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Determining Realistic Proppant Conductivity in Hydraulic Fracture Designs

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    1. Determining Realistic Proppant Conductivity in Hydraulic Fracture Designs

    2. SPE 106301 Determining Realistic Fracture Conductivity and Understanding its Impact on Well Performance Theory and Field Examples Acknowledge co-authorsAcknowledge co-authors

    3. Outline Introduction / Motivation Lab/Reference Conductivity Realistic Conductivity Field Data & Verification Summary

    4. Getting a well to production

    7. Dimensions of a frac vs a Dollar Bill Generic size of a small frac (300 ft half-length)

    8. Dimensions of a dollar bill Official (Bureau of Engraving and Printing)

    9. Proportions of a frac So if we wanted to print a bill on the same paper, but in the correct proportions to our 50 x 600 x 0.125 frac, wed want a bill that is The wellbore would be in diameter..about the size of a pencil.The wellbore would be in diameter..about the size of a pencil.

    10. Some Current Industry Concerns Short Apparent Frac Length Lack of agreement between welltests, decline curves, propagation modeling and frac-mapping Production Modeling Poor predictions of frac/refrac effects, rates, decline curves Poor Gel Cleanup

    12. Common Fracture Design and Optimization Tools Economides taken from SPE 102263 Prats taken from SPE 101821 McGuire & Sikora taken from Monograph 12Economides taken from SPE 102263 Prats taken from SPE 101821 McGuire & Sikora taken from Monograph 12

    13. How does the ISO Conductivity Test Work?

    14. ISO 13503-5 Conductivity Test Ohio Sandstone 2 lb/ft2 Proppant Loading Stress maintained for 50 hours 150 or 250 F Extremely low water (2% KCl) velocity (2 ml/min) Conductivity test procedures were established by the American Petroleum Institute Recommended Practices 61 and later modified by StimLab. This test has subsequently been updated recently in ISO 13503-5. Proppant is uniformly loaded at 2 ppsf between sandstone shims at 150 deg (Sand and RCS) or 250 (ceramics). The desired stress is maintained for 50 hours, and KCl water is pumped at extremely low rates on the order of teaspoon per minute. This test does a poor job of simulating realistic conditions, and the API committee warned that the values obtained may be an order of magnitude higher than expected in an actual fracture. Unfortunately, our industry widely uses these values without adequate adjustment.Conductivity test procedures were established by the American Petroleum Institute Recommended Practices 61 and later modified by StimLab. This test has subsequently been updated recently in ISO 13503-5. Proppant is uniformly loaded at 2 ppsf between sandstone shims at 150 deg (Sand and RCS) or 250 (ceramics). The desired stress is maintained for 50 hours, and KCl water is pumped at extremely low rates on the order of teaspoon per minute. This test does a poor job of simulating realistic conditions, and the API committee warned that the values obtained may be an order of magnitude higher than expected in an actual fracture. Unfortunately, our industry widely uses these values without adequate adjustment.

    15. This photo shows the layout of the conductivity cell. The sandstone shims are Ohio sandstone with a Youngs Modulus of 5 million psi. Water is pumped through the entry port, travels through the proppant pack, and exits the opposite port. The pressure loss is measured across the middle 5 inches, and using Darcys Law, the permeability and conductivity are calculated. The procedures specify that ~ 2 ml/min are pumped through the pack each minute. Less than a teaspoon of water per minute! That equates to a superficial velocity of a 0.2 inches per minute, while velocity in actual fractures often exceeds several feet per second. This is a difference of a factor of 1000! Also, the single phase water is not representative of the complicated oil, water, gas system that may be present in a real fracture.This photo shows the layout of the conductivity cell. The sandstone shims are Ohio sandstone with a Youngs Modulus of 5 million psi. Water is pumped through the entry port, travels through the proppant pack, and exits the opposite port. The pressure loss is measured across the middle 5 inches, and using Darcys Law, the permeability and conductivity are calculated. The procedures specify that ~ 2 ml/min are pumped through the pack each minute. Less than a teaspoon of water per minute! That equates to a superficial velocity of a 0.2 inches per minute, while velocity in actual fractures often exceeds several feet per second. This is a difference of a factor of 1000! Also, the single phase water is not representative of the complicated oil, water, gas system that may be present in a real fracture.

    16. Typical Proppant Conductivity Curve ISO 13503-5 Procedure This plot shows reference conductivity curves for three types of proppants measured with standard reference procedures. This single phase low flow rate regime is accurately described by Darcys Law but is not representative of fracture flow. Recall that the water velocity during this test is on the order of 0.2 inches per minute. They are slow, seepage type velocities.This plot shows reference conductivity curves for three types of proppants measured with standard reference procedures. This single phase low flow rate regime is accurately described by Darcys Law but is not representative of fracture flow. Recall that the water velocity during this test is on the order of 0.2 inches per minute. They are slow, seepage type velocities.

