Remedial Efforts for Fracture Treatment in Horizontal Laterals Robert Reyes, Halliburton

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1 Remedial Efforts for racture Treatment in Horizontal Laterals Robert Reyes, Halliburton Introduction s oil and gas well fracture stimulation has progressed, multiple novel technologies have been developed to keep pace. With the onset of horizontal lateral drilling and completion work, this trend has been magnified even more. It has been reported that 5 to 1, T of recoverable gas reserves have been added by North merica Shale plays alone. In 19 geographical basins, an estimated 35, horizontal wells have been drilled and completed using multistage fracturing techniques. Proved reserves of U.S. oil and natural gas in 1 rose by the highest amounts ever recorded since the U.S. Energy Information dministration (EI) began publishing proved reserves estimates in n important factor for both oil and gas was the expanding application of horizontal drilling and hydraulic fracturing in resource shales and other "tight" (very low permeability) formations. The same technologies that first spurred substantial gains in natural gas proved reserves have more recently expanded into similar oil producing formations. Helping to drive proved reserves increases in 1 were also higher prices used to assess economic viability relative to the prices used for the 9 reporting year, particularly for oil. (EI U.S. Energy Information dministration, ugust 1) racture stimulation methods have evolved significantly from the high rate (1 to 1+ bbl/min) true limited entry design that used perforation techniques in an attempt to fracture treat from the heal to toe with a one-time pump-in stage. Many of these applications were where as much as a mile of lateral was treated in one or two hours in a single operation. On most of these jobs, when a postfrac survey was performed, a large percentage of the lateral would show little or no stimulation, with the toe section most often untreated. This led well operators to seek better completion plans, and new completion and stimulation tools designed to implement such changes. The first major change was to subdivide the wellbore and use the same limited entry perforating technique on shorter sections, with the industry designing new staging plug designs that allowed them to be pumped down the lateral to the desired position and wireline set. Soon, this type of plug would also drag down a multi-shot perf gun in the same operation, and by about -3 we had the perf and plug process in use. New completion designs emerged that required lower injection rates, typically 5-9 bbl/min, depending on the number of dividing stages that were selected or the number of perforated intervals per stage. Thus, staged fracturing completions began to be the dominant method as resource shale completions became more common. This perf and plug method reduced horsepower costs while providing each fractured compartment a better chance to be effectively treated. The savings in horsepower was initially a trade off with the amount of increased time spent performing the stage frac 1

2 treatment, but going back to non-staged completions was not considered an economic option. With decreased total completion time becoming a critical issue for improving economics further, pumping service companies began to address how the stage fracture treatment could be as efficient as the compartmental lower rate plug and perf method yet significantly reduce the stimulation timeframe. The next major solution was sliding sleeves activated by ball drop mechanics. This approach increased the hardware costs of completion, but offered economic benefits of reduced stimulation times y installing the lateral sliding sleeves with a baffle (increasing in opening size as the position approached the heel) each stage would now end by dropping a specifically sized ball from the surface to land on the baffle and slide the sleeve into an open position. Now, instead of shutting down to pump a plug and perforate, the time between stages was reduced significantly. Operators were again able to fracture an entire wellbore lateral (1 to stages) in a day, possibly even allowing for flowback. However, just as plug and perf operations often encounter malfunctions that add costs, so might the ball activated sliding sleeve completion. They may be caused by human error of action or judgment, mechanical failure, or by unforeseen quirks of nature. With respect to premature sticking of plugs or failed perf guns, recovering from these failures is usually possible, with added time and costs for the recovery operations, but seldom with very much loss of producing zones. However, when a failure occurs with a ball activated sliding sleeve assembly in place, the degree of problem may be as small as losing a single pay interval to an issue such as in the case of 1 or more completion stages with sliding sleeves in the lateral and unable to open any of the sliding sleeve ports. Such a case could possibly be solved by milling out all the ball seats and then attempting to revert back to the application of plug and perf technique, requiring possibly a week or longer to recover the wellbore and to pump a perf and plug stimulation. This paper discusses a novel technique detailing a west Texas case history where a service company was asked to recover a well in which all sliding sleeves completion tools were in failure mode. It was decided to open up all zones and use a new product to effectively treat all stages in one pumping treatment. This technique is called diversion frac for proppant distribution. The method is engineered to improve the efficiency of completion techniques; consequently, production increases should be observed. The procedure involves providing all reservoir access points an opportunity to receive fracture stimulation treatment. The access points are the perforations, completion sliding sleeve tools, hydraulic sleeves, hydrojetted holes, open hole, etc., which are the fracture initiation points. y staged dropping of a biodegradable material, which exists in a range of mesh sizes, a previously treated zone is bridged and diverted, sending the trailing fracture treatment stage into the next access point, which should be the next untreated zone least resistant to taking fluid. is saved when the drop is made, and the previously treated zone is diverted, redirecting the treatment fluid that follows to break down the next zone. This process occurs in the same time frame in which crews operating the old plug

