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1 SPE Using Enhanced Fracturing-Fluid Cleanup and Conductivity in the Hosston/Travis Peak Formation for Improved Production N. Modeland, Halliburton; I. Tomova, El Paso; D. Loveless, J. Lowry, J. Holtsclaw, and V. Yeager, Halliburton Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 6 8 February This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract For many years, the Travis Peak/Hosston formation of East Texas and North Louisiana has been hydraulically fractured with various treatment designs, ranging from low-viscosity water fracs using only linear gel or polyacrylamide friction reducers to crosslinked gels typically sourced from guar polymers or guar derivatives. While lower-viscosity fluids can minimize gel damage to the formation, the result is often that less fracture conductivity is achieved because of the inability to transport larger proppant concentrations and maintain width. In late 2010, a new milestone occurred for the East Texas/North Louisiana region as a newly developed crosslinked gel system, souced entirely from the food industry, was incorporated into the Travis Peak/Hosston fracture designs. The fluid system demonstrates both better proppant-transport capabilities and better conductivity-performance numbers than friction-reducer polyacrylamide systems and typical guar fluids. In addition to enhanced cleanup and proppant transport, all of the fluid system s components, having been sourced from the food industry, demonstrate a health, safety, and environmental (HSE) quality that surpasses the previously used fluid systems. This paper will show laboratory test results for retained conductivity and proppant transport for the sourced-from-the-food-industry (SFI) fluid system in comparison to other fracturing gels, both of which should aid in flowback and production of a tight-gas sandstone formation. Case histories for the Landon No. 6 well (a single-stage Travis Peak and Pettet completion in Rusk County, Texas) and the Shadowen 3-2 well (a four-stage Hosston completion of DeSoto Parish, Louisianna) will be examined. These two wells were the early pioneers for this SFI fluid system and have both shown benefits from its improved fluid cleanup and conductivity capabilities. Nearby offset comparisons of the production well show these wells to outperform wells with similarly completed frac stages using different fluid systems. Use of this SFI fluid in the tight-gas sandstones of East Texas and North Louisiana not only exemplifies the environmental stewardship of the oil-and-gas industry, but can also lead to improved estimated ultimate recovery (EUR) of the wells. Background The Travis Peak/Hosston is one of the commonly hydraulic-fracture-stimulated tight-gas sand reservoirs in East Texas. Often, the formation is stimulated as a recompletion for wells drilled for Cotton Valley targets and could potentially hold a strong future as a secondary completion for thousands of the recently drilled Haynesville Shale horizontal wells once their shale-gas production has been exhausted. The structure of the formation has several pay lenses that can be targeted; thus, it often requires multiple treatment stages to develop its total potential (gross target pays often spanning over 1,000 ft). Through the years, several types of stimulation treatments and fluid systems have been used in the Travis Peak/Hosston formation, and because the variance still continues, it is apparant that the optimal treatment methodology is not readily agreed on by the region s operators. Several treatments have been performed with waterfrac methodology using polyachrylamide friction reducers, large fluid volumes, low proppant concentrations, and high rates. Some production studies of the East Texas tight-gas sands have been conducted and indicate improved results and higher initial production (IP) when treated with water fracs (Mayerhofer and Meehan 1998). Some of the advantages to waterfracs include lower gel loading (and subsequently less damage), lower cost of fracturing fluid, and higher treatment rates may improve limited-entry effectiveness when fracturing. However, though low in gel loading, polyacrylamide friction reducers used in waterfracs have been shown difficult to break, and with consideration of the larger fluid volumes being used, they may still provide residue damage to a proppant pack (Palisch et al. 2008). The propped fracture width generated by waterfrac treatments is also generally assumed smaller compared to those for crosslinked

