NEW TOOLS ATTACK PERMIAN BASIN STIMULATION PROBLEMS

June 8, 1992
John W. Ely, Stephen K. Schubarth, Brad C. Wolters, James C. Kromer Ely & Associates Inc. Houston Profitable stimulation treatments in the Permian basin of the southwestern U.S. combine new tools with technology and fluids previously available. A wide selection of fracturing fluids and techniques needs to be considered to solve the varied problems associated with stimulating hydrocarbon reservoirs that are at diverse depths, temperatures, pressures, and lithologies.
John W. Ely, Stephen K. Schubarth, Brad C. Wolters, James C. Kromer
Ely & Associates Inc.
Houston

Profitable stimulation treatments in the Permian basin of the southwestern U.S. combine new tools with technology and fluids previously available.

A wide selection of fracturing fluids and techniques needs to be considered to solve the varied problems associated with stimulating hydrocarbon reservoirs that are at diverse depths, temperatures, pressures, and lithologies.

The Permian basin of West Texas and New Mexico is the most fertile ground in the U.S. for some of the newer stimulation technologies.

In this basin, these new tools and techniques have been applied in many older producing areas that previously were treated with more conventional stimulation techniques, including acidizing and conventional fracturing procedures.

FRAC FLUIDS

Frac fluid choices include low-viscosity linear gels, high-viscosity crosslinked gels, medium-viscosity polyemulsion fluid, foams, and crosslinked foams.

Obviously, this list does not include all of the fracturing fluids available (see box). However, these fluids allow for a wide range of excellent proppant transport. Combined with aggressive proppant schedules, intense quality control, and forced closure, these fluids provide the necessary tools for profitable stimulation treatments in the Permian basin.

LINEAR GELS

Linear gel fracturing with guar gum was initiated in the Permian basin in the 1960s.

In recent years, these gels have found increasing use because of their simplicity and low cost.

Linear fracturing gels are easily degraded and the rheological properties of these systems, both from the standpoint of pumping friction and viscosity in the fracture, are well known.

Operators have found that moderate-viscosity linear gels in the range of 30-50 lb/1,000 gal are adequate for placing high concentrations of proppant. These fluids are selected by operators to lessen cost and for small fracturing treatments where damage removal may be the major problem.

Additionally, if there are any substantial barriers to fracture height growth, it can be restricted by limiting viscosity with linear gel.

Linear gels, in combination with crosslink pads, also are allowing a new technique for selective proppant placement.

Linear gels, whether using guar, hydroxypropylguar, or other derivatives of guar or cellulose, are a valuable tool in stimulating reservoirs in the Permian basin.

BORATE CROSSLINKED
FLUIDS

Borate crosslinked fluids were among the first crosslinked fracturing fluids to be used in the late 1960s. Early borate systems were very difficult to pump and degrade. In the late 1960s, there was no technology to successfully degrade the borates at low temperatures.

Additionally, many of the earlier gels used from 60 to 80 lb/1,000 gal and were very difficult to pump because they yielded excessively high friction pressure.

Today borate systems are, without a doubt, the fluid of choice of virtually all of the service companies. 1-3

These gels typically have only moderate friction pressure if 35 lb/1,000 gal or less base gel is used.

These lower gel concentrations can meet the requirements for a large percentage of all of the producing wells in the Permian basin. Available are delayed crosslink gels that have benefitted from significant development in the area of breaker' technology. These breakers include catalyzed oxidizer breakers and encapsulated breakers 4-6 that assist in complete breakdown of the borate systems.

These borate frac fluids have been used to carry high proppant concentrations with aggressive proppant schedules.

Treatments have yielded excellent results in Permian basin wells.

POLYEMULSION

Polyemulsion is a fluid that has been around since the 1960s. Because of its simplicity and low cost, the fluid has found a rebirth in the Permian basin.

Polyemulsion, which is prepared by combining two-thirds producing oil and linear gel, is an excellent proppant transport and support medium. The fluid has found a tremendous amount of use in the Clearfork, San Andres, and other Permian basin reservoirs.

The main problem with the fluid is high friction pressure. Because of this, the fluid is mostly used in jobs that permit pumping the treatment down the casing.

Treatments have been successfully carried out with concentrations of sand well in excess of 13 ppg. The fluid is an excellent medium for placing proppant across an entire interval.

