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WELL 4309 / ion ispas

ion ispas

ion ispas


Course: Well Completions
Term: Spring 2017
Cost: 25
Name: Hydraulic Fracturing Notes
Description: Hydraulic Fracturing Notes-Final Exam
Uploaded: 05/09/2017
317 Pages 208 Views 0 Unlocks

• What is the damage?

• How do you treat the other zones?

path, where will most of the acid go?

PETR 4309 Well Completions and Stimulation Ion Ispas, PhD Petroleum Engineering  Texas Tech University Spring 2017Stimulation Treatments - Propped vs Acid  Fracturing 2Matrix vs. Fracture Acidizing 3Why Acidizing? - Objectives & Applications • Well stimulation - improve intrinsic formation permeability • Cleanup - formation damage removal • Increase well productivity - carbonate and sandstones (much larger expected in the  carbonates) • In carbonate formations, HCL etches resulting in enlarged boreholes or wormholes into  the formation, bypassing damage • If no damage present don’t use large volumes of acid for a small productivity increase • There is risk of secondary and byproduct reaction from acidizing which must be controlled  to prevent potentially damaging precipitation. • Effective acidizing is different that acid testing in the laboratory( see next slide). Correct  placement of acid is the major concern. (George E. King) 5/8/2017) dm( ytilibaEFFECT OF FLUID COMPOSITION ON PERMEABILITY BP/Amoco Sample 15012 ft. 100 10 Acidizing a core  plug. The  minerals and  physical  constraints in the  core flow path  react to each  fluid flowing  through the core  creating minor  emreP diuqiLFormation Brine 1 De-Ionized Water 03% KCl in  Sea Water 5% KCl in  Sea Water 10% HCl 5% KCl  in Brine changes. Acid,  however, sharply  increased  permeability in  the core.  Transferring this  0 100 200 300 400 500 600 700 Liquid Throughput (PV) type of result to  the formation is  often a problem.5/8/20175 George E. King Will a Substantial Improvement be Always  Expected? • Removal of severe  plugging in carbonates  or sandstones can result  in very large increases in  well productivity • If no damage, seldom  increases production  more than 50%  Undamaged WellAcid Types • HCl - hydrochloric • HCl/HF – hydrochloric and hydrofluoric mixture, often called mud acid.  • Acetic – most common use is vinegar (4%) • Formic – ant and bee sting irritant. • Others – sulfamic and chloroacetic are the dry acids or stick acids used for spot  application of weak acids. 5/8/2017 7 George E. KingHCl or Hydrochloric (Muratic) Acid Hydrogen chloride gas dissolved in water • Maximum concentration about 36 to 38%, depending on temperature. (Note - There is no such thing as 100% hydrochloric acid.) • Increasing HCl content lowers solubility to other gases, additives and salts. • Common Concentrations • 5 to 10% washes for scale, pickling, and preflushes • 10 to 15% for matrix acidizing • 20 to 28% for fracturing • One of the most frequent acid problems is using too strong of an acid. 5/8/2017 8 George E. KingHCl acid in Oil Industry - Reasons for Concentrations • 15% HCl, highest concentration of HCl that earliest inhibitor would work in. • 28% HCl, highest concentration of HCl that can be hauled in an unlined steel tank  (US highway regulation). NOTE: When designing an acid system, testing on representative deposits and core  from the well, consideration of corrosion problems and secondary reactions and  stability of dissolved materials is an absolute necessity. 5/8/2017 9 George E. KingHCl Acid By - Products • Calcium chloride (CaCl2) salt (dissolved) • CO2gas Other common byproducts • Emulsions • Solids from nonreactive parts of formation • Residue from damage deposits • Fine particles released in the formation, etc. 5/8/2017 10 George E. KingAcid Density Acid Initial Spent 10% HCl 8.75 ppg 9 ppg 15% HCl 8.95 ppg 10 ppg 28% HCl 9.3 ppg 11 ppg Initial and spent acid density values are very rough estimates – the specific solution density is also  affected by dissolved gases, additives - such as alcohols and surfactants from the job, mineral - such  as iron from corrosion and/or precipitation prior to the sampling point.  