FRACTURING TECHNIQUE STIMULATES MASSIVE, FRACTURED LIMESTONES
Jim Wilke
Western Co. of North America
Oklahoma City
Jean Harris
Park Avenue Exploration
Oklahoma City
Sammy Graham, Dan Holloman, Jack Ward
Western Co. of North America
Yukon, Okla.
The Kiel fracture process has been rediscovered as an alternative to pad/acid treatments in the Viola formation of central Oklahoma County, Okla.
In recent years new treatment techniques have been developed in the Midcontinent region, while many older techniques still remain in use. The Viola formation in central Oklahoma County, Okla., is a reservoir where different techniques are being used.
Some operators are stimulating the Viola limestone formation with a conventional pad/acid treatment. Others have been willing to try something new or look at proven technology from similar reservoirs.
GEOLOGY
The Viola formation (Trenton-Viola 1) is generally known as a massive limestone group of middle Ordovician age. The formation was named after the village of Viola in Johnson County, Okla., and occurs subsurface throughout most of Oklahoma.
The Viola group consists of a fine-grained limestone, up to 800-ft thick, that was formed by shallow-water sedimentation interrupted by several depositional periods. 2
Erosional debris is present in the lower part of the Viola group. This debris decreases upward as the strata grades to a clean-washed skeletal limestone.
The Viola Dense, which lies near the top of the Viola group, is a horizon of compact limestone. This characteristic, as well as regional faulting, isolates the Viola producing intervals and allows for trapping of hydrocarbons and connate waters.
Because of geological faulting and uplifting, the Viola contains many natural fracture networks. These natural fractures allow the Viola to be produced as a commercial oil and gas reservoir.
The matrix porosity ranges from 4.0 to 1.0%. Because of this low porosity, connecting the natural fracture networks is essential for commercial hydrocarbon production.
The Viola also contains quantities of connate salt water. Dissolution of salt and secondary calcium carbonate deposition can cause blockage of the natural fractures.
Because this dissolution and deposition of blocking materials occurs over time, the problem can exist in older producing wells just as in unstimulated wells. Stimulation techniques have attempted to address both blocking mechanisms.
KIEL FRACTURING
The Kiel dendritic fracture process 3 was developed as an alternative method for stimulating a hydrocarbon-bearing carbonate zone and increasing the zones production rates and recoverable reserves.
The process was invented by Othar M. Kiel in the early 1970s.
Water and sand fracture treatments had been performed in many formations prior to this. However, Kiel's technique implemented several shut-down and flow-back phases in addition to pumping large volumes of water with minimal quantities of sand.
The Kiel fracture process was developed from earlier hydraulically induced subsurface fracture technology in hydrocarbon-bearing formations. The main emphasis of the technique was to incorporate many long secondary (dendritic) fractures along a primary fracture.
As fluid is pumped into a zone, an hydraulic fracture is created in the direction of least principle stress. Generally, this is parallel to the stress fractures or joints in a dolomite or limestone reservoir.
If the hydraulic fracture remains in a parallel orientation to the joints and natural fractures, the treatment may only affect the production of fluids within the single fracture. However, if the fracture is bridged off with blocking materials, the continuing fracture may change orientation by as much as 60-90 from its original direction. 4 The new orientation will allow other joints to be interconnected with the main fracture and increase the total drainage area.
The two types of materials used as diverting/blocking agents are sand (100 or 20/40 mesh) and limestone /dolomite spauls. 3
Sand, added to the injection fluid at surface, and carbonate spauls, created within the reservoir, generally bridge off in the larger lateral fractures. This allows the main fracture to continue extending away from the well bore.
These materials also scour the fracture as the fluid propagates the fracture away from the well bore. The scouring clears any secondary calcium carbonate deposition from the fractures.
If the velocity within the main fracture does not remain high enough to transport the proppant further down the fracture, bridging will occur at the tip of the main fracture. This bridging is identical to a "tip screenout" common in propped fracture theory.
Two additional stimulation mechanisms occur in the Kiel fracture process. The same materials that have been used as diverting/blocking agents act as propping agents to interconnect the natural fracture networks.