Although not perfect in proppant transport, the polyemulsion's high viscosity at low shear rates yields sufficient viscosity that combined with forced closure is effective for a perfect support medium.

FOAM

Because many reservoirs in the Permian basin are underpressured and external energy is required for rapid cleanup, use of foamy fracturing fluids and also crosslinked foams is widespread.7-9

The straight foam fracturing fluids that consist typically of linear gels that may be foamed with nitrogen or CO2 have been successfully used since the late 1970s.

With crosslinked foam fracturing fluids, one can achieve a good combination of an energized fluid and excellent proppant transport. Additionally, with improved fracturing blenders and the technique termed "constant internal phase," proppant concentrations exceeding 12 ppg have been placed.

The aforementioned breaker technologies have also been beneficial in allowing even better cleanup than was needed in the early days of foam fracturing.

DELAYED CROSSLINK FLUIDS

The first crosslinked fracturing fluid pumped in the oil field was an antimony crosslinked guar.10 This and borate crosslinked guar systems dominated the fracturing market until the early 1970s. At that time, titanium crosslinked fluids became the system of choice.

Other crosslinked systems included chrome, aluminum, and eventually zirconium.

In the 1980s, service companies recognized that the advantage of delayed systems was to negate unnecessary shear degradation of the fracturing fluids.11 12

Delayed metallic crosslinked fluids have found success in Permian basin reservoirs. Although usage of these fluids has decreased somewhat with the advent of the high-temperature stable borate, they still are valuable for fracturing deeper, high-temperature reservoirs.

For temperatures in excess of 200 F., the authors feel that delayed crosslinked titanium and zirconium fluids, particularly in the low pH range, are excellent alternatives to borate systems.

Field experience has shown that these fluids supply adequate proppant transport and yield excellent degradation from the hydrolysis occurring because of the low pH inherent in the systems.

TOOLS AND TECHNIQUES

Various tools, techniques, and procedures have been found to yield economically successful fracture stimulation in the Permian basin. There is no single tool or technique that can achieve enhanced stimulation. But several of the techniques combined can profitably stimulate a majority of Permian basin reservoirs.

PROPPANT SCHEDULES

For some time, a majority of service company and operating people in the Permian basin have believed that higher sand concentration in the fracture yields enhanced fracture conductivity and subsequently better stimulation results.13 14

Except for proppant, the other material in the fracturing fluids does not enhance production. One could argue that various surfactants and other additives may enhance wettability or may create some avenues for enhanced production but, in reality, the critical medium for hydraulic fracture stimulation is the proppant.

Even when laboratory tests have indicated opposite results, the authors have found that in many instances, for various reasons, high concentrations of moderate-size proppants have yielded equal or better results compared to larger proppants.

Table 1 shows a typical aggressive proppant schedule. The aggressive proppant schedule yields not only higher proppant concentration in the pack but also assists in placing the proppant by using the enhanced slurry viscosity resulting from the high proppant concentration.

Our designs for the Clearfork, Devonian, and San Andres formations typically average 7-8 ppg. In many areas, we have found through trial and error that optimal stimulation results are achieved by going quickly to 10-12 ppg.

This, of course, is dependant upon closure pressure and relative conductivity needs based upon the permeability of the formation.

In many areas, simply doubling or tripling the amount of proppant placed in the formation can result in successful stimulation. Obviously, this assumes that adequate quality control and flowback procedures are followed.

QUALITY CONTROL

Many papers illustrate the positive results of conventional and intense quality control.15-18

Intense quality control involves pilot testing of the fracturing fluids at bottom hole temperature conditions. These tests assure an adequate viscosity for transporting proppant and complete breakback to water at some point after the treatment is completed.

The authors feel that a very large percentage of fracture treatments conducted previously, particularly those without intense quality control, may have ended with a large portion of the fracture plugged up with fracturing gel.

Field results of treatments in offset wells, with proper quality control procedures, have been astounding. With the typical low-pressure, low-temperature environment existing in the Permian basin, one must be absolutely certain that even linear gels are degraded back to 2-3 cp at ambient temperature.

Any viscosity of non-Newtonian fracturing fluids is greatly multiplied by the very low shear rates that would be seen either in the proppant pack or in the pore channels.

