HORIZONTAL DRILLING FOR IMPROVED RECOVERY

Based on a workshop sponsored by PTTC's Southwest Region on June 11, 1999 in Hobbs, New Mexico

BOTTOM LINE

In the proper reservoir application, horizontal wells yield higher production rates and recovery than vertical wells, yielding attractive economics even though cost may be twice that of vertical wells. Numerous technology advances continue to improve horizontal well performance and broaden application. Among those, underbalanced drilling with its many benefits has probably had the most profound effect.

PROBLEM ADDRESSED

Long reserve life indexes are no longer accepted. Operators are looking for technologies that will enable them to produce more of discovered reserves and produce them faster. Horizontal wells can be an attractive option for doing that because of their greater reservoir exposure, particularly in heterogeneous reservoirs. Horizontal well development can occur through new wells or re-entry operations, and can be single or multilateral applications.

KEY WORDS:

Horizontal drilling, Field case studies, Multilaterals, Underbalanced drilling

SPEAKERS

Horizontal Drilling Overview
Ross A.Clark , First Star Energy Ltd.

Multilateral Horizontals at Ratherford Unit
W.S. Storbeck, Consultant

Underbalanced Drilling Equipment, Design and Application
Bob Cuthbertson, Northland Energy Corporation

Revitalizing a Devonian Carbonate Gas Reservoir with Horizontal Drilling
Dana Rowan and Justin Hoffman, Texaco 211

TECHNOLOGY OVERVIEW

Formation damage is of particular concern in horizontal wells due to extended wellbore exposure times, mechanical filtercake erosion, potentially significant fluid losses, and poor post drilling cleanup. These are the driving forces behind the trend towards underbalanced drilling (UBD). Under- and over-balance refers to the pressure balance relative to bottomhole circulating pressure. Drilling can vary from controlled overbalance (to control differential sticking) to balanced (for unconsolidated reservoirs) to controlled underbalance (for fractured reservoirs,low pressure or low permeability gas reservoirs).

Other advantages of UBD include increased rate of penetration, real-time formation evaluation, and environmental/ economic benefits. Drilling costs can be lowered due to improved ROP, reduced drilling problems, improved bit life, and lower mud costs. Real-time formation evaluation allows for production testing, confirmation of water contacts, and an evaluation of production versus geology (i.e., is the production in this reservoir segment consistent with anticipations). Closed loop circulation systems with recirculation of produced gases provide environmental benefits. With less damage, wells clean up faster and produce at higher rates, providing strong economic incentives.

When planning UBD operations, one must consider both reservoir heterogeneities (porosity, permeability, etc.) and operational changes (during connections and bit trips, interrupted drilling operations, etc.) to maintain underbalanced conditions at all times. UBD techniques are field specific with results dependent upon the local geology and conditions.

There are three key engineering considerations in UBD techniques: (1) controlling gas and liquid ratios to reduce hydrostatic pressure to the bottomhole circulation pressure, (2) maintaining the combined bottomhole volumetric flow for optimum output from positive displacement motors, and (3) ensuring that liquid flow velocities are adequate for removing drill cuttings. Gas for UBD operations can be injected through a parasite string, through the drillpipe, or through a concentric casing scheme. Besides obvious weight considerations, UBD fluid design must consider reservoir and fluid compatibilities, well-bore stability, corrosion, flammability, hole cleaning and lubricity. UBD fluids can be either liquid or gas dominant. Gas-dominant UBD fluids provide improved hole cleaning capabilities. Their properties can be easily modified "on the fly."

UBD drilling equipment includes the drilling system itself (jointed pipe or coiled tubing), wellhead pressure control unit, a surface separation unit, a rig assist snubbing unit, and the inert gas supply system. Coiled tubing drilling systems are the best, although not without some disadvantages, including limitations on casing and drill bit sizes and directional control/wireline telemetry needs.

MWD-geosteering tools, which can involve both gravity and magnetic sensors, have limits in that they sense some distance behind the bit. Logging tools, which are continually evolving for horizontal applications, require special interpretation techniques to account for their sensing parameters in layers parallel to the tools themselves. Production logs are available to help define productivity along the horizontal leg.

