D. Nathan Meehan
Union Pacific Resources Co.
Fort Worth
About this report. . . .
Horizontal well technology produces oil and gas reserves that otherwise might never have been developed. Union Pacific Resources has taken advantage of this new technology to revive production from the tight, fractured Austin chalk trend of Texas. In Canada, horizontal well activity has surpassed the activity level in the U.S. One niche in Canada is improved oil recovery from both heavy and light oil reservoirs. Advances also are being made in describing the complex inflow performance of horizontal wells.
Applying technology to all phases (planning, drilling, completion, stimulation, and production) of horizontal well projects is vital to maximize hydrocarbon recovery and profitability.
Union Pacific Resources Co. (UPRC) has drilled more than 1,100 horizontal wells since 1987 and continues to operate about 15-20 rigs drilling horizontal wells.
Technology has advanced the drilling, completion, formation evaluation, stimulation, and production of horizontal wells. Drilling breakthroughs include dual-powerhead mud motors, retrievable whipstocks, and routine multiple lateral wells. Cost improvements have enabled UPRC to extend activity into deeper zones, which are hotter and more hostile.
State-of-the-art drilling includes as many as four, 4,000+ ft horizontal laterals, horizontal wells at TVDs greater than 16,000 ft, and mud weights in excess of 15 ppg.
Horizontal drilling requires a variety of advanced technology for successful implementation. Some of these technologies have been developed on a proprietary basis by operators; however, most have either been developed by or have been made available to service companies for commercial implementation. Thus, operators competing for leases generally will be able to access key technologies.
The most significant competitive advantages in horizontal well applications are obtained by fully capturing the value offered by technological advances1 and by promoting the use of such technologies.
In the Austin chalk (Fig. 1)(44129 bytes), UPRC operates properties producing more than 480 MMcfd, 40,000 bo/d, and over 100,000 bw/d.
Horizontal wells
Horizontal drilling is not a new idea; however, by 1986, less than 50 modern horizontal wells had been drilled worldwide. This number rose dramatically in the next few years as booms occurred in the Pearsall and Giddings Austin chalk fields and in the Bakken formation in North Dakota and Montana. Activity levels flattened in the U.S. and horizontal drilling stabilized at about 8% of the rig count.
Fig. 2 (32468 bytes) illustrates recent North American horizontal well activity. Canadian activity has grown dramatically and has outstripped U.S. horizontal drilling in 1994 and 1995. UPRC has drilled horizontal wells in more than 14 formations in North America, starting in the Austin chalk trend in 1987.
UPRC had a significant land position in the Giddings (Austin chalk) field as a result of vertical well activity. Economic potential for vertical well drilling was extinct, with only an extensive campaign of water fracs2 enabling UPRC to maintain a large leasehold position.
By mid-1995, UPRC had drilled more than 1,100 grass roots horizontal wells and more than 1,250 horizontal laterals. UPRCs cumulative investment in wells, pipelines, facilities, land, gas plant expansions, etc. for the Austin chalk alone is in excess of $1.1 billion. The estimated full cycle rate-of-return associated with this investment is 19%.
Fig. 3 (23135 bytes) illustrates the growth in net Austin chalk production. The total net reserve addition is more than 115 million BOE (barrels of oil equivalent based on 6 Mscf = 1 BOE).
Austin chalk
Low matrix permeability, naturally fractured reservoirs like the Austin chalk may have high initial flow rates associated with the rapid production of the oil contained in the natural fracture systems. Subsequent declines are often precipitous as the majority of the hydrocarbons are stored in the low-permeability matrix.
Understanding the nature of the distribution of natural fractures is critical to horizontal drilling. Austin chalk horizontal wells often recover the majority of their reserves and income in the first few years. While overall margins are often modest, quick payouts can lead to attractive rates-of-return. Decreasing drilling costs is one of the most critical issues in maximizing profitability in such plays.
Formation evaluation
It is surprising that the majority of North American horizontal wells have no open hole logs. The challenges and complexities of logging horizontal wells are described in References 3-8.
