Optimization of Hydraulic Fractures in CBM Wells

1. Optimization of Hydraulic Fractures in CBM Wells

2. Outline Conductivity requirements in CBM Understanding fluid flow in fractures Field results Other factors to consider When fracture-stimulating coalbed methane wells, it is important to consider the fracture conductivity required to efficiently dewater the coal and produce gas. To investigate this, we will briefly review some fluid flow theory. Then we will show some published field results, and list some other factors that should be considered during fracture design.When fracture-stimulating coalbed methane wells, it is important to consider the fracture conductivity required to efficiently dewater the coal and produce gas. To investigate this, we will briefly review some fluid flow theory. Then we will show some published field results, and list some other factors that should be considered during fracture design.

3. Conductivity Requirements for CBM Fractures Which well requires higher permeability proppant? One issue that is important to examine is any pre-conceived notions regarding how a well needs to be completed. As an example, please consider two wells: A high rate well in the Gulf of Mexico, and a shallow CBM well producing 1/50th as much gas. Which well requires the higher permeability proppant? Although you may not, our industry certainly has some preconceived notions about how these wells should be completed. In the GOM, over 90% of the completions now incorporate aggressive TSOs or FracPacks with high proppant concentrations of ceramic proppants. At the same time, virtually all CBM wells are completed with sand or RCS, typically at much lower sand concentrations. I am aware of only 2 CBM wells where ceramic proppants were attempted, and those production results will be shown shortly. But the question remains, which well has a greater need for high permeability proppant?One issue that is important to examine is any pre-conceived notions regarding how a well needs to be completed. As an example, please consider two wells: A high rate well in the Gulf of Mexico, and a shallow CBM well producing 1/50th as much gas. Which well requires the higher permeability proppant? Although you may not, our industry certainly has some preconceived notions about how these wells should be completed. In the GOM, over 90% of the completions now incorporate aggressive TSOs or FracPacks with high proppant concentrations of ceramic proppants. At the same time, virtually all CBM wells are completed with sand or RCS, typically at much lower sand concentrations. I am aware of only 2 CBM wells where ceramic proppants were attempted, and those production results will be shown shortly. But the question remains, which well has a greater need for high permeability proppant?

4. Darcy�s Law vs. Forchheimer Equation ? P/L = ? v / k Pressure drop is proportional to fluid velocity Applicable only at low flowrates Before you answer, it probably makes sense to briefly review fluid flow theory. In 1856, Henry Darcy performed an experiment with water slowly soaking through a sand column. At these low velocities, he demonstrated that the pressure loss is completely controlled by friction, by viscous drag of the water against the sand grains. But in 1901, Forchheimer demonstrated by flowing gas through a catalyst bed (which is analogous to gas flowing through a propped fracture), that the pressure loss was controlled not only by friction, but by the kinetic energy associated with accelerating the gas through the many direction changes within a proppant pack. That inertial energy, or kinetic energy that is �wasted� in those repeated directions changes ends up being the dominant factor causing substantial pressure losses within proppant packs in all wells producing at economic rates. Basically, Forchheimer demonstrated that the most dominant factor was the velocity. So when we are selecting a proppant, we want it to provide adequate effective permeability (beta) to accommodate the expected gas velocity.Before you answer, it probably makes sense to briefly review fluid flow theory. In 1856, Henry Darcy performed an experiment with water slowly soaking through a sand column. At these low velocities, he demonstrated that the pressure loss is completely controlled by friction, by viscous drag of the water against the sand grains. But in 1901, Forchheimer demonstrated by flowing gas through a catalyst bed (which is analogous to gas flowing through a propped fracture), that the pressure loss was controlled not only by friction, but by the kinetic energy associated with accelerating the gas through the many direction changes within a proppant pack. That inertial energy, or kinetic energy that is �wasted� in those repeated directions changes ends up being the dominant factor causing substantial pressure losses within proppant packs in all wells producing at economic rates. Basically, Forchheimer demonstrated that the most dominant factor was the velocity. So when we are selecting a proppant, we want it to provide adequate effective permeability (beta) to accommodate the expected gas velocity.