After completing the pumping process, the sand and spauls remaining in the fractures will impede the fractures from reaching closure and effectively prop open the fractures created between the natural fractures.
Finally, the large volumes of freshwater pumped will redissolve salt deposits occurring in the natural fracture networks. These two mechanisms allow for longer sustained flow rates and producible volumes.
The pumping procedure begins with a group of slicked freshwater fluid stages and sand stages. Generally, sand concentration is 1-4 ppg. These single stages, referred to as events, are pumped into the zone at high injection rates. This process is usually repeated four to six times (Table 1).
Pumping is temporarily terminated after sufficiently overdisplacing the last sand event. A valve is opened at the surface to allow for the first "reverse flow" phase of the treatment .3
Kiel's theory states that the main benefit of the flow back will be developed due to the creation and placement of spauls within the current fractures. The flow back creates spauls caused by the sudden pressure drop along the fracture and reverse flow of fluids within the fracture. The sand events create spauls by colliding sand with the fracture face.
The spauls are nothing more than fragments of the formation that flow into the fracture from the fracture walls. As the pumping resumes, the spauls and sand events bridge off the existing fractures. The bridge diverts the fracture extension energy into other directions, thus potentially interconnecting the natural joints.
This reverse flow technique is implemented twice near the end of each stage (Table 1). All of this procedure is repeated three to five more times to complete the treatment process.
TREATMENT DESIGN
Over the last several years, several different methods for determining a treatment design have been used by the authors. Kiel established several equations and relationships to calculate the volume and rate schedules required for each stage of a treatment. 3-5 The equations and an example calculation are shown in the example box.
The pump schedule is divided into stages (usually four or five, as previously mentioned) and each stage has several events. The base fluid consists of freshwater containing bactericides and friction reducers. In some cases, surfactants and paraffin dispersants are included.
The first event fluid volume is equal to the displacement volume of the treatment conductor. The next ten events alternate from pad fluid to sand-ladden fluid.
Each sand-event fluid volume (Events 2, 4, 6, 8, and 10) is equal to the pumping rate divided by two. Event No. 11 is primarily an over-flush event which follows the last sand event. The fluid volume in Event 11 is equal to the displacement volume plus 100 bbl.
The final fluid event volume is equal to two thirds of Event No. 11's volume.
Finally, the pad/spacer event fluid volumes (Vep) are calculated.
After these volumes have been calculated, each event's volume is rounded to the nearest 10 or 25 bbl, whichever is appropriate for the injection rate.
EQUIPMENT REQUIREMENTS
The surface equipment necessary to perform a Kiel fracture treatment is extensive (Figs. 1 and 2). Generally, the treatments are performed through 4-1/2 or 5-1/2-in. casing strings at high injection rates. Occasionally, due to well conditions, 3-1/2-in. tubing strings have been used.
These high injection rates can only be attained with multiple pumping units, A treatment of 60 bbl/min at 3,000 psi requires 4,412 hydraulic hp, or a minimum of four pumping units on-line.
The pumps and blender are hooked up to the wellhead in a conventional manner. However, an additional flow line must be rigged up from the treating line back to an empty frac tank for the reverse flow flowback stages (Fig. 2). Up to three frac tanks may be necessary on some wells.
This additional line terminates prior to the frac tank with a three or four valve manifold (1 and 2 in. full-opening plug valves). This valve manifold is then connected to the frac tanks. The manifold arrangement allows for flow through by as many as four valves, or as few as one 1 in.
FRACING THE VIOLA
Generally two different types of stimulation systems have been common in the Viola limestone formation in Oklahoma County over the last 2 years. Historically, the pad/acid system has been the fluid of choice on many Viola limestone formations.
However, recently the Kiel fracture process has proven to be an effective alternative.
KIEL TREATMENTS
The Viola formation Kiel frac treatments in central Oklahoma County have been designed based on several adaptations of the Kiel design theory. The injection rates have ranged from 40 to 60 bbl/min. Treatment conductor size (and pressure limits) more often than the actual zone size has determined the rate. For a 3-1/2 in. conductor, the rate is 40 bbl/min. The injection rate increases to 50 bbl/min for a 5-1/2 in. conductor.