Multilaterals allow operators to target several zones, achieving equivalent lengths at lower cost than with single laterals. Multilaterals minimize formation damage since less time is spent in each leg. Re-entry operations, which employ short- or medium-radius turns, are typically lower cost. Being re-entries, they provide better formation control.

Completions can be either open hole (needs stable hole), slotted liner (for sand control, support), cased, or some hybrid. Advantages of open hole completion are (1) more options to case the lateral after it has been produced and evaluated, (2) easiest and cheapest to perform selective stimulations on, and (3) provides the best production logs. With cased completions, external casing packers can be used to subdivide the lateral into different intervals. In that case, although production logging won't identify the exact source of production, it will narrow it down to intervals.

Horizontal Multilateral Drilling at Ratherford Unit, Utah. Mobil operates the nearly 13,000-acre Ratherford Unit in San Juan County, Utah. Carbon dioxide flooding is currently in progress in the field. Mobil first began using horizontal multilaterals in 1994. Often a well will have three laterals, an upper and lower lateral in one direction plus a middle lateral in the approximate opposite direction. From a completion standpoint, reentry guides allow entry into any lateral at any time. Coiled tubing use is used during completion and stimulation operations. Pay is stimulated with acid, using about 1/3 bbl per foot. Completion/stimulation costs average about $65/ft.

When multilaterals were first used in 1994, multilateral drilling costs averaged $358/ft. With experience and technology advances, these costs have dropped steadily through the years, reaching $103/ft in 1998-the latest year for which full data are available. Recent drilling programs have been very active with 16 wells with 39 laterals drilled in 1998. Combined footage drilled during 1998 was over 74,000 feet of multilaterals. Ninety-five percent (95%) of the drilled footage was within the pay zone itself. Horizontal displacement per multilateral averaged 2000 ft during 1998. Record 24-hr footage during 1998 of 1,846 ft in a multilateral was about a third more than resulted in 1997; reflecting that technology advances and experience continue to improve performance.

Horizontal Drilling to Revitalize a Devonian Carbonate Gas Reservoir, West Texas. Texaco operates the mature Bryant G Devonian Field, a shallow water carbonate reservoir, in Midland County, Texas. Initial development occurred in the mid-1960s with vertical wells, followed by a second wave of vertical well development in the mid-1990s. Cumulative production through the mid-1990s was about 31 BCF. Detailed reservoir modeling revealed heterogeneities amenable to tapping with horizontal wells. In recent years, development has focused on horizontal well development, from both new wells and re-entry drilling. Through mid-1999, 43 horizontal laterals have been drilled (19 new wells within the unit, 13 new wells outside the unit, and 11 re-entries within the unit). Considering data from 34 horizontal laterals, length averages 3,300 ft with average net pay of 1,320 ft. Lateral length ranges from 1,040 to 4,420 ft. Overall production has increased dramatically—production during just the last 3 to 4 years exceeds that experienced during the initial 30 years of field history.

CONNECTIONS:

Ross A. Clark
First Star Energy Ltd.
2100 801 6th Avenue SW
Calgary, Alberta Canada AB T2P 3W2
Phone: 403-221-7712, Email: rclark@firststarenergy.com

W.S. Storbeck, Consultant
414 W. Texas, Suite 208
Midland TX 79701
Phone: 915-682-3874, Email: wgstorbeck@aol.com

Bob Cuthbertson
Northland
1115 Goodnight Trail
Houston, TX 77060-1112
Phone: 281-999-1499, Fax: 281-821-9206

Dana Rowan
Texaco Inc.
P. O. Box 3109
Midland, TX 79702
Phone: 915-688-2944,
Email: rowande@texaco.com

For information on PTTC’s Southwest Region and its activities contact:
Robert Lee, Director, Petroleum Recovery Research Center
New Mexico Institute of Mining and Technology
801 Leroy Place, Socorro, NM 87801-4750
Phone 505-835-5685, Fax 505-835-6031, E-mail lee@prrc.nmt.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