    17. Problem To obtain a realistic proppant conductivity for design, the Modified API test results must be reduced to account for: Non-Darcy Flow Multiphase Flow Reduced Proppant Concentration Gel Damage Other Effects, including Cyclic Stress Fines Migration When designing a fracture treatment, the reference conductivities should be adjusted by several factors. The following slides will demonstrate the cumulative effect of specific issues that are not addressed by the standard test, but would be expected to occur downhole. References will be provided for a more detailed review.When designing a fracture treatment, the reference conductivities should be adjusted by several factors. The following slides will demonstrate the cumulative effect of specific issues that are not addressed by the standard test, but would be expected to occur downhole. References will be provided for a more detailed review.

    18. Problem To obtain a realistic proppant conductivity for design, the Modified API test results must be reduced to account for: Non-Darcy Flow Multiphase Flow Reduced Proppant Concentration Gel Damage Other Effects, including Cyclic Stress Fines Migration

    19. Modified API RP-61 Conductivity Test Ohio Sandstone 2 lb/ft2 Loading Stress maintained for 50 hours 150 or 250 degrees Extremely low water velocity (2 ml/min)

    20. Darcys Equation ? P/L = ? v / k

    21. Flow Convergence

    22. Velocity within Fracture

    24. Heres why you care: If you look at low velocities, as in the API tests, or in Henry Darcys 1856 experiment, you will observe the green datapoints. Our erroneous Darcy models extrapolate that data to estimate the pressure loss in the fracture, and they predict a very modest pressure drop. However, if you calculate the incremental pressure loss due to gas acceleration, you estimate this trend for the Beta*Density*velocity-square term (yellow line). In the lab, when you measure these conditions, you measure the red curve precisely the sum of the two components. Pressure losses in fractures are large and dominated by the inertial component. Increasing the frac width, and minimizing the beta factor of the proppant is typically the most effective way to increase production.Heres why you care: If you look at low velocities, as in the API tests, or in Henry Darcys 1856 experiment, you will observe the green datapoints. Our erroneous Darcy models extrapolate that data to estimate the pressure loss in the fracture, and they predict a very modest pressure drop. However, if you calculate the incremental pressure loss due to gas acceleration, you estimate this trend for the Beta*Density*velocity-square term (yellow line). In the lab, when you measure these conditions, you measure the red curve precisely the sum of the two components. Pressure losses in fractures are large and dominated by the inertial component. Increasing the frac width, and minimizing the beta factor of the proppant is typically the most effective way to increase production.

    25. Scale enlarged. Still have significant effects (at least as much as Darcy) at rates below 1 MMSCFD.Scale enlarged. Still have significant effects (at least as much as Darcy) at rates below 1 MMSCFD.

    26. Beta Factor A material property that can be experimentally measured for each proppant size and type. Essentially a measure of the tortuosity of the flowpath within the proppant pack. Beta can be reduced by: High Initial Permeability/Porosity (high perm equates to less tortuous flow path). Tight Size Distribution (uniform pore size, and high porosity minimizes expansion/contraction losses). High proppant sphericity (angularity is bad). Smooth Proppant Surface So if the most important parameter is typically the beta factor, we should try to explain it. It is a physical property of the material, much like we think of permeability as an intrinsic property. We measure it by flowing higher fluid velocities through the pack, measuring the pressure drop, and back-calculating beta. Beta is essentially a measure of the degree of acceleration a fluid must undergo as it travels through the pore bodies within the pack. To reduce the pressure drop, we want to minimize beta. Generally, this can be accomplished by placing high perm, high porosity proppants, which are tightly sieved, smooth, and spherical.So if the most important parameter is typically the beta factor, we should try to explain it. It is a physical property of the material, much like we think of permeability as an intrinsic property. We measure it by flowing higher fluid velocities through the pack, measuring the pressure drop, and back-calculating beta. Beta is essentially a measure of the degree of acceleration a fluid must undergo as it travels through the pore bodies within the pack. To reduce the pressure drop, we want to minimize beta. Generally, this can be accomplished by placing high perm, high porosity proppants, which are tightly sieved, smooth, and spherical.

    27. 12/20 Hickory/Brady Sand at 6000 psi. Courtesy Stim-Lab, Inc. Proppant Consortium Think Beta and tortuosity for a gas or oil molecule.Think Beta and tortuosity for a gas or oil molecule.

