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SPE-184851-MS Re-Designing from Scratch and Defending Offset Wells: Case Study of a Six-Well Bakken Zipper Project, McKenzie County, ND Peter Bommer and Marc Bayne, Abraxas Petroleum Corporation; Michael Mayerhofer and Mike Machovoe, Liberty Oilfield Services; Maciej Staron, PetraNova Engineering Corp. Copyright 2017, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 24-26 January 2017. 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 Completion optimization in unconventional wells has been an industry goal since the earliest stages of horizontal development. Motivated by the desire for higher financial returns and fueled by the rise of both technology and big data, optimization efforts have become de rigueur. This paper describes an optimization project in which a legacy Bakken completion design was set aside to make way for a "blank slate" analysis. Addressed in this context are the optimization research challenges faced by smaller operators in the play. The resulting re-designed completion was applied on a recent six-well zipper frac in east-central McKenzie County yielding a production increase of 13.5% with a cost reduction of 3.6% compared to legacy completions. On the same zipper project, an active well defense strategy on existing producers offsetting the six-well pad was also employed. With the increase in development density across the Bakken play, well interference associated with fracturing treatments is becoming increasingly common. While such well interference, known as "frac hits", can produce a variety of effects, including some that are beneficial, they are generally considered to be undesirable. Included in this paper is a discussion of the operator's frac hit experience and the results of the active well defense strategies applied in this project.

COMPLETION RE-DESIGN PROJECT Project Background A six-well group on a single pad in the North Fork Field, McKenzie County, ND was selected for implementation of a new frac design. The well group (referred to as the "Super6") is the latest of twentyeight producers drilled on the operator's North Fork field acreage since 2010. This acreage is located in the deep-center basinal region of the Bakken play (Fig 1), with the top of the Upper Bakken Shale averaging -8600 VSS or around 11,500’ TVD.

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Figure 1—North Fork Field / Super6 project location

The history and character of the Middle Bakken/Three Forks reservoir system has been detailed extensively in the literature (Wiley et al, 2004; Bessler et al, 2007; Mille et al 2008). The type log above (Fig 3) demonstrates average thickness of the various sections. Of the twenty-eight field wells, nineteen are completed in the Middle Bakken with nine in the underlying Three Forks. The Super6 group consisted of three wells in each reservoir.

Figure 2—Local structure map, top of Upper Bakken Shale

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Figure 3—North Fork type log

The earliest field wells went on production in November 2010. Since that time, a total of 3.59 MMBO and 7.68 BCF have been recovered. Fig.4 displays the production history for the total well group.

Figure 4—North Fork production history, Units J, R & S

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Well Configuration and Construction The subject acreage consists of three contiguous 1280 acre units (Units J, R, S) oriented in the northsouth direction (Fig. 5). All well development has followed the long axis of the units with typical lateral lengths of 9800’. The only exception to this was an early well that was terminated short of design due to a mechanical difficulty with the intermediate casing shoe. The well-spacing plan is 660’ between wells in the same interval.

Figure 5—Super6 well orientation

All wells were cased with 4 ½" liners set in 7" intermediate casing (Fig.6). All wells except the one with the casing problem, which was cemented, have been completed open-hole with swell packers for inter-stage isolation. Casing exit strategies have varied during the course of development from perf and plug to ballactuated sliding sleeves to the currently-employed hybrid. While perf and plug is the preferred method, toeward sleeves and dissolvable balls are currently being used to eliminate the need for deep drill-out. The specific stage/exit design for the Super6 was 41 total stages with 8 toe-ward sleeves and the rest perf and plug.

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Figure 6—Typical wellbore diagram

Diagnostic Formation Injection Test (DFIT) Analysis DFITs were performed at the toes of four of the Super6 wells (10H TF, 11H MB, 14H TF, and 15H MB). The main purpose of a DFIT is to estimate closure stress, reservoir pressure and formation flow capacity (kh). Since an existing producing pad (completed in 2014 and 2015) was directly offset to the east of the new pad, it was important to evaluate depletion effects from this pad. Well 15H is the closest new well to the producing pad (about 350 ft from a TF producer). The DFIT results for all four wells are summarized in Table 1. A key conclusion from these results is that well 15H is affected by depletion from the offset production, showing a reservoir pressure gradient of 0.34 psi/ft or 3,750 psi, which is about 50% of the original reservoir pressure. The other three wells do not seem to be affected by any significant depletion at this point with reservoir pressure gradients of 0.68 to 0.7 psi/ft. Closure stress gradient is also much lower in well 15H at 0.59 psi/ft versus 0.71 to 0.75 psi/ft in the other three wells. Reservoir permeability or formation flow capacity, kh is fairly similar in wells 11H, 14H and 15H (0.002 to 0.004 md). The western-most well 10H completed in the Three Forks had an order of magnitude higher reservoir permeability (0.06 md) than the other three wells. The reason for this is unclear but could be related to more abundant natural fractures at the toe of this well, where the DFIT was pumped. The leak off mechanisms are variable with a mix of fracture height recession (FHR), pressure-dependent leak off (PDL), and possibly fracture tip extension (FTE).

