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“Independent’s day” at spe/doe 2002 improved oil recovery symposium |
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Based on a workshop Co-sponsored by the Symposium and PTTC's North and South Midcontinent Regions. Presentations during special PTTC session held on April 16, 2002 in Tulsa, Oklahoma.
Current activity in Oklahoma coalbed methane in the Northeast Shelf and Arkoma Basin reveals a viable source of new gas reserves. As in most coalbed methane basins, completion and stimulation practices have a major influence on well productivity and ultimate economics. For conventional oil and gas wells, solid propellant stimulation treatments are proving a low-cost option for increasing productivity. In certain Midcontinent reservoirs producing high water, such as the Arbuckle in Kansas, larger volume gel polymer treatments using MARCITSM technology are proving effective. When wells must be plugged, as all will ultimately be, industry is evaluating lower-cost options to control this exit cost.
Independents must apply new technologies across a broad spectrum of operations-from development of new reserves, such as coalbed methane, to well stimulation to water shut-off to well abandonment to increase their profitability.
Alternative Plugging Technology, Coalbed Methane in Oklahoma, Gel Polymer for Water Shut-off in the Midcontinent, Solid Propellant Stimulation
Oklahoma Coalbed Methane Exploitation
Brian J. Cardott, Oklahoma Geological Survey
Arkoma Basin Coalbed Methane Potential and Practices
John H. Wendell, Jr., Wendell Consulting LLC
Low-Cost and Environmentally Sound Plugging of Abandoned Wells
Larry Watters, Outpost Enterprises, Inc.
Recent Advances in the Use of MARCITSM Gelled Polymers to Economically Decrease Water and Increase Oil Production in the Kansas Arbuckle Formation
J.T. Portwood, TIORCO, INC.
The Gas GunTM-Stimulating Oil and Gas Wells with a Solid Propellant
Richard Schmidt, J Integral Engineering, Inc.
Oklahoma Coalbed Methane Exploitation
More than 1,400 wells in Oklahoma have been drilled exclusively for coalbed methane (CBM) since 1988, in part for the IRS Section 29 tax credit. The Oklahoma commercial coalfield covers about 8,000 square miles in 21 counties in eastern Oklahoma. The coalfield is divided into the northeast Oklahoma shelf and the Arkoma basin. Commercial coal beds are of Desmoinesian (Middle Pennsylvanian) age. Coal beds are 0.1 to 6.2 ft (0.03 to 1.9 m) thick on the shelf and 0.1 to 7.0 ft (0.03 to 2.1 m) thick in the basin. Coal rank, as generalized for all coals at or near the surface, ranges from high-volatile bituminous on the shelf and western Arkoma basin to medium- and low-volatile bituminous in the eastern Arkoma basin in Oklahoma. Rank increases from west to east and with depth in the Arkoma basin, attaining semianthracite rank in Arkansas.
A database of CBM completions records 825 completions on the northeast Oklahoma shelf and 617 completions in the Arkoma basin. Operators presently target ten coal objectives on the shelf and five in the basin. The primary CBM objectives are the Mulky (342 wells) and Rowe (342 wells) coals on the shelf and the Hartshorne coals (575 wells) in the basin.
Coal completion depths range from 256 to 2,428 ft (78 to 740 m) and average 947 ft (289 m) in 738 wells on the shelf, and 347 to 3,726 ft (106 to 1,136 m), averaging 1,421 ft (433 m) in 535 wells in the basin. Initial-potential gas rates range from a trace to 260 Mcfd (average 27 Mcfd) from 663 wells on the shelf, and a trace to 1,150 Mcfd (average 106 Mcfd) from 467 wells in the basin. The maximum initial gas rate was reported in the Hartshorne coal at a true vertical depth of 1,604 ft (489 m) from a horizontal well in Haskell County.
The first horizontal or lateral CBM well in Oklahoma was completed in August 1998. By the end of December 2001, 83 horizontal CBM wells (13% of 617 completions) had been completed in Haskell, Le Flore, and Pittsburg Counties reported by 5 operators. IP gas rates in the horizontal wells were 15 to 1,150 Mcfd (average of 345 Mcfd) at true vertical depths-to-top of coal of 752 to 3,031 ft (229 to 924 m). Higher initial gas rates are possible in a horizontal well than in a single-bed vertical well by drilling at a high angle (perpendicular to oblique) to the face cleat to drain a larger area. Vertical CBM wells exhibit an elliptical drainage pattern as a result of the directional (anisotropic) permeability of the cleat. Horizontal CBM wells are completed open hole. The lateral distance within the coal for 54 horizontal CBM wells ranged from 439 to 2,523 ft (134 to 769 m), with an average of 1,442 ft (440 m).
Initial produced-water rates range from 0 to 1,201 bwpd (average 60 bwpd) from 643 wells on the shelf, and 0 to 320 bwpd (average 19 bwpd) from 416 wells in the basin.