    28. Problem To obtain a realistic proppant conductivity for design, the API test results must be modified to account for: Non-Darcy Flow Multiphase Flow Reduce Proppant Concentration Gel Damage Other Effects, including Cyclic Stress Fines Migration

    29. Multiphase Flow Effects What causes pressure losses in gas wells? Relative permeability: Proppant saturated with liquid is less conducive to flowing gas Saturation changes: Liquid will tend to accumulate in the frac, occupying porosity that is now unavailable for gas flow Phase interaction: The fast-moving gas wastes energy accelerating the droplets of liquid. But the liquid often stops at each pore throat, only to be re-accelerated. Very inefficient flow regime! There are a number of things that change with multiphase flow. The most significant may be the phase interaction. Since the gas has one tenth to one-hundredth the viscosity of the liquid, it wants to shoot through the frac at a much higher velocity. But it is intimately mixed with the liquid. So it entrains a droplet of liquid, accelerates it 100-fold, and then it hits a pore throat, only to be re-accelerated again. Saturation changes may be very large. Much data suggests significant water saturations in fractures and in proppant packs Rel perm. Proppant that is wet with a fluid is typically less conducive to flowing dry gas.There are a number of things that change with multiphase flow. The most significant may be the phase interaction. Since the gas has one tenth to one-hundredth the viscosity of the liquid, it wants to shoot through the frac at a much higher velocity. But it is intimately mixed with the liquid. So it entrains a droplet of liquid, accelerates it 100-fold, and then it hits a pore throat, only to be re-accelerated again. Saturation changes may be very large. Much data suggests significant water saturations in fractures and in proppant packs Rel perm. Proppant that is wet with a fluid is typically less conducive to flowing dry gas.

    30. Effect of liquid on dry gas flow This is the correlation we are currently using to model multiphase flow in gas wells in FracProPT (updated Fall, 2001). This is Bob Barrees more precise data measured in 2001. At this point, we have a single relationship applied at all velocities and all proppant types. Merely a function of fractional flow. Although we recognize that the pressure drop is a function of gas velocity, we merely used the red line, (a curve fit with a gas velocity ~0.5 MMCFD through a bi-wing 50 ft frac height at 2000 psi BHFP. The lab data was measured with 2.8 lb/sq ft CL at 4000 psi stress. One might think these data would be optimistic, or predict a conservatively low GammaThis is the correlation we are currently using to model multiphase flow in gas wells in FracProPT (updated Fall, 2001). This is Bob Barrees more precise data measured in 2001. At this point, we have a single relationship applied at all velocities and all proppant types. Merely a function of fractional flow. Although we recognize that the pressure drop is a function of gas velocity, we merely used the red line, (a curve fit with a gas velocity ~0.5 MMCFD through a bi-wing 50 ft frac height at 2000 psi BHFP. The lab data was measured with 2.8 lb/sq ft CL at 4000 psi stress. One might think these data would be optimistic, or predict a conservatively low Gamma

    31. Problem To obtain a realistic proppant conductivity for design, the API test results must be modified to account for: Non-Darcy Flow Multiphase Flow Reduced Proppant Concentration Gel Damage Other Effects, including Cyclic Stress Fines Migration

    32. In the API/ISO test, proppant is uniformly distributed at 2 lb/ft2 In actual fractures, the actual concentration is typically much lower Typical Tight Gas fracturing it is < 1 lb/ft2 Realistically, the proppant is not uniformly placed, inside of uniform fracture faces The reference conductivity test is performed on relatively wide proppant packs, with perfectly uniform proppant distribution. A vigilant engineer would choose to adjust these results to account for more realistic proppant distributions achieved in actual practice. Non-uniform distributions will concentrate the closure stress on fewer grains, dramatically increasing proppant damage. Although we recognize this effect will occur, inadequate data are available to accurately describe these effects. However, the next slide will show the effect of reducing the fracture width, but maintaining a uniformly packed fracture.The reference conductivity test is performed on relatively wide proppant packs, with perfectly uniform proppant distribution. A vigilant engineer would choose to adjust these results to account for more realistic proppant distributions achieved in actual practice. Non-uniform distributions will concentrate the closure stress on fewer grains, dramatically increasing proppant damage. Although we recognize this effect will occur, inadequate data are available to accurately describe these effects. However, the next slide will show the effect of reducing the fracture width, but maintaining a uniformly packed fracture.