We feel that there is no more important component to successful hydraulic fracturing than using both conventional and intense quality control procedures.

FORCED CLOSURE

The forced closure procedure was first described in 1990.17 This flowback procedure has been used in the Permian basin since 1986.

The first fracture treatment with this technique was in a Canyon sand near San Angelo, Tex. The procedure, which involves immediate flowback of fracturing fluids at controlled rates, has yielded substantial benefits in the Permian basin.

The procedure has no post treatment shut-in time. Unbroken gel is flowed out of the fracture using the inherent supercharge from the treatment to obtain more of the fracturing fluid in a shorter period of time.

The technique decreases proppant production through what we term "reverse gravel packing." It has been shown to allow the removal of more gel in an unbroken state, thereby removing potentially damaging solids from the fracture.

Tests by major oil companies have shown no negative effects of flowing gel or crosslink gel through a proppant pack. We feel that more of the proppant is left in a suspended state near the well bore. Also the technique negates proppant smearing that occurs from ongoing fracture growth after pumping shutdown at the end of the treatment.

Forced closure is a procedure that most operators are starting to use or have been using. We have not seen any negative effects on Permian basin or other wells.

FRACTURE HEIGHT

Perhaps the greatest nemesis to proper design of fracture treatments in the Permian basin has been the assumption that the fracture treatments were contained either within or in close proximity to a producing zone.

In the majority of formations treated, from our experience, the fracture height growth has been radial in extent. What this basically means is that the fracture grows equally up, down, and outward. For example, the fracture grows in the shape of a penny or a coin.

For formations with thin pay zones, this conclusion indicates that very long fracture extensions may not be possible.

In the Permian basin, frac height logs, data from dead strings, and a few treatments with downhole pressure gauges show little evidence of contained fracture height. The exception has been in some Morrow intervals in New Mexico and other isolated incidences where large thick shale or anhydrite sections exist above or below the producing interval.

We believe that over 95% of the time, a GDK or radial frac design model more accurately describes fracture dimensions than assumption of a contained fracture height in either a GDK or Perkins and Kern linear model or even a 3D model with adequate stress barriers.

From our stress tests, few barriers have been found that can withstand the net pressures existing even when pumping low-viscosity fluids.

By understanding the reality of limited fracture height containment, one can understand why large fracture treatments are required to drain a low-permeability reservoir. Secondarily, one can realize the need for smaller spacing to adequately deplete most hydrocarbon-producing reservoirs.

PERFORATED INTERVAL

Because in many cases there is no limit to fracture height growth, there is the potential for multiple planar vertical fractures to occur in long perforated sections.

There is almost a certainty that some degree of inclination occurs either from a deviated well bore or from simple deviations or inclinations in the formations. Therefore, if several holes are perforated over more than 100 ft, several inclined fractures possibly could be created.

Obviously, this is detrimental to proper stimulation because several short fractures rather than a single planar vertical fracture would contain the proppant.

Our recommendation is to fix the center of the interval, minimize the number of perforations, and limit their extent. Typically 10-20 ft is all that is required to cover hundreds of feet of interval with a hydraulic fracture.

It is necessary that the entire fracture be in communication with the perforations by using the forced closure technique. Furthermore, one should not overdisplace or have segments of the fracture nonconnected because of variations in proppant concentration during the treatment.

The major purpose in pumping proppant is to pack a continuous concentration of proppant into the fracture, particularly at the well bore. We recommend that if any variation in proppant concentration occurs, particularly in the downward direction in the later stage of the treatment, the well should be flushed immediately.

The production of proppant because of void spaces near the well bore can ensue and can cause lost continuity in the proppant pack due to variable sand concentrations in the later stages of the treatment.

SURGICAL FRAC DESIGNS

Because the majority of treatments are penny shaped, or radial in nature, one mechanism for control of fracture height growth is simply to restrict the size of the fracture treatment. Additionally, by placing perforations specifically in a section above or below an area not to be propped and again restricting the size of the fracture treatment design, selective placement of proppant can be achieved.

A common scenario in the Permian basin is producing intervals of 50-250 ft with a very definitive water contact in the lower part of the section. In many cases, these wells are perforated throughout the oil zone and many times into the water contact.

