TECHNOLOGY UPDATES FOR THE PERMIAN BASIN

Based on a workshop sponsored by PTTC's Southwest Region on April 6, 2000, in Hobbs, New Mexico.

BOTTOM LINE

Technology advances in underbalanced drilling, mud logging equipment, real-time monitoring of hydraulic fracturing treatments, well stimulation with water fracs, and borehole imaging and cased-hole logging tools each, when applied properly, can improve well/lease profitability. But this improved profitability comes only when the advantages/limitations and proper application environment of each technology advance are known and applied.

PROBLEM ADDRESSED

Technology advances are occurring in all areas of upstream oil and gas operations. Within this broad realm, independents are challenged with staying abreast of these changes that could favorably impact their well/lease profitability. Brief presentations about advances, supported with field examples, provide a valuable service by alerting independents to proven newer technologies. Given this information, independents can make informed decisions about which technologies are appropriate for their operations.

KEY WORDS:

Borehole Imaging Logs, Cased Hole Density Lithology, Logging, Mud Logging Technology, Tiltmeter Fracture Mapping, Underbalanced Drilling, Water Frac

SPEAKERS

Waterfracs and Tiltmeter Fracture Mapping 
Mike Mayerhofer, Pinnacle Resources

Underbalanced Horizontal Drilling
John Willis, Schlumberger

Specialized Logs for Carbonate Reservoir Characterization
Steve Ruppell, Bureau of Economic Geology, University of Texas at Austin

Cased-Hole Lithology & Density Measurements 
Richard Odom, Computalog

Mud Logging
Royce Howard, Howard Atnip Technologies, Inc.

Mud Logging 
John Richards, Permian Basin Instruments, Inc.

TECHNOLOGY OVERVIEW

Tiltmeters. A hydraulic fracture creates characteristic deformation patterns in the rock around the fractures. Extremely sensitive tiltmeters can be used to measure the tilt (deformation) of the earth at several locations around the fracture area, and from these measurements, the geometry and the orientation of the created hydraulic fracture can be determined. Tilt patterns include a gradual bulging of the earth's surface for horizontal fractures, small troughs along the fracture azimuth for vertical fractures, and asymmetrical bulges for dipping fractures.

For a surface tiltmeter survey, 12 to 24 tiltmeters are installed in 5-40 ft boreholes in concentric circles around the frac with the distance from the well being 15 to 75% of the frac depth. Installation in boreholes helps minimize surface noise. Arrays are installed several days before the fracture treatment to allow readings to stabilize. During the fracture treatment, data loggers capture and store data, which is collected manually or by radio after the frac treatment. Surface fracture mapping can help determine not only the fracture geometry, but also fracture growth in multiple planes, and the approximate location of the fracture center.

Downhole tiltmeters are installed in observation well (s) on a single conductor e-line using standard centralizers. The downhole array with 6 to 15 tiltmeters is centered on the frac interval in the well to be treated. With the short distance to the frac, the signal-to-noise ratio from downhole tiltmeters is large. Current 2 7/8-in tools can withstand pressures to 10,000 psi and temperatures up to 270 ºF. Height to length resolution is 5-10% of offset well distance. Accuracy of results depends on the offset well spacing (100 to 2000 ft), orientation of the fracture to the observation well, created frac dimensions, and the number of downhole tiltmeters and arrays deployed. Downhole tiltmeter arrays can give information about fracture length and height versus time, detect out-of-zone fracture growth and/or unstimulated pay, monitor fracture growth in real time, and can provide calibration of fracture growth models for economic optimization.

In the North Robertson field in the Permian Basin, tiltmeter survey data showed that there is little risk of establishing direct communication between injectors and producers. This reinforced the operator's decision to continue developing on a line drive pattern and indicated that injection wells could be operated above parting pressure without undue reservoir risk. Detailed data indicated that it might also be possible to eliminate a stage in the fracturing treatment, reducing treating costs. In another application, tiltmeter data indicated that 120 ft, or over 40% of the interval, was not being fractured, so major treatment modifications were needed to achieve more complete coverage.