    33. Problem To obtain a realistic proppant conductivity for design, the API test results must be modified to account for: Non-Darcy Flow Reduced Proppant Concentration Multiphase Flow Gel Damage Other Effects, including Fines Migration Cyclic Stress

    34. Gel Damage May be considered as three phenomena: - Distributed gel damage, residual regained - Loss of effective width due to filtercake build-up - Loss of effective length due to static gel plug in tip

    35. Problem To obtain a realistic proppant conductivity for design, the API test results must be modified to account for: Non-Darcy Flow Reduced Proppant Concentration Multiphase Flow Gel Damage Other Effects, including Fines Migration Cyclic Stress

    36. 12/20 Hickory/Brady Sand at 6000 psi. Courtesy Stim-Lab, Inc. Proppant Consortium

    37. Stim-Labs subsequent testing showed the effects of cyclic loading from 4000 to 8000 psi. After 25 cycles, a light weight ceramic lost 26% of its conductivity and a resin coated sand lost 35%. Of particular concern is that damage is continuous, and each cycle causes further damage to the pack.Stim-Labs subsequent testing showed the effects of cyclic loading from 4000 to 8000 psi. After 25 cycles, a light weight ceramic lost 26% of its conductivity and a resin coated sand lost 35%. Of particular concern is that damage is continuous, and each cycle causes further damage to the pack.

    38. This slide shows the cumulative effect of these modest damage estimates. Under the ISO Test conditions, a lightweight ceramic may provide 5700 md-ft of conductivity. However, after all these factors, a more realistic estimate may be on the order of 100 md-ft. Note that a more broadly sieved, less spherical white sand is more severely degraded by these factors, and the reference conductivity of 1150 md-ft may decline to merely 7 md-ft of apparent conductivity under realistic conditions. It is interesting to note that under reference conditions, most any proppant would appear to provide adequate conductivity for many formations. However, if realistic proppant damage is considered, fractures are almost always found to be conductivity-limited. A second observation is that a LWC may provide only 4 times the conductivity of frac sand at 6000 psi when evaluated under API conditions. However, under realistic conditions, the ceramic may provide 25 times the flow capacity of sand.This slide shows the cumulative effect of these modest damage estimates. Under the ISO Test conditions, a lightweight ceramic may provide 5700 md-ft of conductivity. However, after all these factors, a more realistic estimate may be on the order of 100 md-ft. Note that a more broadly sieved, less spherical white sand is more severely degraded by these factors, and the reference conductivity of 1150 md-ft may decline to merely 7 md-ft of apparent conductivity under realistic conditions. It is interesting to note that under reference conditions, most any proppant would appear to provide adequate conductivity for many formations. However, if realistic proppant damage is considered, fractures are almost always found to be conductivity-limited. A second observation is that a LWC may provide only 4 times the conductivity of frac sand at 6000 psi when evaluated under API conditions. However, under realistic conditions, the ceramic may provide 25 times the flow capacity of sand.

    39. Realistic Conductivity Estimates Even these values may be optimistic! Fail to account for: Extended duration testing (see SPE 14133, 12616, SPE Drilling April 1986 p5) Higher temperatures Non-uniform proppant distribution Increased crush Chokes or pinch points where inadequately propped Flow convergence with limited-entry perforating Emulsions, foaming, frothing Asphaltenes, wax, scale fouling Severe conditions (the example used minimal damage factors!) Although these residual conductivities are terribly low, they may still be optimistic. They fail to account for extended duration testing beyond 50 hours. They fail to consider non-uniform proppant distribution, causing increased crush and chokes within the fracture. They fail to consider flow convergence in cased hole completions. The reported data are based on lab-grade fluids, and do not adequately consider emulsions, foams, frothing, asphaltenes, or scale deposition. And, this example incorporated very minimal damage factors. There are clearly scenarios where fracture damage is much higher than predicted here.Although these residual conductivities are terribly low, they may still be optimistic. They fail to account for extended duration testing beyond 50 hours. They fail to consider non-uniform proppant distribution, causing increased crush and chokes within the fracture. They fail to consider flow convergence in cased hole completions. The reported data are based on lab-grade fluids, and do not adequately consider emulsions, foams, frothing, asphaltenes, or scale deposition. And, this example incorporated very minimal damage factors. There are clearly scenarios where fracture damage is much higher than predicted here.

    40. Realistic? Is it realistic to believe that our fractures have lost over 95% of their reference conductivity?

    42. Wamsutter Development Typically 2-3 stage XL GW fracs per well Avg Concentration: 0.5 lb/ft2 Designed Half Length: 600 Avg Reference Conductivity: 200-1000 md-ft Realistic Conductivity: 3-15 md-ft AGTC analysis performed on ~150 wells fracd from 2002-2004

    43. Results of AGTC Analyses on wells fracd from 2002-2004

    44. Wamsutter Field Results

    45. Wamsutter Field Results Note that these are very preliminary resultsNote that these are very preliminary results

    46. Wamsutter Field Results Note that these are very preliminary resultsbut directionally show / confirm our lab/modeling work. Note that these are very preliminary resultsbut directionally show / confirm our lab/modeling work.