A coal with favorable characteristics for CBM (e.g., high rank, high gas content, thick, laterally persistent) can result in a poor CBM well if the well completion is inadequate. Coal is a brittle reservoir. Coal fines are often generated during well stimulation and may seal off the permeability. Much is known about the coal geology of the Oklahoma coalfield (e.g., number of coal beds, age, depth, thickness, rank, quality). The present emphasis is on finding permeable sweet spots and matching coal bed characteristics to optimum completion techniques.
Arkoma Basin CBM Potential and Practices
Critical factors to Arkoma Basin CBM producibility include:
Low-Cost and Environmentally Sound Plugging of Abandoned Wells
Plugging Systems, LLC has developed an economical and environmentally sound plugging method that combines off-the-shelf technologies and engineering design calculations. The new plugging application meets regulatory requirements and satisfies the environmental aspects that drive those requirements.
In the United States alone, an estimated 620,000 stripper oil and gas wells (wells at the end of their producing life with production rates of less than 10 bbl/day) are ready to be plugged, along with 350,000 idle wells. These estimates are growing as previously unregistered wells are discovered and uneconomical wells are shut in at greater rates than wells are plugged.
The traditional plugging process requires a workover rig to set up over the well and run tubing, and a cementing service company to mix and pump slurry to create a balanced plug downhole, and additional plugs uphole and at the surface, as required. The current plugging method has several inherent problems: (1) it can require several visits to the location by service company personnel and equipment, (2) the balanced plug is unstable because of density differences between well fluids and cement, and (3) the cement slurry is subject to severe settling and segregation because of its components and the large volume of water used for dilution.
The new plugging method uses technical and operational components from several industries in combination with candidate selection and an engineering design package to create a process that is applicable in most U.S. wells currently requiring plugging. The only equipment required is a modified, off-the-shelf concrete pump that can be towed to the wellsite by one worker in a pickup truck.
Candidate wells must be less than 6,500 ft deep (deeper wells can be plugged, but may require intensive design), have a fluid level some distance below the surface to ensure that pore pressure of exposed formations is less than a water gradient, and have sufficient injectivity into the exposed formation to accept well fluid injection at a rate sufficient to place the plug in an acceptable time period.
With the new plugging method, the slurry is mixed and delivered to the well with a ready-mix truck (a self-contained batch mixer), providing a simple, economical method of delivering the slurry to location without requiring dedicated equipment onsite.
Cement slurry design must drive placement through hydrostatic pressure without breaking down formations. Additionally, the slurry must produce plugs that meet all regulatory requirements. The new plugging method uses ASTM Type 1 (API Class A) cement, which is readily available from construction concrete yards. Water and up to 200% binder are added to obtain a slurry density of 14 to 18 lb/gal. Retarding materials are also added to make the cement manageable for a longer time period. For a typical job, the cement slurry can have fluid time of 8 to 10 hours to ensure delivery to the location and placement in one or more wells. The stable cement composition allows all plugs to be placed accurately-and in one trip.
The new technique's pumping unit is designed to place cement slurries in low-pressure applications, but can typically create pressure up to 1,200 psi. Wiper plugs separate the slurry from other well fluids during placement and provide continued separation after placement. These wiper plugs form a stable platform on which the cement can be set. As the wiper plug is placed in the wellbore, the cement slurry is pumped on top. Because of its weight, the cement becomes the driving force-falling to the bottom of the well, pushing the wiper plug forward, and forcing existing air and produced fluids back into the formation.
Once a well is properly plugged and sealed with the new method, no trace of the plugging operation is left on the surface, with the exception of the faint traces of the road that was originally built to carry the drilling equipment to the site.
MARCITSM Gel Polymer Applications for Water Shut-off in Midcontinent
Gel polymers have a long history in the Midcontinent. Recent large volume treatments using MARCIT technology in Kansas Arbuckle producers are proving quite effective for controlling water production and increasing oil recovery. Success results from two factors-the MARCIT technology itself and using much larger volumes, 1,500 to 5,000 barrels versus the few hundred barrels historically used.
With MARCIT technology, dry polymer is mixed in water and crosslinked with chromium triacetate at the surface, as opposed to previous systems where polymer and crosslinker mix in the reservoir. Gels having viscosity slightly greater than fresh water to rubber can be created in virtually any water, at temperatures up to 240 °F, in high TDS, H2S and CO2 environments. Surface mixing, more robust formulations, and simpler chemistry (only two chemicals) improve gel reliability.
When selecting producer candidates, one should look for (1) significant remaining mobile oil, (2) wells producing at or near their economic limit due to high water production, (3) wells with high fluid levels, (4) natural water-drive reservoirs, and (5) high permeability contrast between oil- and water-saturated rock (i.e., vuggy and/or fractured reservoirs). The new thinking on sizing treatments is to estimate the daily fluid capacity at maximum drawdown, and use an equivalent volume of gel.
Before pumping gel, the wellbore should be cleaned using 350-500 gal 15% NEFE acid pumped away with water. Operators should also run a step-rate test to establish a maximum treating pressure. Polymer-compatible biocide should be used in the mix water, and if produced water is used, lab testing to design the gel is recommended. Gel should be injected at a rate below or equal to the maximum producing rate, staying below the reservoir parting pressure. Stages of increasing polymer concentration are normally used. Treatments should be over-displaced with oil or water to clear the near wellbore conductivity area.
