Horizontal Drilling, Real Michigan Field Experience

Based on a workshop organized by PTTC Midwest Region, Michigan Satellite held in Mount Pleasant, Michigan on March 20, 2003

BOTTOM LINE

From majors through very small independents, producers are drilling profitable horizontal wells/laterals/dual laterals in Michigan in application environments ranging from Niagaran reefs, carbonates, and Stray Sandstones to gas storage fields. Economic results indicate that wells don't necessarily have to be big wells to be profitable. Numerous case studies presented insights about locating horizontals, drilling, logging and production operations.

PROBLEM ADDRESSED

Independents in particular rely on field case studies as they make decisions about new technologies. Horizontal drilling is no longer a new technology, but there are still many applications where it could be used if producers had greater confidence in their ability to profitably execute horizontals. This workshop focused on case studies of horizontals being profitably applied in several different environments in Michigan. 

KEY WORDS:

Application-Gas Storage, Primary, and Secondary, Horizontal Drilling, HydraJet Fracture Stimulation, Logging Horizontal Laterals, Niagaran Reef Development, Permitting, Rod Pumping Horizontals

SPEAKERS

Permitting, Bonding and Other Aspects of Horizontal Wells in Michigan,
Tom Godbold and Tom Wellman, Michigan DEQ

Shell's Niagaran Horizontal Drilling Results,
Mike Fairbanks, SEPCO Michigan Operations

Horizontals For Compartmentalized Reefs, Case Studies,
Dennis Schmude, Schmude Oil, Inc.

Developing SOMOCO Novi 29 Reef with Highly Deviated and Horizontal Wellbores,
Chris Wood, Petroleum Engineer

Horizontal Well Downhole Rod Pump Recommendations,
Randy De Werff, Harbison-Fischer

Six Lakes Gas Storage Horizontal Drilling Project,
Robert Bomar and Ed Dereniewski, Michigan Consolidated Gas Company

Horizontals in Michigan, Successes and Failures,
Kip Howland, Consumers Energy

Horizontal Drilling in the Kawkawlin Dundee Field,
Mike Mesbergen, Muskegon Development Company

Options for Horizontal Well Logging,
Ken Moss, Baker Atlas

Hydrajet-Fracturing Stimulation (SurgiFrac),
Buddy McDaniel, Halliburton Technology Center

TECHNOLOGY OVERVIEW

Permitting, Bonding and Other Aspects of Horizontal Wells in Michigan. Horizontal wells must conform with existing spacing requirements. Exceptions may be obtained through a hearing or a Rule 303 Spacing Exception. Rule 303 pooling must be 100% voluntary. Rule 202 requires a new permit for directional redrills from an existing well to a different bottom hole location. A Change of Well Status Application is required to continue drilling a well below permitted depth, but within the permitted stratigraphic or producing horizon where drilling completion or well completion has occurred. If a well will be plugged back and kicked off above the producing formation, a new permit and bonding are required. If kicked off and horizontally drilled within the existing producing formation, then it can be permitted as a Change of Well Status. The pilot hole and each horizontal drainhole receive individual API numbers.

Shell's Niagaran Horizontal Drilling Results. Since its first Niagaran horizontal in 1986, Shell has drilled 76 Niagaran horizontals. Activity peaked in 1991 with 31 horizontals being drilled. Activity continued strong through 1998, but has since dripped to only a well or so per year. Activity dropped because good reef candidates had been drilled and Shell's experience is that horizontals are not attractive in lower quality reservoirs. Current activity is primarily focused on keeping existing horizontals going.

There are two general drilling objectives—to produce remaining oil under large secondary gas caps in well developed reefs or to develop discontinuous pay in tight, poorly developed reefs. Horizontals are both re-entries using 20 - 100 ft radii or new wells with 200-500 ft radii. The typical horizontal is 4 3/4-in open hole of 300 to 2,000 ft length. Problems experienced in horizontals include: (1) excess gas production, (2) impairment or formation damage, (3) artificial lift and (4) casing failures.

