HORIZONTAL DRILLING IN OIL SHALES

Based on a workshop sponsored by PTTC's Eastern Gulf Region on January 26, 2000 in Jackson, Mississippi

BOTTOM LINE

Improvements in horizontal drilling of fractured oil shale plays can have a steep learning curve. Attaining a cost-effective level of success can be related to efficiency of drilling, prop-er orientation of the horizontal leg to intersect the maximum number of fractures, avoiding formation damage, using appropriate mud systems, and avoiding early drawdown that will close fractures and cut off hydrocarbon drainage into the wellbore. Future success in drilling horizontal wells in the Tuscaloosa Marine Shale of the Gulf Coast may depend on adapting technologies developed in other basins.

PROBLEM ADDRESSED

A single successful horizontal well in the Tuscaloosa Marine Shale indicates that lessons and technologies must be transferred from other oil shale plays. Orientation of fractures controlling fluid flow should be determined to ensure proper orientation of the horizontal leg. Drilling slightly underbalanced and using oil-based muds in oil wet reservoirs may help to prevent formation damage. Unlike vertical wells, horizontal wells cannot be stimulated by sand proppant. Adequate circulation must be ensured to keep the wellbore clean, otherwise tool sticking is likely. Well testing may cause sufficient drawdown to close microfractures. Exploration strategies include mapping areas of thick black shale, peak hydrocarbon generation, fracture intensity, and drilling near good wells. Specialized maps may be very useful, such as and derivative maps to indicate zones of high fracture intensity.

KEY WORDS:

Black Shale, Fractured oil shale, Gulf of Mexico, Horizontal drilling, Microfractures, Tuscaloosa Marine Shale, Underbalanced drilling

SPEAKERS

Horizontal Drilling in Oil Shales: The Bakken
Julie Lefever, North Dakota Geological Survey

Fractured Oil Shale Reservoirs
Gary Lawyer, Exploration Methods, Inc.

Devonian Gas Shale Plays
Bob Cluff, The Discovery Group, Inc.

Application to Tuscaloosa Marine Shale
Wayne Upchurch, Trophy Petroleum Corp. and Randy Braswell, Worldwide Companies

TECHNOLOGY OVERVIEW

The workshop focused on the characteristics of oil and gas shales and on horizontal drilling in these shales. The objective was to transfer recent advances in horizontal drilling in oil shales to producers in the Eastern Gulf Region to facilitate development and production of oil from the Cretaceous Tuscaloosa Marine Shale.

Horizontal Drilling in the Bakken Shale. The first Bakken horizontal well, the #33-11 MOI, drilled by Meridian Oil, Inc., was initially drilled verti-cally. Core examination, logging and drill stem testing (DST) indicated that the formation was tight. Meridian then backed up the hole and kicked off at 9,782 ft. Horizontal drilling was attained at 10,737 ft with a resulting radius of 630 ft. The well was completed in September 1987 for 258 BOPD and 299 MCFD of gas. Horizontal displacement was 2,603 ft and it is still producing in the 8 ft thick upper Bakken shale. The well has produced 346,942 barrels of oil and 4,654 barrels of water through December 1998.

Cost for the #33-11 MOI well was $2 million; it took 57 days to drill. A third set of ten wells drilled by Meridian had an average cost of $1.08 million, averaging 35 days for drilling. By the end of the play, Meridian could drill and complete a horizontal well in the Bakken for about the same price as drilling and completing a vertical well, around $900,000.

Wells that performed poorly were fracture-treated, hoping that fractures would extend beyond the damaged zone to contact the larger regional fracture system that provides the conduit to the wellbore. Effective regional fractures also explain the discrepancy between permeability measurements from well testing and core analysis. Wells treated with gelled oil performed better than those treated with gelled water. Wells treated with water had difficulty unloading the fluid since water introduced into the fractures would cause reduced, near-zero oil relative permeability. Water could be acci-dentally introduced into the system by using a salt-based mud, acidizing the wellbore, or fracturing with water. Additionally, acid treatments could react with pyrite in the shales to form iron hydroxide precipitate. Medium radius wells require only 300 to 700 ft of vertical distance to reach the target horizon.