    47. Fractures are rarely infinitely conductive. Realistic Conductivities are typically less than 5% of reference/published values. Field data confirms these reduced conductivities are realistic estimates of in-situ conductivity Hydraulic fractures must be designed and optimized using models which accurately predict realistic conductivities. Field data confirms that higher conductivity fractures in low perm reservoirs will yield increased production.

    48. SPE 106301 Determining Realistic Fracture Conductivity and Understanding its Impact on Well Performance Theory and Field Examples Questions?Questions?

    49. Following are a few other supporting slides that were not presented.

    50. This slide shows some measured beta factors for three product types under 6000 psi stress. Notice that the beta factors may range by a factor of 6 even at this modest stress. This slide shows some measured beta factors for three product types under 6000 psi stress. Notice that the beta factors may range by a factor of 6 even at this modest stress.

    51. What about Oil Wells? High gas content: Oil wells often display GORs of 550 scf/bbl or 100 m3 gas per m3 oil Pressure (psi) Volume % Gas 15 99% 150 90% 1500 50% 3000 33% BHFP>bubble point 0% Single phase models: Assume 100% liquid Unaccounted for: Gas occupies porosity requiring higher liquid velocity, phase interaction, incremental pressure loss of gas phase So what happens with oil wells? Oil wells are frequently 99% gas by volume at atmospheric conditions. Even at high BHFP (bottomhole flowing pressure), if you are below the bubble point pressure of the oil, you will have substantial fractions of gas present. Meanwhile, Single Phase models are considering only the velocity of the liquid stream. They do not account for the high gas saturations occupying porosity, which requires the liquid to travel at a higher velocity. They ignore the interaction of the two phases, and the ignore the incremental pressure loss of the gas phase So what happens with oil wells? Oil wells are frequently 99% gas by volume at atmospheric conditions. Even at high BHFP (bottomhole flowing pressure), if you are below the bubble point pressure of the oil, you will have substantial fractions of gas present. Meanwhile, Single Phase models are considering only the velocity of the liquid stream. They do not account for the high gas saturations occupying porosity, which requires the liquid to travel at a higher velocity. They ignore the interaction of the two phases, and the ignore the incremental pressure loss of the gas phase

    52. After single-cycle crushing of EconoProp at 6000 psi, approximately 98% of the material remains in-spec. Of the material that crushed, the vast majority remain as large pieces, which are immobile within the fracture, and continue to provide relatively high flow capacity. Only 2 tenths of one percent of the product is reduced below 100 mesh, where it may be mobile within the 20/40 pack. Lower strength sand-based proppants generally produce a much higher percentage of mobile fines. However, with the large, consistent shape of the pore bodies in a ceramic pack, it is not uncommon for these small mobile particles to be produced through the fracture and flow to the surface. In fact, some operators are now monitoring the flowback of proppant fines and using it as an estimate of the degree of cleanup experienced in the fracture. If we assume that the API crush test procedures adequately represent downhole conditions, when we place a fracture containing 100,000 lbs of proppant, we would expect to generate approximately 200 lbs of proppant fines which are small enough to be mobile within the fracture. With efficient cleanup, we would expect to see these particles produced to the surface. It is also worth noting that larger particles cannot migrate through an intact 20/40 proppant pack. They are simply too large to fit through the pore throats. Any time larger proppant particles are produced, it is clear that they did not flow through an intact pack.After single-cycle crushing of EconoProp at 6000 psi, approximately 98% of the material remains in-spec. Of the material that crushed, the vast majority remain as large pieces, which are immobile within the fracture, and continue to provide relatively high flow capacity. Only 2 tenths of one percent of the product is reduced below 100 mesh, where it may be mobile within the 20/40 pack. Lower strength sand-based proppants generally produce a much higher percentage of mobile fines. However, with the large, consistent shape of the pore bodies in a ceramic pack, it is not uncommon for these small mobile particles to be produced through the fracture and flow to the surface. In fact, some operators are now monitoring the flowback of proppant fines and using it as an estimate of the degree of cleanup experienced in the fracture. If we assume that the API crush test procedures adequately represent downhole conditions, when we place a fracture containing 100,000 lbs of proppant, we would expect to generate approximately 200 lbs of proppant fines which are small enough to be mobile within the fracture. With efficient cleanup, we would expect to see these particles produced to the surface. It is also worth noting that larger particles cannot migrate through an intact 20/40 proppant pack. They are simply too large to fit through the pore throats. Any time larger proppant particles are produced, it is clear that they did not flow through an intact pack.