5/8/2017 11 George E. KingHCl/HF acids • For use in removing clay and mud damage • Don’t use it on carbonates (yields a precipitate, calcium fluoride, CaF2) • References of HF and various clay reactions: • Gdanski, R.D.: “Kinetics of the Primary Reaction of HF on Alumino-Silicates” SPE 66564, SPE Production and Facilities,  Vol. 15, No. 4, Nov 2000, p279-287. • Gdanski, R.D.: “Kinetics of the Secondary Reaction of HF on Alumino-Silicates” SPE 59094, SPE Production and  Facilities, Vol. 14, No. 4, Nov 1999, p260-268. • Gdanski, R.D.: “Kinetics of the Teritary Reaction of HF on Aluminosilicates” SPE 31076, SPE Production and Facilities,  Vol. 13, No. 2, Nov 1998, p75-80. 5/8/2017 12 George E. KingHCl/HF concentrations • 12% HCl / 3% HF - mud removal in wellbore • 9% HCl / 1% HF - moderate clay content sandstones In simple terms, the amount of HCl is increased to offset the spending on certain  minerals such as aluminum in clays. The HF requires live HCl to prevent precipitation  of HF reaction products. 5/8/2017 13 George E. KingOther Acids Phosphoric – not recommended in most formations • precipitates calcium phosphate when it spends on calcium minerals – inhibitors  won’t prevent it (inhibitors adsorb). • low corrosion at high temp, but watch long term contact • once used with HF, but not generally recommended. 5/8/2017 14 George E. KingOther Acids Sulfamic: - stick or solid acid • use at bottom hole (BH) temperatures below 150o F – higher temperature may  create sulfuric acid • OK on light coatings of acid soluble scales • very limited dissolving power • commonly used without an inhibitor 5/8/2017 15 George E. KingOther Acids Chloroacetic: (one of the powdered acids, also available in stick form) • very limited reactivity • low dissolving capacity • effective at lowering pH and slowly removing some reactive scales. • commonly used without an inhibitor 5/8/2017 16 George E. KingOther Acids Citric: • iron sequestering agent • very limited reactivity 5/8/2017 17 George E. KingOther Acids Acetic • limited reactivity • limited iron control – can aggregate the formation of some sludges! Use with a  sludge preventer. • expensive for carbonate amount dissolved • less corrosive at high temperatures • maximum concentration used downhole is 10% (by-product solubility problems). • Note: acetic is often used as the acid of choice at higher temperatures but has  very limited reactivity and dissolving capacity (e.g., vinegar is 4% acetic).  5/8/2017 18 George E. KingOther Acids Formic: • expensive for amount of carbonate dissolved (5 times HCl cost on a pound of  carbonate dissolved basis) • less corrosion than HCl at high temperature? • Handling concerns: e.g., Formic is the irritant in bee and ant stings.  5/8/2017 George E. King Engineering GEKEngineering.com 19 George E. KingAcid Mixtures Acetic/ HCl Formic/ HCl • advertised as “slower reacting” – but not so much at higher temperatures • iron control – pH type control only – watch sludge development. (Iron reducer  control and a anti sludger are more effective at preventing sludges.) • high temperature uses based on perception of less corrosion – tests are suggested  for temperatures over 300F. 5/8/2017 20 George E. KingOther Acid Mixtures Formic/ HF • high temperature sandstones – this is a useful product with few problem areas. • Though to be less corrosive at higher temperatures, but recent work shows that it  still needs inhibitor. 5/8/2017 21 George E. KingSulfuric and Nitric Acids • Sulfuric acids not used because of insoluble sulfate by products with calcium.  Sulfuric also reacts with and modifies some oils to sludges. • Nitric acids not used because of danger of creating byproducts with oil that could  raise an explosion hazard.  • Also, no inhibitors. 5/8/2017 22 George E. KingCommon Acidizing Problems • Use of too strong an acid for damage • Use of too much acid • Wrong type of acid • Use of acid at all! • Watch: • temp • reactants • Time • Acid can be very useful, but live acid has only shallow penetration in most  formations and may not react with many forms of damage.  5/8/2017 23 George E. KingAcid Reaction Basics Controls (Limits) on live HCl acid penetration: • Matrix treating: area to volume ratio. In the matrix, the area to volume ratio is  about 20,000:1 – this means the acid spends quickly if the formation or  damage is acid soluble. • Fracture acidizing – with area-to-volume ratios of about 50:1, acid reaction is  slower and the dominant control on penetration distance is leakoff into side  pores and channels. 