The medium radius approach is used because build rate is fast and can be easily controlled. Wells can have a long reach and are easily logged. Optimal wellbore length in Bakken examples ranged from 1,200 to 1,800 ft, although well orientation probably had more of an impact on production than the length of the well. Wells were drilled with a slightly underbalanced oil-based mud system to help control formation damage. Unlike vertical Bakken wells, it was not possible to successful-ly stimulate a horizontal well. Formation damage was minimized by drilling the lateral leg as quickly as possible.

A large part of the problems encountered while drilling horizontal wells were related to an inadequate amount of circulation to keep the hole clean. Because of this, tool sticking was common. After production began, periodic workovers were required to clean out fines from the bottom of the hole. This was usually done with nitrogen.

Fractures are sensitive to drawdown. Horizontal wells cannot be stimulated by sand proppant. Fractures in the shales are held open entirely by the fluid. Microfractures essentially act as the storage system and supply the larger regional fractures with oil. Significant drawdown on the well can cause the microfractures to close adjacent to the wellbore, sealing off the source of oil. This type of damage may be caused by drill stem testing. The damage to the microfracture system result-ing from testing is generally more significant than any information acquired by the test, especially since the DSTs rarely stabilize. Rapid drawdown during initial tests caused closure of microfractures in some wells.

For a horizontal oil shale well to be productive, it must encounter large vertical fractures with a significant amount of associated microfractures. Wells may suffer poor production due to lack of contacting enough frac-tures, contacting fractures with poor conductivity, or intersecting fractures at low angles.

Horizontal wells have a production decline rate and pattern essentially the same as that from vertical wells: sharp, steep decline over the first year followed by a more gradual to non-existent decline. Horizontal wells, however, had about twice the daily production and reserves of vertical wells. Horizontal wells lower drilling costs in the Bakken by 26%. The cost of drilling a horizontal well is about 1.5 times the cost of drilling a vertical hole. However, one horizontal well drains an area that would require two vertical wells and the payout is 1-2 years instead of 3-4 years for vertical wells.

Fractured Oil Shale Reservoirs- Examples from the Niobrara. Factors which affect fracture intensity and spacing include rock composition, grain size, porosity, bed thickness and structural position. Rocks composed of finer-grained particles or more brittle minerals will contain closer spaced fractures.

Factors contributing to a good fractured reservoir include early recognition of fractures, high fracture intensity with good continuity, good relation between reservoir and core porosity, high reservoir energy, no water influx, and, if the reservoir is deep or fine-grained, partial mineralization along fractures to help keep them open. Operators should consider drilling underbalanced or carefully balanced to reduce formation damage. Coring objectives with salt, polymer, or oil-based mud may also reduce formation damage. Operators may want to consider drilling shallow zones with air.

A wide variety of tools are useful to explore a fracture play including structure, isopach, and resistivity cut-off maps, lithologic and mineralogical data, matrix porosity contribution, mechanical rock properties, isopachs of structural deformation, type and orientation, stress-strain orientations, petrographical work, estimation of fracture spacing and width, evaluation of DSTs and flow rates, initial potential tests (IPs), whole core analysis, selection of appropriate suite of logs, burial history and maturation data. Specialized mapping (such as 2nd derivative maps indicating high fracture intensity) should also be considered. Several tools may be needed to determine which fractures contribute to fluid flow.

Devonian Gas Shale Play Characteristics. Devonian oil shales have produced gas since the mid-1800s and include some of the longest life reservoirs in existence. They are geographically widespread and of low geological risk. Devonian shales produce gas from the Appalachian Basin, the Michigan Basin, the Fort Worth Basin, the Illinois Basin, and the Anadarko Basin.

Reservoirs developed in Devonian shales have a num-ber of features in common. Fracture porosity is associat-ed with high permeability and dominates reservoir flow capacity. Fracture porosity is the focus of most explo-ration efforts. Natural high-angle fractures have been observed in nearly all cores. Black shale is brittle (frac-ture prone) but gray shale is ductile. There is a short term production kick, followed by a long, slow decline.