2 2 SPE gel treatments. Though the small propped width can provide enough conductivity for the low-permeability tight-gas reservoir, it might be limiting in flow capacity, which could inhibit the fracturing-fluid cleanup and also allow more severe impact from damages that affect the proppant pack (such as fines, embedment, and proppant diagenesis). Also, if liquid hydrocarbons are present, the importance of width and conductivity becomes more important. Other operators in the region have chosen to stimulate the Travis Peak/Hosston formation with crosslinked gel systems, either in hybrid treatments or entirely gel treatments. The most commonly used systems are guar or carboxymethyl hydroxypropyl guar (CMHPG) gel systems crosslinked using borate or metallic crosslinkers. Some of the advantages of using the gel systems include larger generated fracture width, better proppant distribution and higher conductivity in the fracture. Because using a crosslinked gel allows for higher proppant concentrations to be used, often the fluid volumes and treatment times are reduced compared to waterfrac treatments. The deterrents for using gels are the higher fluid costs associated with their usage, in addition to the residual damage gel created on the fracture face and in the proppant pack. In some shale plays, gel may also inhibit the generation of a complex fracture network; however, in the Travis Peak/Hosston vertical play, planartype fractures are being considered, so this is not likely to be a factor. Gel damage from these treatments, if not broken completely, can take several months or even years to cleanup and can hinder the initial production of the well. However, studies have indicated in some reservoirs that better conductivity in the created fracture from the gel treatments can often lead to better long-term sustainability of the well s production, and thus higher EUR. (Baihly et al. 2011) As hydraulic fracturing has come under public and regulatory scrutinity in recent years, there has been a focused industry push toward greener technologies in drilling and completion services. This initative has not only led to chemicals and procedures that are better suited for safety and the environment, but also in some cases to technologies that can provide superior technical performance. The SFI fluid system described in this paper is one of the more recent technologies spawned from this environmental initiative and has demonstrated results that are in many ways superior to conventional fluid systems. The actual components of the fluid system sourced from the food industry are the gelling agent, surfactant, crosslinker, and breakers. What makes this fluid attractive for use in tight-gas reservoirs is its ability to combine some of the favorable properties of both waterfrac and crosslinked gel treatments. As demonstrated by laboratory results, the crosslinked SFI fluid was able to transport proppant, suspend high proppant concentrations, generate fracture width, and give high proppant-pack regained conductivity (Darling and Rakshpal 1998; Kenny et al. 1996). Laboratory Results and Technical Benefits Many fluid properties were incorporated in this SFI fluid system to maximize its performance in the well without comprising the environmental profile of its constituents. As previously mentioned, the constituents include a polysaccharide gelling agent, a crosslinker, a surfactant, and a suite of breakers (tailored to specific temperatures); all of these ingredients have been identified by the Food and Drug Administration to be safe for the direct addition to food as described in the Code of Federal Regulations (CFR) 21 (Code of Federal Regulations Title ). In addition to meeting these stringent environmental standards, the fluid must have the ability to transport proppant into the fracture, and the fluid must break in such a manner as to leave little residue to maximize the proppant-pack conductivity. Viscosity. The system is applicable over a broad temperature range and can be crosslinked and used for conventional gelled fracturing treatments, or as a linear fluid system. Viscosity for the SFI fluid (Fig. 1) in general is comparable to other standard crosslinked-guar fluids normally used for this purpose in the industry today. Being a complete system allows for adjustments in the gelling agent, crosslinker, and the use of the breaker suite to obtain the desired viscosity and break profile for the necessary bottomhole temperature and fracture geometry (Yeager 2011). Fig. 1 SFI fluid vs. comparable fracturing-fluid viscosity.

3 SPE Proppant Transport. The second required characteristic, the ability of this fluid to transport proppant, has been evaluated using several types of laboratory methods, as previously reported (Loveless et al. 2011). Compared to traditional fluid systems that were used in the offset wells in this area, the proppant transport of the SFI fluid system under static conditions showed significantly better proppant suspension (Fig. 2). Fig. 2 shows the settling rate of 20/40-mesh Ottawa sand in a column with the SFI fluid system compared with a typical crosslinked guar fluid. Fig. 2 Proppant suspension comparison between the SFI fluid and a conventional borate-crosslinked guar system. In a more rigorous test, the systems were compared using a small amplitude oscillatory shear testing criteria to illustrate the relative relaxation time of the two gel systems. The results (Fig. 3) show that the crossover frequency (storage modulus = loss modulus) occurs at a much higher frequency for the crosslinked guar system than it does for the SFI system. This rheological behavior is consistent with the proppant support observed with these systems. Fig. 3 Elastic storage (G') modulus and viscosity-loss modulus (G'') comparison between the SFI fluid and a borate-crosslinked guar system.