5. Consider Downhole Conditions So to estimate the gas velocity, we need to look at downhole conditions. If we examine our somewhat arbitrary GOM well producing 10 MMCFD, we recognize that the BHFP and temperature are much higher than Standard Conditions (1 atm and 32 F). With the ideal gas law, you can quickly estimate that the gas will be compressed 165 times under these conditions. The coal well, on the other hand, is often on compression, and may have a bottom hole pressure of only 10 atm. With a slightly elevated temperature, we estimate a compression of 9-fold from STP. So if we compare the ACTUAL volumes of gas traveling through the fractures, we see that the high rate GOM well produces only about 3 times the ACTUAL VOLUME of gas as the CBM well.So to estimate the gas velocity, we need to look at downhole conditions. If we examine our somewhat arbitrary GOM well producing 10 MMCFD, we recognize that the BHFP and temperature are much higher than Standard Conditions (1 atm and 32 F). With the ideal gas law, you can quickly estimate that the gas will be compressed 165 times under these conditions. The coal well, on the other hand, is often on compression, and may have a bottom hole pressure of only 10 atm. With a slightly elevated temperature, we estimate a compression of 9-fold from STP. So if we compare the ACTUAL volumes of gas traveling through the fractures, we see that the high rate GOM well produces only about 3 times the ACTUAL VOLUME of gas as the CBM well.

6. Consider Downhole Conditions Next, to estimate fluid velocity, we need to consider the area open to flow. In this somewhat arbitrary GOM well, let�s assume a 100 ft frac height and an aggressive TSO achieving 8/10 of an inch of width. (Proppant concentration of 8-10 lb/sq ft or 40-50 kg/m^2). Meanwhile coal is often found in thinner beds, and frac geometry may be more like 30 ft of frac height, and a relatively narrow fracture (especially after embedment). If this arbitrary geometry applies to your formation, then you can see that you may have 13 times more cross-sectional area open to flow in the GOM well than in the CBM�.. So you can determine that the gas velocity is 4-5 times larger in the CBM well, despite delivering only 2% the volume at standard conditions. For our generic CBM well, I estimated the superficial velocity (if there were 100% porosity in the fracture) at 6 inches/second. Recognizing that the proppant does occupy some of the space, you may estimate the mean linear velocity at 1.5 ft/second. If you accept that the gas follows a curvilinear path, then the actual interstitial velocity is more like 2 feet per second. The gas travels around ~800 grain surfaces each second! (assuming 20/40 size proppant of 550 micron diameter)Next, to estimate fluid velocity, we need to consider the area open to flow. In this somewhat arbitrary GOM well, let�s assume a 100 ft frac height and an aggressive TSO achieving 8/10 of an inch of width. (Proppant concentration of 8-10 lb/sq ft or 40-50 kg/m^2). Meanwhile coal is often found in thinner beds, and frac geometry may be more like 30 ft of frac height, and a relatively narrow fracture (especially after embedment). If this arbitrary geometry applies to your formation, then you can see that you may have 13 times more cross-sectional area open to flow in the GOM well than in the CBM�.. So you can determine that the gas velocity is 4-5 times larger in the CBM well, despite delivering only 2% the volume at standard conditions. For our generic CBM well, I estimated the superficial velocity (if there were 100% porosity in the fracture) at 6 inches/second. Recognizing that the proppant does occupy some of the space, you may estimate the mean linear velocity at 1.5 ft/second. If you accept that the gas follows a curvilinear path, then the actual interstitial velocity is more like 2 feet per second. The gas travels around ~800 grain surfaces each second! (assuming 20/40 size proppant of 550 micron diameter)