    53. SPE Papers Documenting Benefit of Increased Conductivity SPE 77675 As documented in SPE paper 77675, more than 80 papers have been published describing production benefits achieved with higher conductivity fractures. Benefits were achieved with combinations of wider fractures, superior proppants, and larger proppant diameter in over 35 geographic regions around the world. These production increases were documented by more than 250 authors, representing over 70 companies. Higher conductivity fractures were found to be beneficial in oil, gas, and condensate reservoirs. These benefits were shown in carbonates, sandstones, and coals, with well depths ranging from 100 to 20,000 feet. Higher conductivity fractures were beneficial in oil wells producing as little as 1 bopd and in gas wells producing less than 250,000 scf/d. A review of all 80 field studies is contained in SPE paper 77675. The following presentation shows the production benefit from 5 fields, spanning a variety of formation types. As documented in SPE paper 77675, more than 80 papers have been published describing production benefits achieved with higher conductivity fractures. Benefits were achieved with combinations of wider fractures, superior proppants, and larger proppant diameter in over 35 geographic regions around the world. These production increases were documented by more than 250 authors, representing over 70 companies. Higher conductivity fractures were found to be beneficial in oil, gas, and condensate reservoirs. These benefits were shown in carbonates, sandstones, and coals, with well depths ranging from 100 to 20,000 feet. Higher conductivity fractures were beneficial in oil wells producing as little as 1 bopd and in gas wells producing less than 250,000 scf/d. A review of all 80 field studies is contained in SPE paper 77675. The following presentation shows the production benefit from 5 fields, spanning a variety of formation types.

    54. Searchable map available on CD or www.carboceramics.com

    55. Other Field Data Validating Increased Conductivity Increases Production (not presented) Over the past 5 years CARBO asked the same question.are these predictions real? We embarked on over a dozen field trials in various reservoir types to prove it to ourselves. This presentation highlights a few of these trials, with particular emphasis on comparing model to actual performance. Over the past 5 years CARBO asked the same question.are these predictions real? We embarked on over a dozen field trials in various reservoir types to prove it to ourselves. This presentation highlights a few of these trials, with particular emphasis on comparing model to actual performance.

    56. Map showing study area. East Texas in Longview area.Smith, Greg, and Upshur County. Map showing study area. East Texas in Longview area.Smith, Greg, and Upshur County.

    57. Field Study Summary Haynesville Limestone in East Texas Depths +12,000 BHST 265 degF Porosity 8-12% Permeability 0.2 md BHSP 3,500 psi Net Pay 75 Closure Grad 0.65 psi/ft Wells drilled in 1978-82 with the original completions consisting of a small acid treatment to remove drilling damage. The field study was performed in the Haynesville lime in East Texas. Go over depths, temp, etc The field study was performed in the Haynesville lime in East Texas. Go over depths, temp, etc

    58. Haynesville Lime Production Simulator Comparison Notice that if Non-Darcy effects are ignored, then there appears to be no difference in proppant performance, meaning that the fracture is behaving in an infinite conductivity nature. However, when ND & MP effects are turned on, notice the drop in predicted rate, as well as the spread that occurs between proppants. This should be easy to see in practice. This was the premise for the field trial.Notice that if Non-Darcy effects are ignored, then there appears to be no difference in proppant performance, meaning that the fracture is behaving in an infinite conductivity nature. However, when ND & MP effects are turned on, notice the drop in predicted rate, as well as the spread that occurs between proppants. This should be easy to see in practice. This was the premise for the field trial.

    59. Field Trial 9 treatments using an economy light weight ceramic (LWC) 9 offset wells that were previously designed using laminar conductivities and treated with RCS were selected for comparison

    60. Initial Production Response Initial production response was used as the first indication of the effectiveness of a frac treatment. All wells had stabilized pre-frac production enabling a comparison based on folds of increase. Both treatment types were successful in increasing production. But Prefrac production rates for LWC wells were lower than for RCS, indicating that the RCS wells were better wells to begin with (better pressure and/or reservoir quality). Therefore, a folds of increase analysis was done.Prefrac production rates for LWC wells were lower than for RCS, indicating that the RCS wells were better wells to begin with (better pressure and/or reservoir quality). Therefore, a folds of increase analysis was done.