Water Fracs. Low permeability reservoirs typically require extended-length fractures to maximize the surface area of the fracture faces and therefore improve production volumes and rates. Conventional fracture jobs achieve this fracture extension by pumping large volumes of propping agents emplaced at high concentrations in viscous gelled-fluid systems. Water fracs are an alternative that reduces stimulation costs. A typical modern water frac involves pumping very large volumes of lightly treated fresh water (10,000 bbl or more, lightly treated with friction reducer, surfactant and clay stabilizer) with low sand concentrations (0.5 ppg during bulk with tail-in from 0.5 to 2 ppg during last 1-5% of job). Higher sand concentrations near the end of the treatment help prop the fracture near the wellbore. Since the treating fluid is primarily water (not gel), clean-up problems sometimes experienced with conventional treatments are minimized. The low viscosity of the water treating fluid tends to maximize length while minimizing fracture height.

There is a combination of mechanisms believed responsible for a water frac's ability to stimulate productivity. Created fractures have rough enough surfaces so that fractures do not completely close. Rock debris may also act as a self-propping agent, or there can be proppant blocking or accumulation in only selected portions of the fracture. Whatever the contributing mechanisms, the created fractures can have conductivity rivaling that of conventional (gel with high proppant concentrations) treatments. Treatments work best in lower permeability reservoirs where less fracture conductivity is needed.

Water fracs have been used extensively in the East Texas Cotton Valley play. There, a comparison of production response from 90 wells (50 water fracs and 40 conventional fracs) reveals that water fracs perform as effectively as conventional fracs at much lower treating costs. Long-term production showed no substantial differences in decline behavior. Larger treatment volumes seemed to perform better. Since gelled fluids are not present, water fracs cleaned up faster than conventional treatments.

Treatment design must be optimized for each reservoir/field. It is desirable to have small increases in net pressure throughout the job to avoid "proppant banking." Without considering costs, higher injection rates and larger volumes are likely to achieve better fracture stimulation. When executing programs, operators should consider using fracture diagnostic techniques to measure fracture geometry and evaluate fracture quality. Low-pressure, partially depleted, low permeability reservoirs or naturally fractured reservoirs are good candidates for water fracs. Reservoirs with stiff rock (high Young's modulus) and normal stress are good candidates.

Water fracs have been performed in the Barnett Shale since 1997. One operator who has performed more than 100 treatments initially used water fracs only in marginal areas where fewer natural fracs are present. There, the lower cost of water fracs prompted their use. The operator has since begun using water fracs in higher productivity areas as well, since lower treating costs more than offset any slight losses in production performance. This operator did discover that sand concentration needed to be reduced from 0.5 ppg to 0.2 ppg to reduce screen-outs. A second operator, based on 150 treatments, experienced 60% cost reduction (as compared to 40# borate cross-linked gel with bauxite) with water fracs using 1/4 to 1 ppg sand, no gel, and resin-coated sand. Jobs are pumped at high,70 to 130 bpm, rates. Well performance has been equivalent to better.

Specialized Logs for Carbonate Reservoir Characterization. Carbonate reservoirs are characterized by complex variations in facies and rock fabrics that result in considerable heterogeneity. Resolution and mapping of these variations are fundamental to accurate definition of petrophysical properties and construction of reservoir models. For the most part, adequate characterization of carbonate facies and rock fabric variability requires large numbers of cores. However, some modern wireline logs, when properly calibrated with cores, can provide surprisingly robust resolution of carbonate reservoir attributes that can rival those obtainable from cores. Spectral gamma ray logs, which differentiate potassium/thorium gamma-ray response from uranium response, are inexpensive wireline logs that can, in some cases, delineate both facies and cycle boundaries. In the Permian Clear Fork Group, for example, siliciclastic-bearing, cycle-top, tidal-flat deposits are readily differentiated from petrophysical properties between these two facies. The spectral log can provide a rigorous basis for detailed petrophysical characterization.

Although generally considered to be a tool for fracture identification, calibrated borehole imaging logs can resolve facies successions and cycle boundaries with nearly the same accuracy as cores. In typical Leonardian and Guadalupian successions, tidal-flat rocks are readily characterized by a thinly layered pattern, deeper subtidal fusilinid-bearing rocks by a vermiform character, and shallow subtidal rocks by a granular pattern on image logs. Grikes, solutions pits, and collapse breccias, commonly associated with karst horizons in Wolfcampian and Pennsylvanian rocks, are also readily definable. The detailed resolution of facies, sedimentary structures, cyclicity, and in some cases, pore types provided by the properly calibrated borehole imaging logs compares with that afforded by cores. These logs offer a viable, commonly lower cost, alternative for gathering critical rock data for carbonate reservoir characterization.