In contrast, matrix porosity in Devonian shales is asso-ciated with very low permeability. Porosity is present only as micropores associated with microfractures.

Well productivity in the Devonian shales shows a low rate (20 to 200 MCFD) but a long life. Decline curves typically include an initial steep region as fractures produce and a long low decline as the matrix desorbs gas. Although there is a huge resource base, wells in the Devonian shales drain small areas, probably 2-40 acres, and have low recovery efficiency of 5-10% of gas in place. Most production wells in Devonian gas shales are vertical. Horizontal wells have been tried several times, but have not clearly been better. It is possible that the horizontal leg of Devonian shale wells has been too short.

Exploration strategies include mapping areas of thick black shale, areas of peak hydrocarbon generation, mapping fracture intensity, as well as drilling near good wells. In general production economics are driven by proximity to pipelines, location relative to end users, drilling depth/cost window, fracture stimulation technology, and horizontal drilling opportunities.

Tuscaloosa Marine Shale Activity. Despite common oil and gas shows from wells in the Tuscaloosa Marine Shale, none so far has been an economical success. Diverse reasons for failure of these wells include failed frac jobs, formation caving, low production rate, and water problems. Significantly, some of these wells produced at low levels for a rela-tively long period of time before being shut in.

At least nine wells have tested the Marine Shale, which are listed here in chronological order: Humble #1 Spears (1962, Amite Co., MS) Sun Oil #1 Spinks (1971, Pike Co., MS) Callon Petroleum #1 Cutrer (1974, Tangipahoa Ph., LA) Callon #2 Cutrer (1975, Tangipahoa Ph., LA) Texas Pacific #1 Blades (1978, Tangipahoa Ph., LA) Dumay, Inc. #1 B.O.S. (1979, Pike Co., MS) UNOCAL #3 James (1991, Wilkinson Co., MS) UPRC #5 Richland Plantation (1998, E. Feliciana Ph., LA) and the Worldwide #1 Braswell (1998, Pike Co., MS). Of particular interest is the Worldwide #1 Braswell which was originally drilled as a vertical lower Tuscaloosa well which tested wet. In May of 1999, this well was drilled and re-completed as the first horizontal well in the Tuscaloosa Marine Shale. Although the well faced numerous drilling problems, and it would not flow all day during early tests, it continues to produce at a low rate through casing.

Two other significant wells that have penetrated the Marine Shale include the Exxon #1 Jackson 4-14 (1982, Amite Co., MS) which blew out and took 8 days to control. The well was reported to have flowed from a drilling break of 5ft/hr to 30ft/hr in the Marine Shale. The second well is the Amerada Hess #1 Montrose Plantation (1989, Wilkinson Co., MS) which blew out and burned after reaching total depth.

CONNECTIONS:

Julie LeFever
North Dakota Geological Survey
600 East Boulevard
Bismarck, ND 58505-0840
Phone: 701-328-8000, Fax: 701-328-8010 e-mail jlefever@rival.ndgs.nd.us

Paul N. Lawless
CNG Producing Co.
1450 Poydras St.,
New Orleans, LA 70110
Phone 504-593-7000,Fax: 504-593-7342 E-mail paul_n_lawless@cngp.cng.com

Gary Lawyer
Exploration Methods, Inc.
2988 Pear Circle, St.
George, UT 84790
Phone 435-656-0242 e-mail gplawyer@infowest.com

Bob Cluff
The Discovery Group, Inc.
1560 Broadway, Suite 1470,
Denver, CO 80202
Phone: 303-831-1515,Fax: 303-831-1551 E-mail bobcluff@discovery-group.com

Wayne Upchurch
Trophy Petroleum Corporation
5201 Cedarpark Dr., Suite L,
Jackson, MS 39206
Phone 601-981-5349, Fax 601-366-1124

For information on PTTC’s Eastern Gulf Region and its activities contact:
Ernest A. Mancini, Professor of Geology University of Alabama
Box 870338, 202 Bevill Bldg., Tuscaloosa, AL 35487
Phone: 205-348-4319, Fax 205-348-0818, E-mail emancini@wgs.geo.ua.edu

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