The Evlutin f Hydraulic Fracturing In the Bakken Petrleum System 1
Murex Petrleum Crpratin is Driven t Be a Leader in the Willistn Basin Privately held upstream il & gas cmpany perating primarily in the Willistn Basin f ND Engaged in Acquisitin, Develpment, and Operatin f il & gas prperties 38 th Largest privately held prducer in the U.S. (OGFJ100P) Drilled the 1 st ecnmic Middle Bakken well in the state f Nrth Dakta (Stacey Lynne 1-12H) Operate 2 f the 3 highest cumulative prductin Middle Bakken wells in Nrth Dakta (Chandler James 25-36H & Amber Renee 25-36H) Innvative cmpany with a passin fr prducing il and gas 2
The Recent Grwth in the Willistn Basin is Fueled By Bakken Develpment t January 2014 - Statewide prductin 933,992 BOPD June 2013 - Statewide prductin 821,415 BOPD 2011 - Nrth Dakta Overtakes Alaska as 2 nd highest il prducing state in U.S. 2008 - Average rig cunt 75, statewide prductin 171,989 BOPD 2004 Murex Petrleum Crpratin drills Stacey Lynne 1-12H 2000 - First hrizntal Bakken well drilled in Elm Culee Field 1987 - Beginning f hrizntal drilling in Upper Bakken Shale 1981 - First cmmercial vertical Bakken well at Elm Culee cmpleted 1955 - Amerada Petrleum Crp. drills first il prducing vertical well near Tiga, ND 1953 - J.W. Nrdquist first describes Bakken Frmatin n the Nessn Anticline 1927 - Oil discvered in Cedar Creek Anticline Mntana 3
Bakken Frmatin Parameters Reservir parameter Typical well value Reservir type Argillaceus carbnate Depth 7,000-11,000 Vertical thickness Shale 3-40 ; Middle member 30-70 Prsity 3-12% Water Saturatin 25-40% Permeability 0.06 md Oil gravity 45 API Pressure gradient Up t 0.75 psi/ft Original il in place (OOIP) 8-13 millin barrels per 1280 acre spacing unit Recvery factr 3-5% Recverable hydrcarbns 200,000-600,000 bbl and 200-700 MMCF Well spacing 640-1,280 acres (up t 8 wells/1280 currently) 4
Targeting Bth The Bakken And The Three Frks Frmatins Will Drive Future Grwth 1 st Bakken Shale Tp Base 1 st Bakken Shale Prsity Water Saturatin Permeability Pressure Gradient 3-12% 25-40% 0.06 md Up t 0.75 psi/ft 2 nd Bakken Shale Tp Three Frks Tp 2-15% 20-100% 0.01-0.19 md Up t 0.50 psi/ft Recverable reserves can be 200-600 MBO per well Birdbear Tp 5
Murex Petrleum Crpratin in the Bakken 6
Drilling Parameters Frm 5,000 dual ppsing lateral t 10,000 + single lateral Mud Prgram Surface hle fresh water (13.5 hle & 9-5/8 casing) Intermediate Hle & Curve OBM (8.75 hle & 7 casing) Lateral Brine (6 hle & 4.5 liner) Spud t Rig Release Oppsing lateral wells: +/- 50 days Single lateral wells in 2008: +/- 30 days Single lateral wells tday: +/- 15 days 7
First Well Design 5,000 Dual Oppsing Laterals 8
1 ST Generatin 10,000 + Single Lateral Design Sltted liner in lateral 9
Current well design - 10,000 + Single Lateral 4.5 liner with sliding sleeves in lateral 10
Evlutin f Murex Hydraulic Fracturing Hail Mary w/ perfrated liners 2004 2008 5,000 Oppsing Laterals 10,000 Single Laterals 1 stage N Cntrl n frac placement in lateral Plug & Perf/ Sliding Sleeve Hybrid 2008 2011 10,000 Single Lateral Multiple stages and targeted stimulatin Blast jints fr islatin between frac prts All Sliding Sleeves 2011 Present 10,000 Single Lateral Multiple stages and targeted stimulatin Blast jints fr islatin between frac prts in all x-link gel systems Packers fr islatin between frac prts in slickwater hybrid systems 11