3 and perforate method would be shutting down to get ready for wireline runs to set a plug and perforate the next zone, which could take two hours per stage on an average well. ackground: Plug and Perforate Method The plug and perforate completion technique has been the primary process for stage frac completions for most of the past decade. The well completion type most commonly applied has been be a cemented liner or casing, or, less often, an openhole liner using casing external packers to partition the annulus into zones, and includes pumping down plugs and perforating guns in horizontal applications. The application consists of gaining entry to the formation by perforating the farthest interval or the toe section and then breaking down the formation and pumping the first fracture treatment into this zone. fter a large flush stage to wash residual proppant from the wellbore and then shutting down, isolation is achieved from the just-treated zone by placing a pump-down mechanical plug above it. Then, the process repeats as the next zone to be treated is perforated (typically to 7 perf clusters), the gun is retrieved and then the interval is broken down and fracture stimulated. This procedure continues until the last planned zone is treated and flushed. In North merica, the plug and perforate process is being used in about 5% of today s horizontal well completions (Halliburton 1). Efficiencies can be improved by combining multiple perforating runs (i.e., multiple stages) into one and a significant amount of time can be saved by using diversion frac for proppant distribution in between these sub-stages. With an hour or two as a baseline to perform wireline runs, running three sub-stages in one run saves two to four hours per treatment. pplications of Diversion rac for Proppant Distribution The service operator s special biodegradable diverting agents provide temporary temperature- or timebased fluid-loss control (i.e., temporary perf sealing) in the near-wellbore region (NW) of the perforations and the fracture of new zones accepting fluid after the diverter arrives. Diverting agents of this type have been used to divert in perforation tunnels, near-field fractures, slotted liners, and open hole zones to redirect the fracturing treatment fluid to non-treated zones (zones that accepted little or no fluid previous to diverter placement). Treatment fluids used to-date include frac gel, acid, scale treatment, and well-control treatments. The treatment can either be placed in aqueous fluid between applications or bullheaded before an application, such as with split casing where one is attempting to divert away from a trouble zone. Volumes required depend on the geometry of where diversion is desired. Reservoir or treating pressure will not affect biodegradable diverters. dvantages of the biodegradable diversion material include reducing treatment time, distributing treatment fluid more efficiently, eliminating the need to drill out plugs, compatibility with many fracturing fluids, and degradation over time. Proper prejob planning with attention to equipment preparations and rig up are keys to successful usage of the Diverter rac (Halliburton 1) for proper pumping. Diverter Delivery and Diversion Using a method to alter flow distribution is called diversion. Its purpose is to divert the flow of fluid from one portion of an interval to another. The diversion method best suited for a particular situation depends on many factors, including but not limited to the type of 3