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Table 1—DFIT results

Re-Design Process In 2015, the operator chose to inventory completions awaiting improved economic conditions. During this period of relative inactivity, a detailed study of current fracturing techniques and results, primarily, but not exclusively, in the Williston Basin was initiated. The goal in this process was to create a more effective frac design starting from the ground up. The intent was to look at all significant strategies and technologies currently available without a bias toward the operator's legacy design. Below are the most significant strategies and technologies that were considered in this study:

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High-energy stimulation – use of larger quantities of fluid and sand, sometimes at higher injection rates. Average proppant concentration can increase or decrease in these designs depending on whether the emphasis is on increasing fluid volumes or proppant mass. The recommended design changes generally fit within this category. Slickwater stimulation – utilizes slickwater only, normally at high pump rates and very low average proppant concentration (< 1.0). This can be a very high-energy method but sacrifices any attempt to provide higher near wellbore conductivity. Higher proppant mass – increased proppant usage on a lbs/ft (ppf) basis has become very common in both conventional and high-energy designs. High concentration friction reducer (HCFR) – utilizes a viscosified FR system to replace crosslinked gel in slurries carrying higher proppant concentrations. This was selected as our primary fluid replacing cross-linked gel in the new design. Self-Suspending Proppant – this is a proppant coated with a polyacrylamide product that viscosifies with the addition of water. While this technology appears to have merit (Goldstein et al, 2015; Parham et al, 2016), the additional expense was not deemed justifiable at this point. Ceramic vs. white sand – the amount of ceramic was reduced in the new design compared with the legacy design, since area data indicated no substantial production uplift with ceramic proppants.

Optimization Research The explosion of available completion options combined with the availability of large amounts of associated production data has served to spur industry's optimization research efforts. At the same time, this large volume of information makes investigative research increasingly complex. Isolating variables in meaningful cause-effect relationships can become difficult as performance-related correlations frequently become clouds. Attempting to determine the importance of specific variables can at times be a daunting task in the face of the large number of factors that must be controlled to isolate results. Small operators face a particular challenge in this because of relatively small well opportunity sets. Larger operators are able to carve out experimental well groups to test a single variable that are often larger than the total undeveloped inventories of the small operator. The smaller company simply does not have the

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same ability to develop useful correlation statistics within the control of its own operations. This same limitation also affects the approach to monitoring technology. While options such as fiber optics, tracers, and microseismic are available to smaller companies just as they are to larger companies, their usefulness is limited in the small world because of the inability to develop statistically robust data sets. These limitations make public data mining critical to the optimization efforts of smaller operators. Data mining is a well-documented analytical technique (LaFollette et al, 2012) that allows access to information from statistically significant data sets generated from sources outside of the operator's direct experience that can be leveraged into completion design efforts. It is not as glamorous as the more extensive research projects that larger companies carry out but can still be quite effective, as demonstrated in this project. In data mining, the simplest approach is the development of bi-variate correlations between individual completion design variables, like total proppant usage, and production results. Fig. 7 shows an example of a bi-variate correlation panel for a particular data set typical of those generated in this project. The relationships between proppant and fluid usage versus results are often quite clear in these correlations, generally showing production uplift with increased material usage. Materials usage versus time plots are also utilized to identify current trends in the play. The correlations displayed in these panels show 1.) increasing proppant and fluid usage by one particular operator in the play over time, 2.) relatively few recent cemented completions, and 3.) possible uplift in production with increased fluid and proppant volume per lateral foot.