Costs for horizontal well logs are higher than for vertical wells because of the mechanics and difficulties associated with negotiating hole curvature and conveying the tools to bottom without gravity. Horizontal wells require the use of:
- Drill pipe-conveyed logs,
- Logging-while-drilling,
- Pump-down logs, or
- Coiled tubing conveyed logs.
What was the spacing, azimuth, intensity, etc. of the natural fractures encountered? Various tools to evaluate natural fractures in horizontal wells are reviewed in References 5 and 6.
UPRC identified oriented microresistivity devices to be most useful in identifying small fractures, predicting well productivity, and in identifying stimulation candidates. The actual benefits from logging many of UPRCs early horizontal wells were far greater than expected.
A few of the early surprises included the consistency of fracture strike. Most natural fractures were vertical to subvertical and parallel.9 Fracture direction tended to parallel the maximum horizontal compressive stress (sH) and was not directly tied to structure.
Well bore breakouts in vertical wells could be used to predict fracture strike and the optimal direction for horizontal wells. Essentially, no fractures were observed at directions other than the primary direction, leading to large permeability anisotropies and the potential for significant interwell interference.7
Small fractures frequently terminate at thin (1 cm) shale streaks, marls, or styolites. Slightly larger fractures may be offset at such barriers and may not hydraulically connect adjacent layers. Larger faults and fractures may propagate through shale intervals in excess of a few meters. References 2 and 7-10 review the in situ and laboratory evidence associated with this observation.
The impact of these observations was critical for subsequent operational decisions. Huge permeability anisotropies led to much wider optimal spacing, requiring far fewer wells. Interference between wells more than 8,000 ft apart was not uncommon.7
The economic benefits of being able to drill wells on larger spacing was critical to commercial field development and avoiding the drilling of hundreds of unnecessary wells. Zonal isolation meant that traverse wells (wells that crossed the entire chalk interval) would be much less attractive than wells that remained in the most intensely fractured intervals. This indicated a need to improve the ability to stay in zone and to a need to drill more than one horizontal lateral per well.
Geological steering
Early horizontal wells targeted a formation depth and were drilled at a prescribed angle using geometric steering. Geosteering technology is steering horizontal wells while drilling using the geological and geophysical measurements made while drilling.8 This process11 has been successful in maintaining well bores in the desired interval, identifying redrill candidates, and in drilling multiple laterals. It would have been very difficult to develop this technology without a critical mass of horizontal well logs.
While there are commercial technologies available for geosteering, UPRC developed a proprietary internal method that has been vital to UPRCs success.
Muds
UPRCs experience with horizontal wells includes drilling in areas of substantial depletion and in gas areas with a high pressure (14 ppg) gradient. Mud issues often dominate the economics of drilling in such areas.
Lost circulation is common in drilling horizontal wells in naturally fractured reservoirs. It is preferable to avoid extensive skin damage. The loss of large fluid quantities is clearly undesirable. Many of the wells UPRC drilled required weighted muds or brine.
Fig. 4 (22549 bytes) shows the estimated ultimate recovery (EUR) for six similar wells requiring drilling fluids of 10-11 ppg. Lost circulation was much less in the wells drilled with mud and the resulting EURs for the wells drilled with mud were significantly greater than those of the wells drilled with brine.
The average cost of the brine wells in this study was $1.5 million, or $200,000 greater than the mud wells. For marginal wells, the net present value (NPV) is often less than $200,000.
Another unconventional mud approach is the use of mud caps. In these applications, the annulus is shut in and the wells are drilled without returns. Water is pumped down the drill pipe and is lost to the natural fracture system along with the cuttings. Mud on the annulus provides pressure control.
Applications for mud caps include very low-pressure formations with severe lost circulation potential and very high-pressure intervals. They are widely used in applications where both high and low-pressure fractures may be encountered.
