In some cases, the shorter 2,000-7,000 foot completions initially out produced their longer infield offsets. It can be seen in figure 2 that there are some areas of the Sanish Field that produce better than other areas and this is interpreted to be reflected in the somewhat inhomogeneous production levels based only on length of the wellbore. Visually, there is a striking contrast to the two fields as shown in figures 13 and 14, below. Figure 13 Parshall Field Monthly Maximum Oil Figure 14 Sanish Field Maximum Monthly Oil Looking at Mountrail County and dividing the wells into two well length classes is described in figures 15 and 16. Figure 15 is the maximum monthly production rate for wellbore lengths in the 2,000 to 7,000 foot range. These lengths are similar to the average well length in the Parshall field. The two figures are strikingly similar even though the Mountrail County collection has sixty percent more wells. The overall trend appears to be similar for the entire county rather than just for the two fields. The Sanish Field (figure 14) has a slightly flatter trend with less average increase per well with time but is basically the same as the overall county.

7 SPE Figure 15 Mountrail County Maximum Monthly Production Horizontal Length 2,000 7,000 feet Figure 16 Mountrail County Maximum Monthly Production Horizontal Length 7,000 14,000 feet With the ever increasing number of stages comes the question, How many stages are sufficient and necessary for a specific length of well. Figure 17 shows the number of stages reported for Mountrail County for horizontal wellbore lengths of 2,000 to 7,000 feet. Figure 18 shows the same information for wellbore lengths of 7,000 to 14,000 feet. The dramatic increase in the number of fracture stages per well in the shorter wellbore lengths does not seem to have improved productivity. This contrasts with the longer 7,000-14,000 foot wellbores, where the increase in well productivity has increased along with increased stage count. Regression coefficients confirm the visual indications. Figure 17 Mountrail County Number of Stages Per Well Horizontal Length 2,000 7,000 feet Figure 18 Mountrail County Number of Stages Per Well Horizontal Length 7,000 14,000 feet Looking at the above information, the authors cross plotted the maximum monthly production per stage vs time (figures 19 and 20) and maximum monthly production per stage vs the number of stages for each class of wells (figures 21 and 22). Figure 19 shows the information for the 2,000-7,000 foot wellbores and indicates a sizable decrease in the monthly maximum production per stage versus time. Figure 20 shows the information for the 7,000-14,000 foot wellbores and indicates a sizable decrease in the monthly maximum production per stage versus time.

8 8 SPE Figure 19 Mountrail County Production per Stage Figure 20 Mountrail County Production per Stage Horizontal Length 2,000 7,000 feet Horizontal Length 7,000 14,000 feet Looking at Figures 21 and 22 it can be observed that the average production per stage decreases as the stage count increases for both classes of wells. We wished to confirm that this is also observed in both the Parshall and the Sanish Fields and the plots of production per stage vs time are presented in Figures 23 and 24. These figures confirm the overall trends observed in Mountrail County. Figure 21 Mountrail County Production per Stage By Stage Horizontal Length 2,000 7,000 feet Figure 22 Mountrail County Production per Stage By Stage Horizontal Length 7,000 14,000 feet Figure 23 Maximum Monthly Production per Stage Parshall Field Figure 24 Maximum Monthly Production per Stage Sanish Field The same trends seen in the Figures 19 and 20 are seen in the Parshall and Sanish Field plots.

9 SPE Fracturing Fluid Volumes and Proppant Quantities The volume of fracturing fluid pumped in each well in both Parshall and Sanish Fields is presented in Figure 25 along with the 40 point moving average of the treatment volume. Similar trend numbers occurred in both fields, so they are plotted together. Figure 26 is a plot of the proppant quantity per well along with the 40 point moving average of the total proppant per well and shows a similar trend, regardless of field. Not surprisingly, based upon the trends shown above, the same trends are observed for the fluid and proppant plots for Mountrail County, shown in figures 27 and 28. Note that the fluid volume per well is increasing slightly more rapidly then the average total proppant increase. Figure 25 Fracture Fluid Volume for Sanish and Parshall Fields Figure 26 Fracture Proppant Quantity for Sanish and Parshall Fields Figure 27 Fracture Fluid Volume for Mountrail County Figure 28 Fracture Proppant Quantity for Mountrail County Figures 29 and 30 show the pounds proppant pumped per stage for both the 2,000 to 7,000 foot group of wells and the 7,000 to 14,000 foot group of wells for all of Mountrail County. Note that both show a slight to moderate downward trend in pounds of proppant per stage vs time. The longer wells appear to have a more significant decrease in proppant per stage with time.