    61. Haynesville Lime Production Folds of Increase Comparison

    62. Production Response, Folds of Increase (FOI) The LWC wells are noticeably better. There are some anomolies, but when coupled with the lab/theoretical data, the results become believeable.The LWC wells are noticeably better. There are some anomolies, but when coupled with the lab/theoretical data, the results become believeable.

    63. Haynesville Lime Production Simulator Comparison to Actual If we go back and compare to the original predictions, and assume the prefrac average rate of 670 MSCFD for the RCS wells, and then use the FOI average show on the previous slide, the LWC & RCS wells begin to match quite well. The incremental increase is a little more than predicted, which may corroborate what we saw in Anchutz. Bottomline is that it is obvious that we are not working in the Darcy model scenerio.If we go back and compare to the original predictions, and assume the prefrac average rate of 670 MSCFD for the RCS wells, and then use the FOI average show on the previous slide, the LWC & RCS wells begin to match quite well. The incremental increase is a little more than predicted, which may corroborate what we saw in Anchutz. Bottomline is that it is obvious that we are not working in the Darcy model scenerio.

    64. Our fourth field study focuses on coal bed methane wells on the Colorado/New Mexico border. Our fourth field study focuses on coal bed methane wells on the Colorado/New Mexico border.

    65. Coal Bed Methane Restimulations of CBM Southern Ute 12-2; 32-9 This plot is the production history of a coal bed methane well in the San Juan Basin. The initial fracture stimulation consisted of 304,000 lbs of frac sand. The red curve shows the gas production, while the blue curve shows the declining water rates. In 1994, the well was restimulated with 12,000 lbs of 40/70 sand and 82,000 lbs of 12/20 sand. In May 1999, the well was restimulated with 258,000 lbs of EconoProp. While analysis of coal bed wells can be complicated, it appears that the EconoProp restimulation treatment steepened both curves, accelerating dewatering and significantly increasing production rates.This plot is the production history of a coal bed methane well in the San Juan Basin. The initial fracture stimulation consisted of 304,000 lbs of frac sand. The red curve shows the gas production, while the blue curve shows the declining water rates. In 1994, the well was restimulated with 12,000 lbs of 40/70 sand and 82,000 lbs of 12/20 sand. In May 1999, the well was restimulated with 258,000 lbs of EconoProp. While analysis of coal bed wells can be complicated, it appears that the EconoProp restimulation treatment steepened both curves, accelerating dewatering and significantly increasing production rates.

    66. Coal Bed Methane Restimulations of CBM Southern Ute 18-2; 32-8 The second CBM well showed similar results. The initial fracture treatment in 1989 contained over million pounds of frac sand. A subsequent restimulation in 1995 appeared to have little impact on the well productivity. In early 1997, the production stabilized and the well produced approximately 1.6 MMcfd over an 18-month period. The zone was stimulated a third time in 1999 with 300,000 lbs of 20/40 EconoProp and production peaked at over 3 million scfd. It has been generally accepted that very high fracture conductivities are required to ensure rapid dewatering of CBM wells. However the apparent success of these first two wells utilizing ceramic proppant has been very encouraging. We look forward to seeing results with larger proppants such as 16/20 or 12/18 CarboLite in future coal bed methane developments.The second CBM well showed similar results. The initial fracture treatment in 1989 contained over million pounds of frac sand. A subsequent restimulation in 1995 appeared to have little impact on the well productivity. In early 1997, the production stabilized and the well produced approximately 1.6 MMcfd over an 18-month period. The zone was stimulated a third time in 1999 with 300,000 lbs of 20/40 EconoProp and production peaked at over 3 million scfd. It has been generally accepted that very high fracture conductivities are required to ensure rapid dewatering of CBM wells. However the apparent success of these first two wells utilizing ceramic proppant has been very encouraging. We look forward to seeing results with larger proppants such as 16/20 or 12/18 CarboLite in future coal bed methane developments.

    67. Another trial (one of our first) was in a tight formation in Green River Basin in WY.Another trial (one of our first) was in a tight formation in Green River Basin in WY.