7. Options to Increase Fracture Conductivity Increase fracture width Reduce gel damage Increase proppant permeability So even before we consider the detrimental impacts of embedment, coal fines migration and plugging, multiphase flow�.. There is reason to be suspicious that we are not supplying adequate conductivity to efficiently produce the gas. There are a number of options to increase conductivity. Three of the more common are: increase width, reduce residual gel damage, or increase the proppant perm. Unfortunately, these first two goals are often in conflict. To increase the frac width, we often try to place higher proppant concentrations. This may require more viscous gels, which can be more damaging. Or if we increase our treating pressures, we may see increased leakoff, and more compaction of the coal and reduction in the width of the cleat system. Often a compromise must be made between the fluid damage and the ability of the fluid to effectively transport high proppant concentrations. The easier parameter to examine in isolation is changing the proppant permeability, and that is what we will investigate here.So even before we consider the detrimental impacts of embedment, coal fines migration and plugging, multiphase flow�.. There is reason to be suspicious that we are not supplying adequate conductivity to efficiently produce the gas. There are a number of options to increase conductivity. Three of the more common are: increase width, reduce residual gel damage, or increase the proppant perm. Unfortunately, these first two goals are often in conflict. To increase the frac width, we often try to place higher proppant concentrations. This may require more viscous gels, which can be more damaging. Or if we increase our treating pressures, we may see increased leakoff, and more compaction of the coal and reduction in the width of the cleat system. Often a compromise must be made between the fluid damage and the ability of the fluid to effectively transport high proppant concentrations. The easier parameter to examine in isolation is changing the proppant permeability, and that is what we will investigate here.

8. Sieve Distribution Many people assume that ceramic proppants are merely stronger sand. And therefore, they assume that at low stress that the less expensive frac sand is every bit as good as ceramic. This is not true. This plot shows that the size distribution of the mined sand follows a fairly normal distribution. You are pretty much stuck with the distribution in the sand body, and filter out the cuts outside the allowable ranges. On the other hand ceramic proppants are manufactured, and the sieve distribution can be optimized. Premium LWC is shown here to have a very tight distribution to maximize porosity, and it is skewed to the large size, to maximize permeability. A Economy LWC has a distribution somewhere in the middle, but is certainly tighter and coarser than sand.Many people assume that ceramic proppants are merely stronger sand. And therefore, they assume that at low stress that the less expensive frac sand is every bit as good as ceramic. This is not true. This plot shows that the size distribution of the mined sand follows a fairly normal distribution. You are pretty much stuck with the distribution in the sand body, and filter out the cuts outside the allowable ranges. On the other hand ceramic proppants are manufactured, and the sieve distribution can be optimized. Premium LWC is shown here to have a very tight distribution to maximize porosity, and it is skewed to the large size, to maximize permeability. A Economy LWC has a distribution somewhere in the middle, but is certainly tighter and coarser than sand.

9. Proppant Shape As well, there is difference in the shape of the proppants. Ceramics typically achieve a roundness and sphericity of 0.9, while frac sands are typically in the 0.7 range, with some occasionally at 0.8As well, there is difference in the shape of the proppants. Ceramics typically achieve a roundness and sphericity of 0.9, while frac sands are typically in the 0.7 range, with some occasionally at 0.8

10. Uniform size and shape will maximize porosity. This plot shows that at low stress, you may be able to change the porosity of the fracture by ~25% by changing proppant type.Uniform size and shape will maximize porosity. This plot shows that at low stress, you may be able to change the porosity of the fracture by ~25% by changing proppant type.

11. Permeability at Low Stresses This change is even more magnified in terms of proppant permeability. Stim-Lab data show that a premium LWC provides 92% higher permeability than 20/40 Jordan sand at 1000 psi stress.This change is even more magnified in terms of proppant permeability. Stim-Lab data show that a premium LWC provides 92% higher permeability than 20/40 Jordan sand at 1000 psi stress.

12. Permeability at Low Stresses With larger 16/30 sand, data suggest a 60% improvement in perm. For 12/18 size (not shown here, in Q&A section) the difference is even larger!With larger 16/30 sand, data suggest a 60% improvement in perm. For 12/18 size (not shown here, in Q&A section) the difference is even larger!

13. The measured beta factors, also show dramatic improvements for the spherical products compared to the more angular sands. Again beta is a measurement of the degree of acceleration that a fluid must undergo as it travels through the pack. These conclusions are easier to understand when you view cross-sectional photographs of the proppant packs.The measured beta factors, also show dramatic improvements for the spherical products compared to the more angular sands. Again beta is a measurement of the degree of acceleration that a fluid must undergo as it travels through the pack. These conclusions are easier to understand when you view cross-sectional photographs of the proppant packs.