10 10 SPE Figure 29 Mountrail County Proppant Lbs per Stage Vs Time Horizontal Length 2,000 7,000 feet Figure 30 Mountrail County Proppant Lbs per Stage Vs Time Horizontal Length 7,000 14,000 feet Production normalized to horizontal length vs the average proppant concentration in the fracture treatment was studied next. Average proppant concentration in each well was calculated by dividing total pounds of proppant by the total fluid volume pumped. The normalized production was calculated by dividing the maximum monthly production by the effective horizontal wellbore length. Figures 31 and 32 below show the pounds per gallon average for each well plotted against the number of fracture stages pumped for wells in Sanish and Parshall Fields. Average proppant concentration decreases overall, as fracturing stage count increases, in the greater Sanish Parshall area (Figures 33 and 34). This average proppant concentration decrease appears to result in decreased productivity, an observation also noted in Mille, et al, Figure 31 Sanish Parshall Maximum Monthly Prod Per ft vs PPG Horizontal Length 2,000 7,000 feet Figure 32 Sanish Parshall Maximum Monthly Prod per ft vs PPG Horizontal Length 7,000 14,000 feet Figure 33 Sanish Parshall PPG vs Frac Stages Figure 34 Sanish Parshall PPG vs Frac Stages Horizontal Length 2,000 7,000 feet Horizontal Length 7,000 14,000 feet

11 SPE In Mountrail County, both published and proprietary data indicate that white sand is used in over 85 percent of the fracture treatments. Twenty-forty (20/40) mesh proppant comprised over 80 percent of the proppant pumped, with the remainder being about 10 percent each 100 mesh and 40/70 mesh. The use of other mesh sizes has been statistically rare. Higher strength ceramics and resin coated proppants comprise about 10 percent of the proppant pumped in the Bakken and almost all ceramic and resin-coated material is 20/40 mesh size. Most of the multistage treatments were pumped in the range of 16 to 40 BPM with the average being about 32 BPM. Fluids were categorized as slick water, linear gel, and crosslinked fluids. Average job total volume was about 900,000 gallons of fracturing fluid. Slightly more than 40 percent of treatments could be characterized as being entirely crosslinked fluid (80 percent of the total injected volume) with some slick water or linear gel pads, sweeps, and flushes. Most of the crosslinked fluid used pound base gel loading. Less than five percent could be called slick water fracturing treatments where the proppant carrying fluid was slick water. Less than 3 percent of treatments consisted of linear gel as the proppant carrying fluid. Approximately 50 percent of fracturing treatments were classed as hybrids, where pads, sweeps, and flushes were linear gel or slick water and the proppant carrying fluid was crosslinked, typically with pound gel loading. We were unable to note a significant difference in productivity success based upon fluid type. Since almost all types of fracture treatments in this study used 20/40 white sand as the major propping material, no production differentiation could be made on proppant type or mesh size. Productivity and Completion System During the past three years there has been a significant increase in the number of fracture stimulations as shown above. As the method of increasing stage count has changed, there has been a question of which completion strategy is better. Both plug and perf and the sliding sleeve completion technique routinely utilize resistive element external packers in an uncemented open hole horizontal wellbore. Prior to sliding sleeve technology, plug and perf was utilized as the primary method for multistage hydraulic fracturing stimulation. Earlier still, the pump and pray technique was utilized by some operators in which pre-perforated liner was utilized and a single stage fracturing treatment was pumped, possibly with some level of fluid diversion attempted through use of either solid bridging materials or ball sealers. Sliding sleeve staging was initially limited by the number of ball and seat size increments which could be utilized for staging. A combination of sliding sleeves for the deeper portion of the horizontal wellbore followed by plug and perf for the remainder of the lateral was referred to as a combo, complex, or hybrid completion method. With advancement in sliding sleeve technology, it is now possible to utilize far more sleeves / stages than in prior years. The significant completion / stimulation cost reduction advantages of sliding sleeve technology have required engineers to ask if the are any associated sacrifices in well productivity. Utilizing data from the North Dakota Industrial commission, the IHS Energy US Well database, and in-house proprietary information, this study has undertaken to examine the question. It was noted previously that stimulation fluid volumes and proppant quantities have both increased in recent years. The number of stages per well has also increased. Figure 35 shows the total fluid volume pumped per stage and shows a relatively consistent volume per stage pumped. Figure 36 shows the quantity of proppant per stage pumped as a function of the number of treatment stages. It shows a significant decrease in the proppant quantity injected per fracturing treatment stage. Figure 35 Mountrail County Frac Fluid Volume per Stage vs Number of Stages Figure 36 Mountrail County Pounds Proppant per Stage vs Number of Stages Preliminary data using combined NDIC data and proprietary data indicated the 3 month cumulative production per stage for sliding sleeve completions is at least as effective as plug and perf or hybrid completions, for at least the 7,000-12,000 foot horizontal wells. Confidentiality agreements limit the quantity of information that may be published. NDIC now requires reporting of sufficient information to analyze this information, but the current completion technique is predominately the sliding sleeve technology and comparison of publicly available information may be slow in coming.

12 12 SPE Conclusions Conclusions to be drawn from this study as of the date of this writing are: Public data sets provide a large-scale source of minable data with which to interpret historical completion / stimulation historical trends against production results. Data sets are frequently incomplete and require careful trend analysis. Production efficiency decreases with increasing lateral length. Production per stage decreases while stage count increases. Decreasing average proppant concentration appears to negatively affect productivity. Acknowledgements The authors gratefully acknowledge the management of Baker Hughes for its support of this work. Parts of this work are based on or may include proprietary data licensed from IHS; Copyright 2011 all rights reserved. References Mille, B., Paneitz, J., Mullen, M., Meijs, R., Tunstall, M., Garcia, M., The Successful Application of a Compartmental Completion Technique Used to Isolate Multiple Hydraulic Fracture Treatments in Horizontal Bakken Shale Wells in North Dakota. Paper SPE , presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, CO, USA.