4 well completion, perforation density, the type of fluid that is produced or injected after the diversion treatment, casing and cement sheath integrity, bottomhole temperature, and bottomhole pressure available as flow-back energy (Reyes et al. 11). In this paper, particle bridging is achieved with a product that is multi-sized, biodegradable, and temporary. Two specific size distributions exist. The action of the smaller particles will nest in the pore throats of the coarse-sized particles and create a seal to fluid flow. characteristic of particle bridging is that it is independent of the size or geometry of the perforation or void space. The variable mesh will accumulate and divert fluid flow. t the designed temperature, the material will soften, helping achieve a seal that is more restrictive to flow, which creates backpressure against any fluid that attempts to flow into a diverted channel; this allows higher pressure in the wellbore that may be needed to initiate flow in a new zone. Once the material is pumped into the perforation or fracture, it will later degrade based on temperature and/or time. The Material form of this agent is effective in wells with a bottomhole static temperature (HST) of 1 to 3. Refer to ig. 1 for the degradation of Material. or wells with lower HSTs, Material is effective in as low as 1 and up to 5 (see ig. for details). or cooler wells, because the degradation takes time to occur, depending on pumping time, it can be acceptable to use diversion frac for proppant distribution, but laboratory testing must confirm the candidate well. ase History was such a well, with HST of only 17 O. Degradation of these materials is based on the dissolution of the materials in water or other brine solutions. or typical well flowback, 1% dissolution is not required. ield experience has indicated that as little as % degradation would result in non-restrictive flowback and clean up times would not be impacted. ase History Wellbore The case history discussed here derives from a horizontal west Texas well in Ward ounty. The well is cased with 7-in. ppf casing to,1 ft, then a.5-in. liner 11. ppf is hung at 7,51 to 1,353 ft. True vertical depth (TVD) is,1 ft. Drilled in the Devonian formation, perforations are at 1,13, 11,9, 11,5, 11,15, 1,73, 1,53, 9,99, 9,33, 9,3,,97,,55, and,3 ft shot with 1 shots per foot. Pore pressure is 3,9 psi with 17 HST. In the original completion sliding sleeves were run as a part of the liner, and the sleeves would not open, causing a job failure. The ball-seat baffles had to be drilled out to allow perforating. Using the diversion frac for proppant distribution material, it was decided to perforate the above depths and have the horizontal lateral 1% open in all zones planned to frac. The fracture treatment design would incorporate diversion to place the proppant treatment into all zones in one large pump-in stage. Tables 1 through 3 present the details for the tubulars, perforations, and lithology of the Ward ounty well.

5 Design It was decided to pump a guar-based crosslinked fluid ( prepared from 15 cp base gel) carrying 1,, 3, and lbm/gal brown /-mesh sand in five separate stages. fter each flush, the plan was to drop lbm of 1-mesh sand with lbm of the diversion frac for proppant distribution material such that it equates to lbm/gal concentration for the diverter combinations based on the volume in which they were mixed. s there were five proppant frac stages planned, diversion material was dropped after Stages 1 through. fter Stage 5, only a flush was to be used. ctual The fracture treatment used the following volumes: 7, gal of linear 15cp fluid used for flushes and to place diverting material downhole; 75,3 gal of crosslinked gel used in pad stages and 9, gal of crosslinked gel used to carry 319, lbm of /-mesh brown sand at 1,, 3, and lbm/gal concentrations; and 5,9 gal of crosslinked gel to carry the diverters at a lbm/gal concentration. Note: ll crosslinked gel was prepared using the 15 cp linear gel. igs. 3 through illustrate diversion effects. Stage 1 (not shown) pumped 7,33 lbm of proppant, and Stage was commenced (ig. 3). Stage first dropped diverter at 11:3 min on the surface and then arrived at the calculated bottom interval at 11:3 min, which corresponds to a -psi increase in pressure in between these two times as diverter approaches an uphole open perforation; operations proceeded to frac, as designed. total of 13,3 lbm of proppant was pumped in Stage. In front of Stage 3 was the second diverter drop (ig. ). Diverter was dropped at 13: on the surface and at 1:11 on the calculated bottom interval, with a -psi increase in pressure at 13:5. Operations proceeded to frac Stage 3. Sand-laden fluid was pumped (not as designed, due to high pressures) at.5 and 1 lbm/gal. total of 3,91 lbm of proppant was pumped. Prior to Stage was the third diverter drop (ig. 5). Diverter was dropped at 15:5 on the surface and at 1:1 on the calculated bottom interval, with a 3-psi increase in pressure at 1:1; operations proceeded to frac Stage. Sand-laden fluid was pumped (not as designed due to pressure rise) from.5, 1,, and 3 lbm/gal. The operator did not attempt to pump the lbm/gal concentration. total of 115,91 lbm of proppant was pumped in Stage. Preceding Stage 5 was the fourth diverter drop (ig. ). Diverter was dropped at 17:5 on the surface and at 1:17 on the calculated bottom interval, with elevated pressures. Pumping sand-laden fluid was not attempted because of maximum pressure, and the job proceeded to the flush stage. 5

