Scott R. ReevesAdvanced Resources International Inc. Arlington, Va.
William K. MorrisonNomeco Oil & Gas Co. Jackson, Mich.
David G. HillGas Research Institute Chicago
Downhole pumps and refracturing are two ways D to significantly improve production rates from the Antrim shale, a tight formation in the Michigan basin (U.S.) and the objective of a major natural gas play.
Candidate wells for restimulation can be identified by pressure build-up tests, and specifically productivity index-vs.-permeability plots based on these tests.
The work in the Bagley East B4-10 well illustrates the possible production improvement.
ANTRIM SHALE
The Antrim shale of the Michigan basin contains a large resource of unconventional natural gas, currently estimated to be more than 76 tcf. The natural gas play is one the most active in the U.S., accounting for more than 10% of all gas well completions in 1991.
In June 1992, 2,270 Antrim shale wells produced 192 MMcfd of natural gas from the main producing trend of the basin.
Despite the high level of development activity, current techniques for completing, stimulating, and producing Antrim shale wells can be improved to maximize gas recovery from this unconventional gas reservoir.
The Antrim shale is a shallow, underpressured, naturally fractured shale reservoir with characteristically low matrix permeability. Sorbed gas, free gas, and mobile water co-exist in the reservoir system.
Early in its life, a typical Antrim well produces considerable quantities of water. As dewatering of the reservoir progresses, water production rates decline and usually gas production increases. This production performance is similar to coalbed methane wells.
Because of the opportunities this resource offers, the Natural Gas Supply Department of the Gas Research Institute (GRI) has targeted the Antrim shale as a focus of research. Specifically, one of GRI's primary research goals is to improve gas production economics from the Antrim shale through a better understanding of reservoir mechanisms, and hence through improved production practices.
One immediate prospect for enhancing gas production and reserves from Antrim shale wells is to use mechanical pumping methods for well dewatering to lower flowing bottom hole pressures (FBHPs). Lower FBHPs should increase gas desorption and relative permeabilities to gas, thereby improving well performance. The most common dewatering practice in the Michigan basin is the reverse gas-lift technique. In this method, high-pressure gas is injected down the tubing/casing annulus and the co-mingled stream of produced gas, injected gas, and formation water is produced up the tubing.
The bottom of the tubing is typically located 10-20 ft above the top producing interval. Flowing bottom hole pressures can be as high as 250 psia, or 50-60% of the reservoir pressure.
Mechanical pumping systems, however, can lower the FBHPs to very low values, approximately 50 psia, provided that wellhead pressures are kept low and the pumps are positioned close to or below the producing intervals.
BAGLEY EAST PROJECT
A cooperative field re- search project was initiated by GRI during 1991 specifically to investigate the potential of mechanical pumping to lower FBHPs and hence improve the production performance of Antrim gas wells. The project team, led by Advanced Resources International Inc., included Nomeco Oil & Gas Co., Robbins & Myers Inc., and Bach Oilfield Services.
An eight-well test pattern, configured similar to a conventional nine-spot and located in Nomeco's Bagley East project in Otsego County, Mich., was selected for the project site (Fig. 1).
Production from the Antrim shale typically is from the lower Antrim shale, consisting of the Norwood, Paxton, and Lachine members. These members lie above the Traverse Group and below the combined Ellsworth shale, upper Antrim, Bedford shale, and Berea sandstone (Fig. 2).
Current production at the Bagley East project, similar to that of the rest of the play, is from the organically rich Norwood and Lachine members of the lower Antrim. These two horizons average 20 ft and 80 ft thick, respectively, at Bagley East. The top of the Lachine occurs at approximately 1,400 ft.
The Paxton member (an organic-poor gray shale) lies between the Norwood and Lachine and averages 40 ft in thickness at Bagley East.
The primary gas storage mechanism in the Antrim shale is adsorption, which has profound implications for production practices. Low FBHPs are required to achieve gas production. A widespread reservoir pressure drawdown (with efficient dewatering) is necessary to desorb gas in quantities suitable for commercial production.