These wells may have been acidized several times. A common problem is a high water/oil ratio. Because of the acid treatments, there are cavities near the well bore that allow proppant from previous treatments to be produced. In many cases, there is little or no effective conductive proppant pack across the producing interval. This is probably due to long shut-in times from conventional fracture treatments where low sand concentrations were used.

A selective treatment for such a well would be to set a bridge plug just above the producing interval, perforating just above the bridge plug, then design and do a fracture treatment that would grow up and down radially so that one does not prop the water contact.

Operators must have a good understanding of stress profiles and rock properties to be assured that the zone above the producing interval is not a barrier to growth and a pinching effect does not occur.

Good success ratios have been achieved with the selective treatments. Typically, water production is not dramatically reduced because of proppant in the water contact. But invariably production of oil and gas increases because of the placement of high concentrations of proppant across the producing interval.

Before implementing this type of design, a frac height log or stress test should be conducted in the well to assure a good understanding of any potential barriers to fracture height growth.

Minimizing the perforated interval combined with selective placement of the fracture initiation point and a realistic evaluation. of fracture height growth is a key to improving the success of hydraulic fracturing.

PIPELINING

The pipelining process 19 involves a combination of fracturing fluids and a good understanding of fracture height growth.

For many years, a successful technique has been used in hydraulic fracturing where acid is used to differentially etch the fracture. Most companies have been pumping viscous pads of polymer or emulsion followed by low-viscosity acid.

This allows differential etching because of fingering of the lower-viscosity fluid through the high-viscosity pad fluids. A particular problem existed in southeastern New Mexico's Delaware formation. There, relatively thin intervals were bounded sometimes above and sometimes below by high-permeability water zones.

Conventional fracture treatments typically yielded good oil production but also high water cut. In cases where the water existed above the interval and boundaries existed below, low-viscosity settling treatments,with linear gel proved beneficial. In a majority of the cases, however, the water contact was just a few feet below the oil contact.

From observations, some researchers formulated a concept after trying to displace a viscous crosslinked fluid from a Plexiglas chamber in which proppant transport tests were being conducted. Instead of piston-like displacement of the crosslink fluid, a fingering phenomenon was observed that followed precisely the entrance ports into the Plexiglas chamber.

The concept is that a radial fracture, or for that matter a confined fracture, could be created with viscous crosslinked gel. By placing the proppant section only across the producing interval, the proppant can be placed selectively in only the producing interval with high differential viscosity.

The basic concept is to create the hydraulic fracture with high-viscosity crosslinked gel. The pad of crosslinked gel is designed based on the desired fracture length. Then, proppant-laden fluid is placed in a low-viscosity linear gel.

By placing perforations only in the producing interval, the proppant placement achieves selectivity across the producing interval.

The size of the proppant stage is determined by iterations with a computer model assuming height confinement due to viscous fingering. Proppant stages are typically quite small compared to the pad and are sized to reach the created length of the pad fluid.

Fig. 1 illustrates a typical pressure profile from a pipeline treatment with a deadstring present. The decrease in the net pressure, which is minimal, may be due to perforation cleanup or to simply a lower net pressure as the proppant and gel move down the fracture.

The increasing pressure at the end, we believe, may be the proppant nearing the tip of the fracture. The results to date with this technique have been nothing short of phenomenal.

Typical designs run fairly low volumes of sand but in high concentrations. This technique has been used on small intervals in the Delaware basin, fairly large sections in the Devonian. The process has also been used in the Clearfork, San Andres, and other areas of the country.

As with all techniques in hydraulic fracturing, we certainly do not have a complete understanding of all of the mechanisms of this procedure. The results we have had to date have been outstanding.

With less than 30,000 lb of proppant, the postfrac buildup analyses have indicated high fracture conductivities with prop-fracture lengths calculated in excess of 200 ft. We do not feel that this technique is limited to thin sections and in fact have successfully used it in areas where there was CO2 breakthrough above an average producing zone. In this particular zone, the upper part of the section was squeezed off, and the treatment was conducted down the tubing. A large crosslinked pad was pumped, followed by linear gel carrying proppant.

For this treatment (Table 2), the design is similar to conventional treatments other than the differential viscosity. Excellent posttreatment stimulation of the oil zone was achieved with no CO2 production.