While the injection rate is based mainly on the successful completions of many fracture treatments, the fluid volumes, ranging from 75 to 100 bbl/ft of zone, have been based on the size of the zone.
For a 50-ft zone, 100 bbl/ft and 1,250 bbl/stage are commonly used.
The bbl/ft decreases for a 75-ft zone to 80 bbl/ft, but the total bbl/stage increases to 1,500 bbl. For a 100-ft zone, 75 bbl/ft and 1,875 bbl/stage are typical.
Generally, a four stage treatment procedure has been used (Table 1). The main procedure includes six sand divertant/fluid-loss events separated by six slicked-water pad events. The actual treatment cost, associated with the stimulation service companies, ranged from $15,000 to $40,000, with the majority averaging between $27,500 and $30,000 (Table 2).
However, this cost does not include water and frac tanks that can range from $3,500 to $7,000. The lower cost water was available from fire hydrants located near the well sites.
Ultimately, the goal of any stimulation process is to increase the well's production rates.
Following the Kiel fracturing process on the studied wells, the production rates for oil, natural gas, and water are tabulated in Table 3.
The initial oil production rate ranged from 713 to 7 bo/d.
Note, however, that the well with an initial potential of 7 bo/d produced 1.343 MMcfd of gas.
The initial natural gas production rates ranged from 1.7 MMcfd to no gas production at all (the latter occurring in a dry oil zone).
Initial water production rates have ranged from 583 bw/d to no water production at all.
These production rates have equated to as much as a 20 fold increase over the initial prefracture flow rates.
PAD/ACID TREATMENTS
Most of the Viola formation pad/acid fracture treatments in central Oklahoma County have been designed with injection rates ranging from 30 to 35 bbl/min. The rate is based on the treatment conductor size (and pressure limits) more often than the actual zone size (similar to the Kiel fracture process). This design is used mainly because of the highly fractured nature of the reservoir and the ultra-high fluid leak-off that occurs.
Gelled pad fluid volumes, ranging from 15 to 30 bbl/ft of zone, have been based on the zone size as well as the gelled or retarded acid volumes that have ranged from 7.5 to 15 bbl/ft of zone.
Generally, a four or five stage treatment procedure has been used with alternating stages of pad and acid. In some treatments, divertant stages have been pumped ahead of the alternating pad stages.
The actual treatment cost of the stimulation service has been from $20,000 to $30,000, with most running about $24,000 to $26,000 This again does not include the cost for water and frac tanks for the gelled water portions of the treatment. Those costs range from $750 to $1,500. Again, the lower cost water was available from fire hydrants located near the well sites.
Unfortunately, for those advocates of pad/acid treatments, most wells in this study that were stimulated in the last 24 months with pad/acid-type treatments have either been plugged back or refractured with the Kiel fracture process. Well 13 was refractured.
Only a few wells, such as Well 20, have been outstanding after stimulation with the pad/acid.
The initial oil production rate has ranged from 708 to 0 bo/d. In some cases, production increased 10 fold over prefracture flow rates.
ACKNOWLEDGMENTS
We would like to thank Oexco Inc. and Park Avenue Exploration for providing the production results; Bill Orr for preparing the computer graphics of the equipment layout; and Park Avenue Exploration and Western Co. of North America for permission to publish this article.
REFERENCES
- Jordan, Louise, Subsurface Stratigraphic Names of Oklahoma, Oklahoma Geological Survey, Guidebook IV, 1957, pp. 193 and 201.
- Amsden, Thomas W., et. al., Geology of the Southern Mid-Continent, Oklahoma Geological Survey, Special Publication 89-2, 1989, p. 7.
- Kiel, Other M., Hydraulic Fracture Process Using Reverse Flow, U.S. Patent No. 3,933,205, 1976.
- Ward, Jack, The Kiel Frac Process, Western Co. of North America, 1983.
- Kiel, Other, unpublished notes from discussion with author Jack Ward, 1988.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.