Frac Size Increased as Technlgy Imprved Average Frac Stages Number per well Frac Sand Vlume Millin lbs per well Water Vlume Thusand bbls per well 40 35 236% 4.0 3.5 125% 80 70 288% 30 3.0 60 25 2.5 50 20 2.0 40 15 1.5 30 10 1.0 20 5 0.5 10 0 2008 2013 0.0 2008 2013 0 2008 2013 12
Hail Mary Design 13
Typical Prppant First Frac Design - Hail Mary 500,000 lb - 40/70 White Sand 2.5 ppg max cncentratin Fluid prperties Slickwater Typical Treating Pressure 9,000 psi Equipment Required 12-14 pump trucks Technlgy at the time Many thught fracs were lngitudinal t wellbre Multistage tls were nt readily available Why did we design the frac this way? Technlgy transfer frm shale gas plays 14
Prs and Cns f Hail Mary Design Prs Cns Quick pump time with minimal equipment N cntrl f frac lcatin in lateral Inexpensive Ineffective at treating entire lateral Fracs are nt lngitudinal t wellbre Lwer prductin than ther methds 15
Plug & Perf/ Sliding Sleeve Hybrid Design 16
Plug & Perf/Sliding Sleeves Hybrid Design 1st Generatin P&P/Sleeve Hybrid Cmpletin Sliding sleeves initially had 1/4 ball size increments Limited the number f stages t 10 in 4.5 liner Remaining stages required plug & perf 2nd Generatin P&P/Sleeve Hybrid Cmpletin Sliding sleeves initially had 1/8 ball size increments Limited the number f stages t 19 in 4.5 liner Remaining stages required plug & perf Plug & Perf Sectins Initially 5 plug & perf clusters per stage 1 length @ 6 spf Each cluster had similar spacing t frac prts Industry research shws that fewer plug & perf clusters are treated than initially thught 2-3 perf clusters per stage became ur standard in later generatin plug & perf jbs 17
Plug & Perf / Sliding Sleeve Hybrid Number f stages 10-19 sliding sleeves & 5-10 P&P stages with 5 per clusters per stage initially Prppant Details 4,000,000 lbs 40/70 & 20/40 white sand Occasinal use f 20/40 Resin Cated sand and 20/40 Ceramic Max cncentratin 6 ppg Fluid Prperties Zircnate x-link system Delayed x-link at lw ph Treating Pressures 6,000 psi Equipment Required 8-10 pump trucks, hydratin unit, blender, wireline equipment Technlgy at the time Limited by number f sleeve sizes Why did we design the frac this way?: Fracs were fund t be semi-transverse and mre stages were required t better stimulate the wellbre Mre stages equated t higher prductin Sleeves had results 10x better than Hail Mary 18
Prs and Cns f Plug & Perf / Sliding Sleeve Hybrid Design Prs Fewer pump trucks than Hail Mary Mre prppant being placed in reservir Mre stages being stimulated in lateral Mre successful than Hail Mary (Higher IP s and cumulative prductin) Cns Larger ftprint n lcatin Mre expensive Mre cmplicated designs Mre time cnsuming (Plug & Perf prtin adds significant time) Wireline risk 19
All Sliding Sleeves Current Design 20
All Sliding Sleeves Frac Design 1st Generatin All Sliding Sleeves Design Packers Plus RepeaterPORT design prvided duble the number f stages that 1/8 ball increment sleeves prvided Allwed fr mre than ne stage t be activated with the same size actuatin ball Murex Petrleum Crpratin was amng the first cmpanies t test RepeaterPORTs Multiple issues were encuntered with mechanics f RepeaterPORTs Likely issues were caused by sand accumulatin within the tl during hydraulic fracturing peratins Packers Plus went back t the drawing bard t reslve issues & design better tls 2nd Generatin Sliding Sleeve Cmpletin A sleeve system was created with 1/16 ball increments This allwed fr duble the stages f 1/8 ball increments with individually sized actuatin balls fr each sleeve Murex Petrleum Crpratin is currently utilizing this technlgy in ur frac designs Future f Sliding Sleeve Cmpletins New generatin f indexing sleeves will allw fr much greater number f stages Murex Petrleum Crpratin in the prcess f testing these prts n current frac jbs 21