REFERENCE

  1. Dawson, J.C., "Thermodynamic Study of Borate Complexation With Guar and Guar Derivatives," Paper No. SPE 22837.

  2. Brannon, H.D. and Ault, M.C.,"New Delayed Borate Crosslinked Fluid Provides Improved Fracture Conductivity in High Temperature Applications," Paper No. SPE 22838.

  3. Harris, P.C., "Chemistry and Rheology of Borate Crosslinked Fluids," Halliburton Services.

  4. Cawiezel, K.E., and Elbel, J.L., "New System for Controlling the Crosslinking Rate of Borate Fracturing Fluids," Paper No. SPE 10077, 60th California Regional Meeting, Ventura, Calif., April 46, 1990.

  5. Gulbis, J., King, M.T., Hawkins, G.W., and Brannon, H.D., "Encapsulated Breaker for Aqueous Polymeric Fluids," Paper No. SPE 19433, Permian Basin and Gas Recovery Conference, Midland, Tex., Mar. 8-9, 1990.

  6. Elbel, J, Gulbis, J., King, M.T., and Maniere, J., "Increased Breaker Concentration in Fracturing Fluids Results in Improved Gas Well Performance," Paper No. SPE 21716, Production Operations Symposium, Oklahoma City, Apr. 7-9, 1991,

  7. Harris, P.C., "Effects of Texture on Rheology of Foam Fracturing Fluids," Paper No. SPE 14257, SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25, 1985.

  8. Watkins, E.K., Wendorff, C.L., and Ainley, B.R., "New Crosslinked Foamed Fracturing Fluid," Paper No. SPE 12027, SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8, 1983.

  9. Craighead, M.S., Hossaini, M., and Freeman, E.R., "Foam Fracturing Utilizing Delayed Crosslinked Gels," Paper No. SPE 14437, SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25, 1985.

  10. Holtmyer, M.D., and Githens, C.f., "Field Performance of a New High Viscosity Water Base Fracturing Fluid," Paper API 875-24E, API Spring Meeting, Rocky Mountain District, Production Division., Denver, Apr. 27-29, 1970.

  11. Conway, M.W., and Harris, E., "Laboratory and Field Evaluation of a Technique for Hydraulic Fracturing Stimulation of Deep Wells," Paper No. SPE 10964, SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29, 1982.

  12. Harms, S.D., Goss, M.L., and Payne, K.L., "New Generation Fracturing Fluid for Ultrahigh Temperature Application," Paper No. SPE 12484, SPE Formation Damage Control Symposium, Bakersfield, Calif., Feb. 13-14, 1994.

  13. Holditch, S.A., and Ely, J.W., "Successful Stimulation of Deep Wells Using High Proppant Concentrations," JPT, August 1973, pp. 959-64.

  14. Ely, J.W., Wolters, B.C., Schubarth, S.K., Jacoby, M.A., and Summers, C.E., "High Proppant Concentration[Low Volume Fracture Treatment Combined with Forced Closure Yields Success in Clearfork Formation," 38th Annual Southwestern Petroleum Short Course, Lubbock, Tex, Apr. 17-18, 1991.

  15. Ely, J.W., and Haskett, S.E., "Field Experience With the GR Rheology Unit," Paper No. SPE 17715, SPE Gas Technology Symposium, Dallas, June 13-15, 1988.

  16. Ely, J.W., Wolters, B.C., and Holditch, 5.A., "Improved Job Execution and Stimulation Success Using Intense Quality Control," 37th Annual Southwestern Petroleum Short Course, Lubbock, Tex, Apr. 18-19, 1990.

  17. Ely, J.W., Arnold, W.T., and Holditch, S.A.,"New Techniques and Quality Control Find Success in Enhancing Productivity and Minimizing Proppant Flowback," Paper No. SPE 20708, 65th Annual Conference and Exhibition, New Orleans, Sept. 23-26, 1990.

  18. Ely, J.W., "Fracture Treatment Monitoring Quality control and Fluid Rheology Research," In Focus-Tight Gas Sands, April 1989, pp. 24-28.

  19. Schubarth, S.K., Wolters, B.C., and Ely, J.W., "New Fracture Design Effectively Places Proppant in Many Permian Basin Formations," Paper No. SPE 24007 SPE Permian Basin Oil & Gas Recovery Conference, Midland, Tex., Mar. 18-20, 1992.

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