Reservoir properties important to understanding this process include methane adsorption isotherms (amount of gas adsorbed in the shale as a function of reservoir pressure) and shale permeability. These parameters were both measured at Bagley East. Methane adsorption isotherms for the Norwood and Lachine members (Fig. 3) illustrate why it is very important to create a widespread reservoir pressure drawdown for maximum gas production.
For a typical initial reservoir pressure of 450 psia, a drawdown to 140 psia, or 31% of the initial reservoir pressure, is required to desorb 50% of the in-place gas in the Lachine and make it available for production. For the same result in the Norwood, the reservoir pressure must also be reduced to 140 psia.
Because Antrim gas wells normally produce significant volumes of water, averaging 28 b/d/well after 15 months at Bagley East, the greatest potential for reducing FBHPs is by minimizing the hydrostatic pressure exerted on the producing shales by water fill-up in the well bore, i.e., through optimized well bore dewatering methods. Permeability is another important reservoir parameter measured at Bagley East. Permeability influences the pressure drawdown that occurs at the outer reaches of the shale reservoir when FBHP is reduced in a producing well.
As permeability increases, it is more likely that a favorable pressure drawdown can be achieved at the drainage boundaries. Base line production, during reverse gas lift, and subsequent pressure build-up tests on all eight wells in the project, estimated the permeability prior to installing a pump in Well C3-10, at the center of the pattern.
The test results are in Table 1. Production averaged 47 Mcfd and 28 b/d water at an average FBHP of 182 psia. This FBHP is approximately 49% of the average extrapolated reservoir pressure as determined from the pressure build-up tests. The high FBHP is the drawback of the reverse gas-lift artificial lift method.
Permeabilities to gas and water averaged 0.2 and 0.6 md respectively, and skin factors ranged from -4.7 to 0.6, averaging -2.6.
Well C3-10 was producing 43 Mcfd and 12 b/d water at a FBHP of 137 psia. The permeabilities to gas and water for this well were 0.10 and 0.12 md, respectively.
Fig. 4 shows the gas productivity index-vs.-gas permeability for all the wells in the project.
The wells exhibiting a high degree of stimulation, average skin factor of -3.8, fall on a line characterized by a high slope. This line indicates that these wells have a greater gas productivity index for a given gas permeability than the less-stimulated wells.
Wells B4-10 and D3-10, which pressure build-up tests show to be unstimulated (skin averaging 0.3), lie on the line with less slope.
Well B3-10, skin factor of -2.3, plots between these two trends. The characteristic that wells with similar skin factors plot on the same line can be used to identify wells with the greatest potential for recompletion.
As an example, if Well B410 were restimulated such that its position on the plot shifted from the unstimulated line to the stimulated fine, its productivity index would be expected to increase by a factor of between 2'/2 and 3. This implies that production would also proportionally increase for the same well bore pressure drawdown.
Therefore, this well would be a good candidate for recompletion. Lowering the FBHP should further improve gas production.
BENEFITS OF PUMPING
To evaluate the benefits of pumping Antrim wells, a progressing cavity pump was installed in the center well of the project, C3-10. The well, TD at 1,350 ft, has 7-in. surface casing to 973 ft, 41/2-in. production casing to 1,546 ft, and 1. 9-in. tubing to 1,385 ft. Both the Lachine interval, 1,417-1,432 ft, and the Norwood interval, 1,5111,526 ft, were perforated with two shots/ft.
Well C3-10 was pumped on an intermittent basis for approximately 6 weeks. Fracturing proppant flow back from the original stimulation of the well, 15 months earlier, created difficulties in maintaining a contiguous pumping operation, and two workovers were required during this project.
Therefore, the three separate periods of pumping were characterized by a different downhole pump assembly and system performance. The periods correspond to the original pump installation and the two modified downhole pump assemblies required because of gas interference and sand production.
However, in each case, the pump was above the Lachine perforations. The tendency of fracturing sand to flow back and accumulate in this well created a risk of sticking the pump in the hole if put below the producing horizons. The first pumping phase was characterized by the pump intake being across the Lachine perforations and without any downhole gas/water separation equipment.