In one application at 14,000 ft TVD, UPRC drilled two laterals in a 13.5 ppg environment. The standpipe pressures required to pump water in such a system approached 5,000 psi, nearing the limit of the 1,600 hp mud pumps. However, these laterals were successfully drilled with a total mud cost of $500,000. A nearby well was drilled conventionally with returns with a total mud bill of $1.2 million with only one lateral.
Fig. 5 (65408 bytes) shows drilling and development cost trends.
Top drives
The drill bit can be rotated by either surface drives that transmit torque using the entire drillstring or by downhole motors. Most low-cost land rigs (such as those used by UPRC) are equipped with surface drives using a rotary table. Highly deviated wells increasingly used top-drive rigs. Top-drive rigs are common offshore, on the North Slope, and increasingly for onshore applications.
Top-drive rigs have several advantages over conventional rotary rigs because the torque is generated in the traveling block. This allows longer stands and results in greater power. Most importantly, for directional and horizontal applications, the top-drive rig permits circulation and rotation while pulling out of the hole.
UPRC has funded the conversion of several rigs to portable top-drives by guaranteeing a certain amount of use for manufacturers who agreed to convert top-drive units for portable use on UPRC-operated rigs.
This was enormously successful and led to multiple competitive products entering the market. The result has been improved safety and significant cost savings for complex wells.
For some wells (such as a routine 10,000 ft TVD normally pressured well with a 4,000 ft lateral) cost savings associated with a top-drive are minimal. Deeper wells and higher-pressured wells usually justify the use of the top-drive units.
Bit selection
Cooperation with bit manufacturers in bit design and testing has resulted in dramatic performance improvements. Specifically, the use of polycrystalline diamond compact (PDC) bits has been outstanding (Fig. 6)(22864 bytes).
Often, UPRC combines PDC bits with mud motors in the shallower, vertical well bore to improve penetration rates. An additional benefit of this approach is a significant decrease in drill pipe washouts. Technological advances in bit selection have been driven primarily by the manufacturers working with the oil companies to rapidly evaluate new designs.
Mud motors
Another example of how UPRC has pushed horizontal drilling technology forward is the development of the dual-powerhead mud motor and the subsequent development of extended motors.11 The ability to increase penetration rates (typically 50% or greater) with this technology has led to its use in virtually every horizontal well UPRC drills.
In 1992, a 500 ft/day drilling rate in the lateral was considered good. This benchmark now has essentially doubled.
One early concern was the potential for increased bit wear. In reality, the smoother torque provided by the extended length motors enables UPRC to use longer cutters and greater weight with less breakage of cutters. The net effect has been improved bit life. Dramatically higher penetration rates accelerate steering errors, so that the necessity of a team effort in geosteering is increased.
Multiple laterals
Multiple laterals (Fig. 7)(66632 bytes) are now routine at UPRC. These include stacked laterals (SL) to access multiple horizons or poorly communicated layers within a formation and opposing laterals (OL) drilled in the same intervals in opposite directions. Arbitrary combinations of these approaches have enabled UPRC to routinely drill multilaterals with four or more horizontal laterals.
Drilling very long horizontal laterals is achievable for distances of 8,000 ft or more. However, the ability to steer the horizontal lateral is severely diminished as the lateral exceeds 3,000-4,000 ft. Torque and drag issues and solids transport problems also complicate ultra-long medium radius wells. The use of OLs minimizes these problems while providing two conventional length horizontal wells with only one surface location, wellhead, vertical hole, etc.
When surface/location costs are large and steering is crucial, OL technology is most attractive for deep wells with significant costs to reach the target formation. Fig. 8 (23873 bytes) shows a typical days depth chart for a multiple-lateral well drilled with a dual-powerhead mud motor and a conventionally drilled dual lateral.
Geosteering of the second lateral is generally improved because of the better reservoir characterization information provided by the first lateral.
Risks in multiple lateral technology include potential damage to open laterals while drilling subsequent laterals and potential difficulties in logging, re-entering, selectively stimulating or shutting off water production, and production logging.
Retrievable whipstocks
It is possible to drill multiple laterals with all laterals open, but operational and safety concerns make it preferable to isolate previously drilled horizontal laterals while drilling and testing subsequent laterals.