14. Intermediate Strength Ceramic20X Photomicrographs Stim-Lab These cross-sectional photomicrographs were prepared by Stim-Lab. The upper and lower edges of the photos show the sandstone core that the proppant was crushed between. After conductivity testing, a yellow or blue epoxy was pumped into the pack and thin-sections were cut and photographed. As you see, the epoxy fills the porosity, which is on the order of 40% for this product. Unfortunately, the test was not run at 1000 psi and with LWC, but the results would be similar. Note the embedment on the 10,000 psi slide. In CBM you may experience much more severe embedment, perhaps losing 1-2 grain layers on each frac face.These cross-sectional photomicrographs were prepared by Stim-Lab. The upper and lower edges of the photos show the sandstone core that the proppant was crushed between. After conductivity testing, a yellow or blue epoxy was pumped into the pack and thin-sections were cut and photographed. As you see, the epoxy fills the porosity, which is on the order of 40% for this product. Unfortunately, the test was not run at 1000 psi and with LWC, but the results would be similar. Note the embedment on the 10,000 psi slide. In CBM you may experience much more severe embedment, perhaps losing 1-2 grain layers on each frac face.

15. Resin Coated Sand20X Photomicrographs Stim-Lab This slide shows the same conditions for a RCS. The clear quartz grains are much prettier as they are transparent, and create some beautiful patterns. But you should notice that even at the lowest stress, there is substantially lower porosity. That is caused by the broader size distribution and irregular shapes. You can imagine that if you were a molecule of gas and had to travel past 550 sand grain surfaces each second, that the energy wasted in acceleration could be more severe than what was lost in frictional drag.This slide shows the same conditions for a RCS. The clear quartz grains are much prettier as they are transparent, and create some beautiful patterns. But you should notice that even at the lowest stress, there is substantially lower porosity. That is caused by the broader size distribution and irregular shapes. You can imagine that if you were a molecule of gas and had to travel past 550 sand grain surfaces each second, that the energy wasted in acceleration could be more severe than what was lost in frictional drag.

16. Field Results So even without considering fines plugging, embedment, multiphase flow, and other CBM specific damage factors, we should be able to see that frac conductivity would be worth investigating. What does the production data indicate? To my knowledge only two CBM wells have been treated with ceramic proppant. We�ll review those first.So even without considering fines plugging, embedment, multiphase flow, and other CBM specific damage factors, we should be able to see that frac conductivity would be worth investigating. What does the production data indicate? To my knowledge only two CBM wells have been treated with ceramic proppant. We�ll review those first.

17. Coal Bed Methane, San Juan Basin SPE 77675 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. Very little change to the slope of either curve is noticed. In May 1999, the well was restimulated with 258,000 lbs of EconoProp. Production suggests that the well rapidly dewatered and the gas rate steeply inclined, and appears to have reached a plateau and is now beginning a normal decline. 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. Very little change to the slope of either curve is noticed. In May 1999, the well was restimulated with 258,000 lbs of EconoProp. Production suggests that the well rapidly dewatered and the gas rate steeply inclined, and appears to have reached a plateau and is now beginning a normal decline.

18. Coal Bed Methane, San Juan Basin SPE 77675 Restimulations of CBM Southern Ute 18-2; 32-8 This second CBM well showed similar results. The initial stimulation 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 produced approximately 1.6 MMcfd over an 18-month period. The zone was stimulated a third time with 300,000 lbs of 20/40 EconoProp and production peaked at over 3 million scfd. It is clear that two wells do not make a defensible field study, especially in CBM. These wells were the first two wells of a trial initiated with Vastar Resources. Unfortunately, Vastar was purchased, and the subsequent owner has not shared all the offset well data with us, so we have not been able to directly compare to offset wells that were treated with sand refracs. But clearly, these wells indicate the newer fracs did improve the dewatering and production characteristics of the wells. This second CBM well showed similar results. The initial stimulation 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 produced approximately 1.6 MMcfd over an 18-month period. The zone was stimulated a third time with 300,000 lbs of 20/40 EconoProp and production peaked at over 3 million scfd. It is clear that two wells do not make a defensible field study, especially in CBM. These wells were the first two wells of a trial initiated with Vastar Resources. Unfortunately, Vastar was purchased, and the subsequent owner has not shared all the offset well data with us, so we have not been able to directly compare to offset wells that were treated with sand refracs. But clearly, these wells indicate the newer fracs did improve the dewatering and production characteristics of the wells.