5/8/2017 24 George E. KingAcid Reaction, HCl-on- Carbonate • Reaction type = first order (fast) • This means that acid spends as quickly as the acid reaches the formation surface  and the byproducts are carried away.  • Remember, the area-to-volume ratio controls the surface area presented to HCl acid for reaction. It also controls how much acid is there to react. 5/8/2017 25 George E. KingAcid Reaction, HCl-on- Carbonate  The stoichiometric relationship of the reaction between ������ and limestone  (��������3) is given below: ��������3+2 ������ → ��������2 + ��2�� + ����2Natural Fracture in Limestone 5/8/2017 27 George E. KingRemember the surface  area issues – HF acid  reaction with clays can be  very quick. The entire picture is  about 25 x 20 microns 5/8/2017 George E. King Engineering GEKEngineering.com 28Acid Reaction, HCl-on-Silica • Very, very slow • More of a tiny solubility of silica in acid than a reaction. Sand grains are very large  compared to the reactive surface area of clays. • For HF reaction on silica, the rate is second order and is slower than the reaction  of HF on clays.  5/8/2017 29 George E. KingApproximate Surface Area of Clays for Common  Clay Structures – Highly Variable Sand Grain 15��10−6��2/g Kaolinite 22 Smectite 82 Illite 113  Chlorite 60 The actual surface areas for clay are highly variable and depends on deposit  configuration. However, the difference between authogenic clay area (clay in the  pore throats) and sand grain area are on the order of 6 to 7 orders of magnitude. 5/8/2017 30 George E. KingSecondary Acid Penetration Control (when not in  the matrix) - Leakoff • Leakoff is required to get acid to flow into the zone. Without it there is no  reaction. • However, by reacting with the flow path, acid increases the rate of leakoff, making  injection into other zones much less likely. 5/8/2017 31 George E. KingAcidizing Diverting • Without any modification of the flow  path, where will most of the acid go?  => Along the path of least resistance. • How do you treat the other zones? =>  Make the high permeability zones  harder to enter or the low perm zones  easier to enter. ? 5/8/2017 George E. King 32Acidizing Diverting • By preferentially reducing the permeability of the  high perm zones, there is a chance to force acid  into the lower perm zones. When the block is  effective, the injection pressure will rise and/or  the injection rate will drop • Most diverting agents still allow some flow  through their “barriers” • A typical formation may have 2 to 3 orders of  magnitude permeability difference between the  minimum and maximum permeabilities • NOTE The blockage must be temporary unless  the high perm zones have watered out 5/8/2017 33George E. King Leakoff Learnings:  Variable Natural Fracture Widths Many natural fractures open or open wider as injection pressure is raised • In these cases permeability can increase by an order of magnitude. Natural fractures may close in some cases with unsupported fractures and high  closure stresses as reservoir pressure declines • Total permeability, including natural fractures, can decline to matrix permeability as they are  closing. 5/8/2017 George E. King Engineering GEKEngineering.com 34 George E. KingAcid Penetration Distance • in wide fractures: 25 to 100+ ft • in narrow fractures: 5 to perhaps about 20 ft • in the matrix: a few inches? • when a few permeability channels are opened by acid in carbonates or  sandstones, “wormholes” or tunnels can develop for short distances (maybe a few  feet). Leakoff usually limits their growth. This assumes uniform reaction – and the most acid will enter (and react) in the  wider fractures.  Acid penetration down a fracture is limited more by leakoff than by spending rate. 5/8/2017 35 George E. KingLeakoff Learnings: Wormholes (uneven reaction) • starts in a high permeability channel or fracture • widens pathway as acid reacts • holes become “rounder”  • limited by side branches (leakoff) • length? – few inches to a few feet. Higher acid viscosity limits leakoff. 