4 4 SPE Regained Conductivity. In addition to the excellent proppant transport and viscosity of the system, the low-residue charcteristic of the system coupled with an aggressive and novel breaking package makes the SFI system exhibit extremely high regained conductivity numbers under aqueous KCl and wet-gas cleanup procedures. The results of these tests have been reported previously (Holtsclaw et al. 2011). Even at 1 lbm/ft 2 of 20/40-mesh Ottawa sand, a cleanup in excess of 90%+ at 2,000 psi closure stress was observed by a third-party laboratory. These results can be attributed to the very low amount of insoluble material present in the system and the breakers. Unlike a conventional guar, which can have as much as 10% insoluble residues that can potentially clog pores in the proppant pack, the SFI system contains less than 0.5% damage-causing residues. Additionally, the breaking mechanism employed in the SFI system is different and does not depend on the addition of molecules to oxidize the polymer backbone. The enhanced performance is shown in Table 1 with 2 lbm/ft 2 of Ottawa sand shut in at 140 F for 24 hours with increasing stress values. The gel loadings for the test were 40 lbm/1,000 gal for the SFI system polymer and 25 lbm/1,000 gal for the guar polymer. The SFI fluid clearly excels as the test conditions become more strenuous, showing how the lack of residual residue and the complete breaking of the gel system can greatly influence the regained conductivity. An additional advantage of the clean break occurs as the well flows back; it not only leaves the proppant in the formation, but it flows back very little, if any, sand or viscous material that must be dealt with and/or disposed. The result will be maximizing the proppant in the fracture and minimizing the conductivity impairment that can cause production and effective fracture length to be lower than expected; avoiding these problems can potentially increase the well s hydrocarbon recovery. TABLE 1 REGAINED CONDUCTIVITY COMPARISON WITH 2 lbm/ft 2 OTTAWA SAND at 140 F Closure Stress, psi SFI System Borate-Crosslinked Guar 2,000 91% 82% 4, % 72% 6, %+ 55% Field Results The first well in the East Texas/North Louisiana region stimulated with the SFI fluid system was the Landon No. 6 well in Rusk County, Texas. This was a single-stage stimulation of the Travis Peak formation; the treatment was a re-entry completion, isolating and moving up the wellbore from the previously stimulated Cotton Valley formation. The treatment was performed with two perforation clusters totaling 11 ft (net) of perforations, spanning 249 ft of total interval. The stimulation was a 40-bbl/min design with a 52-cp linear gel pad followed by crosslinked sand-laden stages starting at 1 lbm/gal and increasing up to 6 lbm/gal proppant concentration of 20/40-mesh proppant. The treatment consisted of about 87,000 gal of fluid and successfully placed over 103,000 lbm of proppant into the formation. The instantaneous shut-in pressures from before and after the treatment indicated a net pressure increase of 330 psi. The treatment plot is shown in Fig. 4.

5 SPE Fig. 4 Travis Peak stimulation treatment chart for the Landon No. 6 well. The 10-month cumulative production results from this stimulation brought on 55.2 MMcf gas, along with 5,175 bbl of oil. The production performance proved to be very economical for this treatment, especially with the production of oil. The oil production of the Landon No. 6 well might be the result of using the SFI fluid to create a highly conductive proppant pack through the fluid s exceptional cleanup and minimal gel residues. Because of the lenticular nature of the Travis Peak/Hosston formation, there was difficulty finding offset wells for a fair comparison. Nearby wells often differed in payzones present and payzone thicknesses, and their completion design. For example, the Landon No. 2 offset well is about 0.44 miles from the Landon No. 6 well (Fig. 5) and used a different completion design. While the Landon No. 6 well was a single-stage dualcluster completion, the Landon No. 2 treatment used two intervals in single-cluster stages that were performed nearly five years apart. Even when combining the oil production of the Landon No. 2 well for both of the 10-month intervals following the two completions, the net oil produced was 4,505 bbl. However, directly comparing the oil production of these two wells could seem overly generous because the Landon No. 2 well had 50% more perforated payzone thickness than the Landon No. 6 well. Also, by stimulating and producing the intervals separately, the predicted fracture placement into both intervals would intuitively be better and would influence the production results. The last reported recovered fracturing fluid loads for the two wells were 69% load recovered for the Landon No. 6 well compared to only 42% for the Landon No. 2 well.