Typical solutions for excess gas production are to perm-seal the curve, case the curve, or set an isolation packer. When only a small portion of the horizontal is producing, high drawdown from that interval can lead to excess gas production. Underbalanced drilling will help avoid formation damage, but stimulation with acid may still be required. Inflatable packers can be used, but they are not reliable for open hole treatments with large differential pressures. In a couple wells, cased and perforated horizontal completions have been used to allow selective stimulation.

Artificial lift problems include gas interference in pumps and excess backpressure in low pressure reservoirs. Downhole gas separators are generally successful in resolving gas interference problems. To reduce backpressure, pumps can be lowered into the laterals themselves. Six casing failures have been experienced in laterals with cased curves. Modified completion and operational practices are addressing casing damage problems.

Horizontals for Compartmentalized Reefs, Case Studies. Michigan reefs are notoriously inhomogeneous with major compartmentalization evident, particularly in salt-plugged reefs. This inhomogeneity and compartmentalization make horizontals well suited, but they must be correctly placed. When properly placed, horizontals can find undrained oil, new compartments or higher pressures. General experience is that potential will be greatest on the basin-ward side of the reef. Examples from five separate reefs were presented to illustrate how horizontals have been effectively employed.

Developing SOMOCO Novi 29 Reef with Highly Deviated and Horizontal Wellbores. Initial development well for the SOMOCO-Novi 29 reef was the 35 degree directional well, Commerce Bank Trustee 1-29. From first production in 1992 through 2000, it had produced over a quarter of million barrels of oil from the Brown Niagaran and underlying bitumen zone. Ultimate recovery from that initial well was estimated at about 358,000 barrels plus 109 Mmcf. In 2000 the Commerce Bank Trustee 1-29 was re-entered, kicked off and a 417 ft lateral with a 272 ft spur drilled to produce additional oil from the southeast edge of the reef. For a workover cost of only $175,000, production more than tripled. A second horizontal well has subsequently been drilled into the north end of the reef. Combined, the incremental reserves attributed to horizontal development are estimated at 283,000 barrels of oil and 1,240 Mmcf.

Horizontal Well Downhole Rod Pump Recommendations. Rod pumps can be placed above the curve in a straight section, in the curved section and in the horizontal section itself. Placement in the straight section enables one pump to drain multiple laterals and operations are most normal. However, backpressures can be too high and gas separation is often a problem. Placement in the curve lowers the backpressure, but it also places the most stress on the pump. Expected pump life is only about 30% of that experienced with conventional vertical placement. Expected pump life increases somewhat when placed in the horizontal, to about 60% of traditional vertical placement. Placement in the horizontal also achieves the lowest back pressure on the formation. Rod pumps have been run through curves with buildup rates up to 30 degrees per 100 feet, but use in curves of 20 to 24 degrees per 100 feet is most common. Mold-on rod guides are advised. Bottomhole separation is critical.

Six Lakes Gas Storage Horizontal Drilling Project. Facing a historic 5.6% per year deliverability decline in its Six Lakes Gas Storage Field in Michigan, Michigan Consolidated Gas Company drilled its first horizontal well in 1993. There are now 20 horizontal wells, including eight dual-leg wells. The first dual-leg horizontal well was drilled in 1999. In drilling wells, surface casing is set at 650 ft and the kickoff point is about 750 ft. The turn is then made and 7-in production casing set in the pay zone. The lateral(s) are then drilled and completed as 6-1/4-in open hole completions. Lateral length varies from 1,007 ft to 3,459 ft with most recent laterals being in the 2,500+ ft range. Drilling times are generally favorable. All together, there is now nearly 70,000 foot of pay exposure in horizontal wells.