6 onclusions for ase History This work discusses a case history from a horizontal west Texas well in Ward ounty involving diversion frac for proppant distribution. The project was initiated with a troubled horizontal wellbore with an economic burden. Having not been stimulated, any treatment seemed costly, as completion tools that had previously failed had to be altered before the operator believed a fracture treatment could be attempted. pumping service company engineered a remedial design stimulation program involving pre-perforating of 1 zones and using a diversion frac for proppant distribution, which was pumped with excellent results. oth the service company and the operator were satisfied with the results, but production numbers have not yet been released at the request of the well operator. The,-ft lateral and 1 perforations encompassing many stages of shale pay were effectively stage fracture treated in approximately 1 hours. This pump-in included 319, lbm of /-mesh brown proppant and 35,939 gal of fracturing fluid with additives and breakers set to create a significant stimulated reservoir volume (SRV), providing the well a very good chance for economic production. ase History: Well The second case history is in Ward ounty, TX where the customer had experienced a troublesome drilling experience and resulted in over-budget costs to drill and breach in liners of two wells. reach in liners was due to dogleg severity at magnitudes of 1% at multiple points after drilling had gone 9 Degrees. Questionable liner threads had apparently failed as liner was lowered into wellbore and a breach occurred. With expensive remediable work foreseeable, the option presented itself to cut losses and move off wells and plug or abandon lateral and move for uphole production. The well operator sought for a new solution. Diversion rac for Proppant Distribution PD was the well operator s chosen option, designed to first seal the beach, then to stage fracture the horizontal below the damaged liner. This would accomplish a few things. irst, this breach repair was relatively inexpensive, unlike scab liners or alternative repairs. Second, it would allow the operator to stimulate and produce from a well that ran overbudget and was possibly going to be a total loss otherwise. The third value point was the internal diameter would be undisturbed, whereas costly patches could limit internal diameter making perforation runs more complex. The fourth advantage is the Proppant Distribution PD stimulation would offer the operator some potential to pay expenses of the costly aborted drilling program. The breach was sealed by pumping Diversion rac for Proppant Distribution PD to prepare the wellbore for a fracture stimulation. The design was to pump three stages with a diversion material and evaluate using surface pressure after each drop of diverter to determine if the next diverter drop was necessary. irst drop was 5 lbm of iodegradable Diverter at.5 lbm/gal in xanthan gel. Note pump schedule in Table :