Since November 1997, 21 wells in three fields have been treated using these larger treatments-Bemis Schutts (17 wells), North Hampton (3 wells) and Blue Hills (1 well). Economic success rate has been 100%, with payouts of total (polymer, plus well preparation and workover ) costs being less than six months. Incremental reserves are estimated at more than 540,000 bbls for three leases in the Bemis Schutts field. Finding costs in three leases in the field range from $0.59 to $2.35 per incremental barrel. Savings in water handling costs alone exceed $1.4 million. To date, lessons learned include: (1) acidizing to clean the wellbore is important, (2) end treatment when surface pressure reaches 100 to 200 psi, (3) overflush to clear conductivity paths around the wellbore, and (4) use as much gel as economically feasible.
Solid Propellant Stimulation with the GasGunTM in the Midcontinent
Many oil and gas wells can be effectively stimulated with a new gas-generating solid-propellant tool known as The GasGun. The tool incorporates a progressively burning solid propellant that generates gas at a rapid rate, which creates multiple fractures radiating 10 to 100 feet from the wellbore. The progressive burning formulation means that the rate at which the propellant burns increases with time, producing gas faster as the material is consumed. Independent research conducted by Sandia National Laboratories showed this formulation to be much more effective than other propellants in controlling peak pressures and in advancing fractures deep into the formation by saving energy until late in the fracturing process when crack volumes are the greatest.
The fracture network removes damage and increases formation permeability near the wellbore. Potential applications include removing skin and damage, preparing formations for acidizing or hydraulic fracturing, stimulating naturally fractured reservoirs or lenticular sands, increasing injection and withdrawal rates in gas storage wells, and improving waterflood efficiency. The process is an economic alternative to hydraulic fracturing and other stimulation methods. Various problems associated with hydraulic fracturing, such as breakout into water-bearing zones, are avoided. Production increases have been long lasting and many treatments have been paid out in one to two weeks.
Compared to hydraulic fracturing, advantages include much lower cost with minimal onsite equipment needed, little vertical growth out of pay, multiple fractures, entire zone stimulated, and low formation damage from incompatible fluids. Compared to explosives, there is no compaction zone or stress cage, pressures last longer for deeper fracture penetration, there is less cleanup and it is easier and safer to handle.
Tools are wireline-conveyed and can be used in open hole or cased wells. Formulations for cased-hole application burn somewhat slower, which reduces the peak pressure and generally avoids damaging the casing. To contain the energy, the tool is covered with a 300 to 5,000 foot fluid tamp. Tools are fielded through wireline companies, with services now available in Illinois, Kansas, Kentucky, Ohio, Oklahoma, and most recently, Texas's Permian Basin.
Over 500 GasGun stimulations have been conducted to date. Approximately 100 wells have been treated in Kansas with successful applications in the Arbuckle dolomite, Mississippi chert and Tarkio limestone. In the Kansas Arbuckle, treatments are used to create a fracture network in the pay while staying out of the nearby water zone, followed with an acid treatment to open and etch the fractures. There also have been numerous applications in the Illinois Basin, two of which are documented in PTTC/World Oil's Petroleum Technology Digest (http://www.pttc.org/case_studies/PTdigest9-01.htm). That case study includes a table (as of Sep 2001) showing where other treatments have been performed. The latest information and extensive field results are available from the J Integral Engineering website (http://www.TheGasGun.com).
Brian Cardott
Oklahoma Geological Survey
100 East Boyd St., Rm. N131
Norman, Oklahoma 73109
Phone: 405-325-3031 Fax: 405-325-7069
Email: bcardott@ou.edu
John H. Wendell, Jr.
Wendell Consulting LLC
1501 Thomas Place
Fort Worth, Texas 76107
Phone: 817-271-4802 cell Fax: 817-731-1553
Email: jwendell@redwineresources.com
Larry Watters
Outpost Enterprises, Inc.
1618 Jones
Duncan, Oklahoma 73533
Phone: 580-255-0191
Email: Larry.Watters@outpostinc.com
JT Portwood
TIORCO, Inc.
P.O. Box 820488
Ft. Worth, Texas 76182-0488
Phone: 817-431-6336 Fax: 817-431-6337
Email: jtportwood@mindspring.com
Richard Schmidt
J Integral Engineering, Inc.
165 SW Tualatin Loop
West Linn, OR 97068
Phone: 503-557-1370 Fax: 503-655-7309
Email: jintegral@thegasgun.com
For information on PTTC’s North and South Midcontinent Regions and
their activities contact:
Rodney Reynolds, Project Manager, Kansas University, Energy Research Center
1930 Constant Ave., Lawrence, Kansas 66047-3726
Phone 785-864-7398, Fax 785-864-7399, Email reynolds@cpe.engr.ukans.edu
Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.
The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.
Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org;
web www.pttc.org
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