6 6 SPE Fig. 5 Field map displaying the Landon No. 6 well (stimulated with the SFI fluid system) and offset wells. The second well stimulated with the SFI fluid was the Shadowens 3-2 well in DeSoto Parish, Louisiana. Similar to the Landon No. 6 well, this Hosston formation completion was a re-entry into a previously completed Cotton Valley formation well. This treatment, however, consisted of four treatment intervals, with each treatment consisting of one to three perforation clusters. Each treatment stage varied in design. The stimulation details for each are outlined in Table 2, and the corresponding treatment plots for each stage are depicted in Figs. 6 through 9. TABLE 2 STIMULATION DETAILS OF THE SHADOWENS 3-2 WELL HOSSTON TREATMENTS Interval 1 Interval 2 Interval 3 Interval 4 Avg job rate, bbl/min Fluid volume, gal 80,424 86,481 33,658 87,599 Total proppant, lbm 64,860 80,120 40, ,890 Max prop conc, lbm/gal Base-gel viscosity, cp

7 SPE Fig. 6 Interval 1 Hosston treatment chart for the Shadowens 3-2 well. Fig. 7 Interval 2 Hosston treatment chart for the Shadowens 3-2 well.

8 8 SPE Fig. 8 Interval 3 Hosston treatment chart for the Shadowens 3-2 well. Fig. 9 Interval 4 Hosston treatment chart for the Shadowns 3-2 well.

9 SPE Similarly to the Landon No. 6 well, there was difficulty obtaining direct production comparisons for this region and formation. However, three nearby offset wells (Fig. 10) were identified that had similar intervals completed for new Hosston production. Because the Shadowens 3-2 well treated with the SFI fluid was a recompletion of an old Cotton Valley well, a portion of its post-completion production had to be attributed to the Cotton Valley zone. The well was producing on average 115 Mcf/d before from the Cotton Valley completion, and this gas rate is taken to be the maximum contribution to the total gas rate from the well after stimulation of the Hosstion formation. In all likelihood, this will likely underestimate the gas rate from the Hosston stimulation, as the production from the constant 115 Mcf/d Cotton Valley contribution would be expected to decline. For the other three wells, the detailed production is from an original Hosston completion, so no rate normalization is needed for an accurate comparison. Though the four wells were all Hosston completions, they had different perforated pay thicknesses and stimulation designs. Table 3 details the well differences, and their respective gas-rate plots once the well s production was turned over to the sales stream are displayed in Fig. 11. It is necessary here to clarify that the two foam-treatment wells (the Bagley Jr. 3 and Bagley Jr. 4) do not depict the high initial gas rates because of certain challenges that exist with allowable CO 2 concentrations in the sales stream. Out of the four wells compared, the Shadowns 3-2 well was clearly the highest performer, with more than twice the 243-day production than the next best performer, the Bagley Jr. 4 well. These results are even more impressive considering that the Shadowens 3-2 well ranked third in quantity (ft) of perforated pay and the proppant was less than the other three wells. In fact, the Shadowens 4-Alt well, which had ranked third in overall proppant quantity, used more than twice the proppant of the Shadowns 3-2 well. The Shadowens 3-2 well used a crosslinked fluid design and obtained the highest of the four wells in overall proppant concentration (total proppant divided by total fluid volume). By keeping this proppant-to-fluid ratio high, the expected fracture geometries of the treatment intervals would likely yield better overall containment with higher conductivity. Alternatively, while the fracture length of the crosslinked gel design is less than that of a large-volume waterfrac, the actual effective propped length might be comparable, or even better. The waterfrac design is subject to proppant settling while the large volumes and high pump rates can lead to fracturing outside of the targeted payzone. Depending on the extent of proppant settling and fracture containment, it is plausible that much of the propped surface area could reside near the wellbore and/or lie outside the intended zone. With a crosslinked gel system, the enhanced width and proppant transportation usually can come at the cost of gel residue damage, which can negate the benefits and decrease the effective fracture length (Holditch and Tschirhart 1996); however, with the SFI fluid system used in the Shadowens 3-2 well, the laboratory results suggest that the fracture cleanup would be comparable to that of a waterfrac. Thus, the improved production demonstrated by the Shadowens 3-2 well could possibly be attributed to the successful placement of well-contained, highly conductive fractures that experienced minimal damage from gel residue to the fracture face and proppant pack achievable through the use of the crosslinked SFI fluid system. Fig. 10 Field map displaying the Shadowens 3-2 well (stimulated with the SFI fluid system) and offsets.