5/8/2017 36 George E. KingGases Used in Acidizing • Why? – flow back assist (unloading energy) • Gasses: • Nitrogen • Carbon Dioxide, CO2, both added CO2and CO2from the acid reaction. • And - just a trace of dissolved oxygen (7 parts per billion in 15% HCl) - this is  usually not a significant factor in most operations, unless specialty corrosion  problems develop. However – chrome 13 pipe may be affected.  5/8/2017 George E. King Engineering GEKEngineering.com 37 George E. KingGas Volumes and Types • High Pressure Gas Wells – no added gas needed? • Low Press Gas Wells – about 100 to 700 scf/bbl depending on bottom hole  pressure (BHP). Check the well unloading performance and consider adjusting the  gas volume.  Type: • Gas Well - Nitrogen or Carbon Dioxide • Oil Well (above bubble point) - Carbon Dioxide • Oil Well (below bubble point) – Nitrogen or Carbon Dioxide 5/8/2017 38 George E. KingGas Considerations • Nitrogen has less than 10% of the solubility of carbon dioxide in oil. • Carbon dioxide can enter the “dense phase” in higher pressure wells and can  affect fluid density.  • On Backflow • Gas provides lift (is a choke needed for flow back optimization?) • Gas may create foams or other emulsions. A foam or emulsion breaker is often used in the over flush to  control problems (foam, precipitates and treater upsets on the backflow). 5/8/2017 39 George E. KingReferences on Facility Upsets Caused by Acidizing • Gidley, J.L., Hanson, H.R>: “Prevention of Central Terminal Upsets Related to  Stimulation and Consolidated Treatments,” SPE 4551, 1973. • Coppel, C.P, Newberg P.L: “Factors Causing Emulsion Upsets in Surface Facilities  Following Acid Stimulation,” SPE 3687 (see also 5154), 1972. • Durham, D.K., Ali, S.A., Stone, P.J.: “Causes and Solutions to Surface Facility Upsets  Following Acid Stimulation in the Gulf of Mexico,” SPE 29528, 1997. 5/8/2017 40 George E. KingPutting Acid To Work • Identify the damage and match an acid or solvent to remove it. • Find a way to get the treatment to the damage. • Find a way to remove the spent acid and other fluids and solids. 5/8/2017 41 George E. KingWellbore cleanout Common formation damage problems (BUT, look at “why” first) • mud/cement/perf/completion fluid particles • scale (acid sometimes) • paraffin (forget the acid) • emulsions (acid???) • sludges (a real thick emulsion, acids worsen the problems) • tars (no acid use here either) 5/8/2017 42 George E. KingPerforation Damage • Debris from perforating • Sand in perf tunnel - mixing? • Mud particles • Particles in injected fluids • Pressure drop induced deposits • scales • asphaltenes • Paraffins • Much of the perforation damage may be removed by breaking down the perforations with water – no acid needed. 5/8/2017 43 George E. KingCement • Crushed cement particles can be removed quickly by HCl, but larger surface area  deposits form a calcium alumino silicate coating of variable composition over the  initial reaction site and the reaction stops. Jetting acid against cement does not allow  the coating to form and the reaction proceeds quickly. • Cement can be acidized by HCl/HF mixtures. • When channels are opened to water following an acid job, it is most likely that the  acid opened an existing channel in the cement that was formerly filled by drilling  mud. • Perforating effects on cement are thought to be minor unless the cement was in poor  shape before perforating. Hundreds of perforating tests at surface shows that  perforating penetrates but rarely shatters cement when the target is confined.  5/8/2017 44 George E. KingNear Well Damage • in-depth plugging by injected particles • migrating fines • water swellable clays • water blocks, water sat. re-establishment • polymer damage • wetting by surfactants • relative permeability problems • matrix structure collapse  Watch the injection pressure response of acid when it reaches the formation – a very  fast drop in pressure at a constant rate indicates very shallow, acid soluble damage. 