After 8 days, the pump stator was entirely worn due to gas interference. A new assembly was installed to correct this problem.
As before, the pump position was maintained above the Lachine perforations. However, for safety reasons the tubing intake was lowered to below the Lachine perforations by using a dip tube that permitted some degree of downhole gas/ water separation.
This system performed adequately for 8 days, until fracturing sand originating from the Lachine passed through and accumulated above the pump, inside the tubing. The sand prevented continued pump operation.
To eliminate sand problems, a third downhole assembly was run and positioned entirely above the Lachine perforations. Included was a "poor boy" downhole gas/water separator for minimizing gas interference problems.
The FBHP in the final pumping period was reduced to 64 psia compared to 137 while on reverse gas-lift production (Fig. 5).
During maximum well bore drawdown, gas production averaged 90 Mcfd or 109% more than the production with reverse gas lift (Fig. 6).
This clearly demonstrates that even moderate reductions in FBHPS, 73 psi in this case, can significantly improve Antrim gas well production.
RESTIMULATION
The difficulties associated with fracturing proppant flow back during pumping suggest that sand control is important in Antrim shale wells that are on pump.
To control the sand, many Antrim operators, who are currently converting wells from reverse gas-lift to pumping, refracture the well with a small treatment containing a resin-coated sand to lock the near-well bore proppant into place and prevent sand flow back.
As noted earlier, however, an additional and perhaps more important benefit of refracturing is the restimulation of wells that were not effectively stimulated originally or that experienced a deterioration in stimulation through time, e.g., by proppant flow back, proppant plugging, etc.
The pressure build-up tests indicated that some wells at the Bagley East project, specifically wells B4-10 and D2-10, are plagued by such post-stimulation problems. To test the benefits of restimulation in older Antrim wells, the Bagley East B4-10 well was refractured in the Norwood and Lachine members, one treatment per zone (Table 2).
Following this operation, the well flowed naturally at 166 Mcfd, a significant improvement from 62 Mcfd prior to restimulation.
This improvement is consistent with the anticipated 21/2 to 3-fold increase expected from the productivity index plot (Fig. 4), and suggests that restimulations can be highly effective at improving the performance of some Antrim wells.
A pump was subsequently installed in the well to further improve gas production and to verify that proppant flow back was effectively controlled with the treatment. Production improved to 255 Mcfd. The fluid level remained at 500 ft above the perforations, and no proppant flow back was evident.
Gas flow rates of 340 Mcfd occurred over brief periods during pumped-off conditions. Fig. 7 illustrates the staged improvement in the production performance of well B4-10.
FIELD IMPROVEMENTS
Several months after this GRI/Nomeco cooperative research project began, the jointly developed production enhancement technologies were applied throughout the Bagley East field.
In the subsequent 4 months, average gas production in the field increased by 94%. Much of the credit can be attributed to the operator's acknowledgment of the value of production technology and its application in the field.
Fig. 8 shows the average per-well production from the Bagley East project for the 18 months ending June 30, 1992.
BIBLIOGRAPHY
1. Decker, D., Coates, J-M.P., and Wicks, D.E., "Stratigraphy, Gas Occurrence, Formation Evaluation and Fracture Characterization of the Antrim Shale, Michigan Basin," GRI Topical Report, GRI 92/0258, October 1992.
2. Kuuskraa, V.A., Wicks, D.E., and Thurber, J.L., "Geologic and Reservoir Mechanisms Controlling Gas Recovery from the Antrim Shale," SPE Paper No. 24883, SPE Annual Technical Conference and Exhibition, Washington, D.C., Oct. 5-7, 1992.
3. Maness Petroleum Corp., Monthly Antrim Shale Gas Production, January 1991-june 1992.
4. Reeves, S.R., and Wicks, D.E., "Field Projects in the Antrim Shale, The Bagley East Project," GRI Topical Report, GRI 92/0419.1-0419.2, October 1992.
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