7 second more aggressive diverter schedule was pumped next (Table 5): fter the first diverter hit, surface pressure showed 5 psi to 3 psi increase was observed. fter the second diverter stage hit, surface pressure showed 595 psi to 3 psi was observed. This was good news and it was decided that Diversion rac for Proppant Distribution PD had achieved objectives and it was decided to schedule and rig up fracture crew and move forward with stimulation. Diversion hart is below, see igure 7. The fracturing equipment was rigged up and the compartment stages below the sealed breach were fracture stimulated. To reduce exposing the perforation and plug runs through the breeched region of wellbore, it was decided to redesign the fracture design from one stage at a time and combine three stages into one pump-in operation. ombining fracture stages into one pumping operation is achieved by using Distribution rac for Proppant Distribution PD. This allows the operation to eliminate top plugs that would normally isolate the previously fracture stage. io Degradable material, (Material ) is used to screenout and seal the previously pumped fractured area allowing operations to then proceed to next fracture treatment into subsequent zone. The material will degrade with time after the fracture stimulation is complete. On this particular well three stages were pumped with two Proppant Distribution PD drops made. onclusion: The liner breech was sealed with the biodegradable material and fracture treatment was resumed using a one pump in operation from below the repair to the toe. This combined three stage in one and used this same biodegradable material as a bridge to isolate the previously fracture stimulated zone. This allowed a troubled well to produce without the expense of a costly well bore remedial repair. ase History The third well was again in Ward ounty, TX. It was a Devonian ormation horizontal well completion. production liner was set at 75 ft and ran to depth of 1511 ft. tieback liner was run to surface. oth liners were.5 inch, 11. lb/ft, P-11 grade. Intervals were as such, see Table below. The stage completion tools had failed and opening the sleeves was not an option. It was decided to drill out the baffles so it would be possible to perforate for all zones below the Woodford, from toe section to the heal portions of the lateral and use Diversion rac for Proppant Distribution PD to divert between stages, fracturing all zones in one pumping operation. The Woodford zone near the heel was not perforated and would not be treated until later. or this operation, the material would divert the zone that accepted the previous treatment stage and open up the next least-resistive zone to break it down. The next treatment stage would go into this newly broken down zone. This process would be repeated up to 11 times until all zones were treated. Table 7 shows a treatment schedule for one zone. Pumping treatment stages 1 1 (skipping stages in between). Drop 1lbs of Material in 1 gallons. Repeat after 11 stages, then shut down and prepare well for wireline. Do not drop Material on 1 th or last pump in. 7

8 onclusion for Well Inheriting the wellbore with 1% completion tool failure and a complex and expensive plan to overcome the situation, remedial efforts went with the biodegradable diverter which allowed the service company to stimulate all stages without costing the well operator the expense of reverting back to plug and perforating methodology. It was observed that all zones were believed to be treated and all 1 stages were completed in one day. This saved days in completion time and allowed operator to flowback well days ahead of schedule. Treatment harts are below with proppant mass pumped. See following charts which all indicate diversion. References EI U.S. Energy Information dministration, ugust 1. Halliburton. 1. ccessrac PD. 1. Technology ulletin SM-1--X, /3/1. Reyes, R. Glasbergen, G., Yeager, V., and Parrish, J. 11. DTS Sensing: n Emerging Technology Offers luid Placement for cid. Paper SPE 1555 presented at the SPE nnual Technical onference and Exhibition, Denver, olorado, US, 3 October November. igures and harts ig. 1 Material (1 lb/gal) degradation testing at 1.

9 ig. Material degradation at 1. TLE 1 TUULRS Name Measured Depth (ft) Outer Diameter (in.) Inner Diameter (in.) Linear Weight (lbm/ft) Grade Production casing to,1 7.7 P-11 Open hole 7,51 to 9,71.15 Production liner 7,51 to 1, P-11 TLE PERORTIONS Interval Name/ Depth (ft) No. of Perfs TVD (ft) Stg 1 perforation interval/ 1,13 to 1,1 1,3 Stg perforation interval/ 11,9 to 11,91 1,1 Stg 3 perforation interval/ 11,5 to 11,57 1,7 Stg perforation interval/ 11,15 to 11,1 1, Stg 5 perforation interval/ 1,73 to 1,7 1,99 Stg perforation interval/ 1,53 to 1,5 1,11 Stg 7 perforation interval/ 9,99 to 9,99 1,119 Stg perforation interval/ 9,33 to 9,3 1,15 Stg 9 perforation interval/ 9,3 to 9,37 1,13 Stg 1 perforation interval/,97 to,9 1,13 Stg 11 perforation interval/,55 to,5 1,1 Stg 1 perforation interval/,3 to,35 1,1 TLE 3 LITHOLOGY Treatment/Depth (ft) Pore Press. (psig) HST ( ) rac. Grad. (psi/ft) DEVONIN/,3 to 1,