5/8/2017 45 George E. KingClays? • Opinion - Most problems blamed on clays are not clay damage. • Only smectite is routinely swellable to water. Some forms may also disperse  particles. • A few forms of kaolinite may disperse in water flows but may be more sensitive to  fluid velocity than fluid type. • Unstable, free-standing chlorite “rims” around sand grains that have been  dissolved are known in the US Gulf Coast. This is rare. The sensitivity is mostly to  fluid flow but do have some acid reactivity. • A form of water sensitive illite has been reported in the North Sea – this is also  rare.  5/8/2017 46 George E. KingWaterblocks • A relative permeability effect made worse by low pressure and poor displacement. • Most likely problem areas: • Gas wells • Low pressure reservoir – Pressure <<0.3 psi/ft • Moderate to low permeability and small pore throats, • Untreated water • Acid may not help – need to reduce the water surface and interfacial tension and  re-establish gas saturation. Inject non-adsorbing surfactant or alcohol (watch the  asphaltenes) and overflush with Nitrogen or CO2gas. May require multiple  treatments.  5/8/2017 47 George E. KingClay Reactions with Acid • See Gdanksi’s papers on HF reactions on clays and minerals. Composition, form  and location are very important.  • Clay may not be completely removed by the quantity of acid available at the  reaction site and particles can be liberated from the matrix in some cases.  5/8/2017 48 George E. KingPolymer Removal • From: muds, pills, frac, carriers • Stability of polymer? - for years in some cases. • Removal methods:  • time at temperature, 1 week w/ breakers, but breakers often separate from polymer during  job. • acid, small volume, 10% HCl, as a soak, but reaching damage is difficult because it is difficult to  get acid to flow into a damaged (low perm) area. • bleach (3% to 5%) - 5 to 15 gal/ft, soak, bleach is corrosive; has problems getting live bleach to  damage. • enzymes and bacteria - soaks, temp critical – good potential if placed correctly. 5/8/2017 49 George E. KingScale Removal • CaCO3- HCl wash, however, for extremely thick CaCO3scales, it may be faster to  remove the deposits by milling. • CaSO4- dissolver/converter – flush the dissolver/converter out of the well, then  acid soak. • BaSO4- some dissolvers may work on scale mixtures, but nearly pure BaSO4at  pressure is only very slowly reactive to common dissolvers. Consider mechanical  removal. • FeS2- good luck! - mechanical best option 5/8/2017 50 George E. KingSludges? • asphaltenes and irons are triggers for formation of a sludge. • 500 ppm iron (or more) • 0.5% asphaltenes (or more) • can be almost rigid when stabilized by high concentrations of silt. • don’t need much energy to form..... • Very, very hard to break – difficult to disperse solvents into highly viscous sludge. • Treatment – soaks with xylene and/or dispersants. Heat, energy (mixing) and  repeat applications help. 5/8/2017 51 George E. KingWill an acid job remove the damage? • Ask some questions: • What is the damage? • What are the drawbacks to acid in the well? • Has it worked in offsets? What is local experience? • Is there another way? • Solvents? • Re-perforating? (easier to control than acid!) • Breakdowns with a “safe” brine? 5/8/2017 52 George E. KingPETR 4309 Well Completions and Stimulation Ion Ispas, PhD Petroleum Engineering  Texas Tech University Spring 2017Reservoir Analysis – Flow regimes Infinite conductivity with  fluid loss damage Infinite conductivity  choked fracture  H. Cinco SPE 10043 2 Reservoir Analysis – Flow regimes Fracture Linear Formation-Linear Bi-Linear Pseudo-Radial H. Cinco SPE 10043 3 Transient Pressure Analysis (Read – SPE 10043 by H.  Cinco) Flow Regime identification and analysis • Linear - plot ∆�� ���� �� • Bi-Linear - plot log(∆��) ���� log(4�� ) or ∆�� ����4�� • Pseudo-Radial - plot ∆�� ���� log(��) 4Transient Pressure Analysis (Read – SPE 10043 by H. Cinco) linear Linear with WBS H. Cinco SPE 10043 5 Transient Pressure Analysis (Read – SPE 10043 by H. Cinco)Bi -Linear Bi –Linear with WBS H. Cinco SPE 10043  6 Transient Pressure Analysis (Read – SPE 10043 by H. Cinco)Damaged fracture (choked) ∆�� ideal 4�� 7 Transient Pressure Analysis (Read – SPE 10043 by H. Cinco) Damaged Fractures8 Transient Pressure Analysis (Read – SPE 10043 by H.  Cinco) Transient (bi-linear & linear) vs Pseudo-Radial Flow Transient flow ends, and pseudo-radial flow starts at �������� ≅ 2 �������� = ��.