Figure 7—Bi-variate correlation panels

Multi-Variate Analysis While bi-variate correlations can be instructive, the interaction of multiple completion and reservoir parameters calls for a more rigorous statistical approach. A multi-variate statistical analysis, as described by Lolon (Lolon et al, 2016), was applied in this project to gain a clearer understanding of these interdependencies, augmenting our bi-variate results. The left-hand map of Fig. 8 shows all producing Bakken system horizontal wells while the right panel shows the subset of wells in area T149N-T151N R96W-R98W used for the multi-variate analysis. The statistical study was performed separately for 186 Middle Bakken wells and 138 Three Forks Wells. The results from the multiple linear regression model are summarized in Table 2. The R2 of 0.51 to 0.57 and

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RMSE (Root Mean Squared Error) of 2.38 bbls/ft of oil to 2.55 bbls/ft of oil (23% to 24% of mean oil production) are acceptable error bars for the multiple linear regression model.

Figure 8—Area of Interest (T149N-T151N R96W-R98W) Table 2—Statistical Analysis for AOI using Multiple Linear Regression Models

For both the Middle Bakken and Three Forks, four variables are dominant in determining the production response. Proppant mass per lateral foot, average proppant concentration, and pump rate are the most important completion parameters affecting production while stabilized 365-day water-cut is the most important indicator of reservoir quality. Proppant mass per lateral foot correlates positively meaning that higher lbs/ft will achieve better production in both formations. Average proppant concentration correlates negatively, which equates to treatments with larger water volumes performing better. Pump rate correlates positively meaning that higher rates can promote a better completion. All of these factors influenced the new Super6 design. Table 3 (Middle Bakken) and Table 4 (Three Forks) show sensitivities on how lbs/ft of proppant and average proppant concentration affect normalized 365-day oil production/ft, along with an estimated well and completion cost change to achieve that goal. In the sensitivities, one parameter is varied as the others

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are maintained at the mean. The combined effect when varying multiple parameters would be even larger. The green shaded rows are the mean for all operators in the area and yellow shaded rows are statistics for the operator of the subject project. In both the Middle Bakken and Three Forks increasing proppant mass from about 350 lbs/ft (operator mean) to 500 lbs/ft could increase oil production in one year by about 30% at an estimated 1.3 to 1.4% increase in well cost (based on cost of larger job sizes). Proppant mass had already been increased by the subject operator to 472 lbs/ft resulting in a 24% increase in one-year production in both formations compared to the mean of other operators in the AOI. Proppant loading was further increased by the operator to 800 lbs/ft in the well group preceding the Super6 (which wells were too recent to include in the multi-variate data set) and then to 880 lbs/ft in the Super6 design. In terms of average proppant concentration as a proxy for larger water treatments, the potential upside in one-year production is 17% in the Middle Bakken and 13% in the Three Forks. Table 3—Middle Bakken Completion Parameter Sensitivities

Table 4—Three Forks Completion Parameter Sensitivities

Design Changes As a result of these studies, several significant changes were made to the legacy design. Table 5 below contrasts the old and new designs.

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Table 5—Historical Design Comparisons

Both the bi-variate and multi-variate studies indicated that a higher energy treatment with a lower average proppant concentration would be beneficial. As such, we increased both total fluid usage and pump rate (30% in each case) and proppant usage (by 11%). The average proppant concentration decreased from 1.61 ppa to 1.25 ppa. While the overall average proppant concentration was decreased, higher concentrations (5.0 ppa) were still included at the end of the pump schedule to improve conductivity in the near-wellbore region. High concentration friction reducer (HCFR) was selected as the viscosifier for the higher ppa sections of the design replacing cross-linked guar gel. The use of HCFR is relatively new and therefore difficult to evaluate using public data but its successful use has been cited in the literature (Motiee et al, 2016). While it does not match cross-linked fluids in terms of absolute viscosity and proppant carrying capacity, its advantages are lower cost and potentially lower residual damage (ibid). While we felt there was an increased screen out risk associated with the use of this fluid, the cost benefits made the attempt worthwhile. One of the reasons for increasing the design pump rate was to help offset the lower carrying capacity of the HCFR. We also elected to divide our stages into three sand ramps deploying granular polylactic acid (PLA) as an inter-ramp diverter. While there is published evidence of diverter effectiveness in cemented applications (Evans et al, 2016), similar support was not found for its use in open hole environments. However, there was anecdotal evidence of open hole effectiveness and ultimately the decision was made that the low incremental cost of diverter use made experimentation acceptable. Fig 10 gives a comparison of the old and new pump schedules. Fig 11 shows typical treating plots for both designs.