19. SPE 77443 Fig 6, Stutz (Anadarko)Helper Federal B-10 Restimulation, Utah Another published example of a refrac where benefit was achieved staying with the same 16/30 frac sandAnother published example of a refrac where benefit was achieved staying with the same 16/30 frac sand

20. SPE 77443 Fig 4, Stutz (Anadarko)Helper Federal 1999 Drilling Program, Utah Another published example of a refrac where benefit was achieved staying with the same 16/30 frac sandAnother published example of a refrac where benefit was achieved staying with the same 16/30 frac sand

21. SPE 22395 Fig 16, Palmer, AmocoCedar Cove Field, Black Warrior Basin, Alabama This plot is from a 1992 paper by Amoco. In the Black Warrior Basin of Alabama, they showed improved production with greater proppant volumes. Most of these fracs were water fracs, with some foam fractures. One well was a sandless frac. From the supplied data, it is not clear whether the increased sand concentrations resulted in additional fracture width, length or height, or whether higher loadings were attempted in better parts of the reservoir. But with low viscosity fluids, it is likely that proppant transport was minimal, and proppant was not transported great distances, so the trend may reasonably be assumed to be somewhat related to achieved conductivity.This plot is from a 1992 paper by Amoco. In the Black Warrior Basin of Alabama, they showed improved production with greater proppant volumes. Most of these fracs were water fracs, with some foam fractures. One well was a sandless frac. From the supplied data, it is not clear whether the increased sand concentrations resulted in additional fracture width, length or height, or whether higher loadings were attempted in better parts of the reservoir. But with low viscosity fluids, it is likely that proppant transport was minimal, and proppant was not transported great distances, so the trend may reasonably be assumed to be somewhat related to achieved conductivity.

22. CBM Field Results Analysis of 900 Virginia CBM wells: Production problems caused by low fracture conductivity � SPE 72380 Propped fractures in Australia CBM are superior to under-reaming in cost and performance. Some wells produce 5 MMSCFD � SPE 64493 �Very high fracture conductivity is needed to ensure rapid dewatering� � SPE 21292 Ultimate gas recovery from CBM depends on maintaining fracture conductivity � SPE 51063 High fracture conductivity �is more important than heretofore recognized.� � SPE 22395 �High fracture conductivity is paramount��SPE 18253 A number of other papers also indicate that additional frac conductivity may be useful. In a Virginia analysis, production problems were related to low conductivity In Australia, more aggressive fracs with 16/30 sand were superior to under-reaming both in cost and production. (This is contrasted with SJB, where �fairway� wells in the best part of the field produce better when under-reamed. In SJB periphery, frac�ed wells outperform. To me, this suggests that frac conductivity constrains productivity, and in the fairway, propped fracs would work if we were capable of placing enough conductivity.) To dewater efficiently, several authors have noted that very high conductivity is needed. The ultimate recovery from CBM depends on placing and retaining very high conductivity fracs. Frac conductivity is more important than currently recognized.A number of other papers also indicate that additional frac conductivity may be useful. In a Virginia analysis, production problems were related to low conductivity In Australia, more aggressive fracs with 16/30 sand were superior to under-reaming both in cost and production. (This is contrasted with SJB, where �fairway� wells in the best part of the field produce better when under-reamed. In SJB periphery, frac�ed wells outperform. To me, this suggests that frac conductivity constrains productivity, and in the fairway, propped fracs would work if we were capable of placing enough conductivity.) To dewater efficiently, several authors have noted that very high conductivity is needed. The ultimate recovery from CBM depends on placing and retaining very high conductivity fracs. Frac conductivity is more important than currently recognized.