������ ����−�� �� ���� ��(������) ∅ �� ���� ������������ ������(����)= 2  The time to the end of transient flow (t) can be calculated  from the above equation.  • If t is in the order of days/weeks, the pseudo-radial flow  regime is dominant • If t is months/years, transient flow may be essential and  the desired ������ > ���� ≫ 2 • Most important parameters for optimum frac design are  (������ and ������)9Folds of Increase (FOI) �������� FOI = ����  ���� ����  ����′ +�� �������� - length doesn’t  • If ������ < 0.5, ����′ = 0.28  ′ �� �� �� ��matter (use of more or better proppant is required  • If ������ > 30, ����′= ����/2 - the fracture is acting like  = �� ℎ ���������������������� �� ��an infinite conductivity fracture and the use of  ��������better proppant would be a waste of money ℎ�� �� ������������������������������10 �������������������������� ���������������� ������������������������, ������ After Cinco –Ley & Michael Smith Transient Pressure Analysis (Read – SPE 10043 by H.  Cinco) Transient (bi-linear & linear) vs Pseudo-Radial Flow Most important parameters for optimum frac design are : ������ and ������ • ������ should be minimum 2 • Optimum ������ (2 for moderate/high permeability formations, to > 2 for tight formations) ������ =������ ������ Reminder: increasing ������ only by increasing ������ Do not reduce ���� to increase ������ 11Fracturing Injection Time Diagnosis  n P   ,erusserP teN goL1 m = to 8 II m = 0 1 4 1 < 0 Log Injection Time • MODE I : slope from 1/8 to 1/4 - Unrestricted extension with confined  height  • MODE II : slope 0 - extension with  fast height growth • MODE III : slope 1 - restricted growth • MODE IV : slope < 0 - uncontrolled  height growth (run-away) Nolte Smith PlotAfter M. Smith 2003 12 Post - Fracture Diagnosis )�� ����(�� ∆ After Smith & Montgomery 13 Post Fracturing Diagnosis After Smith & Montgomery G-Function (Nolte) G-function is a dimensionless function of shut-in time normalized to pumping time4 ( ) { ( ) } G t g t g Δ = Δ − D D π 4 0 ( ) {( ) } [ ] 1.5 1.5 g t t t high efficiency Δ = + Δ − Δ = 1 1 D D D 3 α ( ) ( ) {( ) } [ ] − − 1 0.5 0.5 g t t t t lowefficiency Δ = + Δ + Δ + Δ = 1 sin 1 0.5 α D D D D t t Δ = − p t D t p “g” Bounding Values (Nolte) �� �� =  43������ ∝ = 1 ��2 ������ ∝ = 0.5  16 Ambiguous Closure Using Sqrt(t) Analysis 2 Which one is closure?3 1 e russerP4 6 5 Sqrt(Shut-in Time) From SPE 107877  Barree & Associates 2007 Normal Leakoff G-Function 10500 1 2000 1800 e russerP10000 9500 9000 8500 8000 7500 P vs. G Fracture Closure GdP/dG vs. G dP/dG vs. G 1600 1400 1200 1000 800 600 400 200 0 s evitavireD0 5 10 15 20 25 G(Time) From SPE 107877  Barree & Associates 2007Step Rate Test Source: http://www.advntk.com/pwrijip2003/pwri/final_reports/task_1/srt/srt_final.htmDesign Considerations Fracture Length Optimization - Economics Veatch (1986) economics diagramsDominant Parameter – Fracture Length Low Perm Gas Formation 1600 ��= 0.007 md1400 F CMM ,evitalumuC1200 1000 800 600 400 200 0 ���� = 1100 ft ���� = 650 ft ���� = 1550 ft 0 12 24 36 48 60 72 84 96 108 120 132 144 156 Time (months) Economics – Fracture Length Fracture Length 7 6 r etemaraP cimonocE5 4 3 2 1 0 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 Xf (ft) Economics – (Dominant Parameter – Fracture Conductivity)Efficient Fracture Half Lengths for Various  Permeabilities. George KingStimulation Economics Discounted Payout Δn ∑$ n− = n 1 = (1 i ) + n cost 0 The interest (hurdle) rate (i) indicates when investment will be returned without  lowering corporate investment returns and accounting for inflation (time value of  money) Stimulation Economics Net Present Value Net NPV $n ∑= n n = + 1 (1 ) i n • NPV gives dollar value added to property at present time when full stream of cash flows for  projected relative life of project is used, . • NPV > 0 - attractive investment • NPV < 0 - undesirable investment • NPV is the most widely used indicator which shows the dollar amount of net return PETR 4309 Well Completions and Stimulation Ion Ispas, PhD Petroleum Engineering  Texas Tech University Spring 2017Fracture Conventional vs Unconventional Barry Stephens, 2014

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