Sliding Sleeves: Initial Frac Design Number f stages 37 Prppant Details 3,000,000 lbs 40/70 White Sand & 20/40 White Sand Occasinal use f 20/40 ceramic Max cncentratin 5 ppg Fluid type/cncentratins All gel system Delayed x-link zircnate (lw ph system) 20-22 ppg gel cncentratin Treating Pressures 5,000 6,000 psi Equipment Required 6-10 pump trucks, hydratin unit, blender, chemical trucks Technlgy at the time Currently an industry debate n Plug & Perf vs. Sliding Sleeve Why did we design the frac this way? X-link gel carries sand easily & reduces risk f screenuts Cntinuus pump time lends t a mre ecnmically viable frac jb There des nt appear t be a difference in frac perfrmance with plug & perf vs sliding sleeve designs Histrically had mre mechanical success with sliding sleeves than plug and perf jbs 22
Sliding Sleeves: Current Frac Design Number f stages 37 Prppant Details 3,000,000 lbs 40/70 White Sand & 20/40 White Sand Occasinal use f 20/40 ceramic Max cncentratin 5 ppg Fluid type/cncentratins Slickwater in lwer sand cncentratin prtin f stage (0.5 ppg 1.5 ppg) Delayed x-link zircnate system in higher sand cncentratin prtin f stage (2.0 ppg t 5.0 ppg) Treating Pressures 5,000 6,000 psi Equipment Required 6-10 pump trucks, hydratin unit, blender, chemical trucks Technlgy at the time Multiple peratrs in Willistn Basin are experimenting with slickwater hybrid fracs Currently an industry debate n Plug & Perf vs. Sliding Sleeve Why d we design the fracs this way? Slickwater hybrid jbs crrelate t higher prductin Slickwater hybrid jbs are less expensive than all gel jbs Cntinuus pump time lends t a mre ecnmically viable frac jb There des nt appear t be a difference in frac perfrmance with plug & perf vs sliding sleeve designs Histrically had mre mechanical success with sliding sleeves than plug and perf jbs 23
Prs and Cns f All Sliding Sleeves Design Prs Mre stages being treated in lateral Cntinuus pumping time (time savings) Eliminates need fr wireline (lwer risk prfile) Cns Ptential fr mechanical failures f sleeves If a failure ccurs, sleeves must be drilled ut Less expensive than all Plug & Perf 24
Bigger is better? Mving Frward Mst f Willistn Basin Bakken wells perfrm better with larger fracs Our research shws that the main factr in frac perfrmance is jb size Psitive straight line crrelatin Greater number f sleeves = greater number f transverse fracs Greater vlumes = better frac parameters (half length, prpped width) Technlgy is rapidly evlving and sliding sleeve systems are becming readily available that wuld allw a greater number f frac sleeves (100+) In sme areas f Willistn Basin, bigger is nt better Divide Cunty Three Frks verlays water prductin Large fracs will reach int water zne Lwer Bakken Shale lses thickness Frac islatin frm belw may be cmprmised May frac int water zne beneath Bakken & 3 Frks Refracs f first generatin Bakken wells n the hrizn Our frac jbs are cnstantly evlving and imprving frm well t well 25
26