23. Other Factors to Consider CBM wells are more sensitive to fracture conductivity than traditional reservoirs. In CBM, desorption is driven by Fickian diffusion, which is highly pressure-dependent. � SPE 51063, 52193 A high conductivity frac will reduce the flowing pressure over a larger area, and initiate dewatering and desorption in a greater portion of the CBM reservoir High conductivity fractures distribute pressure drop over larger area, reducing mobilization of coal fines � SPE 18253 It is important to consider that a low rate coal well does not produce the same as a low rate tight sandstone well. In low velocity flow within the sandstone matrix, gas is produced according to Darcy�s Law. But in coal, gas desorption is described by Fick�s Laws. Diffusion is highly pressure dependent, certainly a non-linear relationship. Reducing the pressure losses within the frac allow you to reduce the pressure at the tip of the fracture. By minimizing that pressure, you maximize the gas desorption and can receive benefits larger than observed in tight gas.It is important to consider that a low rate coal well does not produce the same as a low rate tight sandstone well. In low velocity flow within the sandstone matrix, gas is produced according to Darcy�s Law. But in coal, gas desorption is described by Fick�s Laws. Diffusion is highly pressure dependent, certainly a non-linear relationship. Reducing the pressure losses within the frac allow you to reduce the pressure at the tip of the fracture. By minimizing that pressure, you maximize the gas desorption and can receive benefits larger than observed in tight gas.

24. Multiphase Flow in Proppant Packs

25. dP to Initiate Cleanup @ 4.0 lb/sqft + YF130LG +Breakers @ 150 Deg F and 2000 psi Closure Stress Frac gel is not a Newtonian fluid. You must achieve some �threshold� applied pressure before it will begin to move.Frac gel is not a Newtonian fluid. You must achieve some �threshold� applied pressure before it will begin to move.

26. Post-Cleanup Conductivity @ 4.0 lb/sq. ft. + YF130LG + Breakers  150�F and 2000 psi Closure Stress

27. % Retained Conductivity  @ 4.0 lb/sq. ft. + YF130LG + Breakers 150�F and 2000 psi Closure Stress

29. Other Factors to Consider Multiphase flow Coal Fines Plugging / Flowback Coal compaction with high treating pressures Erosion of coal frac faces during treatment by angular sand is likely more severe than with round ceramic. Erosion may contribute to width, but also �contaminates� pack with fines. � SPE 48886 Low reservoir energy to cleanup gel residue. LWC clean up easier than sand. Embedment Additives There are a number of other factors that I will list here, but not discuss unless raised in the question/answer period: The pressure losses due to multiphase flow in the propped fracture are simply enormous. There are issues with coal fines plugging. As you could anticipate from the earlier photographs, the large pores of ceramics are less susceptible to plugging, but you may see more coal fines produced to surface, which could be problematic. Coal compaction and erosion should be considered. CBM wells generally are very low pressured, and gel damage is pronounced. High perm proppants definitely clean up easier in the lab, and has been shown in the field. Embedment can be severe Various additives are marketed as porosity enhancers and coal fines stabilizers.There are a number of other factors that I will list here, but not discuss unless raised in the question/answer period: The pressure losses due to multiphase flow in the propped fracture are simply enormous. There are issues with coal fines plugging. As you could anticipate from the earlier photographs, the large pores of ceramics are less susceptible to plugging, but you may see more coal fines produced to surface, which could be problematic. Coal compaction and erosion should be considered. CBM wells generally are very low pressured, and gel damage is pronounced. High perm proppants definitely clean up easier in the lab, and has been shown in the field. Embedment can be severe Various additives are marketed as porosity enhancers and coal fines stabilizers.

30. Conclusions The conductivity needs of low pressure CBM wells are often underestimated For rapid dewatering and ability to handle multiphase flow, superior fracture conductivity is needed Many frac gels are extremely damaging to coals. It is desirable to use low damage fluids but maintain conductivity Light weight ceramic proppants provide superior productivity In conclusion, coal wells generally need much higher conductivity fractures than is generally assumed. Especially when you consider the certainty of multiphase flow, conductivity needs are much greater than predicted by models. Extreme damage has been observed with frac gels. You have the difficult problem of using minimally damaging fluids but simultaneously maximizing frac width and conductivity. One product that can help but has been largely overlooked are LWC. They clearly can provide some benefits, but are admittedly higher cost.In conclusion, coal wells generally need much higher conductivity fractures than is generally assumed. Especially when you consider the certainty of multiphase flow, conductivity needs are much greater than predicted by models. Extreme damage has been observed with frac gels. You have the difficult problem of using minimally damaging fluids but simultaneously maximizing frac width and conductivity. One product that can help but has been largely overlooked are LWC. They clearly can provide some benefits, but are admittedly higher cost.