Figure 10—Comparative pump schedules

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Figure 11—Comparative treating plots

Implementation of the New Design The new design was deployed on the Super6 zipper in graduated fashion. The first eight stages in each well were conservative in design using cross-linked fluid to carry the heaviest proppant concentrations in an un-diverted schedule. This was to avoid screen outs during the toe-ward sleeve stages where inability to flow back could necessitate a drill-out. Following the sleeves, we proceeded to implement diverted HCFR schedules, first in two-ramp and then in three-ramp designs. In some cases, particularly following screen outs, we reverted to conservative schedules but otherwise we pumped some form of the diverted HCFR design. The exception was in the 15H well nearest the legacy producers lying to the east. DFIT analysis had revealed depletion in this well and the stage design remained weighted toward cross-linked fluid. Screen-out Frequency Screen-out frequency increased in the Super6 wells compared to the legacy North Fork wells (Table 6). Of the twenty-four screen-out events on the Super6, ten were related to diverter activity. Fig 12 shows an event of this kind, with a dramatic reaction to the second diverter drop. Drops sizes ranged from as little as 2 lbs of diverter per drop to 12 lbs per drop and were usually tailored on the fly depending on treating conditions in the given stage. There was indication of diversion on a high percentage of the drops although the magnitude of the reaction was somewhat unpredictable. Table 6—Comparative screen-out statistics

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Figure 12—Diverter related screen out

There were also several late-stage screen-outs that appeared to be a reaction to high concentrations (4.0 to 5.0 ppa). We did not discern a clear relationship between these late-stage occurrences and fluid type in as much as they happened in both cross-linked fluid and HCFR systems. While screen-outs are generally undesirable, it was possible to continue operations on neighboring zipper wells while screen out remediation was performed minimizing downtime. So other than the cost of the additional gel required for post-flow back sweeps, there was little in the way of incremental costs associated with these events. Production and Economic Uplift The new design provided a 13.5% production uplift compared to the modern legacy averages (Table 7). Production results were evaluated using first 60-day metrics (the maximum available on the Super6 wells). The production graphs in Fig 13 compare the Super6 well group performance (green) to the North Fork legacy producers (blue) and a subset of the legacy wells representing more modern completion styles (red). The progressive uplift between the groups represents learning and improved execution, i.e. optimization. The production values plotted are normalized averages for each group. Table 7—Comparative performance metrics

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Figure 13—Comparative performance plots Table 8—Comparative costs

The averaging does not discriminate between Middle Bakken and Three Forks wells. Experience has shown that the two reservoirs perform similarly in this local area, with perhaps a slight bias toward Middle Bakken wells. In as much as the legacy well group averages are weighted toward the Middle Bakken (15 out of 22) versus the Super6 (3 and 3), the Super6 average may be slightly handicapped on a relative basis. The new design proved to be 3.6% less expensive than the legacy design. The relative costs are given in Table 8 above. These values represent an optimized design for each case, normalized on a per lateral foot basis. Economic cases comparing the Super6 results to the modern legacy average indicate an increase in full well rate of return from 53.8% to 75.6%. These economics were run at NYMEX strip pricing as of November 2, 2016. While the absolute RORs are sensitive to total capital, price deck, and other financial parameters, the relative ROR uplift (+/- 40%) is fairly consistent regardless of the economic model selected.

OFFSET WELL DEFENSE As full development mode was initiated on the subject units (660 ft between wells in the same zone), frac hits in wells that were in offsetting positions to active stimulation projects became more frequent. This interference was manifested in several ways including increased water production and the migration of solids into the offsetting wellbores. In several instances the solids migration was so severe that coiled tubing clean-outs were required to restore production in the affected wells. This restorative well work was costly. Fig 14 shows a production plot for a well in the North Fork R Unit hit by an offsetting frac along with photographic evidence of post-hit proppant production in a rod pump barrel. Note that post-frac production was almost non-existent until the wellbore was cleaned out with coiled tubing.