10 10 SPE TABLE 3 COMPLETION AND PRODUCTION DETAILS FOR THE SHADOWENS 3-2 AND OFFSET HOSSTON WELLS Well name Shadowens 3-2 Bagley Jr. 3 Bagley Jr. 4 Shadowens 4-Alt Completion Cotton Valley formation re-entry to Hosston Original Hosston formation completed Original Hosston formation completed Original Hosston formation completed Fluid SFI gelled fluid CO 2 + linear fluid CO 2 + linear gel Waterfrac/linear gel No. of treatment stages Fluid volume, gal 288,192 1,032,570 1,180, ,574 Proppant amount, lbm 308, , , ,730 Perforated pay Top perf/bottom perf, ft 6,920/8,780 6,821/8,850 6,792/8,859 7,436/8,858 Proppant per pay, lbm/ft 3,352 3,733 3,956 8,238 Overall proppant density, lbm/gal Cummulative sales gas at 243 days, mcf ,060 a 80,291 84,564 37,796 a The cumulative gas value was 204,005 Mcf for this well but was adjusted down by 27,945 Mcf to account for Cotton Valley formation contribution. Fig. 11 Sales gas production chart comparing the SFI fluid Hosston well treatment with three similar offset wells. (Note: 115 Mcf was subtracted daily from the Shadowens 3-2 well production to account for the Cotton Valley formation contribution). Conclusions The following conclusions are a result of this work: For all five of the treatment intervals discussed, the SFI fluid system performed as expected in field operations. The SFI fluid system demonstrated repeatable stability, as all treatments were pumped as designed and placed all of the designed proppant. Proppant-transport capabilities for this fluid system during field trials demonstrated that proppant concentrations in excess of 6 lbm/gal can be placed in a ~4,700-psi closure stress environment. The low residue properties of the SFI fluid (<0.5%), combined with its superior proppant suspension, provide a new solution combination that incorporates advantageous properties from both sides of the waterfrac vs. crosslinked gel debate for tight-gas sand formations. Using the newly developed system, a fracture treatment was designed to have the geometric control and conductivity of a crosslinked guar system but retain the low residue and high cleanup properties of a waterfrac. Because all of the components of the SFI fluid system have been identified by the FDA as safe for the direct addition to food, there are many HSE benefits to using the fluid system apart from its performance properties. With consideration of the environment, human exposure, and general public perception, the SFI fluid system

11 SPE provides operators with an option to further advance the environmental stewardship without compromising well production. Though it is difficult to obtain direct production comparisons in the Travis Peak/Hosston formation, the early inital production of the two wells evaluated indicate improved production compared to their direct offsets. Enhanced fracture cleanup and improved proppant conductivity could likely be the outcome from the SFI fluid system. With longer-term production and a larger SFI fluid sample set, a more refined model of the SFI fluid s performance can be made. References Baihly, J., Malpani, R., Xu, J., Jacob, L.K., Malayalam, A., and Darakhshan, J A Comprehensive Completion Study of Recent Cotton Valley Sand Well Production To Optimize Future Designs. Paper SPE SPE presented at the North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, USA, June. doi: / MS Code of Federal Regulations Title 21; Part 170 to 199; Food and Drugs Office of the Federal Register National Archives and Records Administration. Darling, D. and Rakshpal, R Green Chemistry Applied to Corrosion and Scale Inhibitors. Paper No. 207 presented at Corrosion 98 in San Diego, California, USA, March. Holditch, S.A. and Tschirhart, N.R Optimal Stimulation Treatments in Tight Gas Sands. Paper SPE presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, 9 12 October. doi: /96104-MS. Holtsclaw, J., Fleming, J., Saini, R., and Loveless, D Environmentally-focused Crosslinked Gel System Results in High Retained Proppant Pack Conductivity. Paper SPE presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, 30 October 2 November. doi: / MS. Kenny, P., Norman, M., and Friestad, A.M The Development and Field Testing of a Less Hazardous and Technically Superior, Oil Based Drilling Fluid; SPE presentation at the International Conference on Health, Safety & Environment held in New Orleans, Louisiana, USA, 9 12 June. doi: /35952-MS. Loveless, D., Harris, P., Holtsclaw, J., Fleming, J., and Saini, R Fracturing Fluid Sourced Solely from the Food Industry Provides Superior Proppant Transport. Paper SPE presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, 30 October 2 November. doi: / MS. Mayerhofer, M.J. and Meehan, D.N Waterfracs Results from 50 Cotton Valley Wells. Paper SPE presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September. doi: /49104-MS. Palisch, T.T., Vincent, M.C., and Handren, P.J Slickwater Fracturing: Food for Thought. Paper SPE presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, September. doi: / MS. Yeager, V. Clean Stimulation Technology. Upstream Pumping Solutions Spring 2011.