Cased-Hole Lithology and Density Measurements. Often, traditional cased reservoir analyses are not comprehensive enough to be applicable to the mixed lithologies common to Permian Basin reservoirs. The accuracy of the two cased-hole saturation measurements (Sigma and Carbon/Oxygen logging) requires a porosity that is corrected for lithology effects. The saturation equations also require inputs for the effects of the rock matrix in the calculation. Along with correction and correlation of logging measurements, the lithology determination can be important in identifying reservoir characteristics, such as sand or anhydrite content, that are often linked to permeability and a reservoir's ability to produce.

Two new measurements are being developed for Computalog's Pulsed Neutron Decay System (PND-S), a density-based porosity from inelastic scattering of gamma rays and an inferred photo-electric (Pe) factor based on neutron-induced spectroscopy data. The combination of these two new measurements with the existing pulsed-neutron technologies is used to develop a more comprehensive reservoir analysis model. Using the cased-hole density with the neutron porosity can resolve the ambiguities posed by gas-filled porosity and changing rock matrix. Applications of these new measurements were demonstrated in several reservoir analysis examples from the Permian Basin.

Underbalanced Horizontal Drilling. Underbalanced drilling offers several advantages, including reduced formation damage, no differential sticking, and, potentially, elimination of stimulation treatments. But there are additional expenses for nitrogen, possible problems with shale, and the possibility of excessive surface pressure. Crews also must have specialized experience. Required surface equipment includes a rotating BOP for high pressure, rotating head for lower pressure, a nitrogen membrane unit, compressors and booster, a choke manifold and injection pump. Downhole equipment includes a positive displacement motor, wet-connect system, SLIM-1 MWD system, inside back pressure valve and drill bit. Fluid is typically fresh water or brine with surfactant and corrosion inhibitor. Fluid volumes vary from 4 to 8 gpm in 4 3/4- to 6 1/8-in holes to 8 to 12 gpm in 7 7/8- to 8 3/4-in holes. Nitrogen rates vary from +/- 800 cfm for 4 ¾-in holes to +/- 2500 cfm for 8 3/4-in holes. Exact volumes are dependent on the true vertical depth of the well and hole temperature.

Drilling performance with nitrogen versus conventional mud was compared for two wells in Winkler County, Texas. The liquid-drilled well was drilled to a true vertical depth of 4,734 ft with a 1,545 lateral. It required 12 days to drill the well, 131 hours of drilling time, and tested for 700 Mcfd on completion. The well drilled underbalanced with nitrogen achieved a true vertical depth of 4,634 ft. Fluid was used until a 50 degree buildup was achieved, then operations switched to underbalanced drilling with nitrogen. Lateral length was 1,280 ft. It required 8 days to drill the well, 86 hours of drilling time, and tested for 4,300 Mcfd on completion.

Mud Logging. Newer mud logging instrument systems with solid state sensors and power supply have enhanced sensitivity and stability and are not flow sensitive like older equipment. They are not affected by polymer muds or drilling mud additives and with no moving parts/pens/etc., data recorders are much more reliable. Data are accessible via PC from anywhere. Bottom line, data are more sensitive and reliable. That sensitivity and reliability mean more accurate identification of pay zones and ultimately better completions.

CONNECTIONS:

Mike Mayerhofer
Pinnacle Resources
15425 North Freeway, Suite 340
Houston, TX 77090
Phone: 281-876-2323 

John Willis
Schlumberger Oilfield Services
9900 West I20
Midland, TX 
E-mail: jwillis2@midland.anadrill.slb.com 

Steve Ruppell
Bureau of Economic Geology, University of Texas at Austin
Box X, University Station
Austin, TX 78713-8924
Phone: 512-471-2965 E-mail: stephen.ruppel@beg.utexas.edu

Richard Odom
Computalog Research Inc.
500 Winscott Road
Fort Worth, TX 76126
Phone: 817-249-7200 E-mail: odom@computalog.com

Royce Howard
Howard Atnip Technologies, Inc.
P.O. Box 9457
Midland, TX 79708
Phone: 915-699-1607 E-mail: royce@planetwide.com

John Richards
Permian Basin Instruments, Inc.
4002 Norwood
Midland, TX 79707
Phone: 915-687-4445 Fax: 915-687-4452
E-mail: jrich12592@cs.com

For information on PTTC’s Southwest Region and its activities contact:
Robert Lee, Director, Petroleum Recovery Research Center
801 Leroy Place, Socorro, NM 87801
ph 505-835-5938, fax 505-835-6031, e-mail prrc@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.

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