The primary application for retrievable whipstocks is when lateral isolation is required. They are also used when liners must be run in multiple laterals, when re-entering cased, in vertical wells with multiple laterals, and when casing problems require isolation during drilling.
UPRC funded the development of one type of retrievable whipstock and provided testing grounds for other designs.
Water fracs
So called water fracs have been successful in the Austin chalk formation, but with mixed results elsewhere.7 This treatment uses high volumes of water but no proppant. Potential mechanisms include imbibition, gravity drainage, skin damage removal, and repressurization of the reservoir to enhance recovery.
UPRC has treated about 270 vertical and over 200 horizontal wells. Incremental recoveries from horizontal well water fracs alone exceed 6 million BOE.
Begun as a vertical well stimulation, these high rate treatments (70 bbl/min for vertical wells, 150 bbl/min for horizontal wells) allowed UPRC to maintain significant landholdings and to acquire numerous marginal vertical wells. Successes with vertical wells led to tests with horizontal wells.
Improved diversion was obtained by alternating stages of freshwater, wax beads, and acid. Other diverting materials (rock salt, liquid gels, etc.) were tested, with wax beads remaining the diverter of choice.
These beads are lighter than water and are used in slugs of 1,000-6,000 lb/stage at concentrations of 0.5 ppg. Detailed examples are provided in Reference 7 along with potential explanations of the mechanisms involved.
Vapor-recovery units
Vapor-recovery units (VRU) are installed to recover natural gas that would otherwise be vented from storage tanks. Low-pressure separation occurs at 25-35 psi, and stock tanks are near atmospheric pressure. Some additional gas flashes with this final pressure drop. The best candidates include retrograde condensate reservoirs and wells producing 4-10 Mcf/st-tk bbl of 50-55 API gravity condensate.
While there are no environmental requirements for UPRC to install such devices, the use of VRUs is often economic. In the first 40 VRUs installed, UPRC recovered between 10 and 200 Mcfd of rich gas, which is compressed and sold. Cash flow has been increased by about $1 million/year with these devices.
Most VRUs are leased and can be moved with relative ease.
Artificial lift
Gas lift and rod pumps are the main artificial methods employed for Austin chalk horizontal wells. Gas lift is most effective for high fluid volume (1,000 b/d) wells and for lower-pressure wells with GORs that make them impractical to rod pump.
Early gas lift designs used as many as 14 gas-lift stages. Optimization has reduced this number to about 5 stages combined with a screened orifice just above the packer. The gas lift valves are permanent-type valves located in sidepocket mandrels. The screened orifice permits lower gas-injection pressures when the fluid level has declined.
Higher-GOR wells (15 Mcf/st-tk bbl) may be gas lifted to mitigate the effects of liquid loading. These wells may have one or two gas lift valves combined with a screened orifice. Such wells require intermittent gas injection that is often supplied by portable compressor units.
Rod pumps are used for all other wells as soon as they are unable to flow at acceptable rates. Extensive experimentation with placing the pumps deep into the bend or in the horizontal lateral resulted in substantial increases in rod wear, tubing wear, and pump failures with minimal improvements in well performance.
Pumps are typically placed near the casing shoe at angles ranging from 0 to about 30. In the most deviated wells, rod guides and tubing rotators are employed to minimize wear.
Automation
During the early life of horizontal wells, high oil, gas, and (frequently) water rates are common. These wells often justify increased attention from production engineers and field personnel.
Horizontal wells have been demonstrated to drain much larger areas than vertical wells and are correspondingly placed on larger unit sizes. While many horizontal well units are on about 320 acres, many exceed 640-acre spacing, leading to greater travel time between wells for pumpers, gaugers, etc.
The necessity of high-quality, high-frequency data has led UPRC to install sophisticated remote monitoring on essentially all of its horizontal wells.
The level of remote monitoring and control varies based on the productivity and vintage of the well and the proximity of the well to populated areas or environmentally sensitive areas. Many wells can be monitored remotely for high/low pressure alarms, and high liquid levels.
