Various technologies unlock Pinedale anticline tight gas

June 25, 2007
Various technologies have enabled Shell Exploration & Production Co. to produce economically from the tight gas sands found in the Pinedale anticline of Western Wyoming.

Various technologies have enabled Shell Exploration & Production Co. to produce economically from the tight gas sands found in the Pinedale anticline of Western Wyoming.

These technologies include optimally staged hydraulic fracturing, innovative pressure-acquisition modules with gauges and perforating guns mounted outside the casing, wireless transmission of downhole pressure data through the casing, fiberoptic distributed temperature sensing, development of complex 3D static and dynamic models, and microseismic mapping of hydraulic fractures.

“From a technology perspective, Pinedale has been our arena to test and develop new technologies to increase recoveries in these difficult reservoirs,” said John Bickley, team leader, Shell EP Americas Tight Gas Task Force.

“Having a working relationship with the asset allows us to easily apply technologies we develop in the lab to real-world conditions in the field. We have pushed the application of existing technologies and tried new ones. By integrating the results of all these efforts, we have met our objectives to reduce costs, add production, and increase our scope for recovery at Pinedale in an environmentally responsible way.”

Shell expects these lessons from Pinedale will apply to other, unconventional gas reservoirs.

Pinedale anticline

The Pinedale anticline (Fig. 1) is a northwest-southeast trending, doubly plunging, asymmetric anticline covering 150 sq miles (35 miles long and 6 miles wide). The reservoir section has 6,000 ft of highly discontinuous fluvial sandstones, siltstones, and shales from the upper Cretaceous age Lance-Mesaverde interval.

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Producing intervals lie at 7,000-14,000 ft depths and contain 300-1,300 ft of potential pay. The produced gas is mostly methane with few impurities and an average heat content of 1,080 btu/Mscf.

California Co. drilled the first well at Pinedale in 1939, but active field development did not proceed until mid to late 1990s as improved hydraulic fracturing techniques, higher natural gas prices, and commingled production operations enabled economic stimulation and production from tight gas sands.

Nearby Jonah field to the southwest, containing a similar section of tight sands, was the first to see active development.

Shell began operations at Pinedale in 2001 and is one of the three main acreage holders in the field, holding about a 25% working interest. The two other companies with sizable acreage positions are Ultra Petroleum Corp. and Questar Corp.

Shell says its reentry into the Rocky Mountain area was part of the company’s global strategic goal to expand its exposure to North America gas.

The area has huge gas resources: The US Geological Survey has reported that Pinedale contains 159 tcf of gas in place but requires application of both existing and new technologies in drilling and completion operations to produce the gas economically.

Shell formed an internal Tight Gas Task Force (TGTF), a team of technical experts for identifying existing and developing new technologies for producing the gas from Pinedale. Shell says that although it had previous experience in developing tight gas fields in South Texas and Michigan, it knew little about the reservoir characteristics at Pinedale, which has a wide variability in drilling conditions and geology, as well as environmental restrictions that limit development operations for part of the year.

Drilling and completion restrictions at Pinedale protect wildlife migration and winter habitats (Fig. 2). Photo from Shell.
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Drilling and completion restrictions exist year round on portions of Pinedale, and the Big Game Range winter restrictions for protecting wildlife migration and winter habitat currently shut down all drilling and completion activities for the northern two thirds of the anticline from November through May (Fig. 2).

Unraveling Pinedale

To determine the best development strategy for Pinedale, Shell undertook a major data-acquisition effort, performed special core analysis, and used experimental logging tools to predict gas volumes in place and understand well productivity. The Pinedale asset drilling team tested various drilling techniques, including use of skid rigs, underbalanced drilling techniques, slim-hole casing, and a variety of drill bits.

Shell says these modifications have reduced drilling cycle time and costs. The time to drill an average well decreased to 35 days in 2006 from 65 days in 2002, with 25 days being the best performance to date.