    68. Frontier Formation, Wyoming Permeability - .05 md Depth ~ 7800 ft Stress on Proppant ~ 5500 psi Reservoir Pressure - 2390 psi Net pay - 30 feet Fracture Geometry - 160 X 500 X .65 #/sq ft This slide shows the basic reservoir characteristics for a tight gas sand in Wyoming. The field has an interesting development history, as shown in the next slideThis slide shows the basic reservoir characteristics for a tight gas sand in Wyoming. The field has an interesting development history, as shown in the next slide

    69. Optional This slide shows the expected reference conductivity and beta factor for the various completions typesOptional This slide shows the expected reference conductivity and beta factor for the various completions types

    70. This chart shows the predicted rates that would be achieved with each fracture type. Note that a Darcy model suggests very little improvement is expected with increased fracture conductivity. (Because the invalid Darcys Law suggests that the pressure drop in the fracture is negligible). However, more realistic modeling indicates that ~30% production improvement would be expected. (this assumes identical clean up and effective lengths, which underestimates the LWC potential)This chart shows the predicted rates that would be achieved with each fracture type. Note that a Darcy model suggests very little improvement is expected with increased fracture conductivity. (Because the invalid Darcys Law suggests that the pressure drop in the fracture is negligible). However, more realistic modeling indicates that ~30% production improvement would be expected. (this assumes identical clean up and effective lengths, which underestimates the LWC potential)

    71. Predicted Vs. Actual IP Rates for Darcy and Non-Darcy Models Optional review of modeling matches. This slide demonstrates the differences in Darcy and non-Darcy production models. On the vertical axis, we will plot the predicted rate divided by the actual observed IP. When this ratio hits 100%, that means the production model exactly matched initial rates.Optional review of modeling matches. This slide demonstrates the differences in Darcy and non-Darcy production models. On the vertical axis, we will plot the predicted rate divided by the actual observed IP. When this ratio hits 100%, that means the production model exactly matched initial rates.

    72. Predicted Vs. Actual IP Rates for Darcy and Non-Darcy Models As you can see, the Darcy model typically overestimated production, as it failed to consider the realistic pressure losses in the frac. A non-Darcy model matched production within 6%, which is surprisingly accurate in this variable reservoir.As you can see, the Darcy model typically overestimated production, as it failed to consider the realistic pressure losses in the frac. A non-Darcy model matched production within 6%, which is surprisingly accurate in this variable reservoir.

    73. Our final case study reviews the the extensive Morrow Formation, with production in Colorado, Kansas, Oklahoma and Texas. SPE paper 18861 describes the restimulation efforts of Morrow wells completed in 4 counties in Western Oklahoma.Our final case study reviews the the extensive Morrow Formation, with production in Colorado, Kansas, Oklahoma and Texas. SPE paper 18861 describes the restimulation efforts of Morrow wells completed in 4 counties in Western Oklahoma.

    74. Western Oklahoma Refracs (Morrow) SPE 18861, Ennis (Amoco) Initial fracs under-performing Pressure buildup testing on adjacent RCS fracs: 89-117 md-ft 30 - 220 feet half lengths versus 200 to 1400 ft design 7 low perm wells refraced with 20/40 ISP Initial hydraulic fracture treatments in this area provided disappointing results. Pressure transient testing conducted by Amoco on similar wells treated with RCS showed poor effective fracture lengths and conductivities. Seven wells were selected with a variety of initial stimulation types to be refractured with 20/40 Intermediate strength ceramic.Initial hydraulic fracture treatments in this area provided disappointing results. Pressure transient testing conducted by Amoco on similar wells treated with RCS showed poor effective fracture lengths and conductivities. Seven wells were selected with a variety of initial stimulation types to be refractured with 20/40 Intermediate strength ceramic.

    75. The results of the seven restimulation treatments are shown. Well number one was unproductive, and the refracture treatment was unsuccessful. The remaining 6 stimulations provided sustained rate increases of 100,000 to 1.5 million cfd. The seven treatments averaged over 600,000 cfd incremental production.The results of the seven restimulation treatments are shown. Well number one was unproductive, and the refracture treatment was unsuccessful. The remaining 6 stimulations provided sustained rate increases of 100,000 to 1.5 million cfd. The seven treatments averaged over 600,000 cfd incremental production.

    76. The production history of one well was particularly interesting. With 50 feet of pay, this well produced 400,000 cfd prior to stimulation. The well was acidized and stimulated with 10,000 lbs of glass beads, resulting in peak rates around 700,000 cfd. A restimulation effort with 100,000 of sand increased the well rate to 1.4 million cfd. A third stimulation attempt with 120,000 lbs of intermediate strength ceramic increased the well rate to 2.5 million scfd, demonstrating the benefit of larger, more conductive fractures.The production history of one well was particularly interesting. With 50 feet of pay, this well produced 400,000 cfd prior to stimulation. The well was acidized and stimulated with 10,000 lbs of glass beads, resulting in peak rates around 700,000 cfd. A restimulation effort with 100,000 of sand increased the well rate to 1.4 million cfd. A third stimulation attempt with 120,000 lbs of intermediate strength ceramic increased the well rate to 2.5 million scfd, demonstrating the benefit of larger, more conductive fractures.