Depending on the conditions, appropriate alarms and notifications are given, or remote and/or automatic shutdowns can be activated. Automated facilities and monitoring also help verify crude oil and condensate sales volumes.
Remote measuring systems can also serve as the run tickets for oil and saltwater haulers, increasing productivity. Remote monitoring has significantly reduced personnel requirements while improving environmental and safety aspects.
Excellent productivity tools can help leverage the expertise of production engineers, allowing them to detect changes in well behavior that could not be spotted using monthly data. Small variances in high-rate wells have a larger impact on cash flow than large percentage variances in late life wells.
Automated facilities and monitoring also help verify crude oil and condensate sales volumes. Sophisticated equipment can also improve the safety and environmental performance in the field. Conventional vertical wells may not warrant such expenditures.
Surface facilities
Austin chalk gas wells may have a variety of surface equipment depending on the maturity of the wells depletion. Typical gas facilities include a two-phase, 1,000-psi horizontal separator, a three-phase, 250-psi horizontal separator, and a two or three-phase vertical separator.
Flash gas compression compresses separator overhead from the medium and low-pressure separators. Lease dehydration and storage are present along with remote automation equipment. UPRC strives to make this surface equipment as compact as possible and to make clean, attractive locations. An unanticipated benefit of maintaining excellent facilities is that lessors frequently express a preference for an operator with new, clean facilities over a poor boy facility.
Facilities for oil leases include the artificial lift equipment and wider variety of separators and heater treaters.
In areas of high saltwater production, UPRC has installed saltwater gathering systems. Fused high-density polyethylene (HDPE) pipe gathers produced water to a central saltwater disposal well. Centrifugal pumps are used at the lease. This approach has substantially reduced saltwater handling costs.
Substantial solids production may occur during cleanup, especially for wells that had significant lost returns. For these wells, initial testing/production may be to high-rate test separators to minimize the erosional impact of high velocity solids.
Oil is produced during this early phase to frac tanks. A changeover to conventional lease facilities is made as rapidly as practical.
Corrosion
Severe corrosion problems exist in most parts of the Austin chalk due to relatively high concentrations of CO2, particularly in the higher-pressure gas wells. Many wells contain H2S in concentrations of 5-20 ppm. CO2 concentrations of about 4% coupled with high pressures result in extremely high CO2 partial pressures.
The greatest problems occur in the tubing and in the wellheads. UPRC uses plastic-coated tubing for gas wells, with thick films being employed for wells with initial pressures below 8,000 psi and thin films for gas wells with initial pressures above 8,000 psi.
Chemical injection is continuous for gas lift wells and batch injection for pumping wells. Wellheads combine stainless steel and plastic coated elements. Surface equipment is further protected by a surface chemical injection program.
Pipeline corrosion is minimized by dehydrating the gas at the lease to pipeline specifications. This minimizes the potential for corrosion.
Pipelines and heater treaters are protected by cathodic protection for external corrosion.
Organization
Early in the development of the horizontal well play UPRC committed to a team approach with geologists, geophysicists, landmen, and engineers working together. Empowerment can be a buzzphrase or a reality. Ultimately, these teams were able to function independently, approving leasing, redrills, and new well AFEs.
Geosteering technology was transferred from a central petrophysical group to team members after user-friendly software was developed. This required significant training and purchasing a large number of UNIX-based workstations.
Even successful teams will have conflicts. A company-wide commitment to re-engineering helped provide resources to address some of these conflicts. One of UPRCs primary goals was to encourage employees to take risks that have the potential to lower costs and increase recoveries. These will not all work; however, the successful ideas more than pay for numerous failures.
New ideas often challenge existing paradigms and long-held opinions. These need to be questioned. Many paradigms exist because they are successful in predicting and explaining results in vertical wells. Some of these must be replaced as we push the envelope of horizontal well applications.