On the geophysical side, Shell’s team experimented with reprocessing of seismic data and studied natural fractures and outcrops to understand the stress history of the anticline. It also drilled a horizontal well to characterize the natural fracture network.

Shell said the well demonstrated that natural fractures occur throughout the anticline, but in general, it does not believe that natural fractures represent a critical component of reservoir productivity.

Hydraulic fracturing

Massive hydraulic fracturing of the low-permeability reservoirs at Pinedale has enabled operators to produced gas from the reservoirs more efficiently.

Shell says staged hydraulic fracturing increased stimulation efficiency and was one of the first opportunities identified by its task force. Stimulation efficiency is a measure of reservoir height contributing to production relative to the total targeted reservoir height completed. A higher stimulation efficiency will recover more reserves.

In stacked multiple-interval sands, Shell says companies had historically tried to stimulate too much of the vertical interval with a single-stage fracturing job. It, therefore, implemented a program with more stimulation stages per well. This raised completion costs but ultimately will increase stimulation efficiency and reserves recovery, the company said.

Shell describes that in its operations a typical fracture stimulation will include proppant from the 10s to the 100s of thousand lb. It uses both sand and ceramic proppant and places it several 100 ft from the wellbore.

The stimulation jobs include an external casing and perforating technique, EXcape, in which perforating guns are run external to the casing and the firing heads are actuated hydraulically to stimulate more of the pay and improve operational efficiencies. The Excape system developed by Marathon Oil Co., BJ Services Co., and Expro Group also has been effective for stimulating other tight gas sands such as in Alaska (OGJ, Sept. 2, 2002, p. 39) and Canada (OGJ, Oct. 25, 1999, p. 69).

Shell says stimulation designs at Pinedale have evolved to optimize interval staging, proppant types, proppant volumes, and transport fluids.

Completion operations also continue to change. Shell has accelerated cycle times from single-stage treatments and cleanup of 2 weeks duration/stage to 24 continuous completion operations with up to eight stages/day.

In drilling out frac-stage isolation plugs, it has changed the procedures from flaring gas volumes during rig-assisted snubbing operations to flareless, single-trip coiled tubing operations.

Another technology used by Shell is microseismic diagnostic monitoring that reveals the azmuthal orientation and created geometries of hydraulically induced fractures. The technology provides a better understanding of the effectiveness and efficiencies of the fracturing operations and helps optimize well drainage.

Shell says these data are critical for calibrating hydraulic fracture design models and static and dynamic reservoir models. These microseismic fracture maps provide an indication of remaining undrained areas that can be targets in with future drilling.

Data gathering, evaluation

One technology Shell employs at Pinedale is multiple-gauge wireless telemetry. The Cableless Telemetry System (CaTS) was sponsored by Shell and developed by the Expro Group (OGJ, Feb. 21, 2005, p. 41).

This technology uses the casing as the conductor for transmitting downhole pressure and temperature data, eliminating the need of running a separate conductor line in the well.

Shell has installed CaTS in either dedicated monitor wells or wells with the dual purpose of monitoring the completed intervals and producing from them.

The system provides formation pressure and temperatures at multiple depths, measures initial reservoir pressures in isolated reservoir intervals, provides depletion pressures of reservoirs completed and produced in the monitor well, and indicates pressure communication and decline trends in reservoirs in communication with offset producing well.

Shell uses these measurements to assess well drainage areas and to optimize well pattern and spacing between development wells.

Well spacing at Pinedale ranges from 40 to 5 acres, with many wells drilled deviated from well pads that accommodate multiple wellheads and minimize the drilling and production footprint (Fig. 3). Photo from Shell.
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Most fluvial tight gas fields in the area begin with a 40-acre subsurface well spacing and subsequently, companies downspace the fields to 20, 10, or even 5-acre spacing. Greater well spacing reduces development costs because fewer wells are required but may not adequately deplete the field.

Shell notes that optimal well spacing eliminates the risks of drilling through depleted zones, avoids in-fill well placement problems, preserves the desired well pattern and interwell spacing, and maximizes capital efficiency of total completion costs.