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Figure 14—Frac hit effects

While pre-hit production levels have been successfully restored in most cases, the costs of restoration are often quite high, sometimes exceeding $300,000 if coil clean-out was required. In order to reduce the financial impact of such hits, we went through several generations of passive defense where offsets were prepared in various ways prior to initiating frac operations. The first generation involved pulling downhole equipment and shutting the wells in at the wellhead. The next level attempted was to pull the wells and run bridge plugs in the top of the liners. Neither of these strategies proved to be particularly effective. On the Super6 project we decided to attempt a more active strategy. This strategy, involving two phases, was devised with the idea of resisting the incursion of fluids into the offset wells when pressure interference from the offsetting frac operations occurred. Instead of shutting the offsets in, pump trucks were used to pump into the offset producers as frac operations proceeded on the Super6. First, before the Supr6 frac job began, treated fresh water was pumped into the offsets in multiple stages with drops of multi-sieve PLA diverter between each stage. The idea was to temporarily plug off entry points into the wellbore in hopes of being able to hold positive pressure. The second phase of defense was to then pump into the offset wells continuously while the frac operations proceeded on the Super6, again with the intent of maintaining positive pressure. Based on our previous experiences, we decided to defend wells that were within 2000 ft of the nearest Supe6 well, which meant defending 3 wells. The rig up on these wells is shown in Fig 15. The setup was configured in such a way that both injection pressure and injection rate could be measured in each well. Pressure data were telemetered in real time to the Super6 frac van allowing our frac supervisor and the defense pump operator to coordinate the operation.

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Figure 15—Well defense equipment configuration

Pre-Frac Injection The initial pump-in results were mixed. Some minor diverter action was observed, but only with large (100 lbs to 200 lbs) diverter slugs. Pump-in pressures increased by 300 to 500 psi. Pumping large slugs of diverter proved to be problematic as diverter embedment in the valves of the pumps caused problems with pump priming at the low pump rates applied. Diverter also settled out in the discharge manifold of the blender causing problems with feed to the pumps. After leaving the wells shut in overnight, injection performance the next day had returned to the initial conditions of the day before indicating that the plugging effect achieved was not durable. While helpful in learning about the application of large PLA diverters, the first phase of this strategy did not appear to be meaningful as part of the overall defense strategy. Defensive Injection While Fracing The initial plan was to proceed with active defense in the offsets as the two Super6 wells closest to the offsets (S-14H and S-15H) were zippered. Once stimulation of those two wells was complete, we felt there would be an adequate pressure barrier created between the offsets and the more westward Super6 wells to allow the discontinuation of active defense. However, due to operational problems during the frac operations it became impractical to finish the S-14H and S-15H first, which meant that it was necessary to defend during a portion of the treatment of the more westward wells. Also, as the job progressed there was concern about the total amount of water being pumped into the defended wells. Since the S-3H and S-4H wells were already scheduled for coiled tubing clean-outs due to hits sustained during an earlier frac, it was decided to suspend continuous defense operations on those two wells. The S-2H on the other hand, had recently been cleaned out so the continuous defense of this well continued. The other two wells were monitored and only pumped into if a hit was detected. Frac Hits A total of 109 hits were detected during the pumping of the 246 stages of the Super6 pad. Three categories of hits were noted as listed below. Hits traveled as far as 1400 ft and occurred between wells of the same and opposite formations. 1. Super6-to-Super6 hits – 68 occurrences 2. Super6-to-Offset hits – 39 occurrences 3. Offset-to-Offset hits – 2 occurrences

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The panels below (Fig 16) show in cross-section the course of the various hits detected via pressure monitoring during the Super6 frac operation.

Figure 16—Cross-sectional Maps of Frac hits mapping

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Fig 17 is an example of the type of pressure evidence collected throughout the job. These plots display Super6 wellhead pressures in the upper half of the graph and defended well injection rate and wellhead pressure in the lower half. The first plot shows multiple cycles of communication between two Super6 wells, the blue well (fracing) and the purple well (shut-in). The lower plot shows communication between the green Super6 well and the red offset well. There is also indication of offset-to-offset well communication. Similar data were collected and analyzed during the course of pumping all 246 stages on the Super6.

Figure 17—Multi-well pressure-time plots showing observed frac hits

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Defense Results Post-frac production from the S-2H indicates that frac interference did occur. Total fluid production increased 33%, with water increasing and oil decreasing (Fig 18). However, the high post-hit productivity is indication of a clean wellbore. Furthermore, we have seen no indication of sand or other debris in the downhole equipment recovered from the well since the resumption of production. Note that both water and oil production rates had returned to near pre-frac levels at the time of this writing. While this is the normal production trend in wells that have been hit, the major improvement in this case is that a coil tubing cleanout was not required.