The quantity of new data (seismic, land, production, etc.) requires systems and people who are flexible. The number of checks, invoices, AFEs, and well test, require a company-wide effort to avoid an explosive growth in the number of employees. The required productivity increases will challenge all aspects of existing systems and processes.
Alliances
UPRC has entered into several alliances with various service companies and suppliers. These range from very simple agreements designed to lower costs for both parties to alliances involving a great deal of re-engineering of the way we do business.
When technology is evolving rapidly, a close alliance with the wrong technology or service supplier may place an operator at a serious disadvantage. Flexibility and short cycle time may be critical. The greatest guarantee for doing a lot of work with UPRC is delivering cost-effective goods and services on time and at a competitive price.
The most successful alliances eliminate redundancies and unnecessary procedures. The cost savings from de-hassling the system (from scheduling jobs to billing) must be shared by all of the alliance participants. Communication and trust are vital to the long-term success of such alliances.
Maximize product values
Controlling natural gas and crude past the tanks and meters may help make the difference in marginal plays. Natural gas plants and pipelines can be a major part of the overall profitability of the system.
The entire gas value chain including transportation, storage, processing, gathering, direct marketing, and hedging prices can help improve margins.
Successful operations
UPRCs first 1,000 horizontal wells have been an economic success because of the combined efforts of hundreds of UPRC employees along with UPRCs partners and suppliers. Success in a relatively low-margin, high-volume drilling campaign requires real teamwork. Horizontal drilling is clearly here to stay. Activity and applications will continue to increase.
One of the key success factors is minimizing costs. It is important to question each of your drilling and producing assumptions. If it isnt broke, dont fix it wont work in an environment where flat and/or declining product prices are likely. Quantum improvements can be obtained by leveraging your technology development and transfer capabilities.
One should collect enough information to understand the reservoir and focus reservoir characterization efforts on profitability goals and not on science fair projects.
It takes a great deal of discipline to do the right level of technology in an environment that has an extreme focus on cost reduction.
People and culture make the difference in maintaining profitability as horizontal operations mature.
Acknowledgments
The author thanks Union Pacific Resources and the many teams and individuals that contribute to UPRCs success. We also acknowledge the cooperation of the Stanford Horizontal Well Project.
References
1.Messman, J.L., Prospering in a $1.75 World, an address to the Arthur Andersen Oil and Gas Symposium, Dec. 6, 1994, Houston.
2.Meehan, D.N., Practical and Reservoir Aspects of Austin chalk Stimulations, SPE 24783, Fall SPE Meeting, Washington, D.C., 1992.
3.Clavier, C., The Challenge of Logging Horizontal Wells, The Log Analyst, March-April 1991, pp. 63-84.
4.Meehan, D.N., Advances in Horizontal Well Technology, Second JNOC/TRC International Symposium, Tokyo, 1994.
5.Svor, T.R., and Meehan, D.N., Quantifying Horizontal Well Logs in Naturally Fractured ReservoirsPart I, SPE 22634, Fall SPE Meeting, Dallas, 1991.
6.Meehan, D.N., and Svor, T.R., Quantifying Horizontal Well Logs in Naturally Fractured ReservoirsPart II, SPE 22792, Fall SPE Meeting, Dallas, 1991.
7.Meehan, D.N., and Verma, S.K., Integration of Horizontal Well Log Information in Fractured Reservoir Characterization, SPE 24697, Fall SPE Meeting, Washington, D.C., 1992.
8.Meehan, D.N., Geological Steering of Horizontal Wells, Technology Today Series, SPE 29242, JPT, October 1994.
9.Meehan, D.N., Rock Mechanics Issues in Petroleum Engineering, First North American Rock Mechanics Symposium, Austin, June 1994.
10.Friedman. M., Kwon, O. , and French, V.L., Containment of natural fractures in brittle beds of the Austin chalk, First North American Rock Mechanics Symposium, Austin, June 1994.
11.Kyte, D.G., Meehan, D.N., and Svor. T.R., Method of Maintaining a Borehole in a Stratigraphic Interval While Drilling, U.S. Patent No. 5,311,951, May 17,1994.
The Author
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