In the recent 2001-2002 drilling program, costs for the well and initial horizontal leg of average 2,712-ft length was $307,000. This equates to about $113 per foot of open hole section. Since separate location, cement, casing, and wellhead equipment costs are not incurred when a second leg is drilled, costs for that second leg drop significantly-to just $41 per ft of open hole section or $100,000 for an average 2,433 ft second leg. This cost differential explains why dual legs are now strongly preferred. Although horizontal cost is 2.7 times vertical well cost, deliverability is up to 15 times higher. With horizontals there is now nearly 70,000 ft of open hole pay zone exposure. Horizontal wells have reversed the historic deliverability decline and now provide more than half of field deliverability.

Horizontals in Michigan, Successes and Failures. Common targets for horizontals in Michigan are the A2 carbonate, the Michigan Stray Sandstone, and Niagaran reefs. Different drilling and completion practices have evolved for each.

A2 carbonate reservoirs are tight limestone/dolomites with hairline fractures and vugs. Anhydrite filling of vugs and fractures is common. For A2 wells, curves are typically 300 ft radii. 5 ½-in production casing is set through the curve (typically 300 ft radiuses) at 90 degrees and rigid- and bow-type centralizers are used extensively. MWD tools are used exclusively to drill 1000 to 2000 ft laterals. Tri-cone bits are used. When completed, coiled tubing with blast tool is used to acidize the entire open hole section, followed by a flush with a fresh water/surfactant solution. Open flow potentials are typically more than double average vertical wells.

Michigan's Stray Sandstone fields are lenticular reservoirs with lenses often overlapping. Often there are two distinct zones separated by shale with the lower zone being the target zone. Production casing and curves are similar to A2 carbonate horizontals. Although MWD is most common, some wireline steering is used. PDC bits are used exclusively. Wells are typically drilled slightly overbalanced. Following initial flow back and cleanup, coiled tubing with a blast tool is used to hydro-blast the entire open hole section with a weak acid or fresh water/surfactant solution while flowing the well. Open flow potentials are 3 or more times average vertical wells.

Niagaran reef reservoirs are vuggy dolomites with often thick pay zones. 7-in production casing is typically set at 45 degrees 20 ft into the reef, then the rest of the curve drilled. Both PDC and tri-cone bits are used. Although most wells have been drilled slightly overbalanced, underbalanced drilling is gaining favor. Drilling rates of 1 ft/min are not unusual. Penetration rates are held back to avoid well kicks. Lateral lengths of 1,000 to 2,000 feet are common. The entire open hole section is acidized with 10-20,000 gals of 28% HCl, then flushed with fresh water/surfactant solution. Open flow potentials ten times those of average vertical wells are common. 

Horizontal Drilling in the Kawkawlin Dundee Field. Horizontals are being employed in the very mature Kawkawlin Dundee field. Production in Kawkawlin comes from two porosity zones separated by tight limestone. Pay averages 30 feet from both zones. Discovered in 1938, production peaked at about 500 bopd then declined rapidly. The unit has been under waterflood since the 1960s. Prior to the horizontals, unit production was 50-55 Bopd. Most wells still produced, but individual wells were only producing 0.5 to 2 Bopd. Six laterals were drilled, two per year in 1996, 1997 and 1998. Four were "A Zone" wells and two were "B Zone" wells. Combined incremental production from the six laterals has been about 35 Bopd. "A Zone" wells have been better wells, exhibiting higher productivity and encountering higher pressure. Even though they are not big wells, "A Zone" wells still pay out in less than two years using $22 oil prices. Opportunities to improve productivity include drilling laterals in both zones, placing second legs in each lateral, and selective acidizing of intervals. If successful, these opportunities would significantly improve economics of future horizontals.