Figure 18—Offset well S-2H post frac production plot

Costs and Future Refinements As mentioned earlier, frac hit remediation costs in the past have been high. On one particular pad, six out of eight offset wells required extensive remediation to return them to pre-frac levels of productivity, at a cost of $340,000 per well. In contrast, total cost for the defense of the S-2H was $148,500, including pre- and post-frac rig time (Table 9). This equates to a 146% savings over the clean-out average. Table 9—Well defence costs

Potential defensive refinements on future pads include the following:



The pre-frac injection scheme was not helpful and should be eliminated.

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Identifying the highest risk offset wells through pressure monitoring early on in the process could help in determining when to begin defensive injection. This step could minimize the water load and improve post-frac recovery. Communication between personnel is important. We experienced some confusion from one shift to another that hindered consistency. In several instances communication problems delayed the initiation of defensive pumping when hits were detected.

CONCLUSIONS 1. A new completion design resulted in a 13.5% production uplift at a reduced cost yielding a full-well relative ROR increase of 40%. 2. Since multiple changes were made simultaneously in one design, it is not possible to discern the relative contributions of each change. This is an unavoidable reality when optimizing within an opportunity set too small to allow statistically meaningful experimentation with individual parameters. This means that absolute optimization is at best a theoretical notion for smaller operators. 3. The positive production results in this project show that significant improvement in completion results can be attained through the careful study of public data. 4. HCFR proved to be an effective fracturing fluid capable of carrying proppant loads as high as 5.0 ppa at a cost significantly lower than cross-linked guar gel. 5. Treating pressure data indicate that PLA granular diverter was highly effective in an open hole environment. 6. Active well defense during fracturing operations can be effective, not necessarily in eliminating pressure interference, but more in preventing solid materials from invading the wellbore. Post frac remediation costs were cut in half in this project.

References

Besler, M.R., Hohn Engineering, PLLC; Steele, J.W. and Egan, T., Nance Petroleum Corporation et al. 2007. Improving Well Productivity and Profitability in the Bakken-A Summary of Our Experiences Drilling, Stimulating, and Operating Horizontal Wells. Presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. SPE 110679. Evans, S., Holley, E., Dawson, K. et al. 2016. Eagle Ford Case History: Evaluation of Diversion Techniques to Increase Stimulation Effectiveness. Presented at the Unconventional Rescources Technology Conference, San Antonio, Texas, 1-3 August. URTeC:2459883.http://dx.doi.org/10.2118/10.15530--urtec-2016-2459883. Goldstein, B., and VanZeeland, A., Fairmount Santrol; 2015. Self-Suspending Proppant Transport Technology Increases Stimulated Reservoir Volume and Reduces Proppant Pack and Formation Damage. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 28-30 September. SPE-174867-MS. Lafollette, R.; Holcomb, W.D.; Arajon, J. 2012. Practical Data Mining: Analysis of Barnett Shale Production Results with Emphasis on Well Completion and Fracture Stimulation. Society of Petroleum Engineers. http:// dx.doi.org/10.2118/152531-MS. Lolon, E., Liberty Oilfield Services; Hamidieh, K., Rice University; Weijers, L. et al. 2016. Evaluating the Relationship Between Well Parameters and Production Using Multivariate Statistical Models: A Middle Bakken and Three Forks Case History. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 9-11 February. SPE-179171-MS. Mille, B., SPE; Paneitz, J., SPE, Whiting Petroleum; Mullen, M. et al. 2008. The Successful Application of a Compartmental Completion Technique Used to Isolate Multiple Hydraulic-Fracture Treatments in Horizontal Bakken Shale Wells in North Dakota. Presented at the 2008 SPE Annual Conference and Exhibition, Denver, Colorado, 21-14 September. SPE 116469. Motiee, M., Johnson, M., Ward, B. et al. 2016. High concentration Polyacrylamide-Based Friction Reducer Used as a Direct Substitute for Guar-Based Borate Crosslinked Fluid in Fracturing Operations. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 9-11 February. SPE-179154-MS.

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Parham, R., Engebretson, B., McKenzie, S. et al. 2016. Completions Evolution in Williston Basin Reduces Fluid and Chemical Intensity and Increases Production. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 9-11 February. SPE-179111-MS. Wiley, C., SPE, Lyco Energy Corporation; Barree, B., SPE, Barree & Assoc.; Eberhard, M., SPE et al. 2004. Improved Horizontal Well Stimulations in the Bakken Formation, Williston Basin, Montana. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 26-29 September. SPE 90697.

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