The permeability of the sands at Pinedale is in the 5-10 μdarcy range, making it difficult and time consuming to acquire reliable pressure data. Shell says only after installing the long-term monitoring systems that it realized that after drilling, a well required 20-300 days to return to the original pressure.

The CaTS system also provided Shell with the first pressure profile as a function of depth in Pinedale. In addition to installing gauges in dedicated monitor wells, Shell worked with the Expro Group to develop both wireless and wired instrumentation systems external to the casing to enable pressure monitoring of the entire vertical reservoir interval, without compromising the integrity of the casing.

Shell says these technologies allow it to monitor reservoir pressures for a desired period of time and then complete the well for production with selective hydraulic fracture stimulations following the data-acquisition period.

A well in Pinedale may have 20-70 individual sands in a 7,000-14,000-ft interval, and Shell says pressure data are the only data that enable calibration of static and dynamic reservoir models. Pressure gradients in the anticline range from 0.43 psi/ft (normal hydrostatic) at the top of the producing section to 0.8 psi/ft at TD.

Shell installed a world record of 44 individual external pressure-temperature modules in two wells over a 12-day period during the summer of 2006, bringing the total number of pressure gauges installed in monitor wells to 115 across the field during the past 2 years.

Shell says pressure tests show how the sands produce, how many wells are needed, and how to space them. Well spacing affects profitability and depends on where the wells are located on the anticline.

Data from pressure data provide the basis for understanding well performance and recovery efficiencies at Pinedale. Using the pressure information, Shell develops and calibrates 3D static and dynamic models to determine reservoir sand connectivity and drainage of individual wells to design further field development. These data show how pressure declines over time and when matched against complex reservoir models provide values for porosity, connectivity, and permeability.

Shell also employs fiber-optic distributed temperature sensing technology to measure temperature profiles across the massive, commingled production interval. The temperature change shows the movement of the gas within the wellbore. As gas enters the wellbore, it expands and cools, whereas water or condensate expands and becomes warmer. These temperature changes allow one to calculate gas flow rate from various intervals.

By continuously monitoring temperatures in the wellbore over the full reservoir life cycle, Shell can further develop and calibrate 3D models for the field. Operators currently are developing the field on 20 and 10-acre spacing, with 5-acre spacing being evaluated in certain areas.

Shell’s asset team and task force also are working on production data analysis for commingled production from the wellbore by running multiple production logs over time. From these data, the teams can evaluate and discriminate reservoir permeabilities and fracture characteristics, as well as to develop models for characterizing the drainage area.

Shell says these data enable better calibration of the static and dynamic models and provide information on how much gas a well will deliver in a 30-year life and the amount of reserves that can be booked.

Further development

Shell expects to drill thousands of wells to develop this field. Many of Shell’s wells are drilled deviated from a single well pad to minimize the drilling and production operation footprint, although some wellsites have only single wells (Fig. 4).

This single-well producing facility includes the wellhead in the foreground, with surface flowlines to an environmentally protected production building containing a heater and separator. In the far background is the electronic data gathering and transmission building. The three tanks, on the right, store condensate and water (Fig. 4). Photo from Shell.
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By yearend 2006, Shell had participated in drilling more than 260 wells and says its optimization exercise provided a huge savings while capturing economic incremental reserve volumes.

For 2007 and 2008, Shell says its task force is working with selected technology innovations to lead the development of new artificial-lift pump technology to unload liquids from the wellbore and improve outflow performance to ensure maximum recovery from the field.

Shell says application of various technologies at Pinedale has had the following results:

  • Its total gross production reached 300 MMscfd by yearend 2005, and the latest yearly figure available, with 2006 and 2007 expected to show increases.
  • Completions that once took more than 6 months now typically take 7-10 days.
  • Its drilling time averages 39 days/well, considerably less than the nearest competitor.
  • Its recoverable natural gas resources in Pinedale field have increased markedly.