Options for Horizontal Well Logging. To date, there have been four logging conveyance systems used in Michigan horizontals-pump down, push down, pipe-conveyed, and coil-tubing conveyed. Pump down services are most popular, being low risk and low cost. Logs that have been pumped down include gamma ray/neutron, PDK-100, production logging, and perforating. Internal diameter of the pump down string must be continuous for swab cups to work properly. Push down services use a slotted sub located at the bottom of the tubing. The wireline is pinned into the slot and the tubing is then run into the well pushing wireline tools to the desired location. Tubing is then removed, wireline services performed and the tools pulled from the well. The suggested maximum depth is 7000 ft. Push down services are popular on high angle and horizontal wells to convey through casing services. Services that have been pushed down include gamma ray/neutron, compensated neutron, cement bond logs, jet casing cutters, and perforating. Pipe-conveyed or coil tubing-conveyed logging are seldom used in Michigan since they are costly since equipment and personnel must be brought in (at least for Baker Atlas) from the Gulf Coast.

Hydrajet-Fracturing Stimulation (SurgiFrac). Hydrajet-fracturing technology developed by Halliburton Energy Services combines hydrajetting and hydraulic fracturing technologies. Called Surgifrac, the tool/process enables one to perform separate, sequential fracture stimulations in horizontal laterals at multiple locations without the need for mechanical sealing devices. The process uses the dynamic movement of the fluid to divert fluid flow into a specific point in the formation. It requires controlling and evaluating two primary fluid flows and requires two separate pumping systems. The annulus must be pressured at manageable flow rates. It provides highly accurate control of fracture initiation and propagation, a matter of great importance in horizontal wells. The approach is relatively new, having been used in some 65 wells worldwide (as of 8/20/02). Of those 65 wells, 57% are considered economic and technical successes, another 32% were technical successes, and only 11% were definite failures. For more information, review SPE papers 78697, 77905 and 74331 available online at www.spe.org.

CONNECTIONS:

Robert Bomar
Senior Geologist
Michigan Consolidated Gas Company
10450 Nevins Road
Six Lakes, MI 48886
Phone: 989-365-5115
Email: Bomarr@dteenergy.com

Edward Dereniewski
Senior Reservoir Engineer
Michigan Consolidated Gas Company
500 Griswold Street
Detroit, MI 48226
Phone: 313-256-6626
Email: dereniewski@dteenergy.com

Randy De Werff
Harbison-Fischer
1421 North Court Street
Grayville, IL 62544
Phone: 618-375-3841
Email: Rdewerff@hfpumps.com

Mike Fairbanks
SEPCO Michigan Operations
1510 Thomas Road
P.O. Box 610
Kalkaska, MI 49646
Phone: 231-258-6440
Email: Michael.Fairbanks@Shell.com 

Tom Godbold
Michigan DEQ
P.O. Box 30256
Lansing, MI 48909
Phone: 517-241-1545
Email: Godboldt@michigan.gov

Kip Howland
Consumers Energy
1945 W. Parnall
Jackson, MI 49201
Phone: 517-788-1038
Email: Kshowland@cmsenergy.com

Buddy McDaniel
Halliburton Technology Center
2600 South 2nd Street
Duncan, OK 73533
Phone: 580-251-3829
Email: Buddy.Mcdaniel@Halliburton.com 

Mike Mesbergen
Muskegon Development Company
1425 South Mission Road
Mount Pleasant, MI 48858
Phone: 989-772-4900
Email: Mdcmyler@aol.com 

Ken Moss
Baker Atlas
2222 Enterprise Drive
Mount Pleasant, MI 48858
Phone: 989-773-7992
Email: Ken.Moss@bakeratlas.com 

Dennis Schmude
Schmude Oil, Inc.
P.O. Box 1008
Traverse City, MI 49685
Phone: 231-947-4410
Email: Schmudeoil@aol.com 

Tom Wellman
P.O. Box 30256
Lansing, MI 48909
Phone: 517-241-1530
Email: Wellmant@michigan.gov

Chris Wood
Petroleum Engineer
13685 S West Bay Shore, Suite 105
Traverse City, MI 49684
Phone: 231-941-4051
Email: Corsair23@aol.com 


For information on PTTC’s Midwest Region and its activities contact:

Steve Gustison 
Illinois State Geological Survey
615 East Peabody Drive, Champaign, IL 61820
Phone 217-244-9337
Email: gustison@isgs.uiuc.edu

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