10 ig. 3 Pumping of Diverter following Stage 1 and pumping of Stage. ig. Diverter after Stage and pumping of Stage 3. 1

11 ig. 5 Diverter after Stage 3 and pumping of Stage. ig. Diverter after Stage did not allow pumping of Stage 5 proppant. 11

12 Table - asing (Surface) Trt-Stage Stage Desc. low Path luid Desc. iovert NW, Rate-Liq+Prop lean Vol. lbm 1-1 reakdown IN R Water reakdown IN Xanthan gel Diverter IN Xanthan gel lush IN Xanthan gel lush IN R Water Totals 1195 Table 5 - asing (Surface) Trt-Stage Stage Desc. low Path luid Desc. iovert NW, Rate-Liq+Prop lean Vol. lbm -1 reakdown IN R Water reakdown IN Xanthan gel Diverter IN Xanthan gel lush IN Xanthan gel lush IN R Water Totals 1195 hart ig. 7 Treatment chart using two diverter stages to seal breech in liner. 1

13 ig.. racture treatment chart after breech in liner sealed. Pumped three fracture stages without shutting down nor running plugs. Perforated all zones and used iovert Table Stage No., Interval Name/ Depth (ft) Stage 1 - Rapid Stage Initiator Sleeve / Stage - Devonian / Stage 3 - Devonian / Stage - Devonian / Stage 5 - Devonian / Stage - Devonian / Stage 7 - Devonian / Stage - Devonian / (skip this stage) Stage 9 - Devonian / (skip this stage) Stage 1 - Devonian / 1-1 Stage 11 - Devonian / Stage 1 - Devonian / Stage 13 - Devonian / Stage 1 - Devonian / (sleeve open, taking fluid) Stage 15 - Devonian / Stage 1 - Devonian / (skip this stage) Stage 17 - Devonian / (skip this stage) Stage 1 - Devonian / (sleeve open not taking fluid) Stage 19 - Devonian / Stage - Devonian / 9-9 Stage 1 - Devonian / Stage - Woodford /

14 Table 7 Example Stage Program Trt- Stage Stage Desc. low Path luid Desc. Rate- Liq+Prop lean Vol. Proppant Proppant onc. Prop. Mass 1-1 reakdown IN R- Water Diverter IN Material Spacer IN R- Water cid IN 15% erchek S I cid (.3%) Pre-Pad IN R- Water Pad IN R- Water Proppant IN R- Water 5 11 ommon White Laden luid Mesh, SS- 1- Proppant IN R- Water 5 11 ommon White-1. Laden luid Mesh, SS- 1-9 Proppant IN R- Water 5 11 ommon White-1. Laden luid Mesh, SS- 1-1 Proppant IN R- Water 5 11 ommon White Laden luid Mesh, SS Proppant IN R- Water 5 11 ommon White-1. Laden luid Mesh, SS- 1-1 Pre-Pad IN R- Water Pad IN Water rac PS PPT 1-1 Proppant IN Water rac PS 3 5 Premium White-.5 1 Laden luid PPT / Proppant IN Water rac PS 3 5 Premium White- 1 Laden luid PPT /7 1-1 Proppant IN Water rac PS 3 5 Premium White Laden luid PPT / Proppant IN Water rac PS 3 5 Premium White- Laden luid PPT /7 1-1 lush IN R- Water Diverter IN Material lush IN R- Water 5 9 Totals Slurry Proppant onc (lb/gal) Treatment lean Volume (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) :3 13: 13:3 1: 1:3 15: 9/19/1 15:3 9/19/1 ig. 9 - Stage 1: 1,51 lbm of 1 mesh and 9,71 lbm of /7 premium proppant. 1

15 5 1 1 Slurry Proppant onc (lb/gal) Treatment lean Volume (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) : 1: 1: 17: 17: 17: 1: 9/19/1 1: 9/19/1 ig. 1 - Stage : 1,9 lbm of 1 mesh and 97,7 lbm of /7 premium proppant. 1 Slurry Proppant onc (lb/gal) Job lean Vol (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) : 19: : : : 1: 9/19/1 1: 9/19/1 ig Stage 3:,7 lbm of 1 mesh and 11,3 lbm of /7 premium proppant. 15

16 5 1 1 Slurry Proppant onc (lb/gal) Treatment lean Volume (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) : : 3: 3: 3: 9/19/1 13 Global Event Log Intersection ISIP 9//1 :3:9 TP 771 SR. JV 5 : 9//1 : 9//1 ig. 1 - Stage : 19,11 lbm of 1 mesh and 13,33 lbm of /7 premium proppant Slurry Proppant onc (lb/gal) Treatment lean Volume (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) : 1: 1: : : : 9//1 Global Event Log Intersection TP SR JV 1 ISIP 3::5.15 3: 9//1 ig Stage 5: 17,9 lbm of 1 mesh and 1,19 lbm of /7 premium proppant. 1

17 5 1 1 Slurry Proppant onc (lb/gal) Treatment lean Volume (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) : : : : 5: 5: 9//1 Global Event Log Intersection TP SR JV 15 ISIP 5:3: : 9//1 ig. 1- Stage :,13 lbm of 1 mesh and 9,91 lbm of /7 premium proppant Slurry Rate (bpm) Slurry Proppant onc (lb/gal) H Proppant onc (lb/gal) Job lean Vol (bbl) Treatment lean Volume (bbl) :3 7: 7:3 : :3 9: 9//1 9//1 Global Event Log verage TP SR JV verage TP SR JV 1 Start pumping Diverter :31: ISIP :: 3. ig Stage 7: 7,53 lbm of 1 mesh and,13 lbm of /7 premium proppant. 17

18 7 1 1 Slurry Rate (bpm) Slurry Proppant onc (lb/gal) H Proppant onc (lb/gal) Job lean Vol (bbl) Treatment lean Volume (bbl) : 1: 1: 1: 11: 11: 11: 9//1 9//1 Global Event Log Intersection TP SR JV Intersection TP SR JV 1 Start Stage 9:5: ISIP 11:: ig. 1 - Stage : 1,71 lbm of 1 mesh and 5,1 lbm of /7 premium proppant Slurry Proppant onc (lb/gal) Job lean Vol (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) Treatment lean Volume (bbl) : 13: 13: 13: 1: 1: 9//1 1: 9//1 Global Event Log Intersection TP SR JV Intersection TP SR JV egin Stage 9 1:33: reak ormation 13:9: ISIP 1:5: ig Stage 9: 1, lbm of 1 mesh and 9,5 lbm of /7 premium proppant. 1

19 9 1 1 Slurry Proppant onc (lb/gal) Job lean Vol (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) ackside Pressure (psi) : 1: 1: 1: 17: 17: 17: 9//1 Global Event Log Intersection TP SR JV Intersection TP SR JV 3 Start Stage 1 15:37: Start Gel 15:5: End Gel 15:57: Start Gel 17:: End Gel 1:: ISIP 1:5: : 9//1 ig. 1 - Stage 1:,7 lbm of 1 mesh and,9 lbm of /7 premium proppant Slurry Proppant onc (lb/gal) Job lean Vol (bbl) 3 Slurry Rate (bpm) H Proppant onc (lb/gal) ackside Pressure (psi) : : : : 1: 9//1 1: 9//1 Global Event Log Intersection TP SR JV Intersection TP SR JV 3 Start Pumping 19:: Stop Pumping 1:33: ISIP 1:33: ig Stage 11: 1,75 lbm of 1 mesh and 1,99 lbm of /7 premium proppant. 19

20 7 1 1 Slurry Proppant onc (lb/gal) Job lean Vol (bbl) Slurry Rate (bpm) H Proppant onc (lb/gal) ackside Pressure (psi) : 3: 3: 9//1 : : : 9/1/1 1: 9/1/1 Global Event Log Intersection TP SR JV Intersection TP SR JV Stop Pumping 9/1/1 1:: ISIP 9/1/1 1:: ig. - Stage 1:,9 lbm of 1 mesh